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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
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| For the Fiscal Year EndedDecember 31, |
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[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
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| For the transition period from ____________ to ____________ |
Commission | Registrant; State of Incorporation; | I.R.S. Employer |
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1-5324 | NORTHEAST UTILITIES | 04-2147929 |
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0-00404 | THE CONNECTICUT LIGHT AND POWER COMPANY | 06-0303850 |
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1-6392 | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE | 02-0181050 |
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0-7624 | WESTERN MASSACHUSETTS ELECTRIC COMPANY | 04-1961130 |
Securities registered pursuant to Section 12(b) of the Act:
Registrant | Title of Each Class | Name of Each Exchange on Which Registered |
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Northeast Utilities | Common Shares, $5.00 par value | New York Stock Exchange, Inc. |
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Securities registered pursuant to Section 12(g) of the Act:
Registrant | Title of Each Class |
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The Connecticut Light and Power Company | Preferred Stock, par value $50.00 per share, issuable in series, of which the following series are outstanding: |
$1.90 | Series | of 1947 | |
$2.00 | Series | of 1947 | |
$2.04 | Series | of 1949 | |
$2.20 | Series | of 1949 | |
3.90% | Series | of 1949 | |
$2.06 | Series E | of 1954 | |
$2.09 | Series F | of 1955 | |
4.50% | Series | of 1956 | |
4.96% | Series | of 1958 | |
4.50% | Series | of 1963 | |
5.28% | Series | of 1967 | |
$3.24 | Series G | of 1968 | |
6.56% | Series | of 1968 |
Public Service Company of New Hampshire and Western Massachusetts Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.
Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
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Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ü]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
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Northeast Utilities |
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The Connecticut Light and Power Company |
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Public Service Company of New Hampshire |
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Western Massachusetts Electric Company |
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Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
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Northeast Utilities |
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The Connecticut Light and Power Company |
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Public Service Company of New Hampshire |
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Western Massachusetts Electric Company |
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The aggregate market value ofNortheast Utilities’ Common Shares, $5.00 par value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities’ most recently completed second fiscal quarter (June 30, 2008)2010) was$3,970,521,6944,486,982,187based on a closing sales price of$25.5325.48per share for the 155,523,764176,098,202 common shares outstanding on June 30, 2008. 2010. Northeast Utilitiesholds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock ofThe Connecticut Light and Power Company, Public Service Company of New Hampshireand Western Massachusetts Electric Company, respectively.
Indicate the number of shares outstanding of each of the registrants' classes of common stock, as of the latest practicable date:
Company - Class of Stock | Outstanding |
Northeast Utilities |
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The Connecticut Light and Power Company |
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Public Service Company of New Hampshire |
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Western Massachusetts Electric Company |
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Documents Incorporated by Reference:
Description |
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Portions of the Northeast Utilities Proxy Statement expected to be dated |
| Part III |
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms that are found in this report:
COMPANIES
GLOSSARY OF TERMS | |
The following is a glossary of abbreviations or acronyms that are found in this report. | |
CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS: | |
Boulos |
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CL&P | The Connecticut Light and Power Company |
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HWP | HWP Company, formerly the Holyoke Water Power |
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NGS | Northeast Generation Services Company and subsidiaries |
NGS Mechanical | NGS Mechanical, Inc. |
NPT | Northern Pass Transmission LLC, a jointly owned limited liability company, held by NUTV and NSTAR Transmission Ventures, Inc. on a 75 percent and 25 percent basis, respectively |
NUTV | NU Transmission Ventures, Inc. |
NU or the | Northeast Utilities and subsidiaries |
NU Enterprises | NU Enterprises, Inc. |
NUSCO | Northeast Utilities Service Company |
NU parent and other companies | NU parent and other companies is comprised of NU parent, NUSCO |
PSNH | Public Service Company of New Hampshire |
Regulated companies | NU's |
RRR | The Rocky River Realty Company |
SECI | Select Energy Contracting, Inc. |
Select Energy | Select Energy, Inc. |
SESI | Select Energy Services, Inc. |
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WMECO | Western Massachusetts Electric Company |
Yankee | Yankee Energy System, Inc. |
Yankee Gas | Yankee Gas Services Company |
REGULATORS
REGULATORS: | |
CDEP | Connecticut Department of Environmental Protection |
DOE |
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EPA | U.S. Environmental Protection Agency |
DPU | Massachusetts Department of Public Utilities |
DPUC | Connecticut Department of Public Utility Control |
FERC | Federal Energy Regulatory Commission |
MA DEP | Massachusetts Department of Environmental Protection |
NHPUC | New Hampshire Public Utilities Commission |
SEC | Securities and Exchange Commission |
USDEP | U.S. Department of Environmental Protection |
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OTHER
OTHER: | |
2010 Healthcare Act | Patient Protection and Affordable Care Act |
2010 Tax Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act |
AFUDC | Allowance |
AMI | Advanced metering infrastructure |
ARO | Asset Retirement Obligation |
C&LM | Conservation and Load Management |
CAAA | Clean Air Act Amendments |
CERCLA | The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 |
CfD | Contract for Differences |
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CTA | Competitive Transition Assessment |
CWIP | Construction work in progress |
CYAPC | Connecticut Yankee Atomic Power Company |
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EIA | Energy Independence Act |
EMF | Electric and Magnetic Fields |
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EPS | Earnings Per Share |
ERISA | Employee Retirement Income Security Act of 1974 |
ES | Default Energy Service |
ESOP | Employee Stock Ownership Plan |
ESPP | Employee Stock Purchase Plan |
FASB | Financial Accounting Standards Board |
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FMCC | Federally Mandated Congestion |
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GAAP | Accounting principles generally accepted in the United States of America |
GHG | Greenhouse Gas |
GSC | Generation Service Charge |
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GWh | Giga-watt Hours |
HG&E | Holyoke Gas and Electric, a municipal department of the town of Holyoke, MA |
HQ | Hydro-Québec, a corporation wholly-owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada |
HVDC | High voltage direct current |
Hydro Renewable Energy | H.Q. Hydro Renewable Energy, Inc., a wholly-owned subsidiary of Hydro-Québec |
IPP | Independent Power Producers |
ISO-NE | ISO New England, Inc., the New England Independent System Operator |
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KV | Kilovolt |
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LNG | Liquefied |
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LOC | Letter of Credit |
LRS | Last resort service |
MGP | Manufactured Gas Plant |
Millstone | Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3. All three units were sold in March |
MMBtu | One million British thermal units |
Money Pool | Northeast Utilities Money Pool |
Moody's | Moody's Investors Services, Inc. |
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MWh | Megawatt-Hours |
MYAPC | Maine Yankee Atomic Power Company |
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NOx | Nitrogen oxide |
Northern Pass | The high voltage direct current transmission line project from Canada into New Hampshire |
NPDES | National Pollutant Discharge Elimination System |
NU supplemental benefit trust | The NU Trust Under Supplemental Executive Retirement Plan |
NWPP | Northern Wood Power |
PBO | Projected Benefit Obligation |
PBOP | Postretirement Benefits Other Than |
PBOP Plan | Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits |
PCRBs | Pollution Control Revenue Bonds |
Pension Plan | Single uniform noncontributory defined benefit retirement plan |
PGA | Purchased Gas Adjustment |
PPA | Pension Protection Act |
RECs | Renewable Energy Certificates |
Regulatory ROE | The average cost of capital method for calculating the return on equity related to the distribution and generation business segments excluding the wholesale transmission |
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RGGI | Regional Greenhouse Gas Initiative |
RMR | Reliability Must Run |
RNS | Regional Network Service |
ROE | Return on Equity |
RPS | Renewable Portfolio Standards |
RRB | Rate Reduction |
RSUs | Restricted share units |
RTO | Regional Transmission |
S&P | Standard & Poor's Financial Services LLC |
SBC |
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SCRC | Stranded Cost Recovery Charge |
SERP | Supplemental Executive Retirement Plan |
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SS | Standard service |
TCAM | Transmission Cost Adjustment Mechanism |
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UI | The United Illuminating Company |
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VIE | Variable |
WWL Project | The construction of a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of Yankee Gas' LNG plant |
YAEC | Yankee Atomic Electric Company |
Yankee Companies |
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NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
20082010 Form 10-K Annual Report
Table of Contents
| Part I | Page |
Item 1. | Business | 2 |
Item 1A. | Risk Factors |
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Item 1B. | Unresolved Staff Comments |
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Item 2. | Properties |
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Item 3. | Legal Proceedings |
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Item 4. |
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| Part II |
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Item 5. | Market for the Registrants' Common Equity and Related Stockholder Matters |
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Item 6. | Selected Consolidated Financial Data |
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Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
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Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
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Item 8. | Financial Statements and Supplementary Data |
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Item | Changes in and Disagreements |
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Item | Controls and Procedures |
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Item | Other Information |
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| Part III |
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Item 10. | Directors, Executive Officers and Corporate Governance |
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Item 11. | Executive Compensation |
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Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
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Item 13. | Certain Relationships and Related Transactions, and Director Independence |
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Item 14. | Principal Accountant Fees and Services |
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Part IV |
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Item 15. | Exhibits and Financial Statement Schedules |
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Signatures |
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NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
References in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.
From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our "forward-looking statements"forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections mayma y vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to, to:
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actions or inaction by local, state and federal regulatory bodies
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changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services
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changes in weather patterns
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changes in laws, regulations or regulatory policy
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changes in levels and timing of capital expenditures
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disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly
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developments in legal or public policy doctrines
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technological developments
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changes in accounting standards and financial reporting regulations
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fluctuations in the value of our remaining competitive electricity p ositions, contracts
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actions of rating agencies
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The expected timing and likelihood of completion of the proposed merger with NSTAR, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, as well as the ability to successfully integrate the businesses, and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect and
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other presently unknown or unforeseen factors.
Other risk factors are detailed from time to time in our reports filed with the SecuritiesSEC and Exchange Commission (SEC)updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties whichthat may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A "Risk, Risk Factors," included in this combined Annual Report on Form 10-K. ThisTh is Annual Report on Form 10-K also describes material contingencies and critical accounting policies and estimates in the accompanying "Management’sManagement’s Discussion and Analysis"Analysis and "CombinedCombined Notes to Consolidated Financial Statements."Statements. We encourage you to review these items.
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NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
PART I
Item 1.
Business
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.
PROPOSED MERGER WITH NSTAR
On October 18, 2010, we and NSTAR announced that each company’s Board of Trustees unanimously approved a Merger Agreement (the merger agreement) to combine the two companies. The transaction was structured as a merger of equals in a tax-free exchange. Upon the terms and subject to the conditions set forth in the merger agreement, at closing, NSTAR will become a wholly-owned subsidiary of NU. The post-transaction company will provide electric and natural gas energy delivery service to nearly 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire, representing over half of all the customers in New England.
Under the terms of the merger agreement, NSTAR shareholders would receive 1.312 NU common shares for each common share of NSTAR that they own (the "exchange ratio"). The exchange ratio was structured to result in a no premium merger and is based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement. Following completion of the merger, common shares of the post-transaction company will be owned approximately 56 percent by NU shareholders and approximately 44 percent by former NSTAR shareholders. We anticipate that we will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger. Following the closing of the merger, our next quarterly dividend per common share will be increased to an amount that is equivalent to NSTAR’s last quarterly dividend per common share paid prior to the closing, divided by the exchange ratio. Based on the last quarterly dividend paid by NSTAR of $0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, that would result in NU’s quarterly dividend being increased by approximately 18 percent to approximately $0.325 per share, or approximately $1.30 per share on an annualized basis as compared to NU's current annualized dividend of $1.10 per share. NU filed its joint proxy statement/prospectus with the SEC on January 5, 2011 and scheduled a special meeting of shareholders for March 4, 2011, at which shareholders will vote on whether to approve the merger.
Completion of the merger is subject to various customary conditions, including approval by holders of two-thirds of the outstanding common shares of each company and receipt of all required regulatory approvals, including those of the Massachusetts DPU, the FERC and the NRC. We received approval from the FCC on January 4, 2011, and on February 10, 2011, the applicable Hart-Scott-Rodino waiting period expired. Several intervening parties have applied to participate in the regulatory review of the merger and have raised various issues that they believe the regulatory agencies should examine in the course of the proceedings.
In November 2010, the DPUC issued a draft decision stating it lacked jurisdiction over the merger. In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC to reconsider its draft decision. In January 2011, the DPUC issued an Administrative Order stating that it plans to hold a hearing to determine if it has jurisdiction over the merger. Oral arguments surrounding the draft decision were held in February 2011. The DPUC plans to hold an informational hearing at a date to be determined. In addition, legislation proposing to give the DPUC jurisdiction over the merger may be introduced in the Connecticut legislature.
THE COMPANY
NU, headquartered in Berlin,Hartford, Connecticut, is a public utility holding company registered with the Federal Energy Regulatory Commission (FERC)subject to regulation by FERC under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly-owned regulated utility subsidiaries:
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The Connecticut Light and Power Company (CL&P), a regulated electric utility whichthat serves residential, commercial and industrial customers in parts of Connecticut.Connecticut;
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Public Service Company of New Hampshire (PSNH), a regulated electric utility whichthat serves residential, commercial and industrial customers in parts of New Hampshire.Hampshire and continues to own generation assets used to serve customers;
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Western Massachusetts Electric Company (WMECO), a regulated electric utility whichthat serves residential, commercial and industrial customers in parts of western Massachusetts; and
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Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility whichthat serves residential, commercial and industrial customers in parts of Connecticut.
We sometimes refer to CL&P, PSNH, WMECO and Yankee Gas collectively in this Annual Report on Form 10-K as the "regulated companies."
NU also owns certain unregulated businesses through its wholly-owned subsidiary, NU Enterprises, Inc. (NU Enterprises). We have exited most of these businesses.Enterprises. As of December 31, 2008,2010, NU Enterprises's remainingEnterprises’ business consisted of (i) Select Energy Inc.’sEnergy’s few remaining energy wholesale marketing contracts, which are being wound down, and (ii) NU Enterprises’ remaining energy serviceselectrical contracting business.
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Although NU, consolidated, CL&P, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line of business basis. The regulated companies include three business segments:line-of-business, basis - the electric distribution segment (which also includes PSNH’s regulatedthe generation activities), thebusinesses of PSNH and WMECO and our natural gas distribution segmentbusiness) and the electric transmission segment. The regulated companies’ segment of our business representedOur Regulated companies accounted for approximately 99.599 percent of our total earnings of $387.9 million for 2008, excluding an after-tax charge of $29.8 million resulting from the settlement of litigation with Consolidated Edison, Inc. (Con Edison),2010, with electric distribution (including PSNH’s generation activities) representing approximately 42.645 percent, electric transmission representing approximately 47.6 percent, and natural gas distribution representing approximately 9.3 percent. At December 31, 2008, the NU Enterprises business segment included the following legal entities: (i) Select Energy, Inc. (Select Energy), (ii) Northeast Generation Services Company (NGS), (iii) E.S. Boulos Company (Boulos), (iv) the8 percent and electric transmission representing approximately 46 percent of consolidated earnings. The remaining business1 percent of Select Energy Contracting, Inc. (SECI), (iv) NGS Mechanical, Inc., and (v) NU Enterprises parent.
For information regarding each of NU’s segments, see Note 17, "Segment Information," to the Consolidated Financial Statements in this Annual Report on Form 10-K.our 2010 earnings comes from our competitive businesses.
REGULATED ELECTRIC DISTRIBUTION
General
NU’s electric distribution segment is made upconsists of the distribution businesses of CL&P, PSNH and WMECO, which are primarily engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts, respectively, plus PSNH’s regulated electric generation business.business and WMECO’s solar generation. The following table shows the sources of 20082010 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:
Sources of |
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Industrial |
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Other |
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| 100% |
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A summary of changes in the operatingRegulated companies’ retail electric kilowatt-hour (kWh) distribution sales (GWh) for the 12-months ended December 31, 20082010 as compared to December 31, 20072009 on an actual and weather normalized basis (using a 30-year average) is as follows:
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| WMECO |
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| Weather |
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| 2010 |
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| Percentage |
| Weather |
Residential |
| (4.1)% |
| (2.7)% |
| (2.2)% |
| (1.0)% |
| (3.1)% |
| (2.1)% |
| (3.6)% |
| (2.3)% |
| 14,913 |
| 14,412 |
| 3.5% |
| (0.7)% |
Commercial |
| (1.3)% |
| (0.7)% |
| (1.2)% |
| (0.4)% |
| (2.6)% |
| (2.1)% |
| (1.4)% |
| (0.8)% |
| 14,506 |
| 14,474 |
| 0.2% |
| (2.8)% |
Industrial |
| (9.8)% |
| (9.3)% |
| (6.1)% |
| (5.4)% |
| (8.7)% |
| (8.5)% |
| (8.6)% |
| (8.1)% |
| 4,481 |
| 4,423 |
| 1.3% |
| (1.5)% |
Other |
| (3.2)% |
| (3.2)% |
| 2.2 % |
| 2.2 % |
| (14.6)% |
| (14.6)% |
| (3.7)% |
| (3.7)% |
| 330 |
| 336 |
| (1.4)% |
| (1.4)% |
Total |
| (3.7)% |
| (2.8)% |
| (2.5)% |
| (1.6)% |
| (4.2)% |
| (3.5)% |
| (3.5)% |
| (2.6)% |
| 34,230 |
| 33,645 |
| 1.7% |
| (1.7)% |
RetailTotal retail electric sales for all three electric companies were higher in 2008 were lower2010 compared to 2009 due primarily to warmer than those in 2007. The 2008normal weather normalized decrease of 2.6 percent reflects the fact that our customers are responding to the volatile costs of energy and to the economic conditions of our region and the nation. We believe customers will continue to respond to these factors and to the recent and ongoing developments in the financial markets resultingsummer of 2010 and colder than normal weather in an estimated declineDecember 2010. Residential sales benefitted the most from the weather in weather-normalized sales of approximately 1 percent2010 and were higher for all three electric companies in 2010 compared to 2009.
ChangesOn a weather normalized basis, retail sales for all three electric companies were lower in electric sales, however, have less of an impact on2010 compared to 2009. We believe the earnings ofdecrease was due in part to increased conservation efforts by our electric distribution companies than in prior years because non-distribution rate revenues, which represented approximately 76 percent of electric distribution company revenues in 2008, are tracked and reconciled to actual costs. Non-distribution rate revenues include the energy, stranded cost, retail transmission and federally mandated congestion charges (FMCC) and other components of rates. For non-distribution rate revenues, the only impact to earnings is from carrying costs on over- or under-recoveries. With respect to our electric distribution company revenues, about two-thirds of CL&P's and WMECO's revenues and about one-half of PSNH's revenues are recovered through charges that are not dependent on overall sales volumes, such as the customer chargecustomers and the demand charge.continuing effects of the weak economy.
Comparable to our sales results in 2008, our uncollectibles expense has also been influenced by the adverse economic conditions of our region. Our write-offs as a percentage of revenues increased in 2008 for all our electric distribution companies. Similar to changes in our retail sales, changes in our uncollectibles expense have less of an impact on earnings of our electric distribution companies than in prior years as a portion of the uncollectibles expense for each of the electric distribution companies is allocated to its respective energy supply rate and recovered as a tracked expense.
THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION
CL&P’s distribution segment isbusiness consists primarily engaged inof the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. AtAs of December 31, 2008,2010, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut. CL&P does not own any electric generation facilities. In 2010, CL&P had contracts to purchase the electric output from eighteen IPP generators. The term of two of these contracts ended in 2010. In 2011 the sixteen remaining generators are anticipated to provide approximately two million MWh per year through March 2015, with purchase quantities dropping significantly from 2015 through 2024, when the term of the last IPP contract ends. CL&P sells the output of these contracts into the ISO New England market, crediting customer energy charges with the proceeds. CL& ;P has entered into eleven contracts with renewable energy generators under a state program known as Project 150, and UI has entered into 2 other similar contracts under Project 150. CL&P and UI will share the costs and benefits of these contracts on an 80 percent and 20 percent basis, respectively. This cost sharing split is independent of the specific utility that is the counterparty to the contract. It is currently projected that the first of these renewable energy projects will commence commercial operation in 2011.
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The following table shows the sources of 20082010 electric franchise retail revenues for CL&P based on categories of customers:
| Sources of |
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Residential |
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Commercial |
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Industrial |
| 6% | |
Other |
| 1% | |
Total |
| 100% |
Rates
CL&P is subject to regulation by the Connecticut Department of Public Utility Control (DPUC)DPUC, which, among other things, has jurisdiction over its rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.
CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, competitive transition assessment (CTA)CTA, SBC and other charges that are assessed on all customers. CL&P also has regulatory orders allowing it to recover all or substantially all of its prudently incurred stranded costs, which are pre-restructuring expenditures incurred, or commitments for future expenditures made, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates. CL&P has financed
The CTA is a significant portion of its stranded costs through the issuance of rate reduction certificates or bonds (RRBs) secured by its rightcharge assessed to recover stranded costs over time (securitization). CL&Passociated with electric industry restructuring as well as various IPP contracts. The SBC recovers the costs of securitization through the CTA component of its rates. In addition to those stranded costs being recovered through securitizat ion, CL&P’s stranded costs included, as of December 31, 2008, ongoing independent power producer costs and costs associated with various hardship and low income programs as well as payments to municipalities to compensate them for losses in property tax revenue due to decreases in the ongoing decommissioningvalue of the Maine Yankee, Connecticut Yankeeelectric generating facilities resulting directly from electric industry restructuring. The CTA and Yankee Rowe nuclear units.SBC are annually reconciled to actual costs incurred, with any difference refunded to, or recovered from, customers.
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Under state law, all of CL&P's customers are entitled to choose their energy suppliers, while retaining CL&P asremains their electric distribution company. Under "Standard Service" rates for customers with less than 500 kWKW of demand and "Supplier of Last Resort Service" rates for customers with 500 kWKW of demand or greater, CL&P purchases power for those customers who do not choose a competitive energy supplier and passes through the cost to ratepayerssuch customers through the "Generation Service Charge"a combined GSC and the "Bypassable Federally Mandated Congestion Charge" (FMCC) componentsFMCC on customers' bills. The combined GSC and FMCC charges for both types of service recover all of the customer’s bill, whichcosts of procuring energy from CL&P's wholesale suppliers and are adjusted periodically and reconciled on a semi-annual basis.semi-annually in accordance with the directives of the DPUC.
A large percentageAlthough more CL&P customers chose competitive energy suppliers in 2010 than in 2009, CL&P continues to supply approximately 40 percent of CL&P's customers have continued to buy their power from CL&Pits customer load at Standard Service rates or Supplier of Last Resort Service rates. However, CL&Prates while the other 60 percent of its customer load has experienced some customer migrationmigrated to competitive energy suppliers, with the movement concentrated among larger customers.suppliers. Because this customer migration is only for energy supply service, there isit has no impact on CL&P’s delivery business or its operating income.
Distribution Rates: On June 30, 2010, the deliveryDPUC issued a final order in CL&P’s most recent retail rate case approving annualized distribution rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011. The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final payment of CL&P’s RRBs. In its decision, the DPUC also maintained CL&P’s authorized distribution segment regulatory ROE of 9.4 percent. In 2010, CL&P earned a distribution segment regulatory ROE of 7.9 percent, compared to 7.3 percent in 2009, and expects to earn a distribution segment regulatory ROE of approximately 9 percent in 2011.
In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds (ERRBs) that would be amortized over eight years. These bonds will be repaid through a charge on the bills of customers of CL&P and other Connecticut electric distribution companies. For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would have otherwise ended by December 31, 2010 with the businessfinal payment of the principal and interest on its RRBs, and the diversion of about one-third of the annual funding for C&LM programs beginning in April 2012. A lawsuit pending against the DPUC to prevent the issuance of the ERRBs is pending and several bills seeking to modify or prevent the operating incomeissuance have been proposed before the state l egislature.
On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan concluding that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P.&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario." Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million. CL&P has proposed beginning installation of meters in late 2012 and finishing in 2016.
CL&P adjustshas a transmission adjustment clause as part of its retail transmissiondistribution rates, which reconciles on a regularsemi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, thereby recovering all of its retail transmission expenses on a timely basis. (See "Regulated Electric Transmission" in this Annual Report on Form 10-K).
On January 28, 2008, the DPUC approved $77.8 million, or 11.7 percent, and $20.1 million, or 2.6 percent, in annual increases in CL&P’s distribution rates, effective February 1, 2008 and February 1, 2009, respectively. The rate decision included an ROE of 9.4 percent, with CL&P continuing its earnings sharing mechanism, which provides that ratepayers and shareholders share equally in any earnings in excess of its allowed regulatory ROE. For further information on CL&P rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.
Regulatory Update
On May 2, 2008, the DPUC approved CL&P’s revised metering compliance plan that would meet the DPUC's objective of making time-of-use rates available to CL&P customers. The DPUC decision authorized a pilot program involving the installation of advanced metering infrastructure (AMI) meters and a rate design pilot to test new time-of-use and real-time rates to determine customer acceptance and load response to various pricing structures. CL&P expects to conduct the AMI pilot with approximately 3,000 customers during the summer of 2009. The estimated incremental cost of the program is expected to be between $10.6 million to $13 million and such costs are authorized to be recovered from customers, initially through CL&P’s FMCC charges. The non-incremental operating and maintenance expenses are projected to be less than $2 million.
In 2008, pursuant to Connecticut's "Act Concerning Energy Independence," (Energy Independence Act), CL&P signed five contracts and The United Illuminating Company (UI) signed two contracts, each to purchase energy, capacity and renewable energy credits from planned renewable energy plants, including biomass and fuel cell projects, approved by the DPUC, for a total of 109 MW. CL&P had also signed one contract with a biomass project in 2007 to purchase 15 MW of its output. Purchases under the contracts are scheduled to begin in 2009 through 2011 and to extend for periods ranging from 15 to 20 years. As directed by the DPUC, CL&P and UI have also signed a sharing agreement under which they will share the costs and benefits of these contracts, with 80 percent to CL&P and 20 percent to UI. On January 16, 2009, the DPUC issued a draft decision selecting two additional renewable energy project s for a total of 6 MW with which CL&P or UI will sign similar contracts. The final decision is scheduled for March 11, 2009. Additional projects are expected to be selected by the DPUC to achieve a total of 150 MW of additional renewable energy sources in Connecticut. CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.
Also in 2008, CL&P and UI entered into contracts for differences (Peaker CfDs) with developers of three proposed peaking generation units totaling 506 MW of summer peaking capacity, as approved by the DPUC. The Peaker CfDs provide for the payment to the developer of the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. As directed by the DPUC, CL&P and UI will share the net costs and benefits of the Peaker CfDs on a basis of 80 percent and 20 percent, respectively. CL&P’s portion of the costs and benefits will be paid by or refunded to its customers
In 2008, the DPUC issued final decisions in a docket examining the manner of operation and accuracy of CL&P's electric meters and in a docket investigating CL&P billing errors involving approximately 2,000 customers on time of use rates. In the metering docket decision, the DPUC did not fine CL&P, but held that possibility open if CL&P fails to meet benchmarks to be established in the docket. The decision in the time-of-use docket disallowed recovery from customers of the incremental costs associated either directly or indirectly with the billing errors. These incremental costs are not material and have been expensed as incurred.
In prior years, CL&P has submitted to the DPUC its proposed methodology to calculate the variable incentive portion of its Transition Service energy procurement fee, which was effective through 2006 and had requested approval of a pre-tax $5.8 million 2004 incentive fee. In December 2005, the DPUC issued a draft decision authorizing the $5.8 million incentive fee and CL&P recovered the $5.8 million amount by recording it in 2005 earnings through the CTA reconciliation process. CL&P has not recorded any amounts in earnings related to the 2005 or 2006 procurement fee. On January 15, 2009, the DPUC issued a final decision on the 2004 incentive fee that reversed its December 2005 draft decision, and concluded that CL&P was not eligible for the procurement incentive compensation for 2004. As a result, the $5.8 million pre-tax charge was recorded in CL&P’s 2008 earnings, and an obligation to r efund the $5.8 million to customers was established in the CTA reconciliation process as of December 31, 2008. CL&P filed an appeal of this decision on February 26, 2009.
For further information on regulatory actions affecting CL&P, see "Regulatory Developments and Rate Matters - Connecticut - CL&P" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.
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Sources and Availability of Electric Power Supply
As noted above, CL&P does not own any generation assets and purchases its energy requirements to serve its Standard Service and Supplier of Last Resort Service loads from a variety of competitive sources through periodic requestsRFPs. CL&P enters into supply contracts for proposals (RFPs). CL&P issues RFPsStandard Service periodically for periods of up to three years to layer Standard Service full requirements supply contracts in order to mitigate price volatility for its residential and small and medium load commercial and industrial customers. CL&P issues RFPsenters into supply contracts for Supplier of Last Resort service for larger commercial and industrial
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customers every three months. Currently, CL&P has contracts in place contracts with various suppliers through 2010 for all of its Standard Service loads through 2011, 40 percent of expected load for 2012, and to date one tranche has been filled10 percent of expected load for 2013. CL&P’s contracts for its Supplier of Last Resort Service loads extend through the second quarter of 2011.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE - DISTRIBUTION
PSNH’s distribution segmentbusiness (which includes its regulated generation) isgeneration business) consists primarily engaged inof the generation, purchase, delivery and sale of electricity to its residential, commercial and industrial customers. AtAs of December 31, 2008,2010, PSNH furnished retail franchise electric service to approximately 493,000497,000 retail customers in 211 cities and towns in New Hampshire. PSNH also owns and operates approximately 1,200 MW of primarily fossil-fueled electricity generation assets. Approximately 70 MW ofIncluded in those generation assets are hydroelectric units. Included among these generating assets is aits 50 MW wood-burning generating unit (Northern WoodsNorthern Wood Power Project)Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation. PSNH also has contracts with 18 IPPs, the output of which was converted fromit either uses to serve its customer load or sells into the market.
PSNH is constructing its Clean Air Project, a coal-burning unitsulfur dioxide and mercury scrubber at its Merrimack coal-fired generation station, which is currently expected to cost $430 million. The project is scheduled for completion in December 2006.mid-2012. PSNH will recover all related costs through its ES rates described below.
The following table shows the sources of 20082010 electric franchise retail revenues based on categories of customers:
| Sources of |
| % of Total |
Residential |
|
| |
Commercial |
|
| |
Industrial |
|
| |
Other | 1% | ||
Total |
| 100% |
Rates
PSNH is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC)NHPUC, which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.
PSNH’s Energy Service (ES)ES rate recovers PSNH'sits generation and purchased power costs includingfrom customers on a current basis and allows for an ROE of 9.81 percent on PSNH'sits generation assets. PSNH files for approval of updated ES rates annually with the NHPUC, with a six-month true-up, to ensure timely recovery of its costs. PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.
On July 1, 2008, PSNH’s Delivery Service (DS) rates decreased by $0.4 million annually. This amount consisted of a $3.4 million rate reduction related to the full recovery of a rate differential recoupment and an increase of approximately $3 million per year for a two-year period effective July 1, 2008 to eliminate a negative balance in the major storm cost reserve and restore the intended reserve level of $1 million.
Pursuant to a distribution and transmission rate case settlement agreement between PSNH, the NHPUC staff and the Office of Consumer Advocate, the NHPUC approved PSNH’s petition seeking to establish a Transmission Cost Adjusting Mechanism (TCAM) rate to be reset annually consistent with the rate settlement agreement. On May 13, 2008, PSNH filed a July 1, 2007 through June 30, 2008 TCAM reconciliation and a projected TCAM rate to be billed effective July 1, 2008 related to July 1, 2008 through June 30, 2009 TCAM costs.investment.
Under New Hampshire law, the Stranded Cost Recovery Charge (SCRC)SCRC allows PSNH to recover its stranded costs, including expenses incurred throughunder mandated power contracts and other long-term investments and obligations. PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time. Ittime and recovers the costs of these bonds through the SCRC rate.
On an annual basis, PSNH makesfiles with the NHPUC an ES/SCRC reconciliation filing withfor the preceding year. The difference between ES/SCRC revenues and ES/SCRC costs are included in the ES/SCRC rate calculations and refunded to/recovered from customers in the subsequent period approved by the NHPUC.
The TCAM allows PSNH to recover on a fully reconciling basis its transmission related costs. The TCAM is adjusted July 1 of each year.
Distribution Rates: On June 28, 2010, the NHPUC for the previous year. For further informationapproved a joint settlement of PSNH’s rate case that had commenced in 2009, allowing a net distribution rate increase of $45.5 million on PSNH rates, see "Regulatory Developmentsan annualized basis to be effective July 1, 2010, and Rate Matters" in Item 7, "Management's Discussionannualized distribution rate adjustments projected to be a decrease of $2.9 million and Analysisincreases of Financial Condition$9.5 million and Results$11.1 million on July 1 of Operations," in this Annual Report on Form 10-K.
Under the terms of the order issued by the NHPUC approving PSNH’s Northern Wood Power Project, which replaced oneeach of the three 50 MW boiler unitssubsequent years, respectively. PSNH agreed not to file a new distribution rate request that would be effective prior to July 1, 2015. During the term of the settlement, PSNH can only propose changes to its permanent distribution rate level when its 12-month distribution ROE falls below 7 percent for two consecutive quarters or certain specified external events, such as major storms, occur. If PSNH’s 12-month ROE rolling average is greater than 10 percent, anything over the 10 percent level will be all ocated 75 percent to customers and 25 percent to PSNH. The settlement also provided that the authorized regulatory ROE on distribution only plant will continue at the coal-fired Schiller Station, certain revenue, credits and cost avoidances (revenue sources) are shared between PSNH and its customers. These revenue sources include salespreviously allowed level of renewable energy certificates (RECs)9.67 percent. PSNH’s distribution segment regulatory ROE was 10.2 percent (including generation) in 2010, compared to other utilities, brokers, or suppliers, and production tax credits. In any given year, if the combination of revenue sources falls short of a stipulated revenue level, PSNH and its customers each share half of any deficiency, and if the combination exceeds the stipulated revenue level, PSNH and its customers each share half of any excess. The Northern Wood Power Project entered commercial operation on December 1, 2006, and revenue sources exceeded stipulated levels7.2 percent in 2008 due to its performance and favorable pricing2009. We expect PSNH’s distribution segment regulatory ROE will be approximately 9 percent in the Massachusetts and Rhode Islan d markets for the RECs. As a result, customers and shareholders will share equally a benefit of about $7.8 million of incremental revenues for 2008. 2011.
Although PSNH's customers are entitled to choose competitive energy suppliers, with PSNH hasproviding default energy service under its ES rate for those customers who do not elect to use a third party supplier. Prior to 2009, PSNH experienced only a smallminimal amount of customer migration. However, customer migration levels began to date.increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH. By the end of 2010, approximately 2 percent of all of PSNH’s customers (approximately 32 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers. The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sal es
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On December 11, 2008,volume. The customers that did not switch to a major ice storm struck portionsthird party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of New England, severely damaging PSNH’s distribution systems. This was the most severe ice storm in PSNH’s history. Of the 440,000 New Hampshire homes and businesses that lost power, 322,000 were served by PSNH. Restoration operations commenced on December 11, 2008 and were substantially completed by December 25, 2008. PSNH utilized its own line crews, local contractors, line crews from other NU subsidiaries and numerous other line crews from the eastern United States and Canada.these fixed costs.
The operating costNHPUC opened a proceeding in 2010 to consider the effect of storm restorations that meet acustomer migration on ES rates for customers, principally residential and small commercial and industrial customers, remaining on PSNH default energy service. As part of this docket, the NHPUC specified criteriastated its intention to explore the interplay of customer choice, migration issues and power procurement options for PSNH.
PSNH cannot predict if the upward pressure on ES rates will continue into the future, as future customer migration levels, which are funded throughdependent on market prices and supplier alternatives, are uncertain. If future market prices once more exceed the Major Storm Costs Reserve (MSCR). Capital costs for any storm work are charged to property, plant and equipment and are recovered through the normal distribution ratemaking process. As the December 2008 ice storm met the MSCR criteria, $62.7 million of total estimated repair costs of $75 million associated with this storm were charged to the MSCR at December 31, 2008. PSNH intends to request recoveryaverage ES rate level, some or all of these costs as part of its next delivery rate proceeding with the NHPUC. Out of the remaining total storm costs incurred through December 31, 2008, $6.5 million has been expensed and $5.6 million has been capitalizedcustomers on third party supply may migrate back to plant and equipment. PSNH expects to recognize an additional $10 million in 2009 when the weather is warmer and additional clean-up and repairs can be performed. We carry $15 milli on of storm-related insurance system-wide and to the extent that any insurance proceeds are received, a portion would be allocated to PSNH to reduce the amount of deferred or expensed storm costs.
Regulatory Update
In 2006, New Hampshire enacted a law requiring PSNH to reduce the mercury emissions for its coal fired plants by at least 80 percent (with co-benefits of reduction in sulfur dioxide (SO2) emissions as well). Wet scrubber technology will be installed at Merrimack Station in Bow New Hampshire no later than July 1, 2013. Following an August 2008 announcement by PSNH that the cost of this installation would be increasing from the original estimate of $250 million to $457 million, the NHPUC opened an inquiry to determine whether it had authority to assess whether the project is in the public interest. In September 2008, the NHPUC ruled that its authority is limited to determining at a later time the prudence of the costs incurred in complying with the legislation. In October 2008, several parties filed motions with the NHPUC requesting a reconsideration of its ruling; these motions were rejected. On December 11 , 2008, several parties involved in the filing of the October 2008 motion for a rehearing filed an appeal with the New Hampshire Supreme Court requesting that the Court overturn the NHPUC finding that it lacked present authority over this matter. The Supreme Court has indicated that it will hear this appeal, but has not yet issued a schedule for oral arguments.
In July 2008, New Hampshire passed a law establishing a transmission commission responsible for developing a proposal to expand the electric transmission system in northern New Hampshire to encourage the development of new renewable generation sources. On December 1, 2008, the transmission commission submitted its progress report, which concluded that New Hampshire should continue to pursue the upgrade of transmission capacity in its northern region to allow development of its native renewable energy resources. Also, the transmission commission should continue to pursue both local and regional cost allocation issues related to the transmission expansion. We believe the northern New Hampshire region has the potential for over 500 MW of new renewable resources. PSNH has included $130 million in its 2009 to 2013 capital plan for transmission upgrades in the region which assumes that these projects are built and a c ost allocation solution can be agreed to by relevant parties.
In July 2008, New Hampshire passed a law authorizing rate recovery by electric public utilities of investments made in distributed energy resources up to 5 MW, such as renewable energy generation. The total investment is limited to resources having a capability equal to 6 percent of a distribution utility’s peak load. PSNH has not yet included any distributed energy resource investment opportunities in its capital expenditure plans.PSNH.
Sources and Availability of Electric Power Supply
During 2008,2010, about 6788 percent of PSNH’s load was met through its own generation, and long-term power supply rateprovided pursuant to orders of the NHPUC, and contracts with third parties. The remaining 3312 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. PSNH expects to meet its load requirements in 20092011 in a similar manner.
New Hampshire’s "Renewable Energy Act" establishes renewable portfolio standards for electricity sold in the state that require annual increases in the percentage of the electricity sold to retail customers having direct ties to renewable sources. The renewable sourcing requirements began in 2008 and increase each year to reach 23.8 percent by 2025. PSNH plans to meet these standards, in part, through the purchase of Renewable Energy Certificates (RECs) from qualified renewable energy resources. For each MWH of energy produced from a qualifying resource, the producer will receive one REC. Energy suppliers, like PSNH, will purchase these RECs from the producers and will use them to satisfy the RPS requirements. To the extent that PSNH is unable to purchase sufficient RECs, it will be required to make up the difference between the RECs purchased and its total obligation by making an alternative comp liance payment (ACP) for each REC requirement for which PSNH is deficient. The costs of both the RECs and ACPs do not impact earnings, as these costs are being recovered by PSNH through its ES rates. For further information, see "Regulatory Developments and Rate Matters - New Hampshire" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.
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WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION
WMECO’s distribution segment is engaged inbusiness consists primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers. At December 31, 2008,2010, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western third of Massachusetts. Following electric industry restructuring in the 1990s, WMECO does not own anysold all of its generating facilities and now purchases its energy requirements from competitive suppliers. In 2009, pursuant to the Massachusetts Green Communities Act, WMECO was authorized to install 6 MW of solar energy generation in its service territory. In October 2010, WMECO completed construction of a 1.8 MW solar generation facility at a site in Pittsfield, Massachusetts, which began producing electricity generating facilities. Onin late 2010. In January 2011, WMECO announced its plans to develop a second solar generation faci lity at a site in Springfield, Massachusetts. This facility will accommodate 17,000 solar panels, producing up to 4.2 MW of solar energy. WMECO will sell all energy and other products from its solar generation facilities into the ISO New England market. WMECO had a contract with one IPP generator in 2010, the output of which WMECO sold into the ISO New England market. The term of this contract ended on December 31, 2008, WMECO purchased all of the transmission-related assets of its affiliates, Holyoke Water Power Company (HWP) and Holyoke Power and Electric Company (HP&E) for approximately $4 million.2010.
The following table shows the sources of 20082010 electric franchise retail revenues based on categories of customers:
| Sources of |
| % of Total |
Residential |
|
| |
Commercial |
|
| |
Industrial |
| 9% | |
Other |
| 1% | |
Total |
| 100% |
Rates
WMECO is subject to regulation by the Massachusetts Department of Public Utilities (DPU),DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities. WMECO's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to coverrecover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under state law, all of WMECO's customers are now entitled to choose their energy suppliers, while retaining WMECO asremains their distribution company. WMECO purchases electric power from competitive suppliers for, and passes through the cost to, those customers who do not choose a competitive energy supplier (basic service). Basic service charges are adjusted and reconciled on an annual basis. Most of WMECO's residential and smallersmall commercial and industrial customers have continued to buy their power from WMECO at basic service rates. A greater proportion of large commercial and businessindustrial customers have opted for a competitive energy supplier.
WMECO collects its transmission costs through a transmission adjustment clause, which is adjusted annually, thereby allowing WMECOcontinues to recover allsupply approximately 50 percent of its retail transmission expensescustomer load at basic service rates while the other 50 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on a timely basis.WMECO’s delivery business or its operating income.
WMECO also has regulatory orders allowing it to recover all or substantially all ofrecovers certain costs through various tracking mechanisms in its retail rates, including transmission costs, pension costs and prudently incurred stranded costs. WMECO has financed acosts (a portion of its stranded costswhich have been financed through securitization by issuing RRBs secured by the right to recover stranded costs from customers over time. It is recovering the costs of securitization through rates.RRBs) with periodic true-up adjustments.
On January 1, 2008, WMECO’s distribution rates increased by $3 million annually as approved by the Massachusetts DPU in December 2006. WMECO adjusted its rates to include the distribution increase, new basic service contracts, and changes in several tracking mechanisms. On December 29 and 30, 2008, the DPU approved WMECO’s proposed rate changes effective January 1, 2009. The rate changes were made in accordance with WMECO’s various tracking mechanisms.
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The major ice storm on December 11, 2008 also impacted parts of Massachusetts, including areas served by WMECO. As this storm met the storm costs reserve criteria approved in WMECO’s last distribution rate case settlement, $11.3 million of the total $13.8 million estimated repair costs associated with this storm were recognized as a deferred asset at DecemberDistribution Rates: On January 31, 2008. WMECO expects to begin recovery of these costs in its next distribution rate proceeding. The DPU has opened a formal docket to review storm restoration efforts by the state's utilities.
For further information on WMECO’s rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.
Regulatory Update
On July 16, 2008,2011, the DPU issued a final decision in its decoupling generic docket requiring all gasWMECO’s July 2010 rate application, granting a $16.8 million annualized rate increase in distribution revenues and electric utilities to filean allowed ROE of 9.6 percent effective February 1, 2011. The DPU also authorized a full decoupling proposalsmechanism, whereby actual revenue billed by WMECO would be reconciled with their next generalWMECO’s target revenue on an annual basis, WMECO’s request to recover balances of certain active hardship account balances and the recovery of certain storm costs over five years. The DPU did not authorize rate case. The decision rejected calls for partial decoupling or decoupling by rate designrecovery of a proposed $20 million average increase in favor of full decoupling by rate class. On September 2, 2008, WMECO notified the DPU that it expectsWMECO’s capital spending plan. WMECO’s distribution segment regulatory ROE was 4.6 percent in 2010 compared to file its next8.4 percent in 2009. We expect WMECO’s distribution rate casesegment regulatory ROE will be approximately 9 percent in mid-2010 to be effective January 1, 2011. That case will include a proposal to fully decouple distribution revenues from kilowatt-hour sales.
As part of WMECO’s December 2006 rate case settlement agreement approved by the DPU, WMECO becameis subject to service quality (SQ)SQ metrics that measure safety, reliability and customer service. Anyservice, and WMECO pays any charges incurred are paidfor failure to customers through a method approved by the DPU.meet such metrics to customers. WMECO will likelynot be required to pay an assessment charge for its 2008 reliability2010 performance against the metrics established for 2008, primarilyresults as a result of significant storm activity. WMECO has performed at target for other non-storm related reliability metrics. WMECO will fileall of its 2008 SQ results and assessment calculation with the DPUmetrics in March 2009. In 2008, WMECO recorded an estimated pre-tax charge and a regulatory liability of approximately $1.3 million for this assessment.
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In July 2008, Massachusetts enacted "The Green Communities Act of 2007." Aimed at increasing energy efficiency (EE) and the use of renewable resources in the state, the Act contains many provisions important to the state’s utilities. In addition to adopting RGGI requirements, the Act:2010.
·
Removes the cap on utility expenditures for EE and demand response (DR).
·
Requires utilities to file three-year EE and DR plans with a newly created Energy Efficiency Council;
·
Requires utilities to sign long-term contracts for renewable resources;
·
Allows each utility to own and operate up to 50 MW of solar generation;
·
Requires utilities to file a plan with the DPUOn October 16, 2009, WMECO filed its proposal for a dynamic pricing smart grid pilot; and
·
Increases penalties for failure to meet service quality standards from 2 percent of transmission and distribution revenues to 2.5 percent.
By April 30, 2009, WMECO is required to prepare a three-year EE and DR investment plan related to the cost of EE and DR programs established by the Act for review by the Energy Efficiency Council and, ultimately, the DPU. In addition, WMECO filed ameter pilot program with the DPU on February 11, 2009 providing forDPU. However, the Company does not expect it will conduct a three-phase solar generation program subject to DPU authorizationpilot prior to each phase. The initial phase calls for 6 MW of solar generation to be installed at eight host sites in WMECO's service territory upon receipt of DPU approval. This phase of the project is expected to be completed as early as 2010 at a cost of approximately $42 million. The second phase includes an additional 9 MW extending through 2012, and the third and final phase could increase total capacity to the 50 MW maximum. The DPU has six months to issue a decision on WMECO's plan. WMECO is otherwise precluded from making new generation investments, but has not yet included any solar generation investment opportunities in its capital expenditure plans. 2012.
Sources and Availability of Electric Power Supply
As noted above, WMECO does not own any generation assets (other than its recently constructed solar generation) and purchases its energy requirements from a variety of competitive sources through periodic RFPs. For basic service power supply, WMECO issues RFPs periodically, consistent with DPU regulations. On May 14, 2008, WMECO entered into an agreement to secure 50 percent of residential, small commercial and industrial, and street lighting loads for the July 1, 2008 through June 30, 2009 period, and on November 3, 2008 WMECO entered into an agreement to secure power for half of its residential, small commercial and industrial, and street lighting loads for the January 1 through December 31, 2009 period. WMECO will issue an RFP in the second quarter of 2009 to secure the remaining 50 percent of its residential, small commercial and industrial, and street lighting loads for the July 1 through December 31, 2009 period and 50 percent of the load for January 1, 2010 through June 3 0, 2010. For its large commercial and industrial customers, WMECO entered into an agreement on November 3, 2008 to secure power for the first quarter of 2009 and an agreement to secure power for the second quarter 2009 on February 10, 2009. RFPs will be issued quarterly to secure power for the balance of the year.
REGULATED GAS DISTRIBUTION – YANKEE GAS SERVICES COMPANY
Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 200,000)206,000 customers in 71 cities and towns), and size of service territory (2,088(2,187 square miles). Total throughput (sales and transportation) in 2008both 2010 and 2009 was 49.8 billion cubic feet (Bcf) compared with 49.7 Bcf in 2007.approximately 52.5 Bcf. Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas’ service territory buy gas supply and delivery only from Yankee Gas alsowhile commercial and industrial customers have choice in their gas suppliers. Yankee Gas offers firm transportationtransportat ion service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those certain commercial and industrial customers that have the capability to switch from natural gas to a nan alternative fuel on short notice. Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity. In 2007, Yankee Gas completed construction ofalso owns a liquefied natural gas (LNG)1.2 Bcf LNG facility in Waterbury, Connecticut. The LNG facility is capableConnecticut, which enables the company to buy natural gas in periods of storing the equivalent of 1.2 Bcf of natural gas.low demand, store it and use it during peak demand periods when prices are typically higher.
Yankee Gas earned $27.1 million on total gas operating revenues of approximately $577.4 million for 2008. The following table shows the sources of 2008 total2010 gas operating revenues:revenues based on categories of customers:
| Sources of |
| % of Total |
Residential |
|
| |
Commercial |
|
| |
Industrial |
|
| |
Other |
| 3% | |
Total |
| 100% |
For more information regarding Yankee Gas’s financial results, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8, "Financial Statements and Supplementary Data," which includes Note 17, "Segment Information," contained within this Annual Report on Form 10-K.
8
A summary of changes in Yankee Gas firm natural gas sales in million cubic feet for 2008Yankee Gas for 2010 and 2009 and the percentage changes in 2010 as compared to 20072009 on an actual and weather normalized basis (using a 30-year average) is as follows:
|
| Yankee Gas |
| Firm Natural Gas Sales (Mcf) |
|
| ||||||
|
|
|
| Weather |
| 2010 |
| 2009 |
| Percent |
| Weather |
Residential |
| (2.0)% |
| (0.1)% |
| 13,403 |
| 13,562 |
| (1.2)% |
| 4.9% |
Commercial |
| (0.2)% |
| 1.4% |
| 14,982 |
| 14,063 |
| 6.6% |
| 12.1% |
Industrial |
| 9.2% |
| 9.6% |
| 14,866 |
| 14,825 |
| 0.3% |
| 1.7% |
Total |
| 2.1% |
| 3.4% |
| 43,251 |
| 42,450 |
| 1.9% |
| 6.2% |
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Yankee Gas’ firm natural gas sales are subject to many of the same influences as our retail electric sales, but they have recently benefitted from a favorable price for natural gas relative to competing fuels resulting in commercial and industrial customers switching from interruptible service to firm service, and the addition of gas-fired distributed generation in Yankee Gas’ service territory. Actual firm natural gas sales in 2010 were higher than 2009 despite the milder weather during the first quarter 2010 heating season. Firm natural gas sales for 2008 were higher than 2007.benefitted from these trends and from a large commercial customer who began to take service from Yankee Gas mid-way through the third quarter of 2009 and continued to take service throughout all of 2010.
In April 2010, Yankee Gas commenced construction of its WWL project, a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut coupled with the increase of vaporization output of its LNG plant. The 2008 results reflect warmer weather inproject is expected to cost approximately $57.6 million. In 2010, approximately $26.6 million was spent on construction of the first quarter, colder weatherWWL project, which included construction of a segment of pipeline connecting the Cheshire and Wallingford distribution systems. The remainder of the pipeline construction and the expansion of the vaporization capacity of the LNG facility are expected to be completed in the fourth quarter and an increase in industrial sales primarily due to customer-owned gas-fired distributed generation and favorable natural gas prices relative to oil. We have assumed an increase in weather normalized firm natural gas sales of approximately 2.5 percent in 2009. Similar to our electric distribution companies, Yankee Gas recovers a significant portion of its distribution revenues (approximately 40 percent) through charges that are not dependent on usage.
Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC has limited oversight with respect to certain reporting and intrastate gas transportation that Yankee Gas provides. In addition, the FERC regulates the interstate pipelines serving Yankee Gas’s service territory.2011
Rates
Yankee Gas is subject to regulation by the DPUC, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.
Distribution Rates: On January 7, 2011, Yankee Gas recovers its cost of gas supplied to customers through a Purchased Gas Adjustment (PGA) clause in its rate tariff. In 2005 and 2006,filed an application with the DPUC issued decisions requiring an auditto raise natural gas distribution rates by an independent party of approximately $11$32.8 million, in previously recovered PGA revenues associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005. On June 11, 2008, the DPUC issued a final order pursuantor 7.3 percent, to which Yankee Gas was required to refund to customers approximately $5.8 million in recoveries under its Purchased Gas Adjustment clause. Yankee Gas results for 2008 reflect an after-tax charge of $3.5 million associated with that decision.
Under a settlement of its distribution rate filing with the Connecticut Office of Consumer Counsel and the DPUC’s Prosecutorial Division, Yankee Gas’s base rate increased,be effective July 1, 2007,2011, and by $22an additional $13 million, or 4.22.8 percent, net of expected pipeline and commodity cost savings resulting primarily from completion of Yankee Gas’s LNG facility, andto be effective July 1, 2012. Among other items, Yankee Gas was allowed anrequested to maintain its current authorized ROE of 10.1 percent.percent, that $57.6 million of costs associated with the WWL project be placed into rates, and that a substantial increase in capital funding to replace bare steel and cast iron pipe on Yankee Gas' system. A final decision is expected in June 2011. Yankee Gas’ regulatory ROE was 8.6 percent in 2010 compared to 6.6 percent in 2009. We expect Yankee Gas’ distribution segment regulatory ROE to be approximately 9 percent in 2011.
Sources and Availability of Natural Gas Supply
The DPUC requires that Yankee Gas will returnmeet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its portfolio to ratepayers 100 percent of all earningsmeet firm customer needs under a design day scenario (defined as the coldest day in excess30 years) and under a design year scenario (defined as the average of the allowed 10.1 percent ROE. As a resultfour coldest years in the last 30 years). Yankee Gas’ LNG facility enables Yankee Gas to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher. Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the base rate increase,coldest days of winter. Yankee Gas obtains its interstate capacity from the amount of gas supply costs charged to customers throughthree interstate pipelines that currently directly serve Connecticut: the PGA decreased.Algonquin, Tennessee and Iroquois Pipelines. Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Li mited pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines. Yankee Gas considers such transportation arrangements adequate for its needs.
FORWARD CAPACITY MARKETS
On December 1, 2006, a FERC-approved Forward Capacity Market (FCM) settlement agreement was implemented, and the payment of fixed compensation to generators began. The second forward capacity auction concluded on December 10, 2008 for the capacity year June 2011 through May 2012. The bidding reached the established minimum of $3.60 per kilowatt-month with 4,755 MW of excess remaining capacity. This means the effective price will be $3.12 per kilowatt-month compared to the equivalent first forward capacity auction price of $4.25 per kilowatt-month for the 12-month capacity period ending May 31, 2011 and $4.10 per kilowatt-month for the 12-month capacity period ending May 31, 2010. These costs are recoverable in all jurisdictions through the currently established rate structures.
REGULATED ELECTRIC TRANSMISSION
General
CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the rules by which they participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent fromof all market participants, has served since 2005 as the Regional Transmission Operator (RTO)RTO of the New England Transmission System since February 1, 2005.transmission system. ISO-NE works to ensure the reliability of the system, administers, subject to FERC approval, the independent system operator tariff, subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of ourall regional major transmission facilities are regionalizedshared by consumers throughout New England.
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Wholesale Transmission Rates
Wholesale transmission revenues are based onrecovered through formula rates that are approved by the FERC. Most of our wholesaleOur transmission revenues are collected under ISO-NE’s FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3). Tariff No. 3 includes the Regional Network Service (RNS) and Local Network Service (LNS) rate schedules, among other things. The RNS rate, administered by ISO-NE and billed to allrecovered from New England customers through ISO-NE charges which recover costs of transmission and other transmission-related services provided by all regional transmission owners, is reset on June 1stwith a portion of each yearthose revenues collected from the distribution segments of CL&P, PSNH and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The LNS rate, which we administer, is reset on January 1st and June 1st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not covered under the RNS rate, including 100 percent of the construction costs of the New England East-West Solutions (NEEW S) projects. Both the LNS and RNS rates provide for annual true-ups to actual costs. The LNS rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e. RNS, rental, etc.), thereby ensuring that we recover all regional and local revenue requirements as described in Tariff No. 3.WMECO.
FERC ROE Decision
On March 24, 2008,Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC issued an order on rehearing confirming its initial order settingset the base ROE on transmission projects for the New England transmission owners, including NU’s subsidiaries. Including a final adjustment, the order provides a base ROE ofat 11.14 percent and approved incentives that increased the ROE to 12.64 percent for the period beginning November 1, 2006. The order also affirmed FERC’s earlier decision granting a 100 basis point adder for new transmissionthose projects that are built as part of the ISO-NE Regional System Plan and are "completed and on line" by December 31, 2008. In order to receive incentives for projects completed after December 31, 2008, transmission owners are required to make project-specific incentive requests that meet the nexus requirements under FERC guidelines for new projects. In 2008, we recognized $6 million in transmission segment earnings related to this order. This order has been appealed to the D.C. C ircuit Court of Appeals by various state regulators and consumer advocates. The court has set a schedule for the briefing to be concluded in the second quarter of 2009, with no date set for argument.
On May 16, 2008, CL&P filed an application with the FERC to receive ROE incentives for its portions of the Middletown-Norwalk project seeking a waiver of the "completed and on line" date of December 31, 2008 to earn the ROE incentives. Alternatively, CL&P asked FERC to find that this project met the nexus test requirements for incentives under FERC’s guidelines for new projects, and also requested an additional 50 basis point adder for advanced technology used in the project. FERC subsequently granted the waiver request and approved the 100 basis point incentive for the entire Middletown-Norwalk project. The FERC also found that the project met the nexus test, and granted an additional 50 basis point adder for the advanced technology aspects of the 24-mile underground portion of the project. CL&P completed the projectwere in-service by the end of 2008. The 50 basis point adder results inIn addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy. As a totalresult, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects. All appeals of FERC's orders on the ROE for th e underground portion of the Middletown-Norwalk project of 13.1 percent, which represents the overall ROE limit established by FERC. Certain state regulators and municipal utilities had sought rehearing which was denied by FERC and Connecticut state regulatorsNew England transmission owners have since appealed the order to the D.C. Circuit Court of Appeals. been denied.
8
On November 17, 2008, the FERC issued an order granting certain incentives and rate amendments to National Grid USA (National Grid) and us for certain components of the proposed NEEWS projects.project, which is described below. The approved incentives includedinclude (1) an ROE of 12.89 percent, which includes an incentive of 125 basis points;percent; (2) inclusion of 100 percent construction work in progress (CWIP)CWIP costs in rate base; and (3) full recovery of prudently incurred costs if any portion of NEEWS is abandoned for reasons beyond our or National Grid's control. Our portion of the components that received these incentives is estimated to cost approximately $1.41 billion of our $1.49 billion share of the total NEEWS projects. Several parties have sought rehearing of this FERC order on which FERC has not yet acted.
Transmission Projects
InNEEWS
CL&P and WMECO are continuing to develop and build the NEEWS project, which is comprised of GSRP, the Interstate Reliability Project and the Central Connecticut Reliability Project, and is estimated to cost $1.52 billion in the aggregate (approximately $1.45 billion reflecting the impact of UI’s potential investment of up to approximately $69 million as discussed below). CL&P and WMECO commenced substation construction on GSRP in December 2008, we completed2010 and expect to begin overhead line construction in the lastfirst half of our four southwest Connecticut transmission upgrades. The first of those projects, a new 345KV/115KV overhead and underground line between Bethel, Connecticut and Norwalk, Connecticut, was2011. We expect GSRP to be placed in service in October 2006. The remaining three projects were placed in service in 2008. The Middletown-Norwalk project, a 69-mile, 345KV/115 KV transmission project from Middletown to Norwalk, Connecticut constructed jointly with UI, was completed in December 2008. CL&P's portion of this project cost approximately $950 million, $100 million lower than our earlier cost estimate. The 45-mile overhead section of the project entered service on August 28, 2008 and the 24-mile underground section entered service on December 16, 2008. The Glenbrook Cables project, a two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut entered ser vice on November 11, 2008late 2013 at a project cost of approximately $239 million, $16 million higher than previous estimates due to increased construction costs to remove underground obstacles. The Long Island Replacement Cable project, a 138KV, 11-mile undersea transmission project between Norwalk, Connecticut and Northport-Long Island, New York was completed in September 2008. CL&P owns 51 percent of the project, with Long Island Power Authority owning the remainder, and CL&P's portion of the project costs is anticipated to be approximately $78$795 million.
In October 2008, we commenced state regulatory filings for our next series of major transmission projects, NEEWS. That series of projects involves our construction of new overhead 345 KV lines in MassachusettsCL&P is designing and Connecticut as well as associated substation work and 115 KV rebuilds. One of the projects will connect to a new transmission line that National Grid plans to build in Rhode Island and Massachusetts. On September 24, 2008, the New England Independent System Operator (ISO-NE) issued its final technical approval of the NEEWS projects which was a precursor to the siting application process. We estimate that CL&P’s and WMECO’s total capital expenditures for these projects will be $1.49 billion through 2013.
The first of the NEEWS projects, the Greater Springfield Reliability Project, which involves a 115 KV/345 KV line from Ludlow, Massachusetts to North Bloomfield, Connecticut, is the largest and most complicated project within NEEWS. This project is expected
10
to cost approximately $714 million if built according to our preferred route and configuration. CL&P filed its application to build the Connecticut portion of the Greater Springfield Reliability Project with the Connecticut Siting Council (Siting Council) on October 20, 2008 and WMECO filed its application to build its portion of the project with the Massachusetts Energy Facilities Siting Board on October 27, 2008. The Connecticut Energy Advisory Board is currently reviewing Connecticut-based generation, demand side management and other proposed alternatives to the Greater Springfield Reliability Project, which must be submitted to the Siting Council by March 19, 2009. The Siting Council has preliminarily set dates for hearings, public comments and site visits on the Connecticut portion of the project in the second quarter of 2009. If the overall project is approved in 2010 as expected, we currently expect to commence construction in late 2010 and place the project in service in 2013.
Our second major NEEWS project isbuilding the Interstate Reliability Project which is being designed and built in coordination with National Grid. CL&P's shareGrid USA, whose segment of this project includes a 40-mile 345 KV line from Lebanon, Connecticut tophase will interconnect with CL&P’s at the Connecticut-Rhode Island border where it would connect with enhancements National Grid is designing.border. In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project. We expect CL&P's share of the costs of this project to cost approximately $250 million. Municipal consultations concluded in November 2008,be $301 million and CL&P plans to file siting applications with Connecticut regulators by the third quarter of 2009 with construction beginning as early as late 2010. We currently expectthat the project towill be placed in service as early as 2012.in late 2015.
The third parttiming of NEEWS is the Central Connecticut Reliability Project which involves construction of a new line from Bloomfield, Connecticutis expected to Watertown, Connecticut. This line would provide us with another 345 KV connection to move power across the state of Connecticut. The timing of this project would be six to twelve months behind the other two projects,Interstate Reliability Project and CL&P currently expectscost approximately $338 million. ISO-NE continues to fileassess the siting application in early 2010 with construction beginning in 2011. The project is currently expected to be placed in service in 2013 at a cost of approximately $315 million. need date for the Central Connecticut Reliability Project and we expect that ISO-NE will conclude its evaluation by mid-2011.
Included as part of NEEWS are approximately $210$84 million of expenditures for associated reliability related expenditures, someprojects, all of which may be incurredhave received siting approval and most are under construction. The in-service dates for these projects range from later this year through 2013.
Northern Pass Transmission Line Project
NPT is a limited liability company jointly formed by NU and NSTAR to construct, own and operate the Northern Pass transmission line, a new HVDC transmission line from the border of Canada and the United States to Franklin, New Hampshire that will interconnect at the border with a new HVDC transmission line being developed by HQ TransEnergie, the transmission subsidiary of HQ. NUTV, a subsidiary of NU, holds a 75 percent interest in advanceNPT, with NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, holding the remaining 25 percent. Consistent with FERC's February 11, 2011 order accepting the TSA between NPT and Hydro Renewable Energy that was filed December 15, 2011, NPT will charge Hydro Renewable Energy cost-based rates for firm transmission service over the Northern Pass line for a 40-year term. The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the three major projects.project. Upon commercial operation, the ROE will be equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent based on a deemed capital structure for NPT of 50 percent debt and 50 percent equity.
DuringIn October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE. The DOE application seeks permission for NPT to construct and maintain facilities that cross the U.S. border and connect to HQ TransEnergie's facilities in Canada. Assuming timely regulatory review and siting approvals, NPT expects to commence construction of the Northern Pass in 2013, with power flowing across the line in late 2015.
We currently estimate that our 75 percent share of the costs to build the Northern Pass transmission project will be approximately $830 million out of total expected costs of approximately $1.1 billion (including capitalized AFUDC).
Other Transmission Transactions
In July 2010, CL&P and UI entered into an agreement under which UI would acquire certain transmission assets within CL&P's portion of each of the NEEWS segments. Under the terms of the agreement, which has received approval process, state regulators may require changes in configurationfrom the FERC and the DPUC, UI will have the option to address local concerns that could increase construction costs. Our current designinvest up to $69 million or an amount equal to 8.4 percent of CL&P's costs for NEEWS does not contemplate any underground lines. Building any transmission lines underground, particularly 345KV lines, would increase total costs, and our estimate could be increased during the siting approval process.assets, which are expected to aggregate approximately $828 million.
On December 12, 2008, we submitted jointly with NSTAR,17, 2010, CL&P and CTMEEC, a petition with the FERC requesting a declaratory order that would allow us and NSTAR to enternon-profit municipal joint action transmission entity formed by several Connecticut municipal electric companies, entered into a bilateral transmission services agreement with H.Q. Energy Services (U.S.) Inc. (HQUS), a wholly-owned subsidiary of Hydro-Québec. Under such an agreement NU, subject to DPUC approval, under which CTMEEC would acquire a segment of CL&P’s high voltage transmission lines in the town of Wallingford, Connecticut. The transaction was approved by FERC on January 31, 2011. The purchase price will be based on the net book value of the assets at the time of the closing of the sale in May 2011, projected to be approximately $42.3 million. CL&P will continue to operate and NSTAR subsidiaries would sell to HQUS 1,200 megawatts of firm electric transmission service over a new, participant-funded transmission tie line connecting New England withmaintain the Hydro-Québec system in orderlines for HQUS to sell and deliver this same amount of firm electric power from Canadian low-carbon energy resources to New England.CTMEEC.
If FERC issues the declaratory order as we anticipate, NU and NSTAR would subsequently seek approval from FERC of the specific terms and conditions of the transmission arrangement and approvals from state regulators of the terms and conditions of the power purchase arrangements. NU, NSTAR and HQUS have signed memoranda of understanding to develop this transmission project on an exclusive basis. This project would provide a competitive source of low-carbon power that is favorable in comparison to current alternatives. It also would provide for an expansion of New England’s transmission system without raising regional transmission rates.
9
NU, NSTAR and HQUS have also begun discussions on the specifics of a potential long-term power purchase agreement that would ensure the line is utilized to bring low-carbon power to benefit New England customers. A FERC order is expected in the first half of 2009, and if the order approves the proposal, then NU and NSTAR plan to negotiate a power purchase agreement with HQUS later in 2009. The terms of such an agreement would be subject to regulatory approval in several states.
Assuming completion of an acceptable power purchase agreement, and receipt of all necessary state and federal regulatory approvals, we expect this project to be under construction between 2011 and 2014. Our initial estimate of our portion of the construction funding is approximately $525 million. HQUS will reimburse NU and NSTAR for the total costs of this project, including an investment return to these companies, over the estimated 40-year operating life of the transmission line. NU and NSTAR’s intent is to create an agreement that approximates a typical FERC approved cost-of-service rate structure. The revenue recovery model will ultimately require FERC approval.
Transmission Rate Base
Under our FERC-approved tariff, transmission projects generally enter rate base once they are placed in commercial operation. Additionally,However, 100 percent of the NEEWS projects will enter rate base during their construction period. At the end of 2008,2010, our transmission rate base was approximately $2.4$2.8 billion, including approximately $2.0$2.1 billion at CL&P, $250$341 million at PSNH and $80$269 million at WMECO. We forecast that our total transmission rate base will grow to approximately $5.0$4.8 billion by the end of 2013. This increase in transmission rate base is driven by the need to improve the capacity and reliability of our regulated transmission system.
11
A summary of projected year-end transmission rate base by regulated company is as follows (millions of dollars):
Company | 2009 | 2010 | 2011 | 2012 | 2013 |
CL&P | $2,024 | $2,033 | $2,224 | $2,433 | $2,454 |
PSNH | 314 | 325 | 666 | 1,089 | 1,189 |
WMECO | 125 | 218 | 488 | 729 | 876 |
Other | - | - | - | - | 525 |
Totals | $2,463 | $2,576 | $3,378 | $4,251 | $5,044 |
The projected rate base amounts reflected above assume that $1.49 billion in transmission projects associated with NEEWS will be completed before the end of 2013 and the transmission line connecting to HQUS is built. Numerous factors, some of which are beyond our control, may impact the rate base amounts above,2015, including the level and timing of capital expenditures and plant placed in service and regulatory approvals. For more information regarding Regulated Transmission matters, see "Transmission Rate Matters and FERC Regulatory Issues" and "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in this Annual Report on Form 10-K.
approximately $830 million at NPT.
CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM
The principal focus of our construction and capital improvement program is maintaining, upgrading and expanding theour existing electric generation, transmission and distribution systemsystems and our natural gas distribution system. Our consolidated capital expenditures in 2008, including amounts incurred but not paid, cost of removal, allowance for funds used during construction and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors in determining rate base),2010 totaled approximately $1.3$1 billion, almost all of which ($967 million) was expended by the regulatedRegulated companies. The capital expenditures of these companies in 20092011 are estimated to total approximately $851 million. Of this amount, approximately $375$1.2 billion, $477 million is expected to be expended by CL&P, $310$284 million by PSNH, $100$287 million by WMECO and $66$113 million by Yankee Gas. This capital budget includes anticipated costs for all committed capital projects (i.e .,(i.e., generation, transmission, distribution, environmental compliance and others) and those reasonably expectedwe expect to become committed projects in 2009. We expect to evaluate needs beyond 2009 in light of future developments, such as restructuring, industry consolidation, performance and other events. Increases in proposed distribution capital expenditures stems primarily from increasing labor and material costs and an aging infrastructure. The costs (both labor and material) that our regulated companies incur to construct and maintain their electric delivery systems have increased dramatically in recent years. These increases have been driven primarily by higher demand for commodities and electrical products, as well as increased demand for skilled labor. Our regulated companies have many major classes of equipment that are approaching or beyond their useful lives, such as old and obsolete distribution poles, underground primary cables and substation switchgear. Replacement of this equipment is extremely costly.2011.
In 2010, CL&P’s transmission capital expenditures in 2008 totaled approximately $586 million. The decrease in transmission segment$107 million, and its distribution capital expenditures in 2008 as compared with 2007 was primarily due to the early completion of the major southwest Connecticut transmission projects discussed above.totaled approximately $305 million. For 2009,2011, CL&P projects transmission capital expenditures of approximately $97$137 million and distribution capital expenditures of approximately $337 million. During the period 20092011 through 2013,2015, CL&P plans to invest approximately $974 million$1 billion in transmission projects, the majority of which will be for NEEWS.
In addition to its transmission projects, CL&P plans distribution capital expenditures to meet growth requirementsNEEWS and improve the reliability of its distribution system. In 2008, CL&P's distribution capital expenditures totaled approximately $297 million. CL&P projects its distribution capital expenditures in 2009 to be approximately $278 million. CL&P plans to spend approximately $1.59 billion$1.9 billon on distribution projects during the period 2009-2013.projects. If all of the distribution and transmission projects are built as proposed, CL&P’s rate base for electric transmission is projected to increase from approximately $2.0$2.1 billion at the end of 20082010 to approximately $2.5$2.6 billion by the end of 2013,2015, and its rate base for distribution assets is projected to increase from approximately $2.0$2.3 billion to approximately $3.0$3.3 billion over the same period.pe riod.
In 2008,2010, PSNH's transmission capital expenditures totaled approximately $82$49 million, its distribution capital expenditures totaled $98approximately $84 million and its generation capital expenditures totaled $74$177 million. For 2009,2011, PSNH projects transmission capital expenditures of approximately $58$59 million, distribution capital expenditures of approximately $96$113 million and generation capital expenditures of approximately $156$112 million. The increase inbulk of the generation capital expenditures is mostly due to the expenditures for the Merrimack Clean Air project.Project. During the period 2009-2013,2011 through 2015, PSNH plans to spend approximately $1.1 billion$293 million on transmission projects, approximately $559$621 million on distribution projects, and $623$274 million on generation projects. If all of the distribution, generation and transmission projects are built as proposed, PSNH’s rate base for electric transmission is projected to increase from approximately $250 mil lion$341 million at the enden d of 20082010 to approximately $1.2 billion$540 million by the end of 2013,2015, and its rate base for distribution and generation assets is projected to increase from approximately $1.0$1.2 billion to approximately $2.0$1.9 billion over the same period.
In 2008,2010, WMECO's transmission capital expenditures totaled approximately $44.2$95 million, and its distribution capital expenditures totaled approximately $37.8$33.1 million and solar generation expenditures were $10 million. In 2009,2011, WMECO projects transmission capital expenditures of approximately $70$229 million, and distribution capital expenditures of approximately $30 million.$36 million and $22 million on solar generation. During the period 2009-2013,2011 through 2015, WMECO plans to spend approximately $888$732 million on transmission projects, with the bulk of that amount to be spent on the NEEWS Greater Springfield Reliability Project, andGSRP, approximately $168$194 million on distribution projects.projects and $46 million on solar generation. If all of the generation, distribution and transmission projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from approximately $269 million at the end of 2010 to approximately $876$803 million by the end of 20132015 and its rate base forfo r distribution and generation assets is projected to increase from approximately $374$423 million to approximately $497$488 million over the same period.
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In 2008,2010, Yankee Gas’sGas capital expenditures totaled approximately $44$95 million. For 2009,2011, Yankee Gas projects total capital expenditures of approximately $66 million.$113 million, approximately $30 million of which is expected to be related to the WWL project, $37 million related to basic business activities such as relocation of conflicting gas facilities and the purchase of meters, tools and information technology; $30 million related to reliability improvements; and $16 million for load growth and new business requests. During the period 2009-2013,2011 through 2015, Yankee Gas plans on making approximately $399$587 million of capital expenditures.expenditures, including approximately $30 million on the WWL project. Future capital spending will likely be affected by price differences between the cost of natural gas with respect to home heating oil, natural gas supply, new home construction, road reconstruction, regulatory mandates and business requirements. &n bsp;Excluding non-recurring major projects, NU expects that approximately 28 percent of Yankee Gas’ capital expenditures over the 2011-2015 period to be related to basic business activities, approximately 28 percent related to load growth and new business, and approximately 39 percent related to reliability initiatives, with the balance related to the WWL project. If all of Yankee Gas’sGas projects are built as proposed, Yankee Gas’sGas’ investment in its regulated assets is projected to increase from approximately $685$682 million at the end of 20082010 to approximately $890$969 million by the end of 2013.2015.
For more information regarding NU and its subsidiaries' construction and capital improvement programs, see "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in this Annual Report on Form 10-K.
STATUS OF EXIT FROM COMPETITIVE ENERGY BUSINESSES
Since 2005, we have been in the process of exiting our competitive energy businesses and are now focusing exclusively on our regulated businesses. At December 31, 2008, our competitive businesses consisted solely of (i) Select Energy’s few remaining wholesale marketing contracts and NGS and its affiliates, which are winding down, and (ii) Boulos, NU Enterprises’ remaining active energy services business.
On May 31, 2008, Select Energy’s remaining wholesale sales contract in the PJM power pool expired. Select Energy’s wholesale contract with The New York Municipal Power Agency (NYMPA) and related supply contracts expire in 2013. In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a non-derivative contract to operate and purchase the output of a certain generating facility in New England through 2012.
For more information regarding the exit of the competitive businesses, see "NU Enterprises Divestitures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 15, "Restructuring and Impairment Charges and Discontinued Operations," to the consolidated financial statements, contained within this Annual Report on Form 10-K.
FINANCING
We paid dividends on our common shares totaling $129.1NU subsidiaries issued a total of $145 million in 2008, compared to $121long-term debt in 2010. On March 8, 2010, WMECO issued $95 million in 2007, reflecting increases in the quarterly dividend amount that were effective in the third quarters of 2007 and 2008. On February 10, 2009, the NU Board of Trustees declaredsenior unsecured notes due March 1, 2020 carrying a quarterly dividend of $0.2375 per share, payable on March 31, 2009, an increase of $0.10 per share above the previous annualizedcoupon rate of $0.85 per share. This dividend reflects the company’s policy, announced in November 2008,5.1 percent and on April 22, 2010, Yankee Gas issued $50 million of targetingfirst mortgage bonds through a dividend payout ratio of approximately 50 percent of earnings,private placement with a goalmaturity date of continuing the policyApril 1, 2020 carrying a coupon rate of increasing the dividend at a rate above industry average and providing an attractive return to shareholders. NU expects to revisit its dividend levels in the first quarter of each year.4.87 percent.
In general,addition, on April 1, 2010, CL&P completed the regulated companies pay approximately 60remarketing of $62 million of tax-exempt secured PCRBs. The PCRBs carry a coupon rate of 1.4 percent of their cash earningsuntil April 1, 2011, at which time CL&P expects to remarket the bonds.
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On September 24, 2010, NU parent in the form of common dividends. In 2008,entered into a three-year $500 million unsecured revolving credit facility, and CL&P, PSNH, WMECO, and Yankee Gas paid $106.5jointly entered into a three-year $400 million $36.4 million, $39.7 million,unsecured revolving credit facility, both replacing five-year credit facilities on similar terms and $31 million, respectively, in common dividendsconditions that were scheduled to NU parent. In 2008,expire on November 6, 2010. Like the previous facility, NU’s new revolving credit facility allows NU parent contributed $210to borrow on a short-term or long-term basis, or issue LOCs, up to $500 million of equityin the aggregate. Under their new revolving credit facility, CL&P and PSNH are each able to CL&P, $75.6draw up to $300 million, to PSNH, $16.3 million towith WMECO and $20.8Yankee Gas each able to draw up to $200 million, all subject to Yankee Gas. the $400 million maximum aggregate borrowing limit.
Our credit facilities and indentures require that NU parent’s ability to pay common dividends is subject to approval by the Board of Trusteesparent and to NU’s future earnings and cash flow requirements. It is not regulated under the Federal Power Act, but may be limited by certain state statutes, the leverage restrictions tied to its required ratio of consolidated total debt to total capitalization in its revolving credit agreement, and the ability of its subsidiaries, to pay common dividends. The Federal Power Act does, however, limit the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances unless a higher amount is approved by FERC, and PSNH is required to reserve an additional amount under its FERC hydroelectric license conditions. In addition, certain state statutes may impose additional limitations on the regulated companies.including CL&P, PSNH, WMECO and Yankee Gas, alsocomply with certain financial and non-financial covenants as are parties to a revolving credit agreement that imposes leverage restrictions.
Our total debt,customarily included in such agreements, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including RRBs, was approximately $4.8 billion as of December 31, 2008.
During 2008, the NU companies issued an aggregate of $760 million of long-term debt, as follows: On May 27, 2008, CL&P issued $300 million of 10-year first and refunding mortgage bonds carrying a coupon rate of 5.65 percent, and PSNH issued $110 million of 10-year first mortgage bonds with a coupon rate of 6.00 percent. On June 5, 2008, NU parent issued $250 million of five-year senior unsecured notes with a coupon rate of 5.65 percent, and on October 7, 2008, Yankee Gas issued $100 million of 10-year first mortgage bonds at 6.9 percent. In addition, on February 13, 2009, CL&P issued $250 million of 10-year first mortgage bonds at 5.5 percent.
NU parent has a combined credit line and letter of credit (LOC) facility in a nominal aggregate amount of $500 million, including the lending commitment of Lehman Brothers Commercial Bank, Inc. (LBCB) (as discussed below), which expires on November 6, 2010. At December 31, 2008, NU parent had $304 million of borrowings and $87 million of LOCs issued for the benefit of certain subsidiaries outstanding under that facility. NU parent had approximately $50 million of borrowing availability on this facility as of February 25, 2009, excluding the remaining unfunded commitment of LBCB. NU also had approximately $466 million of externally invested cash at February 25, 2009.
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The regulated companies maintain a joint credit facility in a nominal aggregate amount of $400 million, including the lending commitment of LBCB, which also expires on November 6, 2010. There were $315 million of short-term borrowings outstanding under that facility at December 31, 2008. We had approximately $1 million of borrowing availability on this facility as of February 25, 2009, excluding the remaining unfunded commitment of LBCB. NU also had approximately $466 million of externally invested cash at February 25, 2009.
The lenders under these facilities are: Bank of America, N.A.; Barclays Bank PLC; BNY Mellon, N.A.; Citigroup Inc.; HSBC Bank USA, N.A.; JPMorgan Chase Bank, N.A.; LBCB; Sumitomo Mitsui Banking Corporation (Sumitomo); Toronto Dominion (Texas) LLC; Union Bank of California, N.A.; Wachovia Bank, N.A.; and Wells Fargo Bank, N.A. Lehman Brothers Holdings Inc., the parent of LBCB, filed for Chapter 11 bankruptcy protection in September 2008. LBCB's original aggregate lending commitment under the two facilities was $85 million, of which $30 million was assigned to Sumitomo in late September 2008. At December 31, 2008, LBCB had advanced approximately $19.2 million under the facilities and had declined to fund the remainder of its commitment. As a result, when current loans from LBCB are repaid, we will be limited to an aggregate of $845 million of borrowing capacity under our credit facilities, which we believe will provide sufficient operating flexibility to maintain adequate amounts of liquidity.
PSNH has outstanding approximately $407 million of PCRBs, one series of which, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. Since March 2008, a significant majority of this series of PCRBs has been held by remarketing agents as the result of failed auctions due to general market concerns. The interest rate on these PCRBs has reset by formula under the applicable documents every 35 days and has been between 0.2 percent and 4 percent since March 2008. The formula is based on a combination of the ratings on the PCRBs and an index rate, which provides for a current interest rate of 0.3 percent. We are not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agents.
In addition, CL&P has approximately $423.9 million of PCRBs, one series of which, in the aggregate principal amount of $62 million, had a fixed interest rate for a five-year period that expired on September 30, 2008. CL&P chose to acquire these PCRBs on October 1, 2008 as a result of poor liquidity in the tax-exempt market. These PCRBs, which mature in 2031, have not been retired, and CL&P expects to remarket them when conditions in the market improve.
Under their revolving credit facility agreements, each of NU, CL&P, WMECO, PSNH and Yankee Gas must maintainmaintaining a ratio of consolidated debt to total capitalization of no more than 65 percent. At December 31, 2008, NU, CL&P, WMECO, PSNH,All such companies currently are, and Yankee Gas were, and are expectedexpect to remain in compliance with this ratio.these covenants.
For more information regardingWe have annual sinking fund requirements of $4.3 million continuing in 2011 through 2012, the mandatory tender of $62 million of tax-exempt PCRBs by CL&P on April 1, 2011, at which time CL&P expects to remarket the bonds in the ordinary course. Neither NU andnor any of its subsidiaries' financing, see "Note 2, "Short-Term Debt," and Note 11, "Long-Term Debt," to the Consolidated Financial Statements and "Liquidity" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report on Form 10-K.subsidiaries have any debt maturities until April 1, 2012.
In light of the 2010 Tax Act and the related cash flow benefits, we are currently reevaluating the timing of our previously planned NU common equity issuance. If we complete the proposed merger with NSTAR, we would no longer need to undertake the previously planned $300 million NU common equity issuance in 2012 nor issue any additional equity in the foreseeable future.
NUCLEAR DECOMMISSIONING
GeneralGeneral
CL&P, PSNH, WMECO and several other New England electric utilities are the stockholders ofin three inactive regional nuclear generation companies, Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company (MYAPC)CYAPC, MYAPC and Yankee Atomic Electric Company (YAEC) (theYAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. Each Yankee Company collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, PSNH and WMECO.WMECO and several other New England utilities. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates. The ownership percentages of CL&P, PSNH and WMECO in the Yankee Companies are set forth below:
|
| CL&P |
| PSNH |
| WMECO |
| Total |
Connecticut Yankee Atomic Power Company |
| 34.5% |
| 5.0% |
| 9.5% |
| 49.0% |
Maine Yankee Atomic Power Company |
| 12.0% |
| 5.0% |
| 3.0% |
| 20.0% |
Yankee Atomic Electric Company |
| 24.5% |
| 7.0% |
| 7.0% |
| 38.5% |
|
| CL&P |
| PSNH |
| WMECO |
| Total |
CYAPC |
| 34.5% |
| 5.0% |
| 9.5% |
| 49.0% |
MYAPC |
| 12.0% |
| 5.0% |
| 3.0% |
| 20.0% |
YAEC |
| 24.5% |
| 7.0% |
| 7.0% |
| 38.5% |
Our share of the obligations to support the Yankee Companies under FERC-approved rulescontracts is the same as the ownership percentages above.
For more information regarding decommissioning and nuclear assets, see "Deferred Contractual Obligations" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.
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OTHER REGULATORY AND ENVIRONMENTAL MATTERS
General
We are regulated in virtually all aspects of our business by various federal and state agencies, including the FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the DPUC, havingwhich has jurisdiction over CL&P and Yankee Gas, the NHPUC, havingwhich has jurisdiction over PSNH, and the DPU, havingwhich has jurisdiction over WMECO.
Environmental Regulation
We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, our major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies. PSNH owns approximately 1,200 MW of generation assets and plansexpects to spend approximately $457$430 million to installon its Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack Stationcoal station to reduce its mercury emissions of its coal fired plants in compliance with current New Hampshire law.and sulfur dioxide emissions. Compliance with additional increasingly stringent environmental laws and regulations, particularly air and water pollution control requirements may limitcause changes in operations or require further substantial investments in new equipment at existing facilities.
Water Quality Requirements
The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES)NPDES permit from the United States Environmental Protection AgencyEPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of obtaining or renewing all required NPDES or state discharge permits in effect for our facilities. ComplianceIn each of the last three years, the costs incurred by the Company related to compliance with NPDES and state discharge permits has necessitated substantial expenditures and may require further significant expenditures, which are difficulthave not been material. The Company expects to estimate, becauseincur additional costs related to these permits in the future; however, due to uncertainty regarding the imposition of new or additional requirements, or restrictions that could be imposed in the future.Company is unable to accurately estimate such costs.
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Air Quality Requirements
The Clean Air Act Amendments of 1990 (CAAA),CAAA, as well as state laws in Connecticut, Massachusetts and New Hampshire law, impose stringent requirements on emissions of SO2SO2 and nitrogen oxides (NOX)NOX for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included.
In New Hampshire, the Multiple Pollutant Reduction Program capped NOX, SO2 NOX, SO2and carbon dioxide (CO2)CO2 emissions for current compliance beginning in 2007. In addition, a 2006 New Hampshire law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions of its coal fired plants by at least 80 percent (with the co-benefit of reductions in SO2SO2 emissions as well). Wet scrubber technology will be installed at Merrimack Station in Bow, New Hampshire. PSNH currently anticipates that compliance withThe Clean Air Project addresses this law will cost approximately $457 million.requirement. PSNH began site work for this project in November 2008. The project2008 and is scheduled to be completedcomplete it by the end of 2012.mid-2012.
In addition, Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI). RGGI, is a cooperative effort by ten northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2CO2 emissions from fossil fuel-fired electric generating plants. It is the first market-based, mandatory cap-and-trade program in the U.S. designed to reduce greenhouse gas emissions. Each of the participating states has regulations in place to cap and then reduce the amount of CO2 that power plants in their region are allowed to emit. Power sector CO2 emissions are capped at current levels through 2014. The cap will then be reduced by 2.5 percent in each of the four years 2015 through 2018, for a total reduction of 10 percent. RGGI is composed of individual CO2 budget trading programs in each of the participating states. Each participating state’s CO2 budget trading program establishes its respective share of the regional cap, and each state will issue CO2 allowances in a number equivalent to its portion of the regional cap. Each CO2 allowance represents a permit to emit one ton of CO2 in a specific year. The RGGI states will distribute CO2 allowances primarily through regional auctions.
Because CO2CO2 allowances issued by any participating state will be usable across all ten RGGI state programs, the ten individual state CO2 budgetCO2 trading programs, in the aggregate, will form one regional compliance market for CO2CO2 emissions. Initial CO2 allowance auctions were held in 2008 as pre-compliance events to facilitate market price discovery and compliance planning by regulated CO2 emitters. A regulated power plant must hold CO2CO2 allowances equal to its emissions to demonstrate compliance at the end of a three-year compliance period beginningthat began in 2009.
Connecticut adopted regulations in connection with RGGI in July 2008 which established an auction clearing price threshold of $5 per CO2 allowance, above which all auction proceeds will be rebated to customers. For proceeds up to the clearing price threshold, 69.5 percent will be directed to the conservation and load management programs managed by the state’s utilities in conjunction with the Energy Conservation Management Board. Seventy-five percent of the RGGI auction proceeds directed to conservation and load management programs will be allocated to CL&P’s programs. Because neither CL&P does notnor WMECO currently own any generating assets it(other than the solar facilities owned by WMECO, which do not emit CO2), neither is not required to acquire CO2CO2 allowances; however, the CO2allowance costs borne by generators that provide energy supply to CL&P and WMECO will likely be included in wholesale rates charged to CL&P in standard offer type contracts.
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Massachusetts law does not set an auction clearing price threshold for RGGI auctions. The law requires 80 percent of RGGI auction proceeds to be allocated to utility energy efficiency and demand response programs. Because WMECO does not own any generation assets, it is not required to acquire any CO2 allowances; however, thethem, which costs will likely be included in wholesale rates charged to WMECO in standard offer type contracts.
New Hampshire law sets an auction clearing price threshold of $6 per CO2 allowance in 2009, above which all auction proceeds will be rebated toare then recoverable from customers. Proceeds below the threshold are to be used for demand response and energy efficiency programs.
PSNH anticipates that its generating units will emit between 4four million and 5five million tons of CO2CO2 per year after taking into effect the operation of PSNH’s Northern Woods wood-burning generating plant that, underWood Power Project. Under the RGGI formula, this Project decreased PSNH’s responsibility for reducing fossil-fired CO2CO2 emissions by approximately 425,000 tons per year, or almost ten percent. New Hampshire legislation provides up to 2.5 million banked CO2CO2 allowances per year for PSNH’s fossil fueled generating plants during the 2009-20112009 through 2011 compliance period. These banked CO2CO2 allowances will initially comprise approximately one-half of the yearly CO2CO2 allowances required for PSNH’s generating plants to comply with RGGI and suchRGGI. Such banked allowances will decrease over time. PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2CO2 allowances at auction or in the secondary market. The cost of complying with RGGI req uirementsrequirements is recoverable from PSNH customers.
The first regional auction of RGGI CO2 allowances took place on September 25, 2008. Six states offered allowances for sale. At the auction, more than 12.5 million CO2 allowances were sold at the clearing price of $3.07 per CO2 allowance. The auction raised $38.6 million for use by the six RGGI states. The next regional auction took place on December 17, 2008. All ten RGGI states participated and more than 31.5 million CO2 allowances were sold at a clearing price of $3.38 per allowance. The auction raised $106.5 million for use by the ten RGGI states. For 2009, four quarterly regional auctions are scheduled for March, June, September and December.
Each of the states in which we do business also has renewable portfolio standards (RPS). New Hampshire’s renewable portfolio standards provision requires increasingRPS requirements, which generally require fixed percentages of the electricity soldenergy supply to retail customers in the state, beginning in 2008, to have direct ties to renewable sources, ultimately reaching 23.8 percent by 2025. PSNH is required to comply with these standards. We expect that the additional costs incurred to meet this new requirement will be recovered through PSNH’s energy service rates. Connecticut's RPS statutes require that a specific percentage of the generation provided to Connecticut consumers be producedcome from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources. Beginning
New Hampshire’s RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources, beginning in 2008 at four percent and ultimately reaching 23.8 percent by 2025. In 2010, the total RPS obligation was 7.5 percent of total generation supplied to customers. Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements. PSNH also owns renewable sources and uses both internally generated RECs and purchased RECs to meet its RPS obligations. To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient. The costs of both the RECs and alternative compliance payments do not impact earni ngs, as these costs are recovered by PSNH through its ES rates charged to customers.
Connecticut's RPS statute requires electricity suppliers to meet renewable energy standards, beginning with a 4four percent requirementRPS in 2004, the requirement2004. This percentage increases each year. For 2009,2010, the requirement is 12 percent, increasing to&nbs p;was 14 percent by 2010,with goals of 19.5 percent by 2015 and 27 percent by 2020. CL&P is permitted to pass any costs incurred in complying with RPS on to customers through rates.
Massachusetts’ RPS program required electricity suppliers to meet a 1one percent renewable energy standard in 2003 which increased to 4 percent for 2009 and has a goal of 15 percent by 2015. For 2010, the requirement was five percent. WMECO is permitted to pass any costs incurred in complying with RPS on to customers through rates.
In addition, many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on emissions than are currently in effect.
Hazardous Materials Regulations
Prior to the last quarter of the 20th20th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations were often disposed of by depositing or burying such materialsthem on-site or disposing of them at off-site landfills or other facilities. Typical materials disposed of include coal gasification waste,byproducts, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls.biphenyls or that otherwise might be hazardous. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. We have recorded a liability for what we believe is, based upon currently available information, our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability, andliability. We continue to evaluate the environmental impact of our formerfor mer disposal practices. Under federal an dand state law, government agencies and private parties can attempt to impose liability on us for such past disposal.these
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practices. At December 31, 2008,2010, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $27.4$37.1 million, representing 54 liabilities. All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable.58 sites. These costs could be significantly higher if additional remedial actions becomeremediation becomes necessary or when additional information as to the extent of contamination becomes available.
The most significant liabilities currently relate to future clean up costs at former manufactured gas plant (MGP)MGP facilities. These facilities were owned and operated by our predecessor companies to us from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We, through our subsidiaries, currently have partial or full ownership responsibilities at 28 former MGP sites. Of our total recorded liabilities of $27.4 million, a reserve of approximately $25.4 million has been established to address future investigation and/or remediation costs at MGP sites. In addition, Holyoke Water Power Company (HWP),
HWP, a wholly-owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with aan MGP which itsite that HWP sold to Holyoke Gas and Electric (HG&E),HG&E, a municipal electric utility, in 1902. HWP and HG&E share responsibilityis at least partially responsible for the site. HWPthis site and has already conducted substantial investigative and remediation activities.
The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 reports and proposals for further investigations. MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation. HWP has developed and begun to implement plans for
16
additional investigations in conformity with MA DEP’s guidance letter, including estimated costs and schedules. These matters are subject to ongoing discussions with MA DEP and HG&E and may change from time to time.
There are many outcomes that could affect our estimates and require an increase to the reserve, or range of costs, and a reserve increase would be reflected as a charge to pre-tax earnings. However, we cannot reasonably estimate the range of additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time. Further developments may require a material increase to this reserve.
HWP's share of the remediation costs related to this site is not recoverable from customers.
For further information on environmental liabilities, see Note 7B, "Commitments and Contingencies - Environmental Matters" to the Consolidated Financial Statements contained in this Annual Report on Form 10-K.
Electric and Magnetic Fields
For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF)EMF associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.
We have closely monitored research and government policy developments for many years and will continue to do so. In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.
Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government, particularly in recent years. The EPA has initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" and endanger public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated GHG emission reporting beginning in 2012 for 2011 emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF-6 gas and methane.
We are continually evaluating the risks presented by climate change concerns and issues. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations. (See "Air Quality Requirements" in this section for information concerning RGGI) These could include federal "cap and trade" laws, or regulations requiring additional capital expenditures at our generating facilities. In addition, such rules or regulations could potentially impact the prices we pay for goods and services provided by companies directly affected by such rules or regulations. We would expect that any costs of these rules and regulations would be recovered from customers, but such costs could impact energy use by our customers.
Global climate change could potentially impact weather patterns such as increasing the frequency and severity of storms or altering temperatures. These changes could affect our facilities and infrastructure and could also impact energy usage by our customers.
FERC Hydroelectric Project Licensing
New Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
PSNH owns nine hydroelectric generating stations with an aggregate of approximately 66.3 MW of capacity, with a current claimed capability representing winter rates of approximately 69.5 MW. Of these nine plants,71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 20092017 through 2036. As a licensee under the Federal Power Act (FPA),2047. PSNH and its licensed hydroelectric projects are subject to conditions set forth in such licenses, the FPAFederal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.
FERC hydroelectric project licenses expire periodically, and the generating facilities must be relicensed at such times. A new FERC license for PSNH’s Merrimack River Hydroelectric Project, which consists of the Amoskeag, Hooksett and Garvins Falls generating stations, was issued on May 18, 2007. PSNH's Canaan Hydroelectric Project is currently undergoing relicensing proceedings. On January 16, 2009, FERC issued a new license for this project. The new license takes effect upon the July 3, 2009 expiration of its current license. The water quality certification associated with this new license has been appealed to the Vermont Environmental Court.
Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision whichthat expressly permits the FERC to order decommissioning during the license term. However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing. The FERC may also require project
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decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked. PSNH is not presently encountering any of these challenges.
At this time, it appears unlikely that the FERC will order decommissioning of PSNH's hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked. However, it is impossible to predict the outcome of the FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics. Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, any estimates of the cost of project decommissioning are preliminary and subject to change as new information becomes available.
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EMPLOYEES
As of December 31, 2008,2010, we employed a total of 6,1896,182 employees, excluding temporary employees, of which 1,9441,847 were employed by CL&P, 1,2681,240 by PSNH, 366354 by WMECO, 417429 by Yankee Gas and 2,1822,307 were employed by Northeast Utilities Service Company (NUSCO).NUSCO. Approximately 2,3002,212 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are members of the International Brotherhood of Electrical Workers and The United Steelworkers and are covered by 11 union agreements.
INTERNET INFORMATION
Our website address is www.nu.com. We make available through our website a link to the SEC's IDEA site,EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site NU's, CL&P's, WMECO's and PSNH's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 107 Selden56 Prospect Street, Berlin, Connecticut 06037.Hartford, CT 06103.
Item 1A.
Risk Factors
We are subject to a variety of significant risks inIn addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" inincluded directly prior to Item 1, "Business," above.Business, above, we are subject to a variety of significant risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.
The infrastructureactions of regulators can significantly affect our earnings, liquidity and business activities.
The rates that our Regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC. These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters. FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters. The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.
Our transmission, distribution systemand generation systems may not operate as expected, and could require additional unplanned expenseexpenditures, which could adversely affect our earnings.financial position, results of operations and cash flows.
Our ability to manage operational risk with respect toproperly operate of our transmission, distribution and distributiongeneration systems is critical to the financial performance of our business. Our transmission, distribution and distributiongeneration businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age), accidents and; labor disputes. The costs (both labor and material) thatdisputes; disruptions in the delivery of electricity, including impacts on us or our regulated companies incurcustomers; increased capital expenditure requirements, including those due to construct and maintain their electric delivery systems have increased in recent years. These increases have been driven primarily by higher demand for commodities and electrical products,environmental regulation; information security risk, such as well as increased demand for skilled labor. A significant percentagea breach of our regulated company equipment is nearing or at the end of its life cycle,systems on which sensitive utility customer data and account information are stored; catastrophic events such as oldfires, explosions, or other similar occurrences; and obsolete distribution poles, underground primary cablesother unanticipated operations and substation switchgear.maintenance expenses and liabilities. The failure of our transmission, distributions and distributi onsgeneration systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in expenses, including higheroperation and maintenance costs. Any suchAt PSNH, outages at generating stations may be deemed imprudent by state regulators resulting in disallowance of replacement power costs. Such costs which maythat are not be recoverable from our ratepayerscustomers would have an adverse effect on our earnings.financial position, results of operations and cash flows.
The global financial crisis may have impactsLimits on our access to and increases in the cost of capital may adversely impact our ability to execute our business and financial condition that we currently cannot predict.plan.
The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition. The extreme disruption in the capital markets has limited companies’ ability to access the capital and credit markets to support their operations and refinance debt and has led to higher financing costs compared to recent years. We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied byobtained from our operating cash flow, including construction costs. Theflow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, higher interest rates would increase our cost of debt financingborrowing, which could adversely impact our results of operations. A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the proceeds of equity financing may be materially adversely impacted by these market conditions. The inability to raise capital on favorable terms couldmarkets and negatively affect our ability to maintain and to expand our businesses.
Our current credit ratings cause us to believe that we will continue to have access to t he capital markets. However, events beyond our control, such as the disruption in global capital and credit markets in 2008,counterparties may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. In addition, certain of NU parent’s subsidiaries rely, in part, on NU parent for access to capital. Circumstances that limit NU parent’s access to capital could impair its ability to provide those companies with needed capital. The credit crisis could also have an impact on our lenders or our customers, causing them to fail tonot meet their obligations to us. Additionally, the crisis could have a broader impact on business in general in ways that could lead to reduced electricity and gas usage, which could have a negative impact on our revenues.
In addition,We are exposed to the consequencesrisk that counterparties to various arrangements who owe us money, or have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of a prolonged recession may include a lowercapital project. Should any lenders under our credit facilities fail to perform, the level of economic activity and uncertainty regarding energy prices. A lower levelborrowing capacity under those arrangements could decrease. In any such events, our financial position, results of economic activity might result in a decline in energy consumption, which mayoperations, or cash flows could be adversely affect our revenues and future growth. Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses.affected.
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Changes in regulatory or legislative policy and/or regulatory decisions, difficulties in obtaining siting, design or other approvals, global demand for critical resources, or environmental or other concerns, or construction of new generation may delay completion of or displace our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected rates of return.
The successful implementation of ourOur transmission construction plans is subject to the risk thatcould be affected by new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact our ability to meet our construction schedule and/or require us to incur additional expenses and may adversely affect our ability to achieve forecast levels of revenues. In addition, difficultiesregulatory decisions, delays in obtaining required approvals for construction, or increased cost of and difficulty in obtaining critical resources as a resultrequired for construction. Any of global or
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domestic demand for such resourcesevents could cause delays in our construction schedule and may adversely affectaffecting our ability to achieve forecasted earnings.
The regulatory approval process for our planned transmission projects encompasses anrequires extensive permitting, design and technical approval process.activities. Various factors could result in increased cost estimatescosts and delayed construction.delay construction schedules. These include environmental and community concerns and design and siting issues. Recoverability of all such investments in rates may be subject to prudence review at the FERC. While we believe that all such expensescosts have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.
In addition, to the extent that new generation facilities are proposed or built to address the region’s energy needs, the need for our planned transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.
The currently plannedMany of our transmission projects are expected to help alleviate identified reliability issues and to help reduce customers' costs. However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system and supply interruptions or blackouts, may occur which could have an adverse effect on our earnings.
The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base before completion.base. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.
Increases in electric and gas prices the continued economic slowdown and focus on conservation and self-generation by customers andand/or a weak economy, can lead to changes in legislative and regulatory policy promoting energy efficiency, conservation, and self-generation and/or a reduction in our customers’ ability to pay their bills, which may adversely impact our business.
The nation's economy has been affectedEnergy consumption is significantly impacted by significant increasesthe general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy prices, particularly fossil fuels, as well as by a general economic slowdown. The impact of these increases has led toconsumption and increased electricity and natural gas prices for our customers, which, coupled with the continued economic slowdown, has increased the focus on conservation, energy efficiency and self-generation on the part of customers and on legislative and regulatory policies.by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.
In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.
Connecticut, New Hampshire and Massachusetts have each announced policies aimed at increased energy efficiency and conservation. In connection with such policies, all three states have opened proceedings to investigateinvestigated revenue decoupling as a mechanism to align the interests of customers and utilities relative to conservation. In Connecticut, the DPUC authorized decoupling viathrough a rate design that is intended to recover proportionately greater distribution revenue through the fixed Customer and Demand charges, and proportionately less distribution revenue through usage-based charges. In New Hampshire, the per kWh charges .NHPUC conducted a decoupling docket and determined that utilities were free to propose decoupling in the context of a rate case and demonstrate the effect decoupling would have on its risk profile and ROE. PSNH has not yet commenced such a proceeding. In Massachusetts, the DPU has required WMECO to adopt full decoupling in its January 31, 2011 rate decision. At this time it is uncertain what mechanisms will ultimately be adopted by New Hampshire and Massachusetts and what impact these decoupling mechanisms will have on our companies.
ChangesAs a way to promote self-generation and reduce energy costs, Connecticut, Massachusetts, and New Hampshire have taken a greater interest in regulatory policy may adversely affect our transmission franchise rightsallowing customers to receive credit for generation produced at a customer-owned generating facility that exceeds their energy needs. In Massachusetts, in accordance with the Green Communities Act, the DPU adopted rules and regulations concerning net metering that will have this effect. Such rules provide a cost recovery mechanism for affected utilities to recover lost revenues. The Massachusetts DPU is expected to hold further proceedings to address net metering in early 2011. In Connecticut, the DPUC opened a docket to review existing state statutes and determine what limitations currently exist in state law concerning net metering. In addition, any legislation in Connecticut to promote self-generation and net metering could impact CL&P’s financial position, results of operations or facilitate competitioncash flows. In New Hampshire, new legislation dramatically changed the net metering rules in 2010. This new legislation is meant to encourage net metering from customers with small generators and also provides PSNH a cost recovery mechanism for construction of large-scale transmission projects, which could adversely affect our earnings.
We have undertaken a substantial transmission capital investment program and expect to invest approximately $3.5 billion in regulated electric transmission infrastructure from 2009 through 2013.
Although our public utility subsidiaries have exclusive franchise rights for transmission facilities in our service area, the demand for improved transmission reliability could result in changes in federal or state regulatory or legislative policy that could cause us to lose the exclusivity of our franchises or allow other companies to compete with us for transmission construction opportunities. Such a change in policy could result in reduced transmission capital investments, reduce earnings, and limit future growth prospects.lost distribution revenue.
Changes in regulatory and/or legislative policy could negatively impact regional transmission cost allocation rules.
The existing FERC-approved New England transmission tariff allocates the costs of transmission investmentfacilities that provide regional benefits to all customers in New England.of participating transmission-owning utilities. As new investment in regional transmission infrastructure occurs in any one state, thereits cost is a sharing of these regional costsshared across all of New England.England in accordance with relative benefits received. This regional cost allocation is contractually agreed to byset forth in the Transmission Operating Agreement signed by all of the New England transmission owning utilities bututilities. Effective February 1, 2010, this agreement can be changedmodified with the approval of a majority of the transmission owning utilities after February 1, 2010.and FERC. In addition, after that date, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the
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rates our distribution companies' local rates. We are workingcompanies charge their retail customers. FERC is also considering policies to retainencourage the existing regional cost allocation treatment but cannot predictconstruction of transmission for renewable generation that could have the actionseffect of the states or utilities in the region.imposing costs of inter-regional investment on New England customers.
Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution companies.and generation businesses.
Under state law, our utilityRegulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval. There is no assurance that these state commissions will approve the recovery of all such costs prudently incurred
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by our regulatedRegulated companies, such as for construction, operation and maintenance, construction, as well as a return on investment on their respective regulated assets. Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory resistance to the timely recovery of such prudently incurred costs, thereby adversely affecting our cash flows andfinancial position, results of operations.operations or cash flows. Additionally, state legislators may enact laws that significantly impact our Regulated companies’ revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy. Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.
In addition, CL&P and WMECO procure energy for a substantial portion of their customerscustomers’ needs via requests for proposal on an annual, semi-annual or quarterly basis. CL&P and WMECO receive approvals of recoveryapproval to recover the costs of these contract pricescontracts from the DPUC and DPU, respectively. While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.
ThePSNH meets most of its energy requirements for PSNH are currently met primarily through PSNH'sits own generation resources orand fixed-price forward purchase contracts. PSNH’s remaining energy needs are met primarily through spot market or bilateral energy purchases. Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the necessary amount of energy to meet its requirements. PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC. We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.
Migration of customers from PSNH energy service to competitive energy suppliers could increase the cost to the remaining customers of energy produced by PSNH generation assets and decrease our revenues.
PSNH’s ES rates have been higher than competitive energy prices offered to some customers in recent years, primarily due to lower natural gas prices. As a result, by the end of 2010, approximately 2 percent of PSNH’s retail customers (representing approximately 32 percent of load), mostly large commercial and industrial customers, were buying their energy from competitive suppliers rather than from PSNH. The remaining retail customers are experiencing an increase in the cost of energy service supplied by PSNH by 5 percent to 7 percent due to migration of large commercial and industrial customers and the lower base in which to recover PSNH's fixed generation costs. This increase may in turn cause further migration and further increasing of PSNH energy service rates. This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation faciliti es on remaining customers and being unable to support the cost of its generation facilities through an ES rate.
The NHPUC is examining this issue in a proceeding in which hearings ended on December 1, 2010. PSNH has suggested transferring some fixed costs of the generation facilities into a nonbypassable charge while intervening competitive suppliers have proposed taking over the purchased power portion of the load not supplied by PSNH’s generation. Others have also proposed having PSNH bid all of its generation facilities into the market while an RFP process supplies all of the power for PSNH’s energy service. The NHPUC is considering further proceedings to explore these and other issues as well as the NHPUC authority to require PSNH to divest its generation facilities. It is not known what the results of such a proceeding would be, what PSNH may realize as a result of the sale or retirement of one or more of its generation facilities, or to what extent or manner the NHPUC would provide for recovery of any invest ment in its generation facilities.
Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize completion of, or full recovery of costs incurred by PSNH in constructing, the Clean Air Project.
Pursuant to New Hampshire law, PSNH has begun work onis building the Clean Air Project at its Merrimack Station in Bow, New Hampshire. As a result of an increase in the estimated cost of the project from $250 million to $457 million, severalSeveral parties have initiated legal proceedings challenging the project. These proceedings, or new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could result in increased costs to the delay or cancelation of this project or add to its cost. Any delay or cancelation of the project would adversely affect our ability to achieve forecast levels of earnings. If the project were to be canceled, contract payments and termination costs would be a substantial portion of the contractual commitments entered into by PSNH. As of March 31, 2009, the contractual commitments are expected to total approximately $250 million. The actual amount of contract termination costs wo uld depend on timing of the cancelation and negotiations with the contractors. At this time, we cannot predict any legislative or regulatory changes or the outcome of the pending legal proceedings.project.
In addition, PSNH’s investment in the project after it is completed is subject to prudence review by the NHPUC at the time the project is placed in service. A material prudence disallowance of a material nature could adversely affect PSNH’s cash flows andfinancial position, results of operations.operations or cash flows. While we believe thatwe have prudently incurred all expenditures to date, have been prudently incurred, we cannot predict the outcome of any prudency reviews should they occur. Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.
The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial condition and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our
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management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We are developinghave developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.
Grid disturbances, severe weather, or acts of war or terrorism could negatively impact our business.
Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business continuity due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage, solar storm activity or terrorist action) on an interconnected system or the actions of another utility. In addition, we are subject to the risk that acts of war or terrorism, including cyber-terrorism could negatively impact the operation of our system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition, and results of operations.operations or cash flows.
Severe weather, such as ice and snow storms, such as the ice storm that impacted New Hampshire in December 2008, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial.substantial, particularly as customers demand better and quicker response times to outages. The effect of the failure of our facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.
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A negative changeMarket performance or changes in NU's credit ratingsassumptions could require NU parentus to post cash collateralmake significant contributions to our pension and affect our ability to obtain financing.other post-employment benefit plans.
NU parent’s senior unsecured debt ratings by Moody's Investors Service, Standard & Poor's, Inc.We provide a defined benefit pension plan and Fitch Ratingsother post-retirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are currently Baa2, BBB-highly dependent on a variety of factors beyond our control. These factors include estimated investment returns, interest rates, health care cost trends, benefit changes, salary increases and BBB, respectively, with stable outlooks. Were anythe demographics of these ratingsplan participants. If our assumptions prove to declinebe inaccurate, our future costs could increase significantly. In 2008 and 2009, due to non-investment grade level, Select Energythe financial crisis, the value of our pension assets declined. As a result, we made a contribution of $45 million in 2010 and expect to make an approximate $145 million contribution in 2011. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could be asked to provide, as of December 31, 2008, collateral in the form of cash or letters of credit inincrease the amount of $23.2 millioncontributions required to unaffiliated counterparties and cash or letters of creditfund o ur pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of $10 million to two independent system operators. Whilefuture equity and debt financings and negatively affect our credit facilities are sufficient in amounts that would be adequate to meet collateral calls at that level, our ability to meet any future collateral calls would depend on our liquidity and access to bank lines and the capital markets at such time.financial position, results of operations or cash flows.
Changes in wholesale electric sales could require Select Energy to acquire or sell additional electricity on unfavorable terms.
Select Energy's remaining wholesale sales contracts provide electricity to full requirements customers, including a municipal electric company. Select Energy provides a portion of the customer's electricity requirements. The volumes sold under these contracts vary based on the usage of the underlying retail electric customers, and usage is dependent upon factors outside of Select Energy's control, such as economic activity and weather. The varying sales volumes may differ from the supply volumes that Select Energy expected to utilize from electricity purchase contracts. Differences between actual sales volumes and supply volumes may require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions which change due to weather, plant availability, transmission congestion, and input fuel costs. The purchase of additional electricity at high pri ces or sale of excess electricity at low prices could negatively impact Select Energy's cost to serve the contracts.
Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.
Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations which regulate,that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations financial position andor cash flows.
In addition, global climate change issues have received an increased focus on thefrom federal and state government levelsgovernments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations. Although we would expect that any costs of these rules and regulations would be recovered from ratepayers, thecustomers, their impact of these rules and regulations on energy use by ratepayerscustomers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time. The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.
Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates for generation.rates. The cost impact of any such legislationlaws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1, "BusinessBusiness - Other"Other Regulatory and Environmental Matters, - Environmental Regulation"" in this Annual Report on Form 10-K.
We are subjectAs a holding company with no revenue-generating operations, NU parent is dependent on dividends from its subsidiaries, primarily the Regulated companies, its bank facility, and its ability to legal proceedings whichaccess the long-term debt and equity capital markets.
NU parent is a holding company and as such, has no revenue-generating operations of its own. Its ability to meet its financial obligations associated with the debt service obligations on its debt and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or to repay borrowings from NU parent; and/or NU parent’s ability to access its credit
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facility or the long-term debt and equity capital markets. Prior to funding NU parent, the Regulated companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P) and obligations to trade creditors. Additionally, the Regulated companies could resultretain their free cash flow to fund their capital expenditures in large cash obligations. lieu of receiving equity contributions from NU parent. Should the Regulated companies not be able to pay dividends to or repay funds due to NU parent or if NU parent cannot access its bank facilities or the long-term debt and equity capital markets, NU parent’s ability to pay interest, dividends and its own debt obligations would be restricted.
Risks Related to the Proposed Merger with NSTAR
We are engaged in legal proceedings thatmay be unable to satisfy the conditions or obtain the approvals required to complete the merger or such approvals may contain material restrictions or conditions.
The merger is subject to approval by the shareholders of both NU and NSTAR and numerous other conditions, including the approval of various government agencies. Governmental agencies may not approve the merger or such approvals may impose conditions on the completion, or require changes to the terms of the merger, including restrictions on the business, operations or financial performance of the combined company, which could result inbe adverse to the impositioncompany's interests. These conditions or changes could also delay or increase the cost of large cash obligations against us. the merger or limit the net income or financial prospects of the combined company.
We may alsowill be subject to future legal proceedings based on asserted or unasserted claimsbusiness uncertainties and cannot predictcontractual restrictions while the outcome of any of these proceedings. Adverse outcomes in existing or future legal proceedings could result in the imposition of substantial cash damage awards or cash obligations against us.merger is pending.
Further information regarding legal proceedings,The work required to complete the merger may place a significant burden on management and internal resources. Management's attention and other company resources may be focused on the merger instead of on day-to-day management activities, including pursuing other opportunities beneficial to NU. In addition, while the merger is pending our business operations are restricted by the Agreement and Plan of merger to ordinary course of business activities consistent with past practice, which may cause us to forgo otherwise beneficial business opportunities.
We may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.
Uncertainties about the effect of the merger on management personnel and employees may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, which could affect our financial performance.
The merger may not be completed, which may have an adverse effect on our share price and future business and financial results and we could face litigation concerning the merger, whether or not the merger is consummated.
Failure to complete the merger could negatively affect NU's share price, as well as other matters, is set forthour future business and financial results. In addition, purported class actions have been brought against us, NSTAR and others on behalf of holders of NSTAR common shares. If these actions or similar actions that may be brought are successful, the costs of completing the merger could increase, or the merger could be delayed or prevented. We cannot make any assurances that we will succeed in any litigation brought in connection with the merger. See Item 3, "Legal Proceedings."Legal Proceedings, in this Annual Report on Form 10-K for discussion of pending litigation related to the merger.
If the merger is not completed for certain reasons specified in the merger agreement, we may be required to pay NSTAR a termination fee of $135 million plus up to $35 million of certain expenses incurred by NSTAR. In addition, we must pay our own costs related to the merger including, among others, legal, accounting, advisory, financing and filing fees and printing costs, whether the merger is completed or not. Further, if the merger is not completed, we could be subject to litigation related to the failure to complete the merger or other factors, which may adversely affect our business, financial results and share price.
If completed, the merger may not achieve its intended results.
We entered into the merger agreement with the expectation that the merger would result in various benefits. If the merger is completed, our ability to achieve the anticipated benefits will be subject to a number of uncertainties, including whether our businesses can be integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.
Item 1B.
Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
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Item 2.
Properties
Transmission and Distribution System
AtAs of December 31, 2008,2010, our electric operating subsidiaries owned 2931 transmission and 443422 distribution substations that had an aggregate transformer capacity of 4,312,0005,302,000 kilovolt amperes (kVa) and 29,401,00029,861,000 kVa, respectively; 3,0963,094 circuit miles of overhead transmission lines ranging from 69 KV to 345 KV, and 432433 cable miles of underground transmission lines ranging from 69 KV to 345
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KV; 34,89734,957 pole miles of overhead and 2,9253,054 conduit bank miles of underground distribution lines; and 536,203539,379 underground and overhead line transformers in service with an aggregate capacity of 36,730,94037,703,193 kVa.
Electric Generating Plants
As of December 31, 2008,2010, PSNH owned the following electric generating plants:
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Type of Plant |
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| Number |
| Year |
| Claimed |
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Total - Fossil-Steam Plants |
| 5 units |
| 1952-74 |
| 947,980 | |
Total - Hydro-Conventional |
| 20 units |
| 1901-83 |
| 71,105 | |
Total - Internal Combustion |
| 5 units |
| 1968-70 |
| 102,959 | |
Total - Biomass - Steam Plant |
| 1 unit |
| 1954 |
| 45,816 | |
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Total PSNH Generating Plant |
| 31 units |
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| 1,167,860 |
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Claimed capability represents winter ratings as of December 31, 2008.2010. The combined nameplate capacity of the generating plants is approximately 1,200 MW.
Neither As of December 31, 2010, WMECO owned the following electric generating plant:
Type of Plant |
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| Number |
| Year |
| Claimed |
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Total - Solar Fixed Tilt, Photovoltaic |
| 1 unit |
| 2010 |
| 1,800,000 |
** Claimed capability represents the direct current nameplate capacity of the plant.
CL&P nor WMECO owneddid not own any electric generating plants during 2008.2010.
Yankee Gas
AtAs of December 31, 2008,2010, Yankee Gas owned 2728 active gate stations, approximately 270200 district regulator stations and 3,2003,239 miles of natural gas main gas pipelines.pipeline. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, as well asa propane facility in Kensington, Connecticut, and three additional propane facilities that are no longer in Danbury, Kensingtonservice and Vernon, Connecticut.are expected to be sold in 2011.
Franchises
CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distribu tiondistributi on company from owning or operating generation assets. However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAPLocational Installed Capacity (LICAP) costs. In addition, Section 83 of Public Act 07-242, "An Act Concerning Electricity and Energy Efficiency"Efficiency," states that if an existing electric generating plant located in Connecticut is offered for sale, then an electric distribution company, such as CL&P, would be eligible to purchase the generation plant upon obtaining prior approval from the DPUC and a determination by the DPUC that such purchase is in the public interest.
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PSNH. The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The distribution and transmission franchises of PSNH include the power of eminent domain.
WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways. Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain. On December 31, 2008, WMECO purchased all of the transmission-related assets of its affiliates, HWP and HP&E, for approximately $4 million.
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The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including WMECO. The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislatu reLegislature recommending against, in this regard, any changes to the restructuring legislation.
Holyoke Water and Power Company and Holyoke Power and Electric Company. HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them. In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed not to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E, and to amend the charters of HWP and HP&E to reflect that limitation.
Prior to December 31, 2008, the two companies had locations in the public highways for their transmission lines. Such locations were granted pursuant to the laws of Massachusetts by the Massachusetts Department of Public Works or by local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. HP&E has no retail service territory area and sells electric power exclusively at wholesale. On December 31, 2008, HWP and HP&E sold all of their transmission-related assets to WMECO.
Yankee Gas.Yankee Gas directly and from its predecessors in interest holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service.service, which it acquired either directly or from its predecessors in interest. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility. Yankee Gas’sGas’ franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas’sGas’ franchises include, among other rights and powers, the right and power to manufacture,manuf acture, generate, pur chase,purchase, transmit and distribute gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.
Item 3.
Legal ProceedingsPart II
1.Item 5.
Yankee Companies v. U.S. Department of Energy
Yankee Atomic Electric Company (YAEC), Maine Yankee Atomic Power Company (MYAPC), and Connecticut Yankee Atomic Power Company (CYAPC) (the Yankee Companies) commenced litigation in 1998 against the United States Department of Energy (DOE) charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each company into the Nuclear Waste Fund. The funds for those payments were collected from regional electric customers. The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.
In a ruling released in 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. CL&P, PSNH and WMECO expect to pass any recovery onto their customers, therefore, no earnings impact is expected to result. In December 2006, the DOE appealed the decision and the Yankee Companies filed cross-appeals. The Court of Appeals disagreed with the trial court’s method of calculation of the amount of the DOE’s liability, among other things, and vacated the decision of the Court of Federal Claims and remanded the case to make new findings consistent with its decision. The application of any damages which are ultimately recovered to benefit customers is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.
In December 2007, the Yankee Companies filed a second round of lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002.
2.
Connecticut MGP Cost Recovery
On August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) of Pennsylvania for past and future remediation costs related to historic MGP operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut. The NU Companies alleged that UGI controlled operations of the plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests. Investigations and remediation expenditures at the sites to date total over $20 million, and projected potential remediation costs for all sites, based on litigation modeling assumptions, could total as much as $232 million. At this point, we are unable to estimate the potential costs assoc iated with this matter.
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In September 2006, the NU Companies filed a complaint against UGI in the U.S. District CourtMarket for the DistrictRegistrants' Common Equity and Related Stockholder Matters
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Item 6.
Selected Consolidated Financial Data
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Item 7.
Management's Discussion and Analysis of Connecticut seeking a fairFinancial Condition and equitable contribution for the actualResults of Operations
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Item 7A.
Quantitative and anticipated remediation costs related to the former MGP operations. The trial has been scheduled for April 2009.
3.
Other Legal Proceedings
For further discussion of legal proceedings see the following sections of Item 1, "Business": "Regulated Electric Distribution," "Regulated Gas Operations," and "Regulated Electric Transmission" for informationQualitative Disclosures about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "Nuclear Decommissioning" for information related to high-level nuclear waste; and "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters. In addition, see Item 1A, "Risk Factors" for general information about several significant risks.Market Risk
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Item 4.8.
Submission Of Matters To a VoteFinancial Statements and Supplementary Data
72
Item 8A.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
160
Item 8B.
Controls and Procedures
160
Item 9.
Other Information
160
Part III
Item 10.
Directors, Executive Officers and Corporate Governance
161
Item 11.
Executive Compensation
162
Item 12.
Security Ownership of Security HoldersCertain Beneficial Owners and Management and Related Stockholder Matters
195
Item 13.
Certain Relationships and Related Transactions, and Director Independence
197
Item 14.
Principal Accountant Fees and Services
197
Part IV
Item 15.
Exhibits and Financial Statement Schedules
199
Signatures
200
No event that would be described in response to this item occurred with respect to NU or CL&P.
The information called for by Item 4 is omitted for PSNH and WMECO pursuant to General Instruction I (2)(c) of Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries.)
EXECUTIVE OFFICERS OF THE REGISTRANT
This information is provided by NU in reliance on General Instruction G of Form 10-K. All of the Company’s officers serve terms of one year and until their successors are elected and qualified:
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On February 17, 2009, Ms. Payne resigned her position and was appointed Vice President - Shared Services of NUSCO, in each case, effective April 1, 2009.
Gregory B. Butler. Mr. Butler became Senior Vice President and General Counsel of NU effective December 1, 2005, and of CL&P, PSNH and WMECO, subsidiaries of NU, effective March 9, 2006, and was elected a Director of Northeast Utilities Foundation, Inc. effective December 1, 2002. Previously Mr. Butler served as Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005 and Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.
Peter J. Clarke. Mr. Clarke was elected President and Chief Operating Officer and a Director of WMECO, and a Director of Northeast Utilities Foundation, Inc., effective January 1, 2009. Previously, Mr. Clarke served as Vice President - Shared Services of NUSCO, CL&P, PSNH and WMECO, from January 1, 2008 to December 31, 2008; Vice President - Customer Operations of CL&P from July 1, 2006 to December 31, 2007; Vice President - Customer Operations and Relations of CL&P from January 17, 2005 to June 30, 2006; and Director - System Projects of CL&P from March 11, 2002 to January 16, 2005.
Jean M. LaVecchia. Ms. LaVecchia was elected Vice President - Human Resources of NUSCO, effective January 1, 2005 and was elected a Director of Northeast Utilities Foundation, Inc. effective January 30, 2007. Previously, Ms. LaVecchia served as Vice President - Human Resources and Environmental Services from May 1, 2001 to December 31, 2004.
David R. McHale. Mr. McHale was elected Executive Vice President and Chief Financial Officer of NU, CL&P, WMECO and PSNH, effective January 1, 2009, elected a Director of PSNH and WMECO, effective January 1, 2005, of CL&P effective January 15, 2007 and of Northeast Utilities Foundation, Inc. effective January 1, 2005. Previously, Mr. McHale served as Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO from January 1, 2005 to December 31, 2008 and Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.
Leon J. Olivier. Mr. Olivier was elected Executive Vice President and Chief Operating Officer of NU effective May 13, 2008; He also has served as Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; a Director of PSNH and WMECO since January17, 2005 and a Director of CL&P since September 2001. Previously, Mr. Olivier served as Executive Vice President - Operations of NU from February 13, 2007 to May 12, 2008’ Executive Vice President of NU from December 1, 2005 to February 13,
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2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; and President and Chief Operating Officer of CL&P from September 2001 to January 2005.
Shirley M. Payne. Ms. Payne was elected Vice President - Accounting and Controller of NU effective February 13, 2007, and Vice President - Accounting and Controller of CL&P, PSNH and WMECO effective January 29, 2007. Previously, Ms. Payne served as Vice President, Corporate Accounting and Tax of TECO Energy, Inc., from July 2000 to January 26, 2007, and Tax Officer of TECO Energy, Inc., from April 1999 to January 26, 2007.
James B. Robb. Mr. Robb was elected Senior Vice President, Enterprise Planning and Development of NUSCO on September 4, 2007. Previously, Mr. Robb served as Managing Director, Russell Reynolds Associates from December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; and Senior Vice President, Performance Management, Reliant Resources, Inc. from November 2002 to December 2003.
Charles W. Shivery. Mr. Shivery was elected Chairman of the Board, President and Chief Executive Officer of NU effective March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO effective January 19, 2007 and a Director of Northeast Utilities Foundation effective March 3, 2004. Previously, Mr. Shivery served as President (interim) of NU from January 1, 2004 to March 29, 2004; and President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.
There are no family relationships between any executive officer and any Trustee or other executive officer of NU and none of the above executive officers serve as an executive officer pursuant to any agreement or understanding with any other person.
iv
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
References in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.
From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections ma y vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
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actions or inaction by local, state and federal regulatory bodies
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changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services
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changes in weather patterns
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changes in laws, regulations or regulatory policy
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changes in levels and timing of capital expenditures
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disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly
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developments in legal or public policy doctrines
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technological developments
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changes in accounting standards and financial reporting regulations
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fluctuations in the value of our remaining competitive contracts
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actions of rating agencies
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The expected timing and likelihood of completion of the proposed merger with NSTAR, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, as well as the ability to successfully integrate the businesses, and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect and
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other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. Th is Annual Report on Form 10-K also describes material contingencies and critical accounting policies and estimates in the accompanyingManagement’s Discussion and Analysis andCombined Notes to Consolidated Financial Statements. We encourage you to review these items.
1
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
PART I
Item 1.
Business
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.
PROPOSED MERGER WITH NSTAR
On October 18, 2010, we and NSTAR announced that each company’s Board of Trustees unanimously approved a Merger Agreement (the merger agreement) to combine the two companies. The transaction was structured as a merger of equals in a tax-free exchange. Upon the terms and subject to the conditions set forth in the merger agreement, at closing, NSTAR will become a wholly-owned subsidiary of NU. The post-transaction company will provide electric and natural gas energy delivery service to nearly 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire, representing over half of all the customers in New England.
Under the terms of the merger agreement, NSTAR shareholders would receive 1.312 NU common shares for each common share of NSTAR that they own (the "exchange ratio"). The exchange ratio was structured to result in a no premium merger and is based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement. Following completion of the merger, common shares of the post-transaction company will be owned approximately 56 percent by NU shareholders and approximately 44 percent by former NSTAR shareholders. We anticipate that we will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger. Following the closing of the merger, our next quarterly dividend per common share will be increased to an amount that is equivalent to NSTAR’s last quarterly dividend per common share paid prior to the closing, divided by the exchange ratio. Based on the last quarterly dividend paid by NSTAR of $0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, that would result in NU’s quarterly dividend being increased by approximately 18 percent to approximately $0.325 per share, or approximately $1.30 per share on an annualized basis as compared to NU's current annualized dividend of $1.10 per share. NU filed its joint proxy statement/prospectus with the SEC on January 5, 2011 and scheduled a special meeting of shareholders for March 4, 2011, at which shareholders will vote on whether to approve the merger.
Completion of the merger is subject to various customary conditions, including approval by holders of two-thirds of the outstanding common shares of each company and receipt of all required regulatory approvals, including those of the Massachusetts DPU, the FERC and the NRC. We received approval from the FCC on January 4, 2011, and on February 10, 2011, the applicable Hart-Scott-Rodino waiting period expired. Several intervening parties have applied to participate in the regulatory review of the merger and have raised various issues that they believe the regulatory agencies should examine in the course of the proceedings.
In November 2010, the DPUC issued a draft decision stating it lacked jurisdiction over the merger. In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC to reconsider its draft decision. In January 2011, the DPUC issued an Administrative Order stating that it plans to hold a hearing to determine if it has jurisdiction over the merger. Oral arguments surrounding the draft decision were held in February 2011. The DPUC plans to hold an informational hearing at a date to be determined. In addition, legislation proposing to give the DPUC jurisdiction over the merger may be introduced in the Connecticut legislature.
THE COMPANY
NU, headquartered in Hartford, Connecticut, is a public utility holding company subject to regulation by FERC under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly-owned utility subsidiaries:
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The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;
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Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and continues to own generation assets used to serve customers;
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Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts; and
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Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.
NU also owns certain unregulated businesses through its wholly-owned subsidiary, NU Enterprises. As of December 31, 2010, NU Enterprises’ business consisted of (i) Select Energy’s few remaining energy wholesale marketing contracts, which are being wound down, and (ii) NU Enterprises’ electrical contracting business.
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Although NU, CL&P, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line-of-business, basis - the distribution segment (which also includes the generation businesses of PSNH and WMECO and our natural gas distribution business) and the transmission segment. Our Regulated companies accounted for approximately 99 percent of our total earnings of $387.9 million for 2010, with electric distribution representing approximately 45 percent, natural gas distribution representing approximately 8 percent and electric transmission representing approximately 46 percent of consolidated earnings. The remaining 1 percent of our 2010 earnings comes from our competitive businesses.
REGULATED ELECTRIC DISTRIBUTION
General
NU’s electric distribution segment consists of the distribution businesses of CL&P, PSNH and WMECO, which are primarily engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts, respectively, plus PSNH’s regulated electric generation business and WMECO’s solar generation. The following table shows the sources of 2010 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:
Sources of | % of Total | ||
Residential | 59% | ||
Commercial | 33% | ||
Industrial | 7% | ||
Other | 1% | ||
Total | 100% |
A summary of changes in the Regulated companies’ retail electric sales (GWh) for 2010 as compared to 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:
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| 2010 |
| 2009 |
| Percentage |
| Weather |
Residential |
| 14,913 |
| 14,412 |
| 3.5% |
| (0.7)% |
Commercial |
| 14,506 |
| 14,474 |
| 0.2% |
| (2.8)% |
Industrial |
| 4,481 |
| 4,423 |
| 1.3% |
| (1.5)% |
Other |
| 330 |
| 336 |
| (1.4)% |
| (1.4)% |
Total |
| 34,230 |
| 33,645 |
| 1.7% |
| (1.7)% |
Total retail electric sales for all three electric companies were higher in 2010 compared to 2009 due primarily to warmer than normal weather in the summer of 2010 and colder than normal weather in December 2010. Residential sales benefitted the most from the weather in 2010 and were higher for all three electric companies in 2010 compared to 2009.
On a weather normalized basis, retail sales for all three electric companies were lower in 2010 compared to 2009. We believe the decrease was due in part to increased conservation efforts by our customers and the continuing effects of the weak economy.
THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION
CL&P’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2010, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut. CL&P does not own any electric generation facilities. In 2010, CL&P had contracts to purchase the electric output from eighteen IPP generators. The term of two of these contracts ended in 2010. In 2011 the sixteen remaining generators are anticipated to provide approximately two million MWh per year through March 2015, with purchase quantities dropping significantly from 2015 through 2024, when the term of the last IPP contract ends. CL&P sells the output of these contracts into the ISO New England market, crediting customer energy charges with the proceeds. CL& ;P has entered into eleven contracts with renewable energy generators under a state program known as Project 150, and UI has entered into 2 other similar contracts under Project 150. CL&P and UI will share the costs and benefits of these contracts on an 80 percent and 20 percent basis, respectively. This cost sharing split is independent of the specific utility that is the counterparty to the contract. It is currently projected that the first of these renewable energy projects will commence commercial operation in 2011.
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The following table shows the sources of 2010 electric franchise retail revenues for CL&P based on categories of customers:
Sources of | % of Total | ||
Residential | 61% | ||
Commercial | 32% | ||
Industrial | 6% | ||
Other | 1% | ||
Total | 100% |
Rates
CL&P is subject to regulation by the Connecticut DPUC, which, among other things, has jurisdiction over its rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers.
The CTA is a charge assessed to recover stranded costs associated with electric industry restructuring as well as various IPP contracts. The SBC recovers costs associated with various hardship and low income programs as well as payments to municipalities to compensate them for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring. The CTA and SBC are annually reconciled to actual costs incurred, with any difference refunded to, or recovered from, customers.
Under state law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. Under "Standard Service" rates for customers with less than 500 KW of demand and "Supplier of Last Resort Service" rates for customers with 500 KW of demand or greater, CL&P purchases power for those customers who do not choose a competitive energy supplier and passes the cost to such customers through a combined GSC and FMCC on customers' bills. The combined GSC and FMCC charges for both types of service recover all of the costs of procuring energy from CL&P's wholesale suppliers and are adjusted periodically and reconciled semi-annually in accordance with the directives of the DPUC.
Although more CL&P customers chose competitive energy suppliers in 2010 than in 2009, CL&P continues to supply approximately 40 percent of its customer load at Standard Service or Supplier of Last Resort Service rates while the other 60 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on CL&P’s delivery business or its operating income.
Distribution Rates: On June 30, 2010, the DPUC issued a final order in CL&P’s most recent retail rate case approving annualized distribution rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011. The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final payment of CL&P’s RRBs. In its decision, the DPUC also maintained CL&P’s authorized distribution segment regulatory ROE of 9.4 percent. In 2010, CL&P earned a distribution segment regulatory ROE of 7.9 percent, compared to 7.3 percent in 2009, and expects to earn a distribution segment regulatory ROE of approximately 9 percent in 2011.
In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds (ERRBs) that would be amortized over eight years. These bonds will be repaid through a charge on the bills of customers of CL&P and other Connecticut electric distribution companies. For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would have otherwise ended by December 31, 2010 with the final payment of the principal and interest on its RRBs, and the diversion of about one-third of the annual funding for C&LM programs beginning in April 2012. A lawsuit pending against the DPUC to prevent the issuance of the ERRBs is pending and several bills seeking to modify or prevent the issuance have been proposed before the state l egislature.
On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan concluding that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario." Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million. CL&P has proposed beginning installation of meters in late 2012 and finishing in 2016.
CL&P has a transmission adjustment clause as part of its retail distribution rates, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, thereby recovering all of its transmission expenses on a timely basis.
Sources and Availability of Electric Power Supply
As noted above, CL&P does not own any generation assets and purchases energy to serve its Standard Service and Supplier of Last Resort Service loads from a variety of competitive sources through periodic RFPs. CL&P enters into supply contracts for Standard Service periodically for periods of up to three years to mitigate price volatility for its residential and small and medium load commercial and industrial customers. CL&P enters into supply contracts for Supplier of Last Resort service for larger commercial and industrial
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customers every three months. Currently, CL&P has contracts in place with various suppliers for all of its Standard Service loads through 2011, 40 percent of expected load for 2012, and 10 percent of expected load for 2013. CL&P’s contracts for its Supplier of Last Resort Service loads extend through the second quarter of 2011.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE - DISTRIBUTION
PSNH’s distribution business (which includes its generation business) consists primarily of the generation, purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2010, PSNH furnished retail franchise electric service to approximately 497,000 retail customers in 211 cities and towns in New Hampshire. PSNH also owns and operates approximately 1,200 MW of primarily fossil-fueled electricity generation assets. Included in those generation assets is its 50 MW wood-burning Northern Wood Power Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation. PSNH also has contracts with 18 IPPs, the output of which it either uses to serve its customer load or sells into the market.
PSNH is constructing its Clean Air Project, a sulfur dioxide and mercury scrubber at its Merrimack coal-fired generation station, which is currently expected to cost $430 million. The project is scheduled for completion in mid-2012. PSNH will recover all related costs through its ES rates described below.
The following table shows the sources of 2010 electric franchise retail revenues based on categories of customers:
Sources of | % of Total | ||
Residential | 54% | ||
Commercial | 36% | ||
Industrial | 9% | ||
Other | 1% | ||
Total | 100% |
Rates
PSNH is subject to regulation by the NHPUC, which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.
PSNH’s ES rate recovers its generation and purchased power costs from customers on a current basis and allows for an ROE of 9.81 percent on its generation investment.
Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs, including expenses incurred under mandated power contracts and other long-term investments and obligations. PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time and recovers the costs of these bonds through the SCRC rate.
On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year. The difference between ES/SCRC revenues and ES/SCRC costs are included in the ES/SCRC rate calculations and refunded to/recovered from customers in the subsequent period approved by the NHPUC.
The TCAM allows PSNH to recover on a fully reconciling basis its transmission related costs. The TCAM is adjusted July 1 of each year.
Distribution Rates: On June 28, 2010, the NHPUC approved a joint settlement of PSNH’s rate case that had commenced in 2009, allowing a net distribution rate increase of $45.5 million on an annualized basis to be effective July 1, 2010, and annualized distribution rate adjustments projected to be a decrease of $2.9 million and increases of $9.5 million and $11.1 million on July 1 of each of the three subsequent years, respectively. PSNH agreed not to file a new distribution rate request that would be effective prior to July 1, 2015. During the term of the settlement, PSNH can only propose changes to its permanent distribution rate level when its 12-month distribution ROE falls below 7 percent for two consecutive quarters or certain specified external events, such as major storms, occur. If PSNH’s 12-month ROE rolling average is greater than 10 percent, anything over the 10 percent level will be all ocated 75 percent to customers and 25 percent to PSNH. The settlement also provided that the authorized regulatory ROE on distribution only plant will continue at the previously allowed level of 9.67 percent. PSNH’s distribution segment regulatory ROE was 10.2 percent (including generation) in 2010, compared to 7.2 percent in 2009. We expect PSNH’s distribution segment regulatory ROE will be approximately 9 percent in 2011.
PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not elect to use a third party supplier. Prior to 2009, PSNH experienced only a minimal amount of customer migration. However, customer migration levels began to increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH. By the end of 2010, approximately 2 percent of all of PSNH’s customers (approximately 32 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers. The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sal es
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volume. The customers that did not switch to a third party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of these fixed costs.
The NHPUC opened a proceeding in 2010 to consider the effect of customer migration on ES rates for customers, principally residential and small commercial and industrial customers, remaining on PSNH default energy service. As part of this docket, the NHPUC stated its intention to explore the interplay of customer choice, migration issues and power procurement options for PSNH.
PSNH cannot predict if the upward pressure on ES rates will continue into the future, as future customer migration levels, which are dependent on market prices and supplier alternatives, are uncertain. If future market prices once more exceed the average ES rate level, some or all of these customers on third party supply may migrate back to PSNH.
Sources and Availability of Electric Power Supply
During 2010, about 88 percent of PSNH’s load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with third parties. The remaining 12 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. PSNH expects to meet its load requirements in 2011 in a similar manner.
WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION
WMECO’s distribution business consists primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers. At December 31, 2010, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western third of Massachusetts. Following electric industry restructuring in the 1990s, WMECO sold all of its generating facilities and now purchases its energy requirements from competitive suppliers. In 2009, pursuant to the Massachusetts Green Communities Act, WMECO was authorized to install 6 MW of solar energy generation in its service territory. In October 2010, WMECO completed construction of a 1.8 MW solar generation facility at a site in Pittsfield, Massachusetts, which began producing electricity in late 2010. In January 2011, WMECO announced its plans to develop a second solar generation faci lity at a site in Springfield, Massachusetts. This facility will accommodate 17,000 solar panels, producing up to 4.2 MW of solar energy. WMECO will sell all energy and other products from its solar generation facilities into the ISO New England market. WMECO had a contract with one IPP generator in 2010, the output of which WMECO sold into the ISO New England market. The term of this contract ended on December 31, 2010.
The following table shows the sources of 2010 electric franchise retail revenues based on categories of customers:
Sources of | % of Total | ||
Residential | 57% | ||
Commercial | 33% | ||
Industrial | 9% | ||
Other | 1% | ||
Total | 100% |
Rates
WMECO is subject to regulation by the Massachusetts DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities. WMECO's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under state law, WMECO's customers are entitled to choose their energy suppliers, while WMECO remains their distribution company. WMECO purchases electric power from competitive suppliers for, and passes through the cost to, those customers who do not choose a competitive energy supplier (basic service). Basic service charges are adjusted and reconciled on an annual basis. Most of WMECO's residential and small commercial and industrial customers have continued to buy their power from WMECO at basic service rates. A greater proportion of large commercial and industrial customers have opted for a competitive energy supplier.
WMECO continues to supply approximately 50 percent of its customer load at basic service rates while the other 50 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on WMECO’s delivery business or its operating income.
WMECO recovers certain costs through various tracking mechanisms in its retail rates, including transmission costs, pension costs and prudently incurred stranded costs (a portion of which have been financed through securitization by issuing RRBs) with periodic true-up adjustments.
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Distribution Rates: On January 31, 2011, the DPU issued a final decision in WMECO’s July 2010 rate application, granting a $16.8 million annualized rate increase in distribution revenues and an allowed ROE of 9.6 percent effective February 1, 2011. The DPU also authorized a full decoupling mechanism, whereby actual revenue billed by WMECO would be reconciled with WMECO’s target revenue on an annual basis, WMECO’s request to recover balances of certain active hardship account balances and the recovery of certain storm costs over five years. The DPU did not authorize rate recovery of a proposed $20 million average increase in WMECO’s capital spending plan. WMECO’s distribution segment regulatory ROE was 4.6 percent in 2010 compared to 8.4 percent in 2009. We expect WMECO’s distribution segment regulatory ROE will be approximately 9 percent in 2011.
WMECO is subject to SQ metrics that measure safety, reliability and customer service, and WMECO pays any charges incurred for failure to meet such metrics to customers. WMECO will not be required to pay an assessment charge for its 2010 performance results as WMECO performed at target for all of its SQ metrics in 2010.
On October 16, 2009, WMECO filed its proposal for a dynamic pricing smart meter pilot program with the DPU. However, the Company does not expect it will conduct a pilot prior to 2012.
Sources and Availability of Electric Power Supply
As noted above, WMECO does not own any generation assets (other than its recently constructed solar generation) and purchases its energy requirements from a variety of competitive sources through periodic RFPs. For basic service power supply, WMECO issues RFPs periodically, consistent with DPU regulations.
REGULATED GAS DISTRIBUTION – YANKEE GAS SERVICES COMPANY
Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 206,000 customers in 71 cities and towns), and size of service territory (2,187 square miles). Total throughput (sales and transportation) in both 2010 and 2009 was approximately 52.5 Bcf. Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas’ service territory buy gas supply and delivery only from Yankee Gas while commercial and industrial customers have choice in their gas suppliers. Yankee Gas offers firm transportat ion service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice. Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which enables the company to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher.
The following table shows the sources of 2010 gas operating revenues based on categories of customers:
Sources of | % of Total | ||
Residential | 51% | ||
Commercial | 30% | ||
Industrial | 16% | ||
Other | 3% | ||
Total | 100% |
A summary of firm natural gas sales in million cubic feet for Yankee Gas for 2010 and 2009 and the percentage changes in 2010 as compared to 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:
|
| Firm Natural Gas Sales (Mcf) |
|
| ||||
|
| 2010 |
| 2009 |
| Percent |
| Weather |
Residential |
| 13,403 |
| 13,562 |
| (1.2)% |
| 4.9% |
Commercial |
| 14,982 |
| 14,063 |
| 6.6% |
| 12.1% |
Industrial |
| 14,866 |
| 14,825 |
| 0.3% |
| 1.7% |
Total |
| 43,251 |
| 42,450 |
| 1.9% |
| 6.2% |
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Yankee Gas’ firm natural gas sales are subject to many of the same influences as our retail electric sales, but they have recently benefitted from a favorable price for natural gas relative to competing fuels resulting in commercial and industrial customers switching from interruptible service to firm service, and the addition of gas-fired distributed generation in Yankee Gas’ service territory. Actual firm natural gas sales in 2010 were higher than 2009 despite the milder weather during the first quarter 2010 heating season. Firm natural gas sales benefitted from these trends and from a large commercial customer who began to take service from Yankee Gas mid-way through the third quarter of 2009 and continued to take service throughout all of 2010.
In April 2010, Yankee Gas commenced construction of its WWL project, a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut coupled with the increase of vaporization output of its LNG plant. The project is expected to cost approximately $57.6 million. In 2010, approximately $26.6 million was spent on construction of the WWL project, which included construction of a segment of pipeline connecting the Cheshire and Wallingford distribution systems. The remainder of the pipeline construction and the expansion of the vaporization capacity of the LNG facility are expected to be completed in the fourth quarter of 2011
Rates
Yankee Gas is subject to regulation by the DPUC, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.
Distribution Rates: On January 7, 2011, Yankee Gas filed an application with the DPUC to raise natural gas distribution rates by $32.8 million, or 7.3 percent, to be effective July 1, 2011, and by an additional $13 million, or 2.8 percent, to be effective July 1, 2012. Among other items, Yankee Gas requested to maintain its current authorized ROE of 10.1 percent, that $57.6 million of costs associated with the WWL project be placed into rates, and that a substantial increase in capital funding to replace bare steel and cast iron pipe on Yankee Gas' system. A final decision is expected in June 2011. Yankee Gas’ regulatory ROE was 8.6 percent in 2010 compared to 6.6 percent in 2009. We expect Yankee Gas’ distribution segment regulatory ROE to be approximately 9 percent in 2011.
Sources and Availability of Natural Gas Supply
The DPUC requires that Yankee Gas meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas’ LNG facility enables Yankee Gas to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher. Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that currently directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines. Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Li mited pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines. Yankee Gas considers such transportation arrangements adequate for its needs.
ELECTRIC TRANSMISSION
General
CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the rules by which they participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, has served since 2005 as the RTO of the New England transmission system. ISO-NE works to ensure the reliability of the system, administers, subject to FERC approval, the independent system operator tariff, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of all regional major transmission facilities are shared by consumers throughout New England.
Wholesale Transmission Rates
Wholesale transmission revenues are recovered through formula rates that are approved by the FERC. Our transmission revenues are recovered from New England customers through ISO-NE charges which recover costs of transmission and other transmission-related services provided by all regional transmission owners, with a portion of those revenues collected from the distribution segments of CL&P, PSNH and WMECO.
FERC ROE Decision
Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC set the base ROE at 11.14 percent and approved incentives that increased the ROE to 12.64 percent for those projects that were in-service by the end of 2008. In addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy. As a result, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects. All appeals of FERC's orders on the ROE for New England transmission owners have been denied.
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On November 17, 2008, the FERC issued an order granting certain incentives and rate amendments to National Grid and us for certain components of the proposed NEEWS project, which is described below. The approved incentives include (1) an ROE of 12.89 percent; (2) inclusion of 100 percent CWIP costs in rate base; and (3) full recovery of prudently incurred costs if any portion of NEEWS is abandoned for reasons beyond our control. Several parties have sought rehearing of this FERC order on which FERC has not yet acted.
Transmission Projects
NEEWS
CL&P and WMECO are continuing to develop and build the NEEWS project, which is comprised of GSRP, the Interstate Reliability Project and the Central Connecticut Reliability Project, and is estimated to cost $1.52 billion in the aggregate (approximately $1.45 billion reflecting the impact of UI’s potential investment of up to approximately $69 million as discussed below). CL&P and WMECO commenced substation construction on GSRP in December 2010 and expect to begin overhead line construction in the first half of 2011. We expect GSRP to be placed in service in late 2013 at a cost of approximately $795 million.
CL&P is designing and building the Interstate Reliability Project in coordination with National Grid USA, whose segment of this phase will interconnect with CL&P’s at the Connecticut-Rhode Island border. In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project. We expect CL&P's share of the costs of this project to be $301 million and that the project will be placed in service in late 2015.
The timing of the Central Connecticut Reliability Project is expected to be twelve months behind the Interstate Reliability Project and cost approximately $338 million. ISO-NE continues to assess the need date for the Central Connecticut Reliability Project and we expect that ISO-NE will conclude its evaluation by mid-2011.
Included as part of NEEWS are $84 million of expenditures for associated reliability related projects, all of which have received siting approval and most are under construction. The in-service dates for these projects range from later this year through 2013.
Northern Pass Transmission Line Project
NPT is a limited liability company jointly formed by NU and NSTAR to construct, own and operate the Northern Pass transmission line, a new HVDC transmission line from the border of Canada and the United States to Franklin, New Hampshire that will interconnect at the border with a new HVDC transmission line being developed by HQ TransEnergie, the transmission subsidiary of HQ. NUTV, a subsidiary of NU, holds a 75 percent interest in NPT, with NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, holding the remaining 25 percent. Consistent with FERC's February 11, 2011 order accepting the TSA between NPT and Hydro Renewable Energy that was filed December 15, 2011, NPT will charge Hydro Renewable Energy cost-based rates for firm transmission service over the Northern Pass line for a 40-year term. The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project. Upon commercial operation, the ROE will be equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent based on a deemed capital structure for NPT of 50 percent debt and 50 percent equity.
In October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE. The DOE application seeks permission for NPT to construct and maintain facilities that cross the U.S. border and connect to HQ TransEnergie's facilities in Canada. Assuming timely regulatory review and siting approvals, NPT expects to commence construction of the Northern Pass in 2013, with power flowing across the line in late 2015.
We currently estimate that our 75 percent share of the costs to build the Northern Pass transmission project will be approximately $830 million out of total expected costs of approximately $1.1 billion (including capitalized AFUDC).
Other Transmission Transactions
In July 2010, CL&P and UI entered into an agreement under which UI would acquire certain transmission assets within CL&P's portion of each of the NEEWS segments. Under the terms of the agreement, which has received approval from the FERC and the DPUC, UI will have the option to invest up to $69 million or an amount equal to 8.4 percent of CL&P's costs for the assets, which are expected to aggregate approximately $828 million.
On December 17, 2010, CL&P and CTMEEC, a non-profit municipal joint action transmission entity formed by several Connecticut municipal electric companies, entered into an agreement , subject to DPUC approval, under which CTMEEC would acquire a segment of CL&P’s high voltage transmission lines in the town of Wallingford, Connecticut. The transaction was approved by FERC on January 31, 2011. The purchase price will be based on the net book value of the assets at the time of the closing of the sale in May 2011, projected to be approximately $42.3 million. CL&P will continue to operate and maintain the lines for CTMEEC.
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Transmission Rate Base
Under our FERC-approved tariff, transmission projects generally enter rate base once they are placed in commercial operation. However, 100 percent of the NEEWS projects will enter rate base during their construction period. At the end of 2010, our transmission rate base was approximately $2.8 billion, including approximately $2.1 billion at CL&P, $341 million at PSNH and $269 million at WMECO. We forecast that our total transmission rate base will grow to approximately $4.8 billion by the end of 2015, including approximately $830 million at NPT.
CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM
The principal focus of our construction and capital improvement program is maintaining, upgrading and expanding our existing electric generation, transmission and distribution systems and our natural gas distribution system. Our consolidated capital expenditures in 2010 totaled approximately $1 billion, almost all of which ($967 million) was expended by the Regulated companies. The capital expenditures of these companies in 2011 are estimated to total approximately $1.2 billion, $477 million by CL&P, $284 million by PSNH, $287 million by WMECO and $113 million by Yankee Gas. This capital budget includes anticipated costs for all committed capital projects (i.e., generation, transmission, distribution, environmental compliance and others) and those we expect to become committed projects in 2011.
In 2010, CL&P’s transmission capital expenditures totaled approximately $107 million, and its distribution capital expenditures totaled approximately $305 million. For 2011, CL&P projects transmission capital expenditures of approximately $137 million and distribution capital expenditures of approximately $337 million. During the period 2011 through 2015, CL&P plans to invest approximately $1 billion in transmission projects, the majority of which will be for NEEWS and $1.9 billon on distribution projects. If all of the distribution and transmission projects are built as proposed, CL&P’s rate base for electric transmission is projected to increase from approximately $2.1 billion at the end of 2010 to approximately $2.6 billion by the end of 2015, and its rate base for distribution assets is projected to increase from approximately $2.3 billion to approximately $3.3 billion over the same pe riod.
In 2010, PSNH's transmission capital expenditures totaled approximately $49 million, its distribution capital expenditures totaled approximately $84 million and its generation capital expenditures totaled $177 million. For 2011, PSNH projects transmission capital expenditures of approximately $59 million, distribution capital expenditures of approximately $113 million and generation capital expenditures of approximately $112 million. The bulk of the generation capital expenditures is for the Clean Air Project. During the period 2011 through 2015, PSNH plans to spend approximately $293 million on transmission projects, approximately $621 million on distribution projects, and $274 million on generation projects. If all of the distribution, generation and transmission projects are built as proposed, PSNH’s rate base for electric transmission is projected to increase from approximately $341 million at the en d of 2010 to approximately $540 million by the end of 2015, and its rate base for distribution and generation assets is projected to increase from approximately $1.2 billion to approximately $1.9 billion over the same period.
In 2010, WMECO's transmission capital expenditures totaled approximately $95 million, its distribution capital expenditures totaled approximately $33.1 million and solar generation expenditures were $10 million. In 2011, WMECO projects transmission capital expenditures of approximately $229 million, distribution capital expenditures of approximately $36 million and $22 million on solar generation. During the period 2011 through 2015, WMECO plans to spend approximately $732 million on transmission projects, with the bulk of that amount to be spent on GSRP, approximately $194 million on distribution projects and $46 million on solar generation. If all of the generation, distribution and transmission projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from approximately $269 million at the end of 2010 to approximately $803 million by the end of 2015 and its rate base fo r distribution and generation assets is projected to increase from approximately $423 million to approximately $488 million over the same period.
In 2010, Yankee Gas capital expenditures totaled approximately $95 million. For 2011, Yankee Gas projects total capital expenditures of approximately $113 million, approximately $30 million of which is expected to be related to the WWL project, $37 million related to basic business activities such as relocation of conflicting gas facilities and the purchase of meters, tools and information technology; $30 million related to reliability improvements; and $16 million for load growth and new business requests. During the period 2011 through 2015, Yankee Gas plans on making approximately $587 million of capital expenditures, including approximately $30 million on the WWL project. Future capital spending will likely be affected by price differences between the cost of natural gas with respect to home heating oil, natural gas supply, new home construction, road reconstruction, regulatory mandates and business requirements. &n bsp;Excluding non-recurring major projects, NU expects that approximately 28 percent of Yankee Gas’ capital expenditures over the 2011-2015 period to be related to basic business activities, approximately 28 percent related to load growth and new business, and approximately 39 percent related to reliability initiatives, with the balance related to the WWL project. If all of Yankee Gas projects are built as proposed, Yankee Gas’ investment in its regulated assets is projected to increase from approximately $682 million at the end of 2010 to approximately $969 million by the end of 2015.
FINANCING
NU subsidiaries issued a total of $145 million in long-term debt in 2010. On March 8, 2010, WMECO issued $95 million of senior unsecured notes due March 1, 2020 carrying a coupon rate of 5.1 percent and on April 22, 2010, Yankee Gas issued $50 million of first mortgage bonds through a private placement with a maturity date of April 1, 2020 carrying a coupon rate of 4.87 percent.
In addition, on April 1, 2010, CL&P completed the remarketing of $62 million of tax-exempt secured PCRBs. The PCRBs carry a coupon rate of 1.4 percent until April 1, 2011, at which time CL&P expects to remarket the bonds.
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On September 24, 2010, NU parent entered into a three-year $500 million unsecured revolving credit facility, and CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a three-year $400 million unsecured revolving credit facility, both replacing five-year credit facilities on similar terms and conditions that were scheduled to expire on November 6, 2010. Like the previous facility, NU’s new revolving credit facility allows NU parent to borrow on a short-term or long-term basis, or issue LOCs, up to $500 million in the aggregate. Under their new revolving credit facility, CL&P and PSNH are each able to draw up to $300 million, with WMECO and Yankee Gas each able to draw up to $200 million, all subject to the $400 million maximum aggregate borrowing limit.
Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH, WMECO and Yankee Gas, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent. All such companies currently are, and expect to remain in compliance with these covenants.
We have annual sinking fund requirements of $4.3 million continuing in 2011 through 2012, the mandatory tender of $62 million of tax-exempt PCRBs by CL&P on April 1, 2011, at which time CL&P expects to remarket the bonds in the ordinary course. Neither NU nor any of its subsidiaries have any debt maturities until April 1, 2012.
In light of the 2010 Tax Act and the related cash flow benefits, we are currently reevaluating the timing of our previously planned NU common equity issuance. If we complete the proposed merger with NSTAR, we would no longer need to undertake the previously planned $300 million NU common equity issuance in 2012 nor issue any additional equity in the foreseeable future.
NUCLEAR DECOMMISSIONING
General
CL&P, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. Each Yankee Company collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with CL&P, PSNH and WMECO and several other New England utilities. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates. The ownership percentages of CL&P, PSNH and WMECO in the Yankee Companies are set forth below:
|
| CL&P |
| PSNH |
| WMECO |
| Total |
CYAPC |
| 34.5% |
| 5.0% |
| 9.5% |
| 49.0% |
MYAPC |
| 12.0% |
| 5.0% |
| 3.0% |
| 20.0% |
YAEC |
| 24.5% |
| 7.0% |
| 7.0% |
| 38.5% |
Our share of the obligations to support the Yankee Companies under FERC-approved contracts is the same as the ownership percentages above.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
General
We are regulated in virtually all aspects of our business by various federal and state agencies, including the FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the DPUC, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over WMECO.
Environmental Regulation
We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, our major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies. PSNH owns approximately 1,200 MW of generation assets and expects to spend approximately $430 million on its Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack coal station to reduce its mercury and sulfur dioxide emissions. Compliance with additional environmental laws and regulations, particularly air and water pollution control requirements may cause changes in operations or require further investments in new equipment at existing facilities.
Water Quality Requirements
The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a NPDES permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of obtaining or renewing all required NPDES or state discharge permits in effect for our facilities. In each of the last three years, the costs incurred by the Company related to compliance with NPDES and state discharge permits have not been material. The Company expects to incur additional costs related to these permits in the future; however, due to uncertainty regarding the imposition of new or additional requirements, the Company is unable to accurately estimate such costs.
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Air Quality Requirements
The CAAA, as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included.
In New Hampshire, the Multiple Pollutant Reduction Program capped NOX, SO2and CO2 emissions beginning in 2007. In addition, a 2006 New Hampshire law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions of its coal fired plants by at least 80 percent (with the co-benefit of reductions in SO2 emissions as well). The Clean Air Project addresses this requirement. PSNH began site work for this project in November 2008 and is scheduled to complete it by mid-2012.
In addition, Connecticut, New Hampshire and Massachusetts are each members of the RGGI, a cooperative effort by ten northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from fossil fuel-fired electric generating plants. Because CO2 allowances issued by any participating state will be usable across all ten RGGI state programs, the individual state CO2 trading programs, in the aggregate, will form one regional compliance market for CO2 emissions. A regulated power plant must hold CO2 allowances equal to its emissions to demonstrate compliance at the end of a three-year compliance period that began in 2009.
Because neither CL&P nor WMECO currently own any generating assets (other than the solar facilities owned by WMECO, which do not emit CO2), neither is required to acquire CO2 allowances; however, the CO2allowance costs borne by generators that provide energy supply to CL&P and WMECO will likely be included in wholesale rates charged to them, which costs are then recoverable from customers.
PSNH anticipates that its generating units will emit between four million and five million tons of CO2 per year after taking into effect the operation of PSNH’s Northern Wood Power Project. Under the RGGI formula, this Project decreased PSNH’s responsibility for reducing fossil-fired CO2 emissions by approximately 425,000 tons per year, or almost ten percent. New Hampshire legislation provides up to 2.5 million banked CO2 allowances per year for PSNH’s fossil fueled generating plants during the 2009 through 2011 compliance period. These banked CO2 allowances will initially comprise approximately one-half of the yearly CO2 allowances required for PSNH’s generating plants to comply with RGGI. Such banked allowances will decrease over time. PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2 allowances at auction or in the secondary market. The cost of complying with RGGI requirements is recoverable from PSNH customers.
Each of the states in which we do business also has RPS requirements, which generally require fixed percentages of energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.
New Hampshire’s RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources, beginning in 2008 at four percent and ultimately reaching 23.8 percent by 2025. In 2010, the total RPS obligation was 7.5 percent of total generation supplied to customers. Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements. PSNH also owns renewable sources and uses both internally generated RECs and purchased RECs to meet its RPS obligations. To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient. The costs of both the RECs and alternative compliance payments do not impact earni ngs, as these costs are recovered by PSNH through its ES rates charged to customers.
Connecticut's RPS statute requires electricity suppliers to meet renewable energy standards, beginning with a four percent RPS in 2004. This percentage increases each year. For 2010, the requirement was 14 percent with goals of 19.5 percent by 2015 and 27 percent by 2020. CL&P is permitted to pass any costs incurred in complying with RPS on to customers through rates.
Massachusetts’ RPS program required electricity suppliers to meet a one percent renewable energy standard in 2003 and has a goal of 15 percent by 2015. For 2010, the requirement was five percent. WMECO is permitted to pass any costs incurred in complying with RPS on to customers through rates.
In addition, many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on emissions than are currently in effect.
Hazardous Materials Regulations
Prior to the last quarter of the 20th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities. Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. We have recorded a liability for what we believe is, based upon currently available information, our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability. We continue to evaluate the environmental impact of our for mer disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on us for these
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practices. At December 31, 2010, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $37.1 million, representing 58 sites. These costs could be significantly higher if remediation becomes necessary or when additional information as to the extent of contamination becomes available.
The most significant liabilities currently relate to future clean up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We, through our subsidiaries, currently have partial or full ownership responsibilities at 28 former MGP sites.
HWP, a wholly-owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal electric utility, in 1902. HWP is at least partially responsible for this site and has already conducted substantial investigative and remediation activities. HWP's share of the remediation costs related to this site is not recoverable from customers.
Electric and Magnetic Fields
For more than twenty years, published reports have discussed the possibility of adverse health effects from EMF associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.
We have closely monitored research and government policy developments for many years and will continue to do so. In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.
Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government, particularly in recent years. The EPA has initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" and endanger public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated GHG emission reporting beginning in 2012 for 2011 emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF-6 gas and methane.
We are continually evaluating the risks presented by climate change concerns and issues. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations. (See "Air Quality Requirements" in this section for information concerning RGGI) These could include federal "cap and trade" laws, or regulations requiring additional capital expenditures at our generating facilities. In addition, such rules or regulations could potentially impact the prices we pay for goods and services provided by companies directly affected by such rules or regulations. We would expect that any costs of these rules and regulations would be recovered from customers, but such costs could impact energy use by our customers.
Global climate change could potentially impact weather patterns such as increasing the frequency and severity of storms or altering temperatures. These changes could affect our facilities and infrastructure and could also impact energy usage by our customers.
FERC Hydroelectric Project Licensing
Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
PSNH owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047. PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.
Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision that expressly permits the FERC to order decommissioning during the license term. However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing. The FERC may also require project
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decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked. PSNH is not presently encountering any of these challenges.
EMPLOYEES
As of December 31, 2010, we employed a total of 6,182 employees, excluding temporary employees, of which 1,847 were employed by CL&P, 1,240 by PSNH, 354 by WMECO, 429 by Yankee Gas and 2,307 were employed by NUSCO. Approximately 2,212 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are members of the International Brotherhood of Electrical Workers and The United Steelworkers and are covered by 11 union agreements.
INTERNET INFORMATION
Our website address is www.nu.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site NU's, CL&P's, WMECO's and PSNH's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 56 Prospect Street, Hartford, CT 06103.
Item 1A.
Risk Factors
In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included directly prior to Item 1,Business, above, we are subject to a variety of significant risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.
The actions of regulators can significantly affect our earnings, liquidity and business activities.
The rates that our Regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC. These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters. FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters. The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.
Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.
Our ability to properly operate of our transmission, distribution and generation systems is critical to the financial performance of our business. Our transmission, distribution and generation businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age); labor disputes; disruptions in the delivery of electricity, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored; catastrophic events such as fires, explosions, or other similar occurrences; and other unanticipated operations and maintenance expenses and liabilities. The failure of our transmission, distributions and generation systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in operation and maintenance costs. At PSNH, outages at generating stations may be deemed imprudent by state regulators resulting in disallowance of replacement power costs. Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.
Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.
We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations. A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.
Our counterparties may not meet their obligations to us.
We are exposed to the risk that counterparties to various arrangements who owe us money, or have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.
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Changes in regulatory or legislative policy and/or regulatory decisions, difficulties in obtaining siting, design or other approvals, global demand for critical resources, environmental or other concerns, or construction of new generation may delay completion of or displace our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected rates of return.
Our transmission construction plans could be affected by new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations or regulatory decisions, delays in obtaining approvals or difficulty in obtaining critical resources required for construction. Any of such events could cause delays in our construction schedule adversely affecting our ability to achieve forecasted earnings.
The regulatory approval process for our transmission projects requires extensive permitting, design and technical activities. Various factors could result in increased costs and delay construction schedules. These include environmental and community concerns and design and siting issues. Recoverability of all such investments in rates may be subject to prudence review at the FERC. While we believe that all such costs have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.
In addition, our transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.
Many of our transmission projects are expected to help alleviate identified reliability issues and reduce customers' costs. However, if, due to further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, which could have an adverse effect on our earnings.
The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.
Increases in electric and gas prices and/or a weak economy, can lead to changes in legislative and regulatory policy promoting energy efficiency, conservation, and self-generation and/or a reduction in our customers’ ability to pay their bills, which may adversely impact our business.
Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.
In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.
Connecticut, New Hampshire and Massachusetts have each investigated revenue decoupling as a mechanism to align the interests of customers and utilities relative to conservation. In Connecticut, the DPUC authorized decoupling through a rate design that is intended to recover greater distribution revenue through fixed charges, and proportionately less distribution revenue through usage-based charges. In New Hampshire, the NHPUC conducted a decoupling docket and determined that utilities were free to propose decoupling in the context of a rate case and demonstrate the effect decoupling would have on its risk profile and ROE. PSNH has not yet commenced such a proceeding. In Massachusetts, the DPU has required WMECO to adopt full decoupling in its January 31, 2011 rate decision. At this time it is uncertain what impact these decoupling mechanisms will have on our companies.
As a way to promote self-generation and reduce energy costs, Connecticut, Massachusetts, and New Hampshire have taken a greater interest in allowing customers to receive credit for generation produced at a customer-owned generating facility that exceeds their energy needs. In Massachusetts, in accordance with the Green Communities Act, the DPU adopted rules and regulations concerning net metering that will have this effect. Such rules provide a cost recovery mechanism for affected utilities to recover lost revenues. The Massachusetts DPU is expected to hold further proceedings to address net metering in early 2011. In Connecticut, the DPUC opened a docket to review existing state statutes and determine what limitations currently exist in state law concerning net metering. In addition, any legislation in Connecticut to promote self-generation and net metering could impact CL&P’s financial position, results of operations or cash flows. In New Hampshire, new legislation dramatically changed the net metering rules in 2010. This new legislation is meant to encourage net metering from customers with small generators and also provides PSNH a cost recovery mechanism for lost distribution revenue.
Changes in regulatory and/or legislative policy could negatively impact regional transmission cost allocation rules.
The existing FERC-approved New England transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities. As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New England in accordance with relative benefits received. This regional cost allocation is set forth in the Transmission Operating Agreement signed by all of the New England transmission owning utilities. Effective February 1, 2010, this agreement can be modified with the approval of a majority of the transmission owning utilities and FERC. In addition, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the
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rates our distribution companies charge their retail customers. FERC is also considering policies to encourage the construction of transmission for renewable generation that could have the effect of imposing costs of inter-regional investment on New England customers.
Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution and generation businesses.
Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval. There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets. Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows. Additionally, state legislators may enact laws that significantly impact our Regulated companies’ revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy. Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.
In addition, CL&P and WMECO procure energy for a substantial portion of their customers’ needs via requests for proposal on an annual, semi-annual or quarterly basis. CL&P and WMECO receive approval to recover the costs of these contracts from the DPUC and DPU, respectively. While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.
PSNH meets most of its energy requirements through its own generation resources and fixed-price forward purchase contracts. PSNH’s remaining energy needs are met primarily through spot market purchases. Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the energy to meet its requirements. PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC. We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.
Migration of customers from PSNH energy service to competitive energy suppliers could increase the cost to the remaining customers of energy produced by PSNH generation assets and decrease our revenues.
PSNH’s ES rates have been higher than competitive energy prices offered to some customers in recent years, primarily due to lower natural gas prices. As a result, by the end of 2010, approximately 2 percent of PSNH’s retail customers (representing approximately 32 percent of load), mostly large commercial and industrial customers, were buying their energy from competitive suppliers rather than from PSNH. The remaining retail customers are experiencing an increase in the cost of energy service supplied by PSNH by 5 percent to 7 percent due to migration of large commercial and industrial customers and the lower base in which to recover PSNH's fixed generation costs. This increase may in turn cause further migration and further increasing of PSNH energy service rates. This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation faciliti es on remaining customers and being unable to support the cost of its generation facilities through an ES rate.
The NHPUC is examining this issue in a proceeding in which hearings ended on December 1, 2010. PSNH has suggested transferring some fixed costs of the generation facilities into a nonbypassable charge while intervening competitive suppliers have proposed taking over the purchased power portion of the load not supplied by PSNH’s generation. Others have also proposed having PSNH bid all of its generation facilities into the market while an RFP process supplies all of the power for PSNH’s energy service. The NHPUC is considering further proceedings to explore these and other issues as well as the NHPUC authority to require PSNH to divest its generation facilities. It is not known what the results of such a proceeding would be, what PSNH may realize as a result of the sale or retirement of one or more of its generation facilities, or to what extent or manner the NHPUC would provide for recovery of any invest ment in its generation facilities.
Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize completion of, or full recovery of costs incurred by PSNH in constructing, the Clean Air Project.
Pursuant to New Hampshire law, PSNH is building the Clean Air Project at its Merrimack Station in Bow, New Hampshire. Several parties initiated legal proceedings challenging the project. These proceedings, or new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could result in increased costs to the project.
In addition, PSNH’s investment in the project after it is completed is subject to prudence review by the NHPUC at the time the project is placed in service. A material prudence disallowance could adversely affect PSNH’s financial position, results of operations or cash flows. While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudency reviews should they occur. Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.
The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial condition and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our
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management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.
Grid disturbances, severe weather, or acts of war or terrorism could negatively impact our business.
Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business continuity due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage, solar storm activity or terrorist action) on an interconnected system or the actions of another utility. In addition, we are subject to the risk that acts of war or terrorism, including cyber-terrorism could negatively impact the operation of our system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition, results of operations or cash flows.
Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as customers demand better and quicker response times to outages. The effect of the failure of our facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.
Market performance or changes in assumptions could require us to make significant contributions to our pension and other post-employment benefit plans.
We provide a defined benefit pension plan and other post-retirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control. These factors include estimated investment returns, interest rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs could increase significantly. In 2008 and 2009, due to the financial crisis, the value of our pension assets declined. As a result, we made a contribution of $45 million in 2010 and expect to make an approximate $145 million contribution in 2011. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund o ur pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and negatively affect our financial position, results of operations or cash flows.
Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.
Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.
In addition, global climate change issues have received an increased focus from federal and state governments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations. Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time. The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.
Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates. The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1,Business - "Other Regulatory and Environmental Matters," in this Annual Report on Form 10-K.
As a holding company with no revenue-generating operations, NU parent is dependent on dividends from its subsidiaries, primarily the Regulated companies, its bank facility, and its ability to access the long-term debt and equity capital markets.
NU parent is a holding company and as such, has no revenue-generating operations of its own. Its ability to meet its financial obligations associated with the debt service obligations on its debt and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or to repay borrowings from NU parent; and/or NU parent’s ability to access its credit
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facility or the long-term debt and equity capital markets. Prior to funding NU parent, the Regulated companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P) and obligations to trade creditors. Additionally, the Regulated companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NU parent. Should the Regulated companies not be able to pay dividends to or repay funds due to NU parent or if NU parent cannot access its bank facilities or the long-term debt and equity capital markets, NU parent’s ability to pay interest, dividends and its own debt obligations would be restricted.
Risks Related to the Proposed Merger with NSTAR
We may be unable to satisfy the conditions or obtain the approvals required to complete the merger or such approvals may contain material restrictions or conditions.
The merger is subject to approval by the shareholders of both NU and NSTAR and numerous other conditions, including the approval of various government agencies. Governmental agencies may not approve the merger or such approvals may impose conditions on the completion, or require changes to the terms of the merger, including restrictions on the business, operations or financial performance of the combined company, which could be adverse to the company's interests. These conditions or changes could also delay or increase the cost of the merger or limit the net income or financial prospects of the combined company.
We will be subject to business uncertainties and contractual restrictions while the merger is pending.
The work required to complete the merger may place a significant burden on management and internal resources. Management's attention and other company resources may be focused on the merger instead of on day-to-day management activities, including pursuing other opportunities beneficial to NU. In addition, while the merger is pending our business operations are restricted by the Agreement and Plan of merger to ordinary course of business activities consistent with past practice, which may cause us to forgo otherwise beneficial business opportunities.
We may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.
Uncertainties about the effect of the merger on management personnel and employees may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, which could affect our financial performance.
The merger may not be completed, which may have an adverse effect on our share price and future business and financial results and we could face litigation concerning the merger, whether or not the merger is consummated.
Failure to complete the merger could negatively affect NU's share price, as well as our future business and financial results. In addition, purported class actions have been brought against us, NSTAR and others on behalf of holders of NSTAR common shares. If these actions or similar actions that may be brought are successful, the costs of completing the merger could increase, or the merger could be delayed or prevented. We cannot make any assurances that we will succeed in any litigation brought in connection with the merger. See Item 3,Legal Proceedings, in this Annual Report on Form 10-K for discussion of pending litigation related to the merger.
If the merger is not completed for certain reasons specified in the merger agreement, we may be required to pay NSTAR a termination fee of $135 million plus up to $35 million of certain expenses incurred by NSTAR. In addition, we must pay our own costs related to the merger including, among others, legal, accounting, advisory, financing and filing fees and printing costs, whether the merger is completed or not. Further, if the merger is not completed, we could be subject to litigation related to the failure to complete the merger or other factors, which may adversely affect our business, financial results and share price.
If completed, the merger may not achieve its intended results.
We entered into the merger agreement with the expectation that the merger would result in various benefits. If the merger is completed, our ability to achieve the anticipated benefits will be subject to a number of uncertainties, including whether our businesses can be integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.
Item 1B.
Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
18
Item 2.
Properties
Transmission and Distribution System
As of December 31, 2010, our electric operating subsidiaries owned 31 transmission and 422 distribution substations that had an aggregate transformer capacity of 5,302,000 kilovolt amperes (kVa) and 29,861,000 kVa, respectively; 3,094 circuit miles of overhead transmission lines ranging from 69 KV to 345 KV, and 433 cable miles of underground transmission lines ranging from 69 KV to 345 KV; 34,957 pole miles of overhead and 3,054 conduit bank miles of underground distribution lines; and 539,379 underground and overhead line transformers in service with an aggregate capacity of 37,703,193 kVa.
Electric Generating Plants
As of December 31, 2010, PSNH owned the following electric generating plants:
Type of Plant |
|
| Number |
| Year |
| Claimed |
|
|
|
|
|
|
| |
Total - Fossil-Steam Plants |
| 5 units |
| 1952-74 |
| 947,980 | |
Total - Hydro-Conventional |
| 20 units |
| 1901-83 |
| 71,105 | |
Total - Internal Combustion |
| 5 units |
| 1968-70 |
| 102,959 | |
Total - Biomass - Steam Plant |
| 1 unit |
| 1954 |
| 45,816 | |
|
|
|
|
|
|
| |
Total PSNH Generating Plant |
| 31 units |
|
|
| 1,167,860 |
*
Claimed capability represents winter ratings as of December 31, 2010. The combined nameplate capacity of the generating plants is approximately 1,200 MW.
As of December 31, 2010, WMECO owned the following electric generating plant:
Type of Plant |
|
| Number |
| Year |
| Claimed |
|
|
|
|
|
|
| |
Total - Solar Fixed Tilt, Photovoltaic |
| 1 unit |
| 2010 |
| 1,800,000 |
** Claimed capability represents the direct current nameplate capacity of the plant.
CL&P did not own any electric generating plants during 2010.
Yankee Gas
As of December 31, 2010, Yankee Gas owned 28 active gate stations, approximately 200 district regulator stations and 3,239 miles of natural gas main pipeline. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, a propane facility in Kensington, Connecticut, and three additional propane facilities that are no longer in service and are expected to be sold in 2011.
Franchises
CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distributi on company from owning or operating generation assets. However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and Locational Installed Capacity (LICAP) costs. In addition, Section 83 of Public Act 07-242, "An Act Concerning Electricity and Energy Efficiency," states that if an existing electric generating plant located in Connecticut is offered for sale, then an electric distribution company, such as CL&P, would be eligible to purchase the generation plant upon obtaining prior approval from the DPUC and a determination by the DPUC that such purchase is in the public interest.
19
PSNH. The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The distribution and transmission franchises of PSNH include the power of eminent domain.
WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways. Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.
The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including WMECO. The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.
Yankee Gas. Yankee Gas holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service, which it acquired either directly or from its predecessors in interest. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility. Yankee Gas’ franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas’ franchises include, among other rights and powers, the right and power to manuf acture, generate, purchase, transmit and distribute gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.
Item 3.
Part II
Item 5.
Market for Thethe Registrants' Common Equity and Related Stockholder Matters
23
NU. Our common shares are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low closing sales prices for the past two years, by quarters, are shown below.
Year |
| Quarter |
| High |
| Low | ||
|
|
|
|
|
|
|
|
|
2008 |
| First |
| $ | 31.15 |
| $ | 24.01 |
|
| Second |
|
| 27.74 |
|
| 25.12 |
|
| Third |
|
| 28.03 |
|
| 24.52 |
|
| Fourth |
|
| 25.97 |
|
| 19.15 |
|
|
|
|
|
|
|
|
|
2007 |
| First |
| $ | 32.77 |
| $ | 27.40 |
|
| Second |
|
| 33.53 |
|
| 27.37 |
|
| Third |
|
| 29.42 |
|
| 26.93 |
|
| Fourth |
|
| 32.83 |
|
| 27.98 |
There were no purchases made by or on behalf of our company or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2008.
As of January 31, 2009, there were 44,042 common shareholders of our company on record. As of the same date, there were a total of 176,230,893 common shares issued, including 643,860 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.
Pursuant to NU parent's Shareholder Rights Plan (the "Plan"), NU parent distributed to shareholders of record as of May 7, 1999, a dividend in the form of one common share purchase right (a "Right") for each common share owned by the shareholder. The Rights and the Plan expired at the end of the 10-year term on February 23, 2009. NU parent's Board of Trustees adopted the Plan in 1999 to protect its shareholders in the event of an unsolicited bid to acquire the company. If triggered, it would have allowed shareholders other than the acquiror to purchase a specified number of additional shares at a 50 percent discount from the then current market price, thus encouraging the acquiror to negotiate a fair price for NU common shares with the Board. NU parent’s Board of Trustees felt that renewal of the Plan was unnecessary at this time to protect shareholders' rights and accordingly decided to allow it to expire. The Board has the ability in its discretion to adopt a similar plan in the future but has no present intention of doing so.
On February 10, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on March 31, 2009, to shareholders of record as of March 1, 2009.
On October 14, 2008, our Board of Trustees declared a dividend of 21.25 cents per share, payable on December 31, 2008, to shareholders of record as of December 1, 2008.
25
On May 12, 2008, our Board of Trustees declared a dividend of 21.25 cents per share, payable on September 30, 2008, to shareholders of record as of September 1, 2008.
On April 8, 2008, our Board of Trustees declared a dividend of 20 cents per share, payable on June 30, 2008, to shareholders of record as of June 1, 2008.
On February 12, 2008, our Board of Trustees declared a dividend of 20 cents per share, payable on March 31, 2008, to shareholders of record as of March 1, 2008.
On November 13, 2007, our Board of Trustees declared a dividend of 20 cents per share, payable on December 31, 2007, to shareholders of record as of December 1, 2007.
On May 7, 2007, our Board of Trustees declared a dividend of 20 cents per share, payable on September 28, 2007, to shareholders of record as of September 1, 2007.
On April 10, 2007, our Board of Trustees declared a dividend of 18.75 cents per share, payable on June 29, 2007, to shareholders of record as of June 1, 2007.
On February 13, 2007, our Board of Trustees declared a dividend of 18.75 cents per share, payable on March 31, 2007, to shareholders of record as of March 1, 2007.
Information with respect to dividend restrictions for us, CL&P, PSNH, and WMECO is contained in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" under the caption "Liquidity" and in the "Combined Notes to Consolidated Financial Statements," within this Annual Report on Form 10-K.
There is no established public trading market for the common stock of CL&P, PSNH and WMECO. All of the common stock of CL&P, PSNH and WMECO is held solely by NU.
During 2008 and 2007, CL&P approved and paid $106.5 million and $79.2 million, respectively, of common stock dividends to NU.
During 2008 and 2007, PSNH approved and paid $36.4 million and $30.7 million, respectively, of common stock dividends to NU.
During 2008 and 2007, WMECO approved and paid $39.7 million and $12.8 million, respectively, of common stock dividends to NU.
For information regarding securities authorized for issuance under equity compensation plans, see Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters," included in this Annual Report on Form 10-K.
26
Item 6.
Selected Financial Data
NU Selected Consolidated Financial Data (Unaudited)
24
(Thousands of Dollars, except percentages and share information) |
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| |||||
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| $ | 8,207,876 |
| $ | 7,229,945 |
| $ | 6,242,186 |
| $ | 6,417,230 |
| $ | 5,864,161 |
|
Total Assets |
|
| 13,988,480 |
|
| 11,581,822 |
|
| 11,303,236 |
|
| 12,567,875 |
|
| 11,638,396 |
|
Total Capitalization (a) |
|
| 7,293,960 |
|
| 6,667,920 |
|
| 5,879,691 |
|
| 5,595,405 |
|
| 5,293,644 |
|
Obligations Under Capital Leases (a) |
|
| 13,397 |
|
| 14,743 |
|
| 14,425 |
|
| 13,987 |
|
| 14,806 |
|
Income Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
| $ | 5,800,095 |
| $ | 5,822,226 |
| $ | 6,877,687 |
| $ | 7,346,226 |
| $ | 6,480,684 |
|
Income/(Loss) from Continuing Operations |
|
| 260,828 |
|
| 245,896 |
|
| 132,936 |
|
| (256,903) |
|
| 70,423 |
|
Income from Discontinued Operations |
|
| - |
|
| 587 |
|
| 337,642 |
|
| 4,420 |
|
| 46,165 |
|
Income/(Loss) Before Cumulative Effects of Accounting |
|
|
|
|
|
|
|
|
|
|
| (252,483) |
|
| 116,588 |
|
Cumulative Effects of Accounting Changes, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) |
| $ | 260,828 |
| $ | 246,483 |
| $ | 470,578 |
| $ | (253,488) |
| $ | 116,588 |
|
Common Share Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings/(Loss) Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) from Continuing Operations |
| $ | 1.68 |
| $ | 1.59 |
| $ | 0.86 |
| $ | (1.95) |
| $ | 0.55 |
|
Income from Discontinued Operations |
|
| - |
|
| - |
|
| 2.20 |
|
| 0.03 |
|
| 0.36 |
|
Cumulative Effects of Accounting Changes, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) |
| $ | 1.68 |
| $ | 1.59 |
| $ | 3.06 |
| $ | (1.93) |
| $ | 0.91 |
|
Fully Diluted Earnings/(Loss) Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) from Continuing Operations |
| $ | 1.67 |
| $ | 1.59 |
| $ | 0.86 |
| $ | (1.95) |
| $ | 0.55 |
|
Income from Discontinued Operations |
|
| - |
|
| - |
|
| 2.19 |
|
| 0.03 |
|
| 0.36 |
|
Cumulative Effects of Accounting Changes, Net of Tax Benefits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) |
| $ | 1.67 |
| $ | 1.59 |
| $ | 3.05 |
| $ | (1.93) |
| $ | 0.91 |
|
Basic Common Shares Outstanding (Average) |
|
| 155,531,846 |
|
| 154,759,727 |
|
| 153,767,527 |
|
| 131,638,953 |
|
| 128,245,860 |
|
Fully Diluted Common Shares Outstanding (Average) |
|
| 155,999,240 |
|
| 155,304,361 |
|
| 154,146,669 |
|
| 131,638,953 |
|
| 128,396,076 |
|
Dividends Per Share |
| $ | 0.83 |
| $ | 0.78 |
| $ | 0.73 |
| $ | 0.68 |
| $ | 0.63 |
|
Market Price - Closing (high) (b) |
| $ | 31.15 |
| $ | 33.53 |
| $ | 28.81 |
| $ | 21.79 |
| $ | 20.10 |
|
Market Price - Closing (low) (b) |
| $ | 19.15 |
| $ | 26.93 |
| $ | 19.24 |
| $ | 17.61 |
| $ | 17.30 |
|
Market Price - Closing (end of year) (b) |
| $ | 24.06 |
| $ | 31.31 |
| $ | 28.16 |
| $ | 19.69 |
| $ | 18.85 |
|
Book Value Per Share (end of year) |
| $ | 19.38 |
| $ | 18.79 |
| $ | 18.14 |
| $ | 15.85 |
| $ | 17.80 |
|
Tangible Book Value Per Share (end of year) |
| $ | 17.54 |
| $ | 16.93 |
| $ | 16.28 |
| $ | 13.98 |
| $ | 15.17 |
|
Rate of Return Earned on Average Common Equity (%) |
|
| 8.8 |
|
| 8.6 |
|
| 18.0 |
|
| (10.7) |
|
| 5.1 |
|
Market-to-Book Ratio (end of year) |
|
| 1.2 |
|
| 1.7 |
|
| 1.6 |
|
| 1.2 |
|
| 1.1 |
|
Capitalization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Shareholders’ Equity |
|
| 41 | % |
| 44 | % |
| 48 | % |
| 43 | % |
| 44 | % |
Preferred Stock |
|
| 2 |
|
| 2 |
|
| 2 |
|
| 2 |
|
| 2 |
|
Long-Term Debt (a) |
|
| 57 |
|
| 54 |
|
| 50 |
|
| 55 |
|
| 54 |
|
|
|
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
(a)
Includes portions due within one year, but excludes RRBs.
(b)
Market price information reflects closing prices as reflected by the New York Stock Exchange.
27
CL&P Selected Consolidated Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
|
|
| |||||
(Thousands of Dollars) |
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| |||||
Operating Revenues |
| $ | 3,558,361 |
| $ | 3,681,817 |
| $ | 3,979,811 |
| $ | 3,466,420 |
| $ | 2,832,924 |
|
Net Income |
|
| 191,158 |
|
| 133,564 |
|
| 200,007 |
|
| 94,845 |
|
| 88,016 |
|
Cash Dividends on Common Stock |
|
| 106,461 |
|
| 79,181 |
|
| 63,732 |
|
| 53,834 |
|
| 47,074 |
|
Property, Plant and Equipment, net |
|
| 5,089,124 |
|
| 4,401,846 |
|
| 3,634,370 |
|
| 3,166,692 |
|
| 2,824,877 |
|
Total Assets |
|
| 8,336,118 |
|
| 7,018,099 |
|
| 6,321,294 |
|
| 5,765,072 |
|
| 5,306,913 |
|
Rate Reduction Bonds |
|
| 378,195 |
|
| 548,686 |
|
| 743,899 |
|
| 856,479 |
|
| 995,233 |
|
Long-Term Debt (a) |
|
| 2,270,414 |
|
| 2,028,546 |
|
| 1,519,440 |
|
| 1,258,883 |
|
| 1,052,891 |
|
Preferred Stock - Non-Redeemable |
|
| 116,200 |
|
| 116,200 |
|
| 116,200 |
|
| 116,200 |
|
| 116,200 |
|
Obligations Under Capital Leases (a) |
|
| 11,207 |
|
| 13,602 |
|
| 14,264 |
|
| 13,488 |
|
| 14,093 |
|
PSNH Selected Consolidated Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
|
|
| |||||
(Thousands of Dollars) |
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| |||||
Operating Revenues |
| $ | 1,141,202 |
| $ | 1,083,072 |
| $ | 1,140,900 |
| $ | 1,128,427 |
| $ | 968,749 |
|
Net Income |
|
| 58,067 |
|
| 54,434 |
|
| 35,323 |
|
| 41,739 |
|
| 46,641 |
|
Cash Dividends on Common Stock |
|
| 36,376 |
|
| 30,720 |
|
| 41,741 |
|
| 42,383 |
|
| 27,186 |
|
Property, Plant and Equipment, net |
|
| 1,580,985 |
|
| 1,388,405 |
|
| 1,242,378 |
|
| 1,155,423 |
|
| 1,031,703 |
|
Total Assets |
|
| 2,628,833 |
|
| 2,106,969 |
|
| 2,071,276 |
|
| 2,294,583 |
|
| 2,205,374 |
|
Rate Reduction Bonds |
|
| 235,139 |
|
| 282,018 |
|
| 333,831 |
|
| 382,692 |
|
| 428,769 |
|
Long-Term Debt (a) |
|
| 686,779 |
|
| 576,997 |
|
| 507,099 |
|
| 507,086 |
|
| 457,190 |
|
Obligations Under Capital Leases (a) |
|
| 1,931 |
|
| 1,141 |
|
| 1,356 |
|
| 498 |
|
| 712 |
|
WMECO Selected Consolidated Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
|
|
| |||||
(Thousands of Dollars) |
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| |||||
Operating Revenues |
| $ | 441,527 |
| $ | 464,745 |
| $ | 431,509 |
| $ | 409,393 |
| $ | 379,229 |
|
Net Income |
|
| 18,330 |
|
| 23,604 |
|
| 15,644 |
|
| 15,085 |
|
| 12,373 |
|
Cash Dividends on Common Stock |
|
| 39,706 |
|
| 12,779 |
|
| 7,946 |
|
| 7,685 |
|
| 6,485 |
|
Property, Plant and Equipment |
|
| 624,205 |
|
| 559,357 |
|
| 526,094 |
|
| 499,317 |
|
| 468,884 |
|
Total Assets |
|
| 1,048,489 |
|
| 991,088 |
|
| 988,693 |
|
| 945,996 |
|
| 922,472 |
|
Rate Reduction Bonds |
|
| 73,176 |
|
| 86,731 |
|
| 99,428 |
|
| 111,331 |
|
| 122,489 |
|
Long-Term Debt (a) |
|
| 303,868 |
|
| 303,872 |
|
| 261,777 |
|
| 259,487 |
|
| 207,684 |
|
(a)
Includes portions due within one year, but excludes RRBs.
28
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
26
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
70
Item 8.
Financial Statements and Supplementary Data
72
Item 8A.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
160
Item 8B.
Controls and Procedures
160
Item 9.
Other Information
160
Part III
Item 10.
Directors, Executive Officers and Corporate Governance
161
Item 11.
Executive Compensation
162
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
195
Item 13.
Certain Relationships and Related Transactions, and Director Independence
197
Item 14.
Principal Accountant Fees and Services
197
Part IV
Item 15.
Exhibits and Financial Statement Schedules
199
Signatures
200
iv
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
References in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.
From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections ma y vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
·
actions or inaction by local, state and federal regulatory bodies
·
changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services
·
changes in weather patterns
·
changes in laws, regulations or regulatory policy
·
changes in levels and timing of capital expenditures
·
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly
·
developments in legal or public policy doctrines
·
technological developments
·
changes in accounting standards and financial reporting regulations
·
fluctuations in the value of our remaining competitive contracts
·
actions of rating agencies
·
The expected timing and likelihood of completion of the proposed merger with NSTAR, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, as well as the ability to successfully integrate the businesses, and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect and
·
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. Th is Annual Report on Form 10-K also describes material contingencies and critical accounting policies and estimates in the accompanyingManagement’s Discussion and Analysis andCombined Notes to Consolidated Financial Statements. We encourage you to review these items.
1
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
PART I
Item 1.
Business
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.
PROPOSED MERGER WITH NSTAR
On October 18, 2010, we and NSTAR announced that each company’s Board of Trustees unanimously approved a Merger Agreement (the merger agreement) to combine the two companies. The transaction was structured as a merger of equals in a tax-free exchange. Upon the terms and subject to the conditions set forth in the merger agreement, at closing, NSTAR will become a wholly-owned subsidiary of NU. The post-transaction company will provide electric and natural gas energy delivery service to nearly 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire, representing over half of all the customers in New England.
Under the terms of the merger agreement, NSTAR shareholders would receive 1.312 NU common shares for each common share of NSTAR that they own (the "exchange ratio"). The exchange ratio was structured to result in a no premium merger and is based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement. Following completion of the merger, common shares of the post-transaction company will be owned approximately 56 percent by NU shareholders and approximately 44 percent by former NSTAR shareholders. We anticipate that we will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger. Following the closing of the merger, our next quarterly dividend per common share will be increased to an amount that is equivalent to NSTAR’s last quarterly dividend per common share paid prior to the closing, divided by the exchange ratio. Based on the last quarterly dividend paid by NSTAR of $0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, that would result in NU’s quarterly dividend being increased by approximately 18 percent to approximately $0.325 per share, or approximately $1.30 per share on an annualized basis as compared to NU's current annualized dividend of $1.10 per share. NU filed its joint proxy statement/prospectus with the SEC on January 5, 2011 and scheduled a special meeting of shareholders for March 4, 2011, at which shareholders will vote on whether to approve the merger.
Completion of the merger is subject to various customary conditions, including approval by holders of two-thirds of the outstanding common shares of each company and receipt of all required regulatory approvals, including those of the Massachusetts DPU, the FERC and the NRC. We received approval from the FCC on January 4, 2011, and on February 10, 2011, the applicable Hart-Scott-Rodino waiting period expired. Several intervening parties have applied to participate in the regulatory review of the merger and have raised various issues that they believe the regulatory agencies should examine in the course of the proceedings.
In November 2010, the DPUC issued a draft decision stating it lacked jurisdiction over the merger. In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC to reconsider its draft decision. In January 2011, the DPUC issued an Administrative Order stating that it plans to hold a hearing to determine if it has jurisdiction over the merger. Oral arguments surrounding the draft decision were held in February 2011. The DPUC plans to hold an informational hearing at a date to be determined. In addition, legislation proposing to give the DPUC jurisdiction over the merger may be introduced in the Connecticut legislature.
THE COMPANY
NU, headquartered in Hartford, Connecticut, is a public utility holding company subject to regulation by FERC under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly-owned utility subsidiaries:
●
The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;
●
Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and continues to own generation assets used to serve customers;
●
Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts; and
●
Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.
NU also owns certain unregulated businesses through its wholly-owned subsidiary, NU Enterprises. As of December 31, 2010, NU Enterprises’ business consisted of (i) Select Energy’s few remaining energy wholesale marketing contracts, which are being wound down, and (ii) NU Enterprises’ electrical contracting business.
2
Although NU, CL&P, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line-of-business, basis - the distribution segment (which also includes the generation businesses of PSNH and WMECO and our natural gas distribution business) and the transmission segment. Our Regulated companies accounted for approximately 99 percent of our total earnings of $387.9 million for 2010, with electric distribution representing approximately 45 percent, natural gas distribution representing approximately 8 percent and electric transmission representing approximately 46 percent of consolidated earnings. The remaining 1 percent of our 2010 earnings comes from our competitive businesses.
REGULATED ELECTRIC DISTRIBUTION
General
NU’s electric distribution segment consists of the distribution businesses of CL&P, PSNH and WMECO, which are primarily engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts, respectively, plus PSNH’s regulated electric generation business and WMECO’s solar generation. The following table shows the sources of 2010 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:
| Sources of | % of Total | |
Residential | 59% | ||
Commercial | 33% | ||
Industrial | 7% | ||
Other | 1% | ||
Total | 100% |
A summary of changes in the Regulated companies’ retail electric sales (GWh) for 2010 as compared to 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:
|
| 2010 |
| 2009 |
| Percentage |
| Weather |
Residential |
| 14,913 |
| 14,412 |
| 3.5% |
| (0.7)% |
Commercial |
| 14,506 |
| 14,474 |
| 0.2% |
| (2.8)% |
Industrial |
| 4,481 |
| 4,423 |
| 1.3% |
| (1.5)% |
Other |
| 330 |
| 336 |
| (1.4)% |
| (1.4)% |
Total |
| 34,230 |
| 33,645 |
| 1.7% |
| (1.7)% |
Total retail electric sales for all three electric companies were higher in 2010 compared to 2009 due primarily to warmer than normal weather in the summer of 2010 and colder than normal weather in December 2010. Residential sales benefitted the most from the weather in 2010 and were higher for all three electric companies in 2010 compared to 2009.
On a weather normalized basis, retail sales for all three electric companies were lower in 2010 compared to 2009. We believe the decrease was due in part to increased conservation efforts by our customers and the continuing effects of the weak economy.
THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION
CL&P’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2010, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut. CL&P does not own any electric generation facilities. In 2010, CL&P had contracts to purchase the electric output from eighteen IPP generators. The term of two of these contracts ended in 2010. In 2011 the sixteen remaining generators are anticipated to provide approximately two million MWh per year through March 2015, with purchase quantities dropping significantly from 2015 through 2024, when the term of the last IPP contract ends. CL&P sells the output of these contracts into the ISO New England market, crediting customer energy charges with the proceeds. CL& ;P has entered into eleven contracts with renewable energy generators under a state program known as Project 150, and UI has entered into 2 other similar contracts under Project 150. CL&P and UI will share the costs and benefits of these contracts on an 80 percent and 20 percent basis, respectively. This cost sharing split is independent of the specific utility that is the counterparty to the contract. It is currently projected that the first of these renewable energy projects will commence commercial operation in 2011.
3
The following table shows the sources of 2010 electric franchise retail revenues for CL&P based on categories of customers:
| Sources of | % of | |
Residential | 61% | ||
Commercial | 32% | ||
Industrial | 6% | ||
Other | 1% | ||
Total | 100% |
Rates
CL&P is subject to regulation by the Connecticut DPUC, which, among other things, has jurisdiction over its rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers.
The CTA is a charge assessed to recover stranded costs associated with electric industry restructuring as well as various IPP contracts. The SBC recovers costs associated with various hardship and low income programs as well as payments to municipalities to compensate them for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring. The CTA and SBC are annually reconciled to actual costs incurred, with any difference refunded to, or recovered from, customers.
Under state law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. Under "Standard Service" rates for customers with less than 500 KW of demand and "Supplier of Last Resort Service" rates for customers with 500 KW of demand or greater, CL&P purchases power for those customers who do not choose a competitive energy supplier and passes the cost to such customers through a combined GSC and FMCC on customers' bills. The combined GSC and FMCC charges for both types of service recover all of the costs of procuring energy from CL&P's wholesale suppliers and are adjusted periodically and reconciled semi-annually in accordance with the directives of the DPUC.
Although more CL&P customers chose competitive energy suppliers in 2010 than in 2009, CL&P continues to supply approximately 40 percent of its customer load at Standard Service or Supplier of Last Resort Service rates while the other 60 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on CL&P’s delivery business or its operating income.
Distribution Rates: On June 30, 2010, the DPUC issued a final order in CL&P’s most recent retail rate case approving annualized distribution rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011. The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final payment of CL&P’s RRBs. In its decision, the DPUC also maintained CL&P’s authorized distribution segment regulatory ROE of 9.4 percent. In 2010, CL&P earned a distribution segment regulatory ROE of 7.9 percent, compared to 7.3 percent in 2009, and expects to earn a distribution segment regulatory ROE of approximately 9 percent in 2011.
In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds (ERRBs) that would be amortized over eight years. These bonds will be repaid through a charge on the bills of customers of CL&P and other Connecticut electric distribution companies. For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would have otherwise ended by December 31, 2010 with the final payment of the principal and interest on its RRBs, and the diversion of about one-third of the annual funding for C&LM programs beginning in April 2012. A lawsuit pending against the DPUC to prevent the issuance of the ERRBs is pending and several bills seeking to modify or prevent the issuance have been proposed before the state l egislature.
On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan concluding that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario." Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million. CL&P has proposed beginning installation of meters in late 2012 and finishing in 2016.
CL&P has a transmission adjustment clause as part of its retail distribution rates, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, thereby recovering all of its transmission expenses on a timely basis.
Sources and Availability of Electric Power Supply
As noted above, CL&P does not own any generation assets and purchases energy to serve its Standard Service and Supplier of Last Resort Service loads from a variety of competitive sources through periodic RFPs. CL&P enters into supply contracts for Standard Service periodically for periods of up to three years to mitigate price volatility for its residential and small and medium load commercial and industrial customers. CL&P enters into supply contracts for Supplier of Last Resort service for larger commercial and industrial
4
customers every three months. Currently, CL&P has contracts in place with various suppliers for all of its Standard Service loads through 2011, 40 percent of expected load for 2012, and 10 percent of expected load for 2013. CL&P’s contracts for its Supplier of Last Resort Service loads extend through the second quarter of 2011.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE - DISTRIBUTION
PSNH’s distribution business (which includes its generation business) consists primarily of the generation, purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2010, PSNH furnished retail franchise electric service to approximately 497,000 retail customers in 211 cities and towns in New Hampshire. PSNH also owns and operates approximately 1,200 MW of primarily fossil-fueled electricity generation assets. Included in those generation assets is its 50 MW wood-burning Northern Wood Power Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation. PSNH also has contracts with 18 IPPs, the output of which it either uses to serve its customer load or sells into the market.
PSNH is constructing its Clean Air Project, a sulfur dioxide and mercury scrubber at its Merrimack coal-fired generation station, which is currently expected to cost $430 million. The project is scheduled for completion in mid-2012. PSNH will recover all related costs through its ES rates described below.
The following table shows the sources of 2010 electric franchise retail revenues based on categories of customers:
| Sources of | % of | |
Residential | 54% | ||
Commercial | 36% | ||
Industrial | 9% | ||
Other | 1% | ||
Total | 100% |
Rates
PSNH is subject to regulation by the NHPUC, which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.
PSNH’s ES rate recovers its generation and purchased power costs from customers on a current basis and allows for an ROE of 9.81 percent on its generation investment.
Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs, including expenses incurred under mandated power contracts and other long-term investments and obligations. PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time and recovers the costs of these bonds through the SCRC rate.
On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year. The difference between ES/SCRC revenues and ES/SCRC costs are included in the ES/SCRC rate calculations and refunded to/recovered from customers in the subsequent period approved by the NHPUC.
The TCAM allows PSNH to recover on a fully reconciling basis its transmission related costs. The TCAM is adjusted July 1 of each year.
Distribution Rates: On June 28, 2010, the NHPUC approved a joint settlement of PSNH’s rate case that had commenced in 2009, allowing a net distribution rate increase of $45.5 million on an annualized basis to be effective July 1, 2010, and annualized distribution rate adjustments projected to be a decrease of $2.9 million and increases of $9.5 million and $11.1 million on July 1 of each of the three subsequent years, respectively. PSNH agreed not to file a new distribution rate request that would be effective prior to July 1, 2015. During the term of the settlement, PSNH can only propose changes to its permanent distribution rate level when its 12-month distribution ROE falls below 7 percent for two consecutive quarters or certain specified external events, such as major storms, occur. If PSNH’s 12-month ROE rolling average is greater than 10 percent, anything over the 10 percent level will be all ocated 75 percent to customers and 25 percent to PSNH. The settlement also provided that the authorized regulatory ROE on distribution only plant will continue at the previously allowed level of 9.67 percent. PSNH’s distribution segment regulatory ROE was 10.2 percent (including generation) in 2010, compared to 7.2 percent in 2009. We expect PSNH’s distribution segment regulatory ROE will be approximately 9 percent in 2011.
PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not elect to use a third party supplier. Prior to 2009, PSNH experienced only a minimal amount of customer migration. However, customer migration levels began to increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH. By the end of 2010, approximately 2 percent of all of PSNH’s customers (approximately 32 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers. The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sal es
5
volume. The customers that did not switch to a third party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of these fixed costs.
The NHPUC opened a proceeding in 2010 to consider the effect of customer migration on ES rates for customers, principally residential and small commercial and industrial customers, remaining on PSNH default energy service. As part of this docket, the NHPUC stated its intention to explore the interplay of customer choice, migration issues and power procurement options for PSNH.
PSNH cannot predict if the upward pressure on ES rates will continue into the future, as future customer migration levels, which are dependent on market prices and supplier alternatives, are uncertain. If future market prices once more exceed the average ES rate level, some or all of these customers on third party supply may migrate back to PSNH.
Sources and Availability of Electric Power Supply
During 2010, about 88 percent of PSNH’s load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with third parties. The remaining 12 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. PSNH expects to meet its load requirements in 2011 in a similar manner.
WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION
WMECO’s distribution business consists primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers. At December 31, 2010, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western third of Massachusetts. Following electric industry restructuring in the 1990s, WMECO sold all of its generating facilities and now purchases its energy requirements from competitive suppliers. In 2009, pursuant to the Massachusetts Green Communities Act, WMECO was authorized to install 6 MW of solar energy generation in its service territory. In October 2010, WMECO completed construction of a 1.8 MW solar generation facility at a site in Pittsfield, Massachusetts, which began producing electricity in late 2010. In January 2011, WMECO announced its plans to develop a second solar generation faci lity at a site in Springfield, Massachusetts. This facility will accommodate 17,000 solar panels, producing up to 4.2 MW of solar energy. WMECO will sell all energy and other products from its solar generation facilities into the ISO New England market. WMECO had a contract with one IPP generator in 2010, the output of which WMECO sold into the ISO New England market. The term of this contract ended on December 31, 2010.
The following table shows the sources of 2010 electric franchise retail revenues based on categories of customers:
| Sources of | % of Total | |
Residential | 57% | ||
Commercial | 33% | ||
Industrial | 9% | ||
Other | 1% | ||
Total | 100% |
Rates
WMECO is subject to regulation by the Massachusetts DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities. WMECO's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under state law, WMECO's customers are entitled to choose their energy suppliers, while WMECO remains their distribution company. WMECO purchases electric power from competitive suppliers for, and passes through the cost to, those customers who do not choose a competitive energy supplier (basic service). Basic service charges are adjusted and reconciled on an annual basis. Most of WMECO's residential and small commercial and industrial customers have continued to buy their power from WMECO at basic service rates. A greater proportion of large commercial and industrial customers have opted for a competitive energy supplier.
WMECO continues to supply approximately 50 percent of its customer load at basic service rates while the other 50 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on WMECO’s delivery business or its operating income.
WMECO recovers certain costs through various tracking mechanisms in its retail rates, including transmission costs, pension costs and prudently incurred stranded costs (a portion of which have been financed through securitization by issuing RRBs) with periodic true-up adjustments.
6
Distribution Rates: On January 31, 2011, the DPU issued a final decision in WMECO’s July 2010 rate application, granting a $16.8 million annualized rate increase in distribution revenues and an allowed ROE of 9.6 percent effective February 1, 2011. The DPU also authorized a full decoupling mechanism, whereby actual revenue billed by WMECO would be reconciled with WMECO’s target revenue on an annual basis, WMECO’s request to recover balances of certain active hardship account balances and the recovery of certain storm costs over five years. The DPU did not authorize rate recovery of a proposed $20 million average increase in WMECO’s capital spending plan. WMECO’s distribution segment regulatory ROE was 4.6 percent in 2010 compared to 8.4 percent in 2009. We expect WMECO’s distribution segment regulatory ROE will be approximately 9 percent in 2011.
WMECO is subject to SQ metrics that measure safety, reliability and customer service, and WMECO pays any charges incurred for failure to meet such metrics to customers. WMECO will not be required to pay an assessment charge for its 2010 performance results as WMECO performed at target for all of its SQ metrics in 2010.
On October 16, 2009, WMECO filed its proposal for a dynamic pricing smart meter pilot program with the DPU. However, the Company does not expect it will conduct a pilot prior to 2012.
Sources and Availability of Electric Power Supply
As noted above, WMECO does not own any generation assets (other than its recently constructed solar generation) and purchases its energy requirements from a variety of competitive sources through periodic RFPs. For basic service power supply, WMECO issues RFPs periodically, consistent with DPU regulations.
REGULATED GAS DISTRIBUTION – YANKEE GAS SERVICES COMPANY
Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 206,000 customers in 71 cities and towns), and size of service territory (2,187 square miles). Total throughput (sales and transportation) in both 2010 and 2009 was approximately 52.5 Bcf. Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas’ service territory buy gas supply and delivery only from Yankee Gas while commercial and industrial customers have choice in their gas suppliers. Yankee Gas offers firm transportat ion service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice. Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which enables the company to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher.
The following table shows the sources of 2010 gas operating revenues based on categories of customers:
Sources of | % of Total | ||
Residential | 51% | ||
Commercial | 30% | ||
Industrial | 16% | ||
Other | 3% | ||
Total | 100% |
A summary of firm natural gas sales in million cubic feet for Yankee Gas for 2010 and 2009 and the percentage changes in 2010 as compared to 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:
|
| Firm Natural Gas Sales (Mcf) |
|
| ||||
|
| 2010 |
| 2009 |
| Percent |
| Weather |
Residential |
| 13,403 |
| 13,562 |
| (1.2)% |
| 4.9% |
Commercial |
| 14,982 |
| 14,063 |
| 6.6% |
| 12.1% |
Industrial |
| 14,866 |
| 14,825 |
| 0.3% |
| 1.7% |
Total |
| 43,251 |
| 42,450 |
| 1.9% |
| 6.2% |
7
Yankee Gas’ firm natural gas sales are subject to many of the same influences as our retail electric sales, but they have recently benefitted from a favorable price for natural gas relative to competing fuels resulting in commercial and industrial customers switching from interruptible service to firm service, and the addition of gas-fired distributed generation in Yankee Gas’ service territory. Actual firm natural gas sales in 2010 were higher than 2009 despite the milder weather during the first quarter 2010 heating season. Firm natural gas sales benefitted from these trends and from a large commercial customer who began to take service from Yankee Gas mid-way through the third quarter of 2009 and continued to take service throughout all of 2010.
In April 2010, Yankee Gas commenced construction of its WWL project, a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut coupled with the increase of vaporization output of its LNG plant. The project is expected to cost approximately $57.6 million. In 2010, approximately $26.6 million was spent on construction of the WWL project, which included construction of a segment of pipeline connecting the Cheshire and Wallingford distribution systems. The remainder of the pipeline construction and the expansion of the vaporization capacity of the LNG facility are expected to be completed in the fourth quarter of 2011
Rates
Yankee Gas is subject to regulation by the DPUC, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.
Distribution Rates: On January 7, 2011, Yankee Gas filed an application with the DPUC to raise natural gas distribution rates by $32.8 million, or 7.3 percent, to be effective July 1, 2011, and by an additional $13 million, or 2.8 percent, to be effective July 1, 2012. Among other items, Yankee Gas requested to maintain its current authorized ROE of 10.1 percent, that $57.6 million of costs associated with the WWL project be placed into rates, and that a substantial increase in capital funding to replace bare steel and cast iron pipe on Yankee Gas' system. A final decision is expected in June 2011. Yankee Gas’ regulatory ROE was 8.6 percent in 2010 compared to 6.6 percent in 2009. We expect Yankee Gas’ distribution segment regulatory ROE to be approximately 9 percent in 2011.
Sources and Availability of Natural Gas Supply
The DPUC requires that Yankee Gas meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas’ LNG facility enables Yankee Gas to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher. Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that currently directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines. Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Li mited pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines. Yankee Gas considers such transportation arrangements adequate for its needs.
ELECTRIC TRANSMISSION
General
CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the rules by which they participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, has served since 2005 as the RTO of the New England transmission system. ISO-NE works to ensure the reliability of the system, administers, subject to FERC approval, the independent system operator tariff, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of all regional major transmission facilities are shared by consumers throughout New England.
Wholesale Transmission Rates
Wholesale transmission revenues are recovered through formula rates that are approved by the FERC. Our transmission revenues are recovered from New England customers through ISO-NE charges which recover costs of transmission and other transmission-related services provided by all regional transmission owners, with a portion of those revenues collected from the distribution segments of CL&P, PSNH and WMECO.
FERC ROE Decision
Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC set the base ROE at 11.14 percent and approved incentives that increased the ROE to 12.64 percent for those projects that were in-service by the end of 2008. In addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy. As a result, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects. All appeals of FERC's orders on the ROE for New England transmission owners have been denied.
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On November 17, 2008, the FERC issued an order granting certain incentives and rate amendments to National Grid and us for certain components of the proposed NEEWS project, which is described below. The approved incentives include (1) an ROE of 12.89 percent; (2) inclusion of 100 percent CWIP costs in rate base; and (3) full recovery of prudently incurred costs if any portion of NEEWS is abandoned for reasons beyond our control. Several parties have sought rehearing of this FERC order on which FERC has not yet acted.
Transmission Projects
NEEWS
CL&P and WMECO are continuing to develop and build the NEEWS project, which is comprised of GSRP, the Interstate Reliability Project and the Central Connecticut Reliability Project, and is estimated to cost $1.52 billion in the aggregate (approximately $1.45 billion reflecting the impact of UI’s potential investment of up to approximately $69 million as discussed below). CL&P and WMECO commenced substation construction on GSRP in December 2010 and expect to begin overhead line construction in the first half of 2011. We expect GSRP to be placed in service in late 2013 at a cost of approximately $795 million.
CL&P is designing and building the Interstate Reliability Project in coordination with National Grid USA, whose segment of this phase will interconnect with CL&P’s at the Connecticut-Rhode Island border. In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project. We expect CL&P's share of the costs of this project to be $301 million and that the project will be placed in service in late 2015.
The timing of the Central Connecticut Reliability Project is expected to be twelve months behind the Interstate Reliability Project and cost approximately $338 million. ISO-NE continues to assess the need date for the Central Connecticut Reliability Project and we expect that ISO-NE will conclude its evaluation by mid-2011.
Included as part of NEEWS are $84 million of expenditures for associated reliability related projects, all of which have received siting approval and most are under construction. The in-service dates for these projects range from later this year through 2013.
Northern Pass Transmission Line Project
NPT is a limited liability company jointly formed by NU and NSTAR to construct, own and operate the Northern Pass transmission line, a new HVDC transmission line from the border of Canada and the United States to Franklin, New Hampshire that will interconnect at the border with a new HVDC transmission line being developed by HQ TransEnergie, the transmission subsidiary of HQ. NUTV, a subsidiary of NU, holds a 75 percent interest in NPT, with NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, holding the remaining 25 percent. Consistent with FERC's February 11, 2011 order accepting the TSA between NPT and Hydro Renewable Energy that was filed December 15, 2011, NPT will charge Hydro Renewable Energy cost-based rates for firm transmission service over the Northern Pass line for a 40-year term. The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project. Upon commercial operation, the ROE will be equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent based on a deemed capital structure for NPT of 50 percent debt and 50 percent equity.
In October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE. The DOE application seeks permission for NPT to construct and maintain facilities that cross the U.S. border and connect to HQ TransEnergie's facilities in Canada. Assuming timely regulatory review and siting approvals, NPT expects to commence construction of the Northern Pass in 2013, with power flowing across the line in late 2015.
We currently estimate that our 75 percent share of the costs to build the Northern Pass transmission project will be approximately $830 million out of total expected costs of approximately $1.1 billion (including capitalized AFUDC).
Other Transmission Transactions
In July 2010, CL&P and UI entered into an agreement under which UI would acquire certain transmission assets within CL&P's portion of each of the NEEWS segments. Under the terms of the agreement, which has received approval from the FERC and the DPUC, UI will have the option to invest up to $69 million or an amount equal to 8.4 percent of CL&P's costs for the assets, which are expected to aggregate approximately $828 million.
On December 17, 2010, CL&P and CTMEEC, a non-profit municipal joint action transmission entity formed by several Connecticut municipal electric companies, entered into an agreement , subject to DPUC approval, under which CTMEEC would acquire a segment of CL&P’s high voltage transmission lines in the town of Wallingford, Connecticut. The transaction was approved by FERC on January 31, 2011. The purchase price will be based on the net book value of the assets at the time of the closing of the sale in May 2011, projected to be approximately $42.3 million. CL&P will continue to operate and maintain the lines for CTMEEC.
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Transmission Rate Base
Under our FERC-approved tariff, transmission projects generally enter rate base once they are placed in commercial operation. However, 100 percent of the NEEWS projects will enter rate base during their construction period. At the end of 2010, our transmission rate base was approximately $2.8 billion, including approximately $2.1 billion at CL&P, $341 million at PSNH and $269 million at WMECO. We forecast that our total transmission rate base will grow to approximately $4.8 billion by the end of 2015, including approximately $830 million at NPT.
CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM
The principal focus of our construction and capital improvement program is maintaining, upgrading and expanding our existing electric generation, transmission and distribution systems and our natural gas distribution system. Our consolidated capital expenditures in 2010 totaled approximately $1 billion, almost all of which ($967 million) was expended by the Regulated companies. The capital expenditures of these companies in 2011 are estimated to total approximately $1.2 billion, $477 million by CL&P, $284 million by PSNH, $287 million by WMECO and $113 million by Yankee Gas. This capital budget includes anticipated costs for all committed capital projects (i.e., generation, transmission, distribution, environmental compliance and others) and those we expect to become committed projects in 2011.
In 2010, CL&P’s transmission capital expenditures totaled approximately $107 million, and its distribution capital expenditures totaled approximately $305 million. For 2011, CL&P projects transmission capital expenditures of approximately $137 million and distribution capital expenditures of approximately $337 million. During the period 2011 through 2015, CL&P plans to invest approximately $1 billion in transmission projects, the majority of which will be for NEEWS and $1.9 billon on distribution projects. If all of the distribution and transmission projects are built as proposed, CL&P’s rate base for electric transmission is projected to increase from approximately $2.1 billion at the end of 2010 to approximately $2.6 billion by the end of 2015, and its rate base for distribution assets is projected to increase from approximately $2.3 billion to approximately $3.3 billion over the same pe riod.
In 2010, PSNH's transmission capital expenditures totaled approximately $49 million, its distribution capital expenditures totaled approximately $84 million and its generation capital expenditures totaled $177 million. For 2011, PSNH projects transmission capital expenditures of approximately $59 million, distribution capital expenditures of approximately $113 million and generation capital expenditures of approximately $112 million. The bulk of the generation capital expenditures is for the Clean Air Project. During the period 2011 through 2015, PSNH plans to spend approximately $293 million on transmission projects, approximately $621 million on distribution projects, and $274 million on generation projects. If all of the distribution, generation and transmission projects are built as proposed, PSNH’s rate base for electric transmission is projected to increase from approximately $341 million at the en d of 2010 to approximately $540 million by the end of 2015, and its rate base for distribution and generation assets is projected to increase from approximately $1.2 billion to approximately $1.9 billion over the same period.
In 2010, WMECO's transmission capital expenditures totaled approximately $95 million, its distribution capital expenditures totaled approximately $33.1 million and solar generation expenditures were $10 million. In 2011, WMECO projects transmission capital expenditures of approximately $229 million, distribution capital expenditures of approximately $36 million and $22 million on solar generation. During the period 2011 through 2015, WMECO plans to spend approximately $732 million on transmission projects, with the bulk of that amount to be spent on GSRP, approximately $194 million on distribution projects and $46 million on solar generation. If all of the generation, distribution and transmission projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from approximately $269 million at the end of 2010 to approximately $803 million by the end of 2015 and its rate base fo r distribution and generation assets is projected to increase from approximately $423 million to approximately $488 million over the same period.
In 2010, Yankee Gas capital expenditures totaled approximately $95 million. For 2011, Yankee Gas projects total capital expenditures of approximately $113 million, approximately $30 million of which is expected to be related to the WWL project, $37 million related to basic business activities such as relocation of conflicting gas facilities and the purchase of meters, tools and information technology; $30 million related to reliability improvements; and $16 million for load growth and new business requests. During the period 2011 through 2015, Yankee Gas plans on making approximately $587 million of capital expenditures, including approximately $30 million on the WWL project. Future capital spending will likely be affected by price differences between the cost of natural gas with respect to home heating oil, natural gas supply, new home construction, road reconstruction, regulatory mandates and business requirements. &n bsp;Excluding non-recurring major projects, NU expects that approximately 28 percent of Yankee Gas’ capital expenditures over the 2011-2015 period to be related to basic business activities, approximately 28 percent related to load growth and new business, and approximately 39 percent related to reliability initiatives, with the balance related to the WWL project. If all of Yankee Gas projects are built as proposed, Yankee Gas’ investment in its regulated assets is projected to increase from approximately $682 million at the end of 2010 to approximately $969 million by the end of 2015.
FINANCING
NU subsidiaries issued a total of $145 million in long-term debt in 2010. On March 8, 2010, WMECO issued $95 million of senior unsecured notes due March 1, 2020 carrying a coupon rate of 5.1 percent and on April 22, 2010, Yankee Gas issued $50 million of first mortgage bonds through a private placement with a maturity date of April 1, 2020 carrying a coupon rate of 4.87 percent.
In addition, on April 1, 2010, CL&P completed the remarketing of $62 million of tax-exempt secured PCRBs. The PCRBs carry a coupon rate of 1.4 percent until April 1, 2011, at which time CL&P expects to remarket the bonds.
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On September 24, 2010, NU parent entered into a three-year $500 million unsecured revolving credit facility, and CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a three-year $400 million unsecured revolving credit facility, both replacing five-year credit facilities on similar terms and conditions that were scheduled to expire on November 6, 2010. Like the previous facility, NU’s new revolving credit facility allows NU parent to borrow on a short-term or long-term basis, or issue LOCs, up to $500 million in the aggregate. Under their new revolving credit facility, CL&P and PSNH are each able to draw up to $300 million, with WMECO and Yankee Gas each able to draw up to $200 million, all subject to the $400 million maximum aggregate borrowing limit.
Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH, WMECO and Yankee Gas, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent. All such companies currently are, and expect to remain in compliance with these covenants.
We have annual sinking fund requirements of $4.3 million continuing in 2011 through 2012, the mandatory tender of $62 million of tax-exempt PCRBs by CL&P on April 1, 2011, at which time CL&P expects to remarket the bonds in the ordinary course. Neither NU nor any of its subsidiaries have any debt maturities until April 1, 2012.
In light of the 2010 Tax Act and the related cash flow benefits, we are currently reevaluating the timing of our previously planned NU common equity issuance. If we complete the proposed merger with NSTAR, we would no longer need to undertake the previously planned $300 million NU common equity issuance in 2012 nor issue any additional equity in the foreseeable future.
NUCLEAR DECOMMISSIONING
General
CL&P, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. Each Yankee Company collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with CL&P, PSNH and WMECO and several other New England utilities. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates. The ownership percentages of CL&P, PSNH and WMECO in the Yankee Companies are set forth below:
|
| CL&P |
| PSNH |
| WMECO |
| Total |
CYAPC |
| 34.5% |
| 5.0% |
| 9.5% |
| 49.0% |
MYAPC |
| 12.0% |
| 5.0% |
| 3.0% |
| 20.0% |
YAEC |
| 24.5% |
| 7.0% |
| 7.0% |
| 38.5% |
Our share of the obligations to support the Yankee Companies under FERC-approved contracts is the same as the ownership percentages above.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
General
We are regulated in virtually all aspects of our business by various federal and state agencies, including the FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the DPUC, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over WMECO.
Environmental Regulation
We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, our major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies. PSNH owns approximately 1,200 MW of generation assets and expects to spend approximately $430 million on its Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack coal station to reduce its mercury and sulfur dioxide emissions. Compliance with additional environmental laws and regulations, particularly air and water pollution control requirements may cause changes in operations or require further investments in new equipment at existing facilities.
Water Quality Requirements
The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a NPDES permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of obtaining or renewing all required NPDES or state discharge permits in effect for our facilities. In each of the last three years, the costs incurred by the Company related to compliance with NPDES and state discharge permits have not been material. The Company expects to incur additional costs related to these permits in the future; however, due to uncertainty regarding the imposition of new or additional requirements, the Company is unable to accurately estimate such costs.
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Air Quality Requirements
The CAAA, as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included.
In New Hampshire, the Multiple Pollutant Reduction Program capped NOX, SO2and CO2 emissions beginning in 2007. In addition, a 2006 New Hampshire law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions of its coal fired plants by at least 80 percent (with the co-benefit of reductions in SO2 emissions as well). The Clean Air Project addresses this requirement. PSNH began site work for this project in November 2008 and is scheduled to complete it by mid-2012.
In addition, Connecticut, New Hampshire and Massachusetts are each members of the RGGI, a cooperative effort by ten northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from fossil fuel-fired electric generating plants. Because CO2 allowances issued by any participating state will be usable across all ten RGGI state programs, the individual state CO2 trading programs, in the aggregate, will form one regional compliance market for CO2 emissions. A regulated power plant must hold CO2 allowances equal to its emissions to demonstrate compliance at the end of a three-year compliance period that began in 2009.
Because neither CL&P nor WMECO currently own any generating assets (other than the solar facilities owned by WMECO, which do not emit CO2), neither is required to acquire CO2 allowances; however, the CO2allowance costs borne by generators that provide energy supply to CL&P and WMECO will likely be included in wholesale rates charged to them, which costs are then recoverable from customers.
PSNH anticipates that its generating units will emit between four million and five million tons of CO2 per year after taking into effect the operation of PSNH’s Northern Wood Power Project. Under the RGGI formula, this Project decreased PSNH’s responsibility for reducing fossil-fired CO2 emissions by approximately 425,000 tons per year, or almost ten percent. New Hampshire legislation provides up to 2.5 million banked CO2 allowances per year for PSNH’s fossil fueled generating plants during the 2009 through 2011 compliance period. These banked CO2 allowances will initially comprise approximately one-half of the yearly CO2 allowances required for PSNH’s generating plants to comply with RGGI. Such banked allowances will decrease over time. PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2 allowances at auction or in the secondary market. The cost of complying with RGGI requirements is recoverable from PSNH customers.
Each of the states in which we do business also has RPS requirements, which generally require fixed percentages of energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.
New Hampshire’s RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources, beginning in 2008 at four percent and ultimately reaching 23.8 percent by 2025. In 2010, the total RPS obligation was 7.5 percent of total generation supplied to customers. Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements. PSNH also owns renewable sources and uses both internally generated RECs and purchased RECs to meet its RPS obligations. To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient. The costs of both the RECs and alternative compliance payments do not impact earni ngs, as these costs are recovered by PSNH through its ES rates charged to customers.
Connecticut's RPS statute requires electricity suppliers to meet renewable energy standards, beginning with a four percent RPS in 2004. This percentage increases each year. For 2010, the requirement was 14 percent with goals of 19.5 percent by 2015 and 27 percent by 2020. CL&P is permitted to pass any costs incurred in complying with RPS on to customers through rates.
Massachusetts’ RPS program required electricity suppliers to meet a one percent renewable energy standard in 2003 and has a goal of 15 percent by 2015. For 2010, the requirement was five percent. WMECO is permitted to pass any costs incurred in complying with RPS on to customers through rates.
In addition, many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on emissions than are currently in effect.
Hazardous Materials Regulations
Prior to the last quarter of the 20th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities. Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. We have recorded a liability for what we believe is, based upon currently available information, our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability. We continue to evaluate the environmental impact of our for mer disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on us for these
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practices. At December 31, 2010, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $37.1 million, representing 58 sites. These costs could be significantly higher if remediation becomes necessary or when additional information as to the extent of contamination becomes available.
The most significant liabilities currently relate to future clean up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We, through our subsidiaries, currently have partial or full ownership responsibilities at 28 former MGP sites.
HWP, a wholly-owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal electric utility, in 1902. HWP is at least partially responsible for this site and has already conducted substantial investigative and remediation activities. HWP's share of the remediation costs related to this site is not recoverable from customers.
Electric and Magnetic Fields
For more than twenty years, published reports have discussed the possibility of adverse health effects from EMF associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.
We have closely monitored research and government policy developments for many years and will continue to do so. In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.
Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government, particularly in recent years. The EPA has initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" and endanger public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated GHG emission reporting beginning in 2012 for 2011 emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF-6 gas and methane.
We are continually evaluating the risks presented by climate change concerns and issues. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations. (See "Air Quality Requirements" in this section for information concerning RGGI) These could include federal "cap and trade" laws, or regulations requiring additional capital expenditures at our generating facilities. In addition, such rules or regulations could potentially impact the prices we pay for goods and services provided by companies directly affected by such rules or regulations. We would expect that any costs of these rules and regulations would be recovered from customers, but such costs could impact energy use by our customers.
Global climate change could potentially impact weather patterns such as increasing the frequency and severity of storms or altering temperatures. These changes could affect our facilities and infrastructure and could also impact energy usage by our customers.
FERC Hydroelectric Project Licensing
Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
PSNH owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047. PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.
Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision that expressly permits the FERC to order decommissioning during the license term. However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing. The FERC may also require project
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decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked. PSNH is not presently encountering any of these challenges.
EMPLOYEES
As of December 31, 2010, we employed a total of 6,182 employees, excluding temporary employees, of which 1,847 were employed by CL&P, 1,240 by PSNH, 354 by WMECO, 429 by Yankee Gas and 2,307 were employed by NUSCO. Approximately 2,212 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are members of the International Brotherhood of Electrical Workers and The United Steelworkers and are covered by 11 union agreements.
INTERNET INFORMATION
Our website address is www.nu.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site NU's, CL&P's, WMECO's and PSNH's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 56 Prospect Street, Hartford, CT 06103.
Item 1A.
Risk Factors
In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included directly prior to Item 1,Business, above, we are subject to a variety of significant risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.
The actions of regulators can significantly affect our earnings, liquidity and business activities.
The rates that our Regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC. These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters. FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters. The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.
Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.
Our ability to properly operate of our transmission, distribution and generation systems is critical to the financial performance of our business. Our transmission, distribution and generation businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age); labor disputes; disruptions in the delivery of electricity, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored; catastrophic events such as fires, explosions, or other similar occurrences; and other unanticipated operations and maintenance expenses and liabilities. The failure of our transmission, distributions and generation systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in operation and maintenance costs. At PSNH, outages at generating stations may be deemed imprudent by state regulators resulting in disallowance of replacement power costs. Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.
Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.
We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations. A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.
Our counterparties may not meet their obligations to us.
We are exposed to the risk that counterparties to various arrangements who owe us money, or have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.
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Changes in regulatory or legislative policy and/or regulatory decisions, difficulties in obtaining siting, design or other approvals, global demand for critical resources, environmental or other concerns, or construction of new generation may delay completion of or displace our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected rates of return.
Our transmission construction plans could be affected by new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations or regulatory decisions, delays in obtaining approvals or difficulty in obtaining critical resources required for construction. Any of such events could cause delays in our construction schedule adversely affecting our ability to achieve forecasted earnings.
The regulatory approval process for our transmission projects requires extensive permitting, design and technical activities. Various factors could result in increased costs and delay construction schedules. These include environmental and community concerns and design and siting issues. Recoverability of all such investments in rates may be subject to prudence review at the FERC. While we believe that all such costs have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.
In addition, our transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.
Many of our transmission projects are expected to help alleviate identified reliability issues and reduce customers' costs. However, if, due to further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, which could have an adverse effect on our earnings.
The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.
Increases in electric and gas prices and/or a weak economy, can lead to changes in legislative and regulatory policy promoting energy efficiency, conservation, and self-generation and/or a reduction in our customers’ ability to pay their bills, which may adversely impact our business.
Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.
In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.
Connecticut, New Hampshire and Massachusetts have each investigated revenue decoupling as a mechanism to align the interests of customers and utilities relative to conservation. In Connecticut, the DPUC authorized decoupling through a rate design that is intended to recover greater distribution revenue through fixed charges, and proportionately less distribution revenue through usage-based charges. In New Hampshire, the NHPUC conducted a decoupling docket and determined that utilities were free to propose decoupling in the context of a rate case and demonstrate the effect decoupling would have on its risk profile and ROE. PSNH has not yet commenced such a proceeding. In Massachusetts, the DPU has required WMECO to adopt full decoupling in its January 31, 2011 rate decision. At this time it is uncertain what impact these decoupling mechanisms will have on our companies.
As a way to promote self-generation and reduce energy costs, Connecticut, Massachusetts, and New Hampshire have taken a greater interest in allowing customers to receive credit for generation produced at a customer-owned generating facility that exceeds their energy needs. In Massachusetts, in accordance with the Green Communities Act, the DPU adopted rules and regulations concerning net metering that will have this effect. Such rules provide a cost recovery mechanism for affected utilities to recover lost revenues. The Massachusetts DPU is expected to hold further proceedings to address net metering in early 2011. In Connecticut, the DPUC opened a docket to review existing state statutes and determine what limitations currently exist in state law concerning net metering. In addition, any legislation in Connecticut to promote self-generation and net metering could impact CL&P’s financial position, results of operations or cash flows. In New Hampshire, new legislation dramatically changed the net metering rules in 2010. This new legislation is meant to encourage net metering from customers with small generators and also provides PSNH a cost recovery mechanism for lost distribution revenue.
Changes in regulatory and/or legislative policy could negatively impact regional transmission cost allocation rules.
The existing FERC-approved New England transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities. As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New England in accordance with relative benefits received. This regional cost allocation is set forth in the Transmission Operating Agreement signed by all of the New England transmission owning utilities. Effective February 1, 2010, this agreement can be modified with the approval of a majority of the transmission owning utilities and FERC. In addition, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the
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rates our distribution companies charge their retail customers. FERC is also considering policies to encourage the construction of transmission for renewable generation that could have the effect of imposing costs of inter-regional investment on New England customers.
Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution and generation businesses.
Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval. There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets. Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows. Additionally, state legislators may enact laws that significantly impact our Regulated companies’ revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy. Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.
In addition, CL&P and WMECO procure energy for a substantial portion of their customers’ needs via requests for proposal on an annual, semi-annual or quarterly basis. CL&P and WMECO receive approval to recover the costs of these contracts from the DPUC and DPU, respectively. While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.
PSNH meets most of its energy requirements through its own generation resources and fixed-price forward purchase contracts. PSNH’s remaining energy needs are met primarily through spot market purchases. Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the energy to meet its requirements. PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC. We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.
Migration of customers from PSNH energy service to competitive energy suppliers could increase the cost to the remaining customers of energy produced by PSNH generation assets and decrease our revenues.
PSNH’s ES rates have been higher than competitive energy prices offered to some customers in recent years, primarily due to lower natural gas prices. As a result, by the end of 2010, approximately 2 percent of PSNH’s retail customers (representing approximately 32 percent of load), mostly large commercial and industrial customers, were buying their energy from competitive suppliers rather than from PSNH. The remaining retail customers are experiencing an increase in the cost of energy service supplied by PSNH by 5 percent to 7 percent due to migration of large commercial and industrial customers and the lower base in which to recover PSNH's fixed generation costs. This increase may in turn cause further migration and further increasing of PSNH energy service rates. This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation faciliti es on remaining customers and being unable to support the cost of its generation facilities through an ES rate.
The NHPUC is examining this issue in a proceeding in which hearings ended on December 1, 2010. PSNH has suggested transferring some fixed costs of the generation facilities into a nonbypassable charge while intervening competitive suppliers have proposed taking over the purchased power portion of the load not supplied by PSNH’s generation. Others have also proposed having PSNH bid all of its generation facilities into the market while an RFP process supplies all of the power for PSNH’s energy service. The NHPUC is considering further proceedings to explore these and other issues as well as the NHPUC authority to require PSNH to divest its generation facilities. It is not known what the results of such a proceeding would be, what PSNH may realize as a result of the sale or retirement of one or more of its generation facilities, or to what extent or manner the NHPUC would provide for recovery of any invest ment in its generation facilities.
Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize completion of, or full recovery of costs incurred by PSNH in constructing, the Clean Air Project.
Pursuant to New Hampshire law, PSNH is building the Clean Air Project at its Merrimack Station in Bow, New Hampshire. Several parties initiated legal proceedings challenging the project. These proceedings, or new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could result in increased costs to the project.
In addition, PSNH’s investment in the project after it is completed is subject to prudence review by the NHPUC at the time the project is placed in service. A material prudence disallowance could adversely affect PSNH’s financial position, results of operations or cash flows. While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudency reviews should they occur. Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.
The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial condition and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our
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management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.
Grid disturbances, severe weather, or acts of war or terrorism could negatively impact our business.
Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business continuity due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage, solar storm activity or terrorist action) on an interconnected system or the actions of another utility. In addition, we are subject to the risk that acts of war or terrorism, including cyber-terrorism could negatively impact the operation of our system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition, results of operations or cash flows.
Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as customers demand better and quicker response times to outages. The effect of the failure of our facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.
Market performance or changes in assumptions could require us to make significant contributions to our pension and other post-employment benefit plans.
We provide a defined benefit pension plan and other post-retirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control. These factors include estimated investment returns, interest rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs could increase significantly. In 2008 and 2009, due to the financial crisis, the value of our pension assets declined. As a result, we made a contribution of $45 million in 2010 and expect to make an approximate $145 million contribution in 2011. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund o ur pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and negatively affect our financial position, results of operations or cash flows.
Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.
Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.
In addition, global climate change issues have received an increased focus from federal and state governments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations. Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time. The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.
Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates. The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1,Business - "Other Regulatory and Environmental Matters," in this Annual Report on Form 10-K.
As a holding company with no revenue-generating operations, NU parent is dependent on dividends from its subsidiaries, primarily the Regulated companies, its bank facility, and its ability to access the long-term debt and equity capital markets.
NU parent is a holding company and as such, has no revenue-generating operations of its own. Its ability to meet its financial obligations associated with the debt service obligations on its debt and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or to repay borrowings from NU parent; and/or NU parent’s ability to access its credit
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facility or the long-term debt and equity capital markets. Prior to funding NU parent, the Regulated companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P) and obligations to trade creditors. Additionally, the Regulated companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NU parent. Should the Regulated companies not be able to pay dividends to or repay funds due to NU parent or if NU parent cannot access its bank facilities or the long-term debt and equity capital markets, NU parent’s ability to pay interest, dividends and its own debt obligations would be restricted.
Risks Related to the Proposed Merger with NSTAR
We may be unable to satisfy the conditions or obtain the approvals required to complete the merger or such approvals may contain material restrictions or conditions.
The merger is subject to approval by the shareholders of both NU and NSTAR and numerous other conditions, including the approval of various government agencies. Governmental agencies may not approve the merger or such approvals may impose conditions on the completion, or require changes to the terms of the merger, including restrictions on the business, operations or financial performance of the combined company, which could be adverse to the company's interests. These conditions or changes could also delay or increase the cost of the merger or limit the net income or financial prospects of the combined company.
We will be subject to business uncertainties and contractual restrictions while the merger is pending.
The work required to complete the merger may place a significant burden on management and internal resources. Management's attention and other company resources may be focused on the merger instead of on day-to-day management activities, including pursuing other opportunities beneficial to NU. In addition, while the merger is pending our business operations are restricted by the Agreement and Plan of merger to ordinary course of business activities consistent with past practice, which may cause us to forgo otherwise beneficial business opportunities.
We may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.
Uncertainties about the effect of the merger on management personnel and employees may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, which could affect our financial performance.
The merger may not be completed, which may have an adverse effect on our share price and future business and financial results and we could face litigation concerning the merger, whether or not the merger is consummated.
Failure to complete the merger could negatively affect NU's share price, as well as our future business and financial results. In addition, purported class actions have been brought against us, NSTAR and others on behalf of holders of NSTAR common shares. If these actions or similar actions that may be brought are successful, the costs of completing the merger could increase, or the merger could be delayed or prevented. We cannot make any assurances that we will succeed in any litigation brought in connection with the merger. See Item 3,Legal Proceedings, in this Annual Report on Form 10-K for discussion of pending litigation related to the merger.
If the merger is not completed for certain reasons specified in the merger agreement, we may be required to pay NSTAR a termination fee of $135 million plus up to $35 million of certain expenses incurred by NSTAR. In addition, we must pay our own costs related to the merger including, among others, legal, accounting, advisory, financing and filing fees and printing costs, whether the merger is completed or not. Further, if the merger is not completed, we could be subject to litigation related to the failure to complete the merger or other factors, which may adversely affect our business, financial results and share price.
If completed, the merger may not achieve its intended results.
We entered into the merger agreement with the expectation that the merger would result in various benefits. If the merger is completed, our ability to achieve the anticipated benefits will be subject to a number of uncertainties, including whether our businesses can be integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.
Item 1B.
Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
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Item 2.
Properties
Transmission and Distribution System
As of December 31, 2010, our electric operating subsidiaries owned 31 transmission and 422 distribution substations that had an aggregate transformer capacity of 5,302,000 kilovolt amperes (kVa) and 29,861,000 kVa, respectively; 3,094 circuit miles of overhead transmission lines ranging from 69 KV to 345 KV, and 433 cable miles of underground transmission lines ranging from 69 KV to 345 KV; 34,957 pole miles of overhead and 3,054 conduit bank miles of underground distribution lines; and 539,379 underground and overhead line transformers in service with an aggregate capacity of 37,703,193 kVa.
Electric Generating Plants
As of December 31, 2010, PSNH owned the following electric generating plants:
Type of Plant |
|
| Number |
| Year |
| Claimed |
|
|
|
|
|
|
| |
Total - Fossil-Steam Plants |
| 5 units |
| 1952-74 |
| 947,980 | |
Total - Hydro-Conventional |
| 20 units |
| 1901-83 |
| 71,105 | |
Total - Internal Combustion |
| 5 units |
| 1968-70 |
| 102,959 | |
Total - Biomass - Steam Plant |
| 1 unit |
| 1954 |
| 45,816 | |
|
|
|
|
|
|
| |
Total PSNH Generating Plant |
| 31 units |
|
|
| 1,167,860 |
*
Claimed capability represents winter ratings as of December 31, 2010. The combined nameplate capacity of the generating plants is approximately 1,200 MW.
As of December 31, 2010, WMECO owned the following electric generating plant:
Type of Plant |
|
| Number |
| Year |
| Claimed |
|
|
|
|
|
|
| |
Total - Solar Fixed Tilt, Photovoltaic |
| 1 unit |
| 2010 |
| 1,800,000 |
** Claimed capability represents the direct current nameplate capacity of the plant.
CL&P did not own any electric generating plants during 2010.
Yankee Gas
As of December 31, 2010, Yankee Gas owned 28 active gate stations, approximately 200 district regulator stations and 3,239 miles of natural gas main pipeline. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, a propane facility in Kensington, Connecticut, and three additional propane facilities that are no longer in service and are expected to be sold in 2011.
Franchises
CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distributi on company from owning or operating generation assets. However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and Locational Installed Capacity (LICAP) costs. In addition, Section 83 of Public Act 07-242, "An Act Concerning Electricity and Energy Efficiency," states that if an existing electric generating plant located in Connecticut is offered for sale, then an electric distribution company, such as CL&P, would be eligible to purchase the generation plant upon obtaining prior approval from the DPUC and a determination by the DPUC that such purchase is in the public interest.
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PSNH. The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The distribution and transmission franchises of PSNH include the power of eminent domain.
WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways. Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.
The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including WMECO. The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.
Yankee Gas. Yankee Gas holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service, which it acquired either directly or from its predecessors in interest. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility. Yankee Gas’ franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas’ franchises include, among other rights and powers, the right and power to manuf acture, generate, purchase, transmit and distribute gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.
Item 3.
Legal Proceedings
1.
Yankee Companies v. U.S. Department of Energy
The Yankee Companies (YAEC, MYAPC, and CYAPC) commenced litigation in 1998 against the DOE charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each company into the Nuclear Waste Fund. The funds for those payments were collected from regional electric customers. The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.
In 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. In December 2006, the DOE appealed the decision and the Yankee Companies filed cross-appeals. The Court of Appeals disagreed with the trial court’s method of calculation of the amount of the DOE’s liability, among other things, and vacated the decision of the Court of Federal Claims and remanded the case to make new findings consistent with its decision. On September 7, 2010, the trial court issued its decision following remand and awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed. Briefs are due in the first quarter of 2011. The application of any damages that are ultimately recovered to benefit customers, is est ablished in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.
In December 2007, the Yankee Companies filed a second round of lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002.
2.
Connecticut MGP Cost Recovery
In September 2006, CL&P and Yankee Gas (the NU Companies) filed a complaint against UGI Utilities, Inc. (UGI) in the U.S. District Court for the District of Connecticut seeking past and future remediation costs related to historic MGP operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut. The NU Companies allege that UGI controlled operations of the plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests. Investigations and remediation activity and expenditures at the sites are ongoing. A trial was held in April 2009.
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On May 22, 2009, the court granted judgment in favor of the NU Companies with respect to the Waterbury-North site, and granted judgment in favor of UGI with respect to the remaining sites. Judgment was entered on March 31, 2010. On April 23, 2010, the NU Companies filed a Notice of Appeal with respect to the court’s decision, which has been fully briefed. The Phase II trial, which would determine what portion of the remediation costs at the Waterbury-North site are attributable to UGI's control, is scheduled for August 31, 2011. Any recovery resulting from the case (following the appeal and the Waterbury-North complaint) would flow back to the NU Companies' customers, and the NU Companies would continue to seek recovery as appropriate of remediation and other associated costs with regard to the sites for which no recovery from UGI will be forthcoming.
3.
Litigation Related to the Proposed Merger with NSTAR
In October 2010, NSTAR, the members of the NSTAR board of trustees, NU, and two wholly-owned NU subsidiaries, NU Holding Energy 1 LLC and NU Holding Energy 2 LLC, were named defendants in eight lawsuits (since consolidated) filed in the Superior Court for Suffolk County, Massachusetts, and one lawsuit filed in federal court in the district of Massachusetts. The lawsuits, each of which was brought by a single shareholder, purport to be brought on behalf of classes of NSTAR shareholders opposed to the terms of the merger agreement. The original complaints made virtually identical allegations that, among other things, NSTAR’s trustees breached their fiduciary duties by failing to maximize the value to be received by NSTAR’s shareholders, and that the other defendants aided and abetted the NSTAR trustees’ breaches of fiduciary duties. Both the state and federal complaints sought and continue to seek, among other things, to enj oin defendants from consummating the merger and either rescission of the merger, to the extent it is completed, or monetary damages. On December 10, 2010, the state-court plaintiffs filed their consolidated amended complaint, which, in addition to the already-pending claims, alleged that the disclosures in the preliminary joint proxy statement/prospectus NU filed jointly with NSTAR, were insufficiently detailed, pointing to various aspects of the section entitled "The Merger." On January 6, 2011, NU and NSTAR each moved to dismiss the claims asserted against them for failure to state a claim. In addition, NU and NSTAR jointly moved for a protective order staying the discovery that some of the Plaintiffs had served contemporaneously with their complaints. On January 13, 2011, Plaintiffs moved the Court to expedite proceedings in anticipation of their making a subsequent motion for preliminary injunction to enjoin the March 4, 2011 shareholder vote. Plaintiffs also filed a purported "emergency" motion to obtain discovery from Lexicon Partners, NSTAR's financial advisors. NU and NSTAR opposed both motions, which the Court subsequently denied and scheduled a "litigation control" conference for February 28, 2011 "to address proper scheduling of any and all related motions anticipated by the parties." On February 11, 2011, Plaintiffs filed a motion for preliminary injunction seeking to enjoin the March 4, 2011 shareholder vote. NU and NSTAR will file their opposition to the motion on or before February 22, 2011 on the grounds that it lacks any legal or evidentiary basis. There have been no developments in the federal case, in which the plaintiff has never served NSTAR, NU, or any other defendant with his complaint. NU and NSTAR believe both the federal and state lawsuits are without merit and are defending the lawsuits vigorously.
4.
Bankruptcy of Independent Power Producer
On February 1, 2011, an independent power producer, AES Thames, L.L.C. (Thames), which is the counterparty to a CL&P electricity purchase agreement, filed a voluntary petition for bankruptcy in the U.S. Bankruptcy Court in Delaware (Case No. 11-10334). Thames owns and operates a 181 MW coal fired generation plant in Montville, Connecticut providing electric energy to CL&P and process steam to a nearby paperboard manufacturer. Citing market conditions and regulatory and legislative uncertainties, Thames had advised CL&P on January 24, 2011 that it was shutting the plant down for an undetermined period. Under an amendment to the electricity purchase agreement entered into in 1999, Thames agreed to supply CL&P with energy from the plant for a reduced price in exchange for a substantial prepayment. The electricity purchase agreement was due to expire in 2015. CL&P has appeared in the Delaware bankruptcy proceeding and intends to assert all available legal rights to protect its customers’ interests. Management cannot estimate the effects of this proceeding, but does not believe there will be a material impact on CL&P’s financial position, results or operations or cash flows.
5.
Other Legal Proceedings
For further discussion of legal proceedings see the following sections of Item 1,Business: "- Regulated Electric Distribution," "-Regulated Gas Distribution - Yankee Gas Services Company," and "- Electric Transmission," for information about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "- Nuclear Decommissioning" for information related to high-level nuclear waste; and "- Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters. In addition, see Item 1A,Risk Factors, for general information about several significant risks.
21
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the executive officers of NU as of February 24, 2011. All of the Company’s officers serve terms of one year and until their successors are elected and qualified:
Name | Age | Title | ||
Jay S. Buth | 41 | Vice President - Accounting and Controller. | ||
Gregory B. Butler | 53 | Senior Vice President and General Counsel. | ||
Jean M. LaVecchia* | 59 | Vice President - Human Resources of NUSCO. | ||
David R. McHale | 50 | Executive Vice President and Chief Financial Officer of NU. | ||
Leon J. Olivier | 62 | Executive Vice President and Chief Operating Officer of NU. | ||
James B. Robb* | 50 | Senior Vice President, Enterprise Planning and Development of NUSCO. | ||
Charles W. Shivery | 65 | Chairman of the |
*
Deemed executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.
Jay S. Buth. Mr. Buth was elected Vice President - Accounting and Controller of NU, CL&P, PSNH and WMECO, effective June 9, 2009. Previously, Mr. Buth served as Controller, and Vice President and Controller at NJR Service Corporation, a subsidiary of New Jersey Resources Corporation, a gas utility holding company, from June 2006 to January 2009. He also served as Director - Finance at Allegheny Energy, Inc. from May 2004 to May 2006.
Gregory B. Butler. Mr. Butler was elected Senior Vice President and General Counsel of NU effective December 1, 2005, and of CL&P, PSNH and WMECO, subsidiaries of NU, effective March 9, 2006, and was elected a Director of CL&P, PSNH and WMECO April 22, 2009 and a Director of Northeast Utilities Foundation, Inc. effective December 1, 2002. Previously Mr. Butler served as Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005 and Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.
Jean M. LaVecchia. Ms. LaVecchia was elected Vice President - Human Resources of NUSCO, effective January 1, 2005 and was elected a Director of CL&P, PSNH and WMECO April 22, 2009 and a Director of Northeast Utilities Foundation, Inc. effective January 30, 2007. Previously Ms. LaVecchia served as Vice President - Human Resources and Environmental Services from May 1, 2001 to December 31, 2004.
David R. McHale. Mr. McHale was elected Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO, effective January 1, 2009, elected a Director of PSNH and WMECO, effective January 1, 2005, of CL&P effective January 15, 2007 and of Northeast Utilities Foundation, Inc. effective January 1, 2005. Previously, Mr. McHale served as Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO from January 1, 2005 to December 31, 2008 and Vice President and Treasurer of NU, PSNH and WMECO from July 1998 to December 31, 2004.
Leon J. Olivier. Mr. Olivier was elected Executive Vice President and Chief Operating Officer of NU effective May 13, 2008; He also has served as Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; a Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001. Previously, Mr. Olivier served as Executive Vice President - Operations of NU from February 13, 2007 to May 12, 2008; Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; and President and Chief Operating Officer of CL&P from September 2001 to January 2005.
James B. Robb. Mr. Robb was elected Senior Vice President, Enterprise Planning and Development of NUSCO on September 4, 2007 and was elected a Director of CL&P, PSNH and WMECO April 22, 2009. Previously, Mr. Robb served as Managing Director, Russell Reynolds Associates from December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; and Senior Vice President, Performance Management, Reliant Resources, Inc. from November 2002 to December 2003.
Charles W. Shivery. Mr. Shivery was elected Chairman of the Board, President and Chief Executive Officer of NU effective March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO effective January 19, 2007 and a Director of Northeast Utilities Foundation effective March 3, 2004. Previously, Mr. Shivery served as President (interim) of NU from January 1, 2004 to March 29, 2004; and President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.
Item 4.
[RESERVED]
22
PART II
Item 5.
Market for the Registrants' Common Equity and Related Stockholder Matters
NU. Our common shares are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low sales prices for the past two years, by quarter, are shown below.
Year |
| Quarter |
| High |
| Low | ||
|
|
|
|
|
|
|
|
|
2010 |
| First |
| $ | 28.00 |
| $ | 24.68 |
|
| Second |
|
| 28.21 |
|
| 24.83 |
|
| Third |
|
| 30.25 |
|
| 25.24 |
|
| Fourth |
|
| 32.21 |
|
| 29.51 |
|
|
|
|
|
|
|
|
|
2009 |
| First |
| $ | 25.05 |
| $ | 19.45 |
|
| Second |
|
| 22.40 |
|
| 19.99 |
|
| Third |
|
| 24.72 |
|
| 21.38 |
|
| Fourth |
|
| 26.33 |
|
| 22.54 |
There were no purchases made by or on behalf of our company or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2010.
As of January 31, 2011, there were 40,210 registered common shareholders of our company on record. As of the same date, there were a total of 195,808,704 common shares issued. There were no unallocated ESOP shares held in the ESOP trust as of December 31, 2010.
Pursuant to NU parent's Shareholder Rights Plan (the "Plan"), NU parent distributed to shareholders of record as of May 7, 1999, a dividend in the form of one common share purchase right (a "Right") for each common share owned by the shareholder. The Rights and the Plan expired at the end of the 10-year term on February 23, 2009.
On February 8, 2011, our Board of Trustees declared a dividend of 27.5 cents per share, payable on March 31, 2011 to shareholders of record as of March 1, 2011.
On October 12, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on December 31, 2010 to shareholders of record as of December 1, 2010.
On July 12, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on September 30, 2010 to shareholders of record as of September 1, 2010.
On April 13, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on June 30, 2010 to shareholders of record as of June 1, 2010.
On February 9, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on March 31, 2010 to shareholders of record as of March 1, 2010.
On October 13, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on December 31, 2009 to shareholders of record as of December 1, 2009.
On July 14, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on September 30, 2009 to shareholders of record as of September 1, 2009.
On April 14, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on June 30, 2009 to shareholders of record as of June 1, 2009.
On February 10, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on March 31, 2009 to shareholders of record as of March 1, 2009.
Information with respect to dividend restrictions for us, CL&P, PSNH, and WMECO is contained in Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations, under the caption "Liquidity" and Item 8,Financial Statements and Supplementary Data, in theCombined Notes to Consolidated Financial Statements, within this Annual Report on Form 10-K.
There is no established public trading market for the common stock of CL&P, PSNH and WMECO. All of the common stock of CL&P, PSNH and WMECO is held solely by NU.
During 2010 and 2009, CL&P approved and paid $217.7 million and $113.8 million, respectively, of common stock dividends to NU.
23
During 2010 and 2009, PSNH approved and paid $50.6 million and $40.8 million, respectively, of common stock dividends to NU.
During 2010 and 2009, WMECO approved and paid $14.9 million and $18.2 million, respectively, of common stock dividends to NU.
For information regarding securities authorized for issuance under equity compensation plans, see Item 12,Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, included in this Annual Report on Form 10-K.
Item 6.
Selected Consolidated Financial Data
NU Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and common |
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 |
| |||||
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| $ | 9,567,726 |
| $ | 8,839,965 |
| $ | 8,207,876 |
| $ | 7,229,945 |
| $ | 6,242,186 |
|
Total Assets |
|
| 14,522,042 |
|
| 14,057,679 |
|
| 13,988,480 |
|
| 11,581,822 |
|
| 11,303,236 |
|
Total Capitalization (a) |
|
| 8,627,985 |
|
| 8,253,323 |
|
| 7,293,960 |
|
| 6,667,920 |
|
| 5,879,691 |
|
Obligations Under Capital Leases (a) |
|
| 12,236 |
|
| 12,873 |
|
| 13,397 |
|
| 14,743 |
|
| 14,425 |
|
Income Statement Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
| $ | 4,898,167 |
| $ | 5,439,430 |
| $ | 5,800,095 |
| $ | 5,822,226 |
| $ | 6,877,687 |
|
Income from Continuing Operations |
|
| 394,107 |
|
| 335,592 |
|
| 266,387 |
|
| 251,455 |
|
| 138,495 |
|
Income from Discontinued Operations |
|
| - |
|
| - |
|
| - |
|
| 587 |
|
| 337,642 |
|
Net Income Attributable to Noncontrolling Interests |
|
| 6,158 |
|
| 5,559 |
|
| 5,559 |
|
| 5,559 |
|
| 5,559 |
|
Net Income Attributable to Controlling Interests |
| $ | 387,949 |
| $ | 330,033 |
| $ | 260,828 |
| $ | 246,483 |
| $ | 470,578 |
|
Common Share Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations |
| $ | 2.20 |
| $ | 1.91 |
| $ | 1.68 |
| $ | 1.59 |
| $ | 0.86 |
|
Income from Discontinued Operations |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 2.20 |
|
Net Income Attributable to Controlling Interests |
| $ | 2.20 |
| $ | 1.91 |
| $ | 1.68 |
| $ | 1.59 |
| $ | 3.06 |
|
Diluted Earnings Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations |
| $ | 2.19 |
| $ | 1.91 |
| $ | 1.67 |
| $ | 1.59 |
| $ | 0.86 |
|
Income from Discontinued Operations |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 2.19 |
|
Net Income Attributable to Controlling Interests |
| $ | 2.19 |
| $ | 1.91 |
| $ | 1.67 |
| $ | 1.59 |
| $ | 3.05 |
|
Weighted Average Common Shares Outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
| 176,636,086 |
|
| 172,567,928 |
|
| 155,531,846 |
|
| 154,759,727 |
|
| 153,767,527 |
|
Diluted |
|
| 176,885,387 |
|
| 172,717,246 |
|
| 155,999,240 |
|
| 155,304,361 |
|
| 154,146,669 |
|
Dividends Declared Per Share |
| $ | 1.03 |
| $ | 0.95 |
| $ | 0.83 |
| $ | 0.78 |
| $ | 0.73 |
|
Market Price - Closing (high) (b) |
| $ | 32.05 |
| $ | 26.33 |
| $ | 31.15 |
| $ | 33.53 |
| $ | 28.81 |
|
Market Price - Closing (low) (b) |
| $ | 24.78 |
| $ | 19.45 |
| $ | 19.15 |
| $ | 26.93 |
| $ | 19.24 |
|
Market Price - Closing (end of year) (b) |
| $ | 31.88 |
| $ | 25.79 |
| $ | 24.06 |
| $ | 31.31 |
| $ | 28.16 |
|
Book Value Per Share (end of year) |
| $ | 21.60 |
| $ | 20.37 |
| $ | 19.38 |
| $ | 18.79 |
| $ | 18.14 |
|
Tangible Book Value Per Share (end of year) (c) |
| $ | 19.97 |
| $ | 18.74 |
| $ | 17.54 |
| $ | 16.93 |
| $ | 16.28 |
|
Rate of Return Earned on Average Common |
|
| 10.7 |
|
| 10.2 |
|
| 8.8 |
|
| 8.6 |
|
| 18.0 |
|
Market-to-Book Ratio (end of year) (e) |
|
| 1.5 |
|
| 1.3 |
|
| 1.2 |
|
| 1.7 |
|
| 1.6 |
|
Capitalization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Equity |
|
| 44 | % |
| 44 | % |
| 41 | % |
| 44 | % |
| 48 | % |
Preferred Stock, not subject to mandatory redemption |
|
| 1 |
|
| 1 |
|
| 2 |
|
| 2 |
|
| 2 |
|
Long-Term Debt (a) |
|
| 55 |
|
| 55 |
|
| 57 |
|
| 54 |
|
| 50 |
|
|
|
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
| 100 | % |
(a)
Includes portions due within one year, but excludes RRBs for Long-Term Debt.
(b)
Market price information reflects closing prices as reflected by the New York Stock Exchange.
(c)
Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding.
(d)
Net Income divided by the average change in Common Shareholders' Equity.
(e)
The closing market price divided by the book value per share.
See theCombined Notes to the Consolidated Financial Statements for a description of any accounting changes materially affecting the comparability of the information reflected in the table above.
24
CL&P Selected Consolidated Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
|
|
| |||||
(Thousands of Dollars) |
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 |
| |||||
Operating Revenues |
| $ | 2,999,102 |
| $ | 3,424,538 |
| $ | 3,558,361 |
| $ | 3,681,817 |
| $ | 3,979,811 |
|
Net Income |
|
| 244,143 |
|
| 216,316 |
|
| 191,158 |
|
| 133,564 |
|
| 200,007 |
|
Cash Dividends on Common Stock |
|
| 217,691 |
|
| 113,848 |
|
| 106,461 |
|
| 79,181 |
|
| 63,732 |
|
Property, Plant and Equipment, Net |
|
| 5,586,504 |
|
| 5,340,561 |
|
| 5,089,124 |
|
| 4,401,846 |
|
| 3,634,370 |
|
Total Assets |
|
| 8,287,585 |
|
| 8,364,564 |
|
| 8,336,118 |
|
| 7,018,099 |
|
| 6,321,294 |
|
Rate Reduction Bonds |
|
| - |
|
| 195,587 |
|
| 378,195 |
|
| 548,686 |
|
| 743,899 |
|
Long-Term Debt (a) |
|
| 2,583,102 |
|
| 2,582,361 |
|
| 2,270,414 |
|
| 2,028,546 |
|
| 1,519,440 |
|
Preferred Stock Not Subject to Mandatory Redemption |
|
| 116,200 |
|
| 116,200 |
|
| 116,200 |
|
| 116,200 |
|
| 116,200 |
|
Obligations Under Capital Leases (a) |
|
| 10,613 |
|
| 10,956 |
|
| 11,207 |
|
| 13,602 |
|
| 14,264 |
|
PSNH Selected Consolidated Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
|
|
| |||||
(Thousands of Dollars) |
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 |
| |||||
Operating Revenues |
| $ | 1,033,439 |
| $ | 1,109,591 |
| $ | 1,141,202 |
| $ | 1,083,072 |
| $ | 1,140,900 |
|
Net Income |
|
| 90,067 |
|
| 65,570 |
|
| 58,067 |
|
| 54,434 |
|
| 35,323 |
|
Cash Dividends on Common Stock |
|
| 50,584 |
|
| 40,844 |
|
| 36,376 |
|
| 30,720 |
|
| 41,741 |
|
Property, Plant and Equipment, Net |
|
| 2,053,281 |
|
| 1,814,714 |
|
| 1,580,985 |
|
| 1,388,405 |
|
| 1,242,378 |
|
Total Assets |
|
| 2,889,840 |
|
| 2,697,191 |
|
| 2,628,833 |
|
| 2,106,969 |
|
| 2,071,276 |
|
Rate Reduction Bonds |
|
| 138,247 |
|
| 188,113 |
|
| 235,139 |
|
| 282,018 |
|
| 333,831 |
|
Long-Term Debt (a) |
|
| 836,365 |
|
| 836,255 |
|
| 686,779 |
|
| 576,997 |
|
| 507,099 |
|
Obligations Under Capital Leases (a) |
|
| 1,428 |
|
| 1,670 |
|
| 1,931 |
|
| 1,141 |
|
| 1,356 |
|
WMECO Selected Consolidated Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
| |||||||
(Thousands of Dollars) |
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 |
| |||||
Operating Revenues |
| $ | 395,161 |
| $ | 402,413 |
| $ | 441,527 |
| $ | 464,745 |
| $ | 431,509 |
|
Net Income |
|
| 23,090 |
|
| 26,196 |
|
| 18,330 |
|
| 23,604 |
|
| 15,644 |
|
Cash Dividends on Common Stock |
|
| 14,882 |
|
| 18,203 |
|
| 39,706 |
|
| 12,779 |
|
| 7,946 |
|
Property, Plant and Equipment, Net |
|
| 817,146 |
|
| 705,760 |
|
| 624,205 |
|
| 559,357 |
|
| 526,094 |
|
Total Assets |
|
| 1,199,559 |
|
| 1,101,800 |
|
| 1,048,489 |
|
| 991,088 |
|
| 988,693 |
|
Rate Reduction Bonds |
|
| 43,325 |
|
| 58,735 |
|
| 73,176 |
|
| 86,731 |
|
| 99,428 |
|
Long-Term Debt (a) |
|
| 400,288 |
|
| 305,475 |
|
| 303,868 |
|
| 303,872 |
|
| 261,777 |
|
Obligations Under Capital Leases (a) |
|
| 83 |
|
| 105 |
|
| 126 |
|
| - |
|
| - |
|
(a)
Includes portions due within one year, but excludes RRBs for Long-Term Debt.
25
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report on Form 10-K. References in this Annual Report to "NU," the "Company," "we," "us" and "our" refer to Northeast Utilities and its consolidated subsidiaries. All per share amounts are reported on a diluted basis.
Refer to the Glossary of Terms included in this Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the consolidated financial statements.
The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the net income or loss attributable to controlling interests of each business by the weighted average diluted NU common shares outstanding for the period. We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results and guidance by business. We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses. This non-GAAP financial measure should not be considered as an al ternative to our consolidated diluted EPS determined in accordance with GAAP as an indicator of operating performance.
The discussion below also includes non-GAAP financial measures referencing our 2010 earnings and EPS excluding expenses related to NU's proposed merger with NSTAR and certain non-recurring benefits from the settlement of tax issues as well as our 2008 earnings and EPS excluding a significant charge resulting from the settlement of litigation. We use these non-GAAP financial measures to more fully compare and explain the 2010, 2009 and 2008 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income, management believes that this non-GAAP presentation is more representative of our performance and provides additional and useful information to readers of this report in analyzing historical and future performance. These non-GAAP financial measures should not be considered as alternatives to reported Net Income Attributable to Controlling Interests or EPS deter mined in accordance with GAAP as indicators of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interests are included under "Financial Condition and Business Analysis-Overview-Consolidated" and "Financial Condition and Business Analysis-Future Outlook" inManagement's Discussion and Analysis, herein. All forward-looking information for 2011 and thereafter provided in thisManagement’s Discussion and Analysis assumes we will operate on a stand-alone basis, excluding the impacts of the proposed merger with NSTAR, unless otherwise indicated.
Financial Condition and Business Analysis
Current Economic Conditions:Proposed Merger with NSTAR: As widely reported,
On October 18, 2010, we and NSTAR announced that each company's Board of Trustees unanimously approved a Merger Agreement (the "agreement") to create a combined company that will be called Northeast Utilities. The transaction was structured as a merger of equals in a tax-free exchange. The post-transaction company will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire, representing over half of all the capitalcustomers in New England.
Under the terms of the agreement, NSTAR shareholders would receive 1.312 NU common shares for each NSTAR common share that they own (the "exchange ratio"). The exchange ratio was structured to result in a no premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement. Based on the number of NU common shares and credit markets are experiencing uncertaintyNSTAR common shares estimated to be outstanding immediately prior to the closing of the merger, upon such closing, NU shareholders will own approximately 56 percent of the post-transaction company and volatilityformer NSTAR shareholders will own approximately 44 percent of the post-transaction company. It is anticipated that we would issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger.
Subject to the conditions in the agreement, our first quarterly dividend per common share declared after the completion of the merger will be increased to an unprecedented extent. This disruptionamount that is equivalent, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing. Based on the last quarterly dividend paid by NSTAR, and assuming there are no changes to such dividend prior to the closing of the merger, this anticipated amount would be approximately $0.325 per share, or approximately $1.30 per share on an annualized basis.
Completion of the merger is subject to various customary conditions, including, among others, approval by holders of two-thirds of the outstanding common shares of each company and receipt of all required regulatory approvals. The companies anticipate that the regulatory approvals can be obtained to permit the merger to close in the second half of 2011. Special meetings of shareholders of both companies to approve the merger are scheduled for March 4, 2011. On November 24, 2010, NU and NSTAR filed a joint petition requesting Massachusetts DPU approval of their proposed merger by May 15, 2011. On January 5, 2011, a public hearing and procedural conference were held before the DPU. The schedule has weakenedsubsequently been suspended pending a decision on the appropriate standard of review for the merger. On January 4, 2011, we received approval from the FCC, and may continue to weaken economic conditions in parallelon February 10, 2011, the applicable Ha rt-Scott-Rodino waiting period expired. On January 7, 2011, NU and NSTAR filed an application with the general decline in consumer confidence in the Northeast and throughout the United States. So far, the limited access to capital and higher cost of capital for businesses and consumers has reduced spending, resulted in job losses, and pressured economic growth for the foreseeable future. These weak economic conditions have affected and could continue to affect our revenues and future earnings growth and could result in greater risk of default by our counterparties, including customers, weaker sales growth, increased energy conservation, and higher bad debt expense, among other things. The weak economic conditions are also expected to put pressure on our ab ility to obtain distribution rate relief or to receive approvals on major transmission projects that will ultimately increase customer rates. We have included our best estimateFERC, requesting approval of the impacts of these factors in the assumptions that were used to develop our earnings guidance; however, we are unable to predict the ultimate impact of these conditions on our results of operations, financial position, or liquidity.merger by May 10, 2011.
26
In November 2010, the DPUC issued a draft decision stating that it lacked jurisdiction over the merger. In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC to reconsider its draft decision. In January 2011, the DPUC issued an Administrative Order stating that it plans to hold a hearing to determine if it has jurisdiction over the merger. Oral arguments surrounding the draft decision were held in February 2011. The DPUC plans to hold an informational hearing at a date to be determined. In addition, we expectlegislation proposing to make significant levels of investments in our capital projects in 2009 through 2013. The disruptiongive the DPUC jurisdiction over the merger may be introduced in the capital markets has limited some companies’ ability to access the capital and credit markets to support their operations and refinance debt and has led to higher financing costs compared to recent years. We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for our capital requirements, including construction costs. We believe our current credit ratings will allow us to have access to the capital markets as needed (as evidenced by CL&P's issuance of $250 million of 10-year bonds in February 2009 at 5.5 percent). However, events beyond our control, such as the disruption in global capital and credit markets that occurred in September 2008, may create further uncertainty that could increase our cost of capital or impair our ability to access the capital markets. In addition, certain of NU’s subsidiaries rely, in part, on NU parent for access to capital. Circumstances that limit NU parent’s access to capital could impair its ability to provide those companies with needed capital. At this point in time, while the impact of continued market volatility and the extent and impacts of the ongoing economic downturn cannot be predicted, we currently believe that we have sufficient operating flexibility and access to funding sources to maintain adequate liquidity.Connecticut legislature.
Executive Summary
The following items in this executive summary are explained in more detail in this Annual Report:
Results, Strategy and Outlook:Results:
·
We earned $260.8$387.9 million, or $1.67$2.19 per share, in 2008,2010, compared with $246.5$330 million, or $1.59$1.91 per share, in 2007. Results for 2008 included an after-tax charge2009. Improved results were due primarily to the impact of $29.8 million, or $0.19 per share, resultingthe CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010, higher retail electric sales due to weather impacts, the non-recurring benefits from the settlement of litigationtax issues in the fourth quarter of 2010, and our continued success in managing operation and maintenance costs. These benefits were partially offset by higher pension and storm-related expenses and expenses related to our proposed merger with Con Edison. Excluding that charge, our earnings in 2008 were $290.6NSTAR.
·
Our Regulated companies earned $384 million, or $1.86 per share.
29
·
After payment of CL&P preferred dividends, our regulated companies, which consist of CL&P, Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Yankee Gas Services Company (Yankee Gas), earned $289.1 million, or $1.85$2.16 per share, in 2008,2010, compared with $228.7$323.5 million, or $1.47$1.87 per share, in 2007. The 2008 results included earnings of $150.8 million in2009.
·
Earnings from the distribution segment of our Regulated companies (which also includes the generation segmentbusinesses of PSNH and WMECO and the natural gas distribution segmentbusiness of Yankee Gas), and $138.3 totaled $206.2 million, or $1.16 per share, in 2010, compared with $159.2 million, or $0.92 per share, in 2009. Earnings from the transmission segment. In 2007,segment of our distribution segment earned $146.2Regulated companies totaled $177.8 million, and our transmission segment earned $82.5 million. or $1.00 per share, in 2010, compared with $164.3 million, or $0.95 per share, in 2009.
·
Our competitive businesses, orwhich are held by NU Enterprises, Inc. (NU Enterprises), earned $13.1$8.3 million, or $0.08$0.05 per share, in 2008,2010, compared with $11.7$15.8 million, or $0.08$0.09 per share, in 2007.2009. NU Enterprises recorded $0.7 million of after-tax mark-to-market gains in 2010, compared with $3.8 million of after-tax mark-to-market gains in 2009.
·
NU parent and other companies recorded net expenses of $41.4$4.4 million, or $0.26$0.02 per share, in 2008,2010, compared with net incomeexpenses of $6.1$9.3 million, or $0.04$0.05 per share, in 2007. Excluding2009. The 2010 results include a fourth quarter non-recurring benefit of $15.7 million, or $0.09 per share, associated with the litigation settlement of tax issues and a fourth quarter after-tax charge of $9.4 million, or $0.06 per share, associated with expenses related to Con Edison,NU’s proposed merger with NSTAR.
Outlook:
·
Excluding certain non-recurring costs related to our proposed merger with NSTAR of approximately $0.15 per share, we project consolidated 2011 earnings of between $2.25 per share and $2.40 per share. This projection includes distribution segment earnings of between $1.25 per share and $1.35 per share, transmission segment earnings of between $1.05 per share and $1.10 per share, and net expenses at NU parent and other companies recorded net expenses of $11.6 million, or $0.07approximately $0.05 per share, excluding merger-related costs of approximately $0.15 per share. The number of outstanding NU common shares used to calculate this guidance is approximately 177 million shares. Results from our competitive businesses are factored into the NU parent and other companies’ results. This projection assumes we will operate on a stand-alone basis in 2008.
·
In 2008, CL&P completed2011, although our proposed merger with NSTAR is expected to close in the final threesecond half of its four major transmission projects in southwest Connecticut. The projects were completed approximately $80 million below their $1.68 billion budget and the final project was completed approximately one year ahead of schedule. Also, in October 2008, CL&P and WMECO filed siting applications to build their portions of the $714 million Greater Springfield Reliability Project, which is the largest project within the New England East-West Solutions (NEEWS) series of projects. Refer to "Business Developments and Capital Expenditures - Regulated Companies - Transmission Segment" in this Management’s Discussion and Analysis for further discussion.20 11.
·
We project consolidated 2009 earningsa compound average annual EPS growth rate through 2015 of between $1.806 percent and 9 percent using 2009 EPS of $1.91 per share and $2.00 per share, including earningsas the base level. Assuming completion of between $1.00 per share and $1.10 per shareour proposed merger with NSTAR, we expect our EPS growth rate will be at our distribution segment, between $0.85 per share and $0.90 per share at our transmission segment and between $0.00 per share and $0.05 per share at our remaining competitive businesses, and net expensesthe higher end of $0.05 per share at NU parent and other companies. This projection assumes the issuance of between $250 million and $300 million of additional equity in mid-2009. Our 2009 forecast reflects our expectations of lower electric sales and higher pension and uncollectible expense than what we experienced in 2008, due to current economic conditions. this range.
·
We project capital expenditures for 2011 through 2015 of approximately $6.6 billion (approximately $1.2 billion in 2011). During 2008,that time period, we announced thatexpect our corporate headquarters will be relocatedRegulated company rate base to increase from its current location in Berlin, Connecticutapproximately $7.3 billion at the end of 2010 to a recently purchased office building in downtown Hartford, Connecticut. We expect to move approximately 175 corporate employees into Hartford by$11.4 billion at the summerend of 2009.
Legal, Regulatory and Other Items:2015, excluding any impacts from the merger.
·
On January 28, 2008,February 8, 2011, our Board of Trustees declared a quarterly common dividend of $0.275 per share, payable on March 31, 2011 to shareholders of record as of March 1, 2011, which equates to $1.10 per share on an annualized basis. Assuming completion of our proposed merger with NSTAR, based on the Connecticut Departmentlast quarterly dividend paid by NSTAR of Public Utility Control (DPUC) approved$0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, our first quarterly dividend per common share declared would be approximately $0.325 per share, or approximately $1.30 per share on an increase in CL&P’s annual distribution rates of $77.8 million, effective February 1, 2008, and an incremental $20.1 million annual increase, effective February 1, 2009.annualized basis.
·
On March 13, 2008, we entered into a settlement agreement with Con Edison that settled all claims in the civil lawsuit between Con EdisonStrategy, Regulatory and us relating to our proposed but unconsummated merger. Under the terms of the settlement agreement, we paid Con Edison $49.5 million on March 26, 2008, which resulted in an after-tax charge of $29.8 million. This amount is not recoverable from ratepayers.
·
On March 24, 2008, the Federal Energy Regulatory Commission (FERC) issued a rehearing order confirming its initial decision setting the base return on equity (ROE) for transmission projects for the New England transmission owners. Including a final adjustment, the order provides a base ROE of 11.14 percent for the period beginning November 1, 2006. The order also affirmed FERC's earlier decision granting a 100 basis point adder for transmission projects that are part of the New England Independent System Operator (ISO-NE) Regional System Plan and are completed and on line by December 31, 2008. In 2008, we added $6 million ($4.9 million for CL&P) in transmission segment earnings related to this order.
·
On June 11, 2008, the DPUC issued a final order requiring Yankee Gas to refund to customers approximately $5.8 million in previous recoveries through Yankee Gas' Purchased Gas Adjustment (PGA) clause. Yankee Gas results for 2008 reflect an after-tax charge of $3.5 million associated with that decision.
·
On July 16, 2008, the Massachusetts Department of Public Utilities (DPU) issued a decision requiring all gas and electric utilities to file full decoupling proposals with their next general rate case. On September 2, 2008, WMECO notified the DPU that it expects to file its next distribution rate case in mid-2010 to be effective January 1, 2011. The distribution rate case will include a proposal to fully decouple distribution revenues from kilowatt-hour (KWH) sales.
·
On July 17, 2008, the FERC confirmed the 100 basis point incentive ROE for the Middletown-Norwalk transmission project and approved an additional 50 basis points, capped at the overall ROE limit, to the ROE CL&P will earn on the advanced technology aspects of its 24-mile underground portion of the 69-mile project, which entered service in December 2008. This decision adds approximately $0.9 million to CL&P’s annual transmission segment earnings beginning in 2009.
·
In October 2008, CL&P had entered into contracts for differences (CfDs) with developers of three peaking generation units approved by the DPUC. These units will have a total of approximately 500 megawatts (MW) of peaking capacity. As directed by the DPUC, CL&P and The United Illuminating Company (UI) entered into a sharing agreement, whereby CL&P is responsible for
30
80 percent and UI for 20 percent of the net costs or benefits of these CfDs. CL&P’s portion of the costs and benefits will be paid by or refunded to its customers.
·
On November 17, 2008, the FERC issued an order granting incentives and rate amendments to National Grid USA and us for NEEWS transmission upgrade components. Our portion of these components is currently estimated to comprise about $1.41 billion of the total $1.49 billion cost estimate for our portion of NEEWS. The approved incentives included cash recovery through rates for 100 percent construction work in progress (CWIP), an incentive ROE of 12.89 percent and recovery of prudently incurred costs associated with project elements that may be cancelled for reasons outside of our control or National Grid USA's control.
·
On December 11, 2008, a major ice storm struck portions of New England causing approximately $100 million of damage to PSNH's, WMECO's and CL&P's distribution systems. This was the most severe ice storm in PSNH's history, and most of the $100 million in damages was to its system. CL&P’s system suffered the least amount of damage from the storm. Some of these costs are covered by insurance, a small portion was expensed in 2008 and the balance should be recoverable in future rates and has been deferred or capitalized. None of the companies experienced a material impact to their results of operations from this storm.
·
On December 12, 2008, NU and NSTAR submitted a joint petition for a declaratory order to the FERC to allow NU and NSTAR to enter into a bilateral transmission services agreement with H.Q. Energy Services (U.S.) Inc. (HQUS), a wholly-owned subsidiary of Hydro-Québec. Under such an agreement, NU and NSTAR would sell 1,200 MW of firm electric transmission service over a newly constructed, participant-funded transmission tie line connecting New England with the Hydro-Québec system in order for HQUS to sell and deliver into New England this same amount of firm electric power from Canadian low-carbon energy resources. NU, NSTAR and HQUS have signed memoranda of understanding to develop this transmission project on an exclusive basis. Our portion of this project is currently estimated to cost approximately $525 million. Refer to "Business Development and Capital Expenditures" in t his Management’s Discussion and Analysis for further discussion.
·
On January 15, 2009, the DPUC issued a final decision reversing its December 2005 draft decision regarding CL&P’s proposed methodology to calculate the variable incentive portion of its transition service procurement fee in 2004. The final decision concluded that CL&P was not eligible for this procurement incentive. CL&P recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings. A $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of CL&P, and an obligation to refund the $5.8 million to customers was established as of December 31, 2008. CL&P filed an appeal of this decision on February 26, 2009.
LiquidityOther Items::
·
While the impact of continued market volatility and the extent and impacts of any economic downturn cannot be predicted, we currently believe that we have sufficient operating flexibility and access to funding sources to maintain adequate liquidity (as evidenced by CL&P's issuance of $250 million of 10-year bonds in February 2009 at 5.5 percent). The credit outlooks for NU parent and our regulated companies are all stable. Our companies have modest risk of calls for collateral. We also have only one series of bonds maturing before 2012 ($50 million in the second quarter of 2009), and capital expenditures projected for 2009 are significantly less than 2008. No cash contributions to our pension plan are required during 2009; however, due to the substantial decrease in our pension plan assets in 2008 and unless there is a change in current funding requirements, we will be required to make an estimated $150 million contribution in 2010. Refer to "Liquidity - Impact of Financial Market Conditions" in this Management’s Discussion and Analysis for further discussion.
·
Our cash capital expenditures totaled $1.3 billion in 2008, compared with $1.1 billion in 2007. We were successful in meeting our extensive 2008 capital plan. In 2009, we expect cash capital expenditures to be approximately $880 million, primarily because of lower transmission capital expenditures at CL&P.
·
We issued $760 million of long-term debt in 2008 at rates of between 5.65 percent and 6.9 percent, and $250 million in February 2009 at a rate of 5.5 percent. We expect further external financings totaling $400 million to $450 million in mid-2009 (or earlier depending on market opportunities), including approximately $150 million of long-term debt by PSNH, subject to regulatory approval, and between $250 million and $300 million of additional equity by NU parent. Refer to "Liquidity" in this Management’s Discussion and Analysis for further discussion.
·
On June 30, 2008, due2010, the DPUC issued a final decision in CL&P's distribution rate case that approved annualized rate increases of $63.4 million effective July 1, 2010 and an additional $38.5 million effective July 1, 2011. The decision approved CL&P’s proposal to defer implementation of the availabilityfirst increase by six months until January 1, 2011 and lower relative costmaintained CL&P’s authorized distribution segment regulatory ROE of other liquidity sources, CL&P chose to terminate the arrangement under which CL&P could sell to a financial institution up to $100 million of accounts receivable and unbilled revenues.9.4 percent.
27
·
AfterOn June 28, 2010, the NHPUC approved the distribution rate case settlement agreement among PSNH, the NHPUC staff and the Office of Consumer Advocate. Under the agreement, the settling parties agreed to a net annualized distribution rate increase of $45.5 million, effective July 1, 2010, and annualized distribution rate adjustments projected to be a decrease of $2.9 million and increases of $9.5 million and $11.1 million on July 1 of each of the three subsequent years. PSNH’s authorized distribution business regulatory ROE remained at 9.67 percent.
·
On January 31, 2011, the DPU issued a final decision in WMECO's distribution rate case that approved an annualized rate increase of $16.8 million effective February 1, 2011 and an authorized distribution segment regulatory ROE of 9.6 percent.
·
On January 7, 2011, Yankee Gas filed an application with the DPUC to increase distribution rates by $32.8 million effective July 1, 2011 and by an additional $13 million effective July 1, 2012. Among other items, Yankee Gas requested to maintain its current authorized regulatory ROE of 10.1 percent. A final decision is expected in June 2011.
·
On February 11, 2011, the FERC accepted without modification the TSA that NPT and Hydro Renewable Energy entered into in connection with the Northern Pass transmission project. Assuming timely receipt of other regulatory reviews and siting approvals, NPT expects to place the project in service in late 2015.
·
CL&P and WMECO have received siting approvals in Connecticut and Massachusetts, respectively, for the first and largest component of our NEEWS project, GSRP, which involves the construction of 115 KV and 345 KV lines from Ludlow, Massachusetts, to Bloomfield, Connecticut. We commenced substation construction in December 2010, and expect to begin overhead line construction in the first half of 2011. We expect the cost of this project to be $795 million and to place the project in service in late 2013.
·
Construction of PSNH’s Clean Air Project at Merrimack Station was approximately 80 percent complete as of December 31, 2010 and is projected to cost approximately $430 million, which is approximately $27 million below the project’s previously announced cost of $457 million. The project must be operational by July 1, 2013, but PSNH expects it will commence operations by mid-2012.
·
On December 17, 2010, President Obama signed into law the 2010 Tax Act. We expect the 2010 Tax Act to provide NU with cash flow benefits of approximately $250 million in 2011 and approximately $450 million to $550 million over the period 2011 through 2013.
Liquidity:
·
Cash capital expenditures totaled $954.5 million in 2010, compared with $908.1 million in 2009.
·
Cash flows provided by operating activities in 2010 totaled $832.6 million, compared with $745 million in 2009 (amounts are net of RRB payments). The improved cash flows were due primarily to the absence in 2010 of costs incurred at PSNH and WMECO related to the major storm in December 2008 that were paid in the first quarter of 2009, a decrease in Fuel, Materials and Supplies attributable to a $31.8 million reduction bond (RRB) payments included in financing activities,coal inventory levels at PSNH, and increases in amortization on regulatory deferrals within PSNH’s ES and CL&P’s CTA tracking mechanisms. Offsetting these favorable cash flow impacts was a $45 million contribution to our Pension Plan. Excluding the impact of our proposed merger with NSTAR, we hadproject 2011 cash flows provided by operations in 2008operating activities, net of $418.5RRB payments, of approximately $950 million which represented anto $1 billion. The increase of $429.8 million from 2007. This increase was primarilyover 2010 is due prim arily to the absence in 2008 of approximately $400 million in tax payments in 2007 related to the 2006 saleaccelerated depreciation provisions of the competitive generation business,2010 Tax Act and the impact of the 2010 distribution rate case decisions. Those benefits are partially offset by the litigation settlement paymentprojected 2011 contributions to Con Edisonour Pension Plan of $49.5 million in 2008. Refer to "Liquidity - Consolidated" in this Management’s Discussion and Analysis for further discussion.approximately $145 million.
·
In 2009, we project operatingCash and cash flowsequivalents totaled $23.4 million as of approximately $500December 31, 2010, compared with $27 million after repaymentas of RRBs. This projection does not include any contributions to our pension plan, as they are not required to be paid inDecember 31, 2009. The primary reasons for the projected increase from 2008 are that our major southwest Connecticut transmission projects will be fully reflected in rates in 2009 due to their
31
completion in the second half of 2008 and that the 2008 Con Edison settlement payment is absent in 2009, partially offset by the payment in 2009 of major storm costs incurred in December 2008 that likely will not be fully recovered from customers in 2009. Excluding potential contributions to our pension plan, we currently project our internally-generated cash flows to grow to approximately $1 billion by 2013.
·
On September 24, 2010, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a three-year $400 million unsecured revolving credit facility, replacing a five-year $400 million credit facility that was scheduled to expire on November 6, 2010. On September 24, 2010, NU parent entered into a three-year $500 million unsecured revolving credit facility, replacing a five-year $500 million credit facility that was scheduled to expire on November 6, 2010. Both new revolving credit facilities expire on September 24, 2013. As of February 25, 2009,December 31, 2010, we had approximately $466$600.9 million of externally invested cash. At this time, we also had approximately $51 million ofaggregate borrowing availability on our revolving credit lines, excluding the remaining unfunded commitmentas compared to $702.8 million as of Lehman Brothers Commercial Bank (LBCB) (refer to "Liquidity - Impact of Financial Market Conditions" for further discussion). December 31, 2009.
·
We issued $145 million of new long-term debt in 2010, consisting of $95 million by WMECO and $50 million by Yankee Gas. Additionally, CL&P remarketed $62 million of tax-exempt PCRBs. In 2011, in addition to remarketing the CL&P $62 million PCRBs, we expect to issue approximately $260 million of long-term debt comprised of $160 million by PSNH and $100 million by WMECO in the second half of 2011. We have no debt maturities until April 2012.
Overview
Consolidated:We earned $387.9 million, or $2.19 per share, in 2010, compared with $330 million, or $1.91 per share, in 2009 and $260.8 million, or $1.67 per share, in 2008, compared with $246.5 million, or $1.59 per share, in 20072008. Improved results were due primarily to the impact of the CL&P and $470.6 million, or $3.05 per share, in 2006. Results for 2008 included an after-tax charge of $29.8 million, or $0.19 per share, resultingPSNH 2010 distribution rate case decisions that were effective July 1, 2010, higher retail electric sales due to warmer than normal summer weather and colder than normal December 2010 weather, the non-recurring benefits from the settlement of litigation with Con Edison. Excluding that charge,tax issues in the fourth quarter of 2010, lower uncollectibles expense, our continued success in managing operation and maintenance costs, and increased earnings in 2008the
28
transmission segment. These benefits were $290.6 million, or $1.86 per share. Results for 2006 included an after-tax gain of $314 million, or $2.03 per share,partially offset by higher pension and storm-related expenses, expenses related to our proposed merger with NSTAR, charges associated with the saleenactment of the 2010 Healthcare Act, and lower earnings at our competitive generation business, and a reductionbusinesses. Due primarily to weather impacts, retail electric sales were up 1.7 percent in income tax expense at CL&P of $74 million, or $0.48 per share, pursuant to a PLR received from the IRS. Results in 2007 and 2006 included discretionary pre-tax donations to the NU Foundation (Foundation) of $3 million and $25 million, respectively. There was no such contribution in 2008. 2010 compared with 2009.
A summary of our earnings by business, which als oalso reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by segment,business, to the most directly comparable GAAP measures of consolidated net incomeNet Income Attributable to Controlling Interests and fully diluted EPS, for 2008, 20072010, 2009 and 20062008 is as follows:
|
| For the Years Ended December 31, | ||||||||||||||||
|
| 2008 |
| 2007 |
| 2006 | ||||||||||||
(Millions of Dollars, except |
| Amount |
| Per Share |
| Amount |
| Per Share |
| Amount |
| Per Share | ||||||
Net Income (GAAP) |
| $ | 260.8 |
| $ | 1.67 |
| $ | 246.5 |
| $ | 1.59 |
| $ | 470.6 |
| $ | 3.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated companies |
| $ | 289.1 |
| $ | 1.85 |
| $ | 228.7 |
| $ | 1.47 |
| $ | 183.3 |
| $ | 1.19 |
Competitive businesses |
|
| 13.1 |
|
| 0.08 |
|
| 11.7 |
|
| 0.08 |
|
| (102.7) |
|
| (0.66) |
NU parent and other companies |
|
| (11.6) |
|
| (0.07) |
|
| 6.1 |
|
| 0.04 |
|
| 2.0 |
|
| 0.01 |
Non-GAAP earnings |
|
| 290.6 |
|
| 1.86 |
|
| 246.5 |
|
| 1.59 |
|
| 82.6 |
|
| 0.54 |
Con Edison litigation charge |
|
| (29.8) |
|
| (0.19) |
|
| - |
|
| - |
|
| - |
|
| - |
Gain on sale of competitive |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reduction in income tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (GAAP) |
| $ | 260.8 |
| $ | 1.67 |
| $ | 246.5 |
| $ | 1.59 |
| $ | 470.6 |
| $ | 3.05 |
|
| For the Years Ended December 31, | ||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | ||||||||||||
(Millions of Dollars, except |
| Amount |
| Per Share |
| Amount |
| Per Share |
| Amount |
| Per Share | ||||||
Net Income Attributable to |
| $ | 387.9 |
| $ | 2.19 |
| $ | 330.0 |
| $ | 1.91 |
| $ | 260.8 |
| $ | 1.67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Companies |
| $ | 384.0 |
| $ | 2.16 |
| $ | 323.5 |
| $ | 1.87 |
| $ | 289.1 |
| $ | 1.85 |
Competitive Businesses |
|
| 8.3 |
|
| 0.05 |
|
| 15.8 |
|
| 0.09 |
|
| 13.1 |
|
| 0.08 |
NU Parent and Other Companies |
|
| (10.7) |
|
| (0.05) |
|
| (9.3) |
|
| (0.05) |
|
| (11.6) |
|
| (0.07) |
Non-GAAP Earnings |
|
| 381.6 |
|
| 2.16 |
|
| 330.0 |
|
| 1.91 |
|
| 290.6 |
|
| 1.86 |
Non-Recurring Tax Settlements |
|
| 15.7 |
|
| 0.09 |
|
| - |
|
| - |
|
| - |
|
| - |
Merger-Related Costs (after-tax) |
|
| (9.4) |
|
| (0.06) |
|
| - |
|
| - |
|
| - |
|
| - |
Litigation Charge (after-tax) |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (29.8) |
|
| (0.19) |
Net Income Attributable to |
| $ | 387.9 |
| $ | 2.19 |
| $ | 330.0 |
| $ | 1.91 |
| $ | 260.8 |
| $ | 1.67 |
Regulated Companies:Our regulatedRegulated companies segment their earnings between theirconsist of the distribution and electric transmission segments, and their electric andwith Yankee Gas natural gas distribution segments, withsegment and PSNH and WMECO generation activities included in the electric distribution segment. A summary of regulated companyour Regulated companies' earnings by segment for 2008, 20072010, 2009 and 20062008 is as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
CL&P Transmission* |
| $ | 115.6 |
| $ | 66.7 |
| $ | 46.9 |
PSNH Transmission |
|
| 16.7 |
|
| 10.7 |
|
| 8.3 |
WMECO Transmission |
|
| 6.0 |
|
| 5.1 |
|
| 4.6 |
Total Transmission* |
| $ | 138.3 |
| $ | 82.5 |
| $ | 59.8 |
CL&P Distribution* |
| $ | 70.0 |
| $ | 61.4 |
| $ | 147.6 |
PSNH Distribution |
|
| 41.4 |
|
| 43.7 |
|
| 27.0 |
WMECO Distribution |
|
| 12.3 |
|
| 18.5 |
|
| 11.0 |
Yankee Gas |
|
| 27.1 |
|
| 22.6 |
|
| 11.9 |
Total Distribution* |
| $ | 150.8 |
| $ | 146.2 |
| $ | 197.5 |
Net Income - Regulated Companies* |
| $ | 289.1 |
| $ | 228.7 |
| $ | 257.3 |
*After preferred dividends of CL&P in all years.
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2008 | |||
CL&P Transmission |
| $ | 143.9 |
| $ | 136.8 |
| $ | 115.6 |
PSNH Transmission |
|
| 20.7 |
|
| 18.0 |
|
| 16.7 |
WMECO Transmission |
|
| 13.0 |
|
| 9.5 |
|
| 6.0 |
NUTV |
|
| 0.2 |
|
| - |
|
| - |
Total Transmission |
| $ | 177.8 |
| $ | 164.3 |
| $ | 138.3 |
CL&P Distribution |
| $ | 94.1 |
| $ | 74.0 |
| $ | 70.0 |
PSNH Distribution |
|
| 69.3 |
|
| 47.5 |
|
| 41.4 |
WMECO Distribution |
|
| 10.1 |
|
| 16.7 |
|
| 12.3 |
Yankee Gas |
|
| 32.7 |
|
| 21.0 |
|
| 27.1 |
Total Distribution |
| $ | 206.2 |
| $ | 159.2 |
| $ | 150.8 |
Net Income - Regulated Companies |
| $ | 384.0 |
| $ | 323.5 |
| $ | 289.1 |
The higher 20082010 and 20072009 transmission segment earnings reflect a higher level ofincreasing investment in this segment as we continued to build out our transmission infrastructure to meet the region’s reliability needs. CL&P’sneeds of our customers and the region. Our transmission segment earnings increased primarily due to the investment by CL&P of approximately $1.6 billion since the beginning of 2005 in the southwest Connecticut transmission projects that were completed in 2008. At December 31, 2008, our transmission segment rate base was approximately $2.4totaled $2.76 billion at the end of 2010, compared with approximately $1.5$2.6 billion at December 31, 2007.the end of 2009.
CL&P’s 20082010 distribution segment earnings were $8.6$20.1 million higher than 20072009 due primarily due to higher distribution revenues resulting from athe DPUC distribution rate increasecase decision that was effective FebruaryJuly 1, 2008,2010. The decision allowed CL&P to defer operating and maintenance expenses for the last six months of 2010 in lieu of cash rate relief until new rates begin on January 1, 2011. CL&P’s 2010 earnings also benefitted from lower depreciation expense as authorized in the distribution rate case decision, lower interest expense as a settlementresult of federalthe favorable resolution of state tax matters, aaudits in the fourth quarter of 2010, and lower effective income tax rate,uncollectibles expenses. Partially offsetting these favorable items were higher storm restoration costs and higher other revenues resulting from financial incentives under Connecticut's "Act Concerning Energy Independence"pension costs. CL&P’s 2010 retail electric sales were 1.8 percent higher than 2009 due primarily to promote distributed generation and demand side management. These items were partially offset by a 3.7 percent decline in sales, higher operating costs, including full-year storm expenses, maintenance expenses, and interest expense, a $5.8 million pre-tax charge to refundwarmer than normal weather during the 2004 procurement incentive fee that was recognized in 2005 earnings, and losses on investments in the Trust Under
32
Supplemental Executive Retirement Plan ("supplemental benefit trust").summer of 2010. CL&P’s distribution segment Regulatorysegm ent regulatory ROE was 7.5 percent in 2008 and 7.9 percent in 2007.2010 compared to 7.3 percent in 2009. We expect CL&P’s distribution segment Regulatoryregulatory ROE in 2009 will be approximately 7 percent. 9 percent in 2011.
PSNH’s 2010 distribution segment earnings were $21.8 million higher than 2009. The improved performance in 2010 was due primarily to higher revenues as a result of distribution rate increases effective August 1, 2009 and July 1, 2010, higher AFUDC earnings related to the Clean Air Project capital expenditures, and higher retail electric sales of 1.3 percent due primarily to warmer than normal weather during the summer of 2010. The permanent distribution rate case settlement approved on June 28, 2010 allowed for certain costs to be recovered retroactive to August 1, 2009. These favorable items were partially offset by higher expenses, including employee benefit costs, storm restoration costs, depreciation, interest expense and income taxes as a result of a higher effective tax rate in 2010. PSNH’s distribution segment regulatory ROE was 10.2 percent (including generation) in 2010, compared to 7.2 per cent in 2009. We expect PSNH’s distribution segment regulatory ROE will be approximately 9 percent in 2011.
WMECO’s 2010 distribution segment earnings in 2008 were $2.3$6.6 million lower than 2007. The decrease in 2008 earnings was2009 due primarily due to higher operating costs including full-year storm expenses,restoration costs, employee benefit costs, depreciation and interestproperty taxes as well as a net $2.1 million after-tax charge primarily related to uncollectibles expense as a 2.5 percent decline in sales, losses onresult of the supplemental benefit trust andoutcome of the absence of a $4.5 million pre-tax benefitdistribution rate case decision from the implementation of the retail transmission cost tracking mechanism in the second quarter of 2007.DPU on January 31, 2011. These
29
unfavorable items were partially offset by an increase in PSNH’sstronger retail distribution revenues that resulted from distribution rate increases on July 1, 2007 and January 1, 2008, a pre-tax adjustmentrevenues. WMECO’s 2010 retail electric sales were 2.4 percent higher than 2009 due primarily to its generation cost recovery mechanismwarmer than normal weather during the summer of $1.9 million, and a settlement of federal tax matters. PSNH’s distribution segment Regulatory ROE was 8.3 percent in 2008 and 9.5 percent in 2007. We expect PSNH’s distribution segment Regulatory ROE in 2009 will be app roximately 8 percent, with the earnings of the generation portion of this segment based on its authorized ROE of 9.8 percent.
WMECO’s 2008 distribution segment earnings were $6.2 million lower than 2007 primarily due to higher operating costs, including full-year storm expenses, and uncollectibles expense, a 4.2 percent decline in sales, a $1.6 million pre-tax charge related to a DPU ruling on WMECO’s 2005 and 2006 transition cost reconciliations, a $1.3 million pre-tax charge for potential refunds to customers from an assessment under the DPU’s service quality index criteria, and losses on the supplemental benefit trust. These items were partially offset by a $3 million annualized distribution rate increase that took effect January 1, 2008 and a settlement of federal tax matters.2010. WMECO’s distribution segment Regulatoryregulatory ROE was 7.24.6 percent in 2008 and 9.72010 compared to 8.4 percent in 2007.2009. On January 31, 2011, the DPU authorized a distribution segment regulatory ROE of 9.6 percent as part of its distribution rate case decision. We expect WMECO’s distribution segment Regulatoryregulatory ROE in 2009 will be approximately 8 percent.9 percent in 2011.
Yankee Gas’ 2010 earnings in 2008 were $4.5$11.7 million higher than 20072009 due primarily dueto lower uncollectibles expenses, higher revenues attributable to a distribution rate increase that took effect on July 1, 2007 and a 2.11.9 percent increase in firm natural gas sales. These increasessales as compared to 2009, and lower depreciation expense. Partially offsetting these favorable items were partially offset by higher operating costs, including uncollectibles expense, maintenance expense, and interest expense, and a DPUC order requiring Yankee Gas to refund $5.8 million of previous gas cost recoveries.employee benefit costs. Yankee Gas’ Regulatoryregulatory ROE was 8.38.6 percent in 2008 and 8.72010 compared to 6.6 percent in 2007. We expect2009. In June 2011 we anticipate the DPUC will issue a decision on Yankee Gas’ Regulatoryrequest to raise its distribution rates effective July 1, 2011. Yankee Gas’ request includes a recommendation to maintain its authorized regulatory ROE in 2009 will be approximately 9of 10.1 percent.
For the distribution segment of our regulatedRegulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric KWHGWh sales and Yankee Gas firm natural gas sales for 20082010 as compared to 20072009 on an actual and weather normalized basis (using a 30-year average) is as follows:
|
| Electric |
| Firm Natural Gas | ||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO |
| Total |
| Yankee Gas | ||||||||||
|
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
Residential |
| (4.1)% |
| (2.7)% |
| (2.2)% |
| (1.0)% |
| (3.1)% |
| (2.1)% |
| (3.6)% |
| (2.3)% |
| (2.0)% |
| (0.1)% |
Commercial |
| (1.3)% |
| (0.7)% |
| (1.2)% |
| (0.4)% |
| (2.6)% |
| (2.1)% |
| (1.4)% |
| (0.8)% |
| (0.2)% |
| 1.4 % |
Industrial |
| (9.8)% |
| (9.3)% |
| (6.1)% |
| (5.4)% |
| (8.7)% |
| (8.5)% |
| (8.6)% |
| (8.1)% |
| 9.2 % |
| 9.6 % |
Other |
| (3.2)% |
| (3.2)% |
| 2.2 % |
| 2.2 % |
| (14.6)% |
| (14.6)% |
| (3.7)% |
| (3.7)% |
| - % |
| - % |
Total |
| (3.7)% |
| (2.8)% |
| (2.5)% |
| (1.6)% |
| (4.2)% |
| (3.5)% |
| (3.5)% |
| (2.6)% |
| 2.1 % |
| 3.4 % |
|
| Electric |
| Firm Natural Gas | ||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO |
| Total |
| Yankee Gas | ||||||||||
|
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
|
|
| Weather |
Residential |
| 3.5% |
| (1.0)% |
| 2.5% |
| (0.5)% |
| 5.1% |
| 1.4% |
| 3.5% |
| (0.7)% |
| (1.2)% |
| 4.9% |
Commercial |
| 0.1% |
| (3.0)% |
| (0.1)% |
| (3.0)% |
| 1.5% |
| (1.4)% |
| 0.2% |
| (2.8)% |
| 6.6% |
| 12.1% |
Industrial |
| 1.7% |
| (1.0)% |
| 1.6% |
| (1.9)% |
| (0.6)% |
| (2.4)% |
| 1.3% |
| (1.5)% |
| 0.3% |
| 1.7% |
Other |
| - |
| - |
| 0.4% |
| 0.4% |
| (19.9)% |
| (19.9)% |
| (1.4)% |
| (1.4)% |
| - |
| - |
Total |
| 1.8% |
| (1.8)% |
| 1.3% |
| (1.8)% |
| 2.4% |
| (0.6)% |
| 1.7% |
| (1.7)% |
| 1.9% |
| 6.2% |
A summary of our retail electric sales in gigawatt hours (GWH)GWh for CL&P, PSNH and WMECO and firm natural gas sales in million cubic feet for Yankee Gas for 20082010 and 20072009 is as follows:
|
| Electric |
| Firm Natural Gas |
| Electric |
| Firm Natural Gas | ||||||||||||||||
|
|
|
| 2007 |
| Percentage |
| 2008 |
| 2007 |
| Percentage | ||||||||||||
Residential |
| 14,509 |
| 15,051 |
| (3.6)% |
| 13,467 |
| 13,742 |
| (2.0)% |
| 14,913 |
| 14,412 |
| 3.5% |
| 13,403 |
| 13,562 |
| (1.2)% |
Commercial |
| 14,885 |
| 15,103 |
| (1.4)% |
| 12,939 |
| 12,965 |
| (0.2)% |
| 14,506 |
| 14,474 |
| 0.2% |
| 14,982 |
| 14,063 |
| 6.6 % |
Industrial |
| 5,149 |
| 5,635 |
| (8.6)% |
| 13,310 |
| 12,193 |
| 9.2 % |
| 4,481 |
| 4,423 |
| 1.3% |
| 14,866 |
| 14,825 |
| 0.3 % |
Other |
| 340 |
| 353 |
| (3.7)% |
| - |
| - |
| - % |
| 330 |
| 336 |
| (1.4)% |
| - |
| - |
| - |
Total* |
| 34,883 |
| 36,142 |
| (3.5)% |
| 39,717 |
| 38,900 |
| 2.1 % | ||||||||||||
Total |
| 34,230 |
| 33,645 |
| 1.7% |
| 43,251 |
| 42,450 |
| 1.9 % |
*Amounts may not total due to rounding of GWH.
RetailActual retail electric sales for 2008all three electric companies were higher in 2010 compared to 2009 due primarily to warmer than normal summer weather and colder than normal weather in December 2010. Residential sales benefitted the most from the favorable impacts of the weather in 2010 and were higher for all three electric companies in 2010 compared to 2009. Cooling degree days in 2010 for Connecticut and Western Massachusetts were 77 percent higher than 2009 and 41 percent above normal. In New Hampshire, cooling degree days in 2010 were 107 percent higher than 2009 and 42 percent above normal.
On a weather normalized basis, retail electric sales for all three electric companies were lower than 2007. The 2008 weather normalized decrease of 2.6 percent reflects the fact that our customers are respondingin 2010 compared to the increased costs of energy and to the adverse economic conditions of our region and the nation.2009. We believe customers will continue to respond to these factors and to the recent disruptions and ongoing uncertainty in the financial markets, and have estimated a decline of approximately 1 percentdecrease in weather normalized electricresidential sales was due in part to increased conservation efforts by our customers and continuing effects of the weak economy on our customers. The decline in commercial sales in 2010 compared to 2009 which is reflectedcan be attributed in our earnings guidance. We experienced positivepart to relatively weak employment growth, higher vacancy rates and uncertainty in our weather normalized electricconsumer confidence. Industrial sales were also lower in 2010 compared to 2009 due to a lack of 1.3 percent for January 2009.manufacturing sector hiring although industrial sales benefitted from increased manufacturing hours worked. Our commercial and industrial sales continue to be negatively impacted by additional installation of gas-fired distributed generation and utilization of C&LM programs.
Changes inOur firm natural gas sales are subject to many of the same influences as our retail electric sales, however,but have less of an impact on the earnings of the electric companies than in prior years because non-distribution rate revenues, which represented approximately 76 percent of electric company revenues in 2008, are tracked and reconciled to actual costs. Non-distribution rate revenues include the energy, stranded cost, retail transmission and federally mandated congestion costs (FMCC) charges and other components of rates. For non-distribution rate revenues, the only impact to earnings isbenefitted from carrying costs on over- or underrecoveries. With respect to the distribution revenues, about two-thirds of CL&P's and WMECO's revenues and about one-half of PSNH's revenues are recovered through charges that are not dependent on overall sales volumes, such as the customer chargea favorable price for natural gas and the demand charge.
33
In addition to the manner in which the distribution rate revenues are recovered from customers, there are other reasons why changes in 2008 sales as compared to 2007 had less of an impact on our earnings. For example, some of the decline in 2008 industrial sales was due to qualifiedgas-fired distributed generation in Yankee Gas’ service territory. Actual firm natural gas sales in 2010 were higher than 2009 despite the milder weather during the first quarter 2010 heating season. Heating degree days in 2010 for Connecticut replacing our distribution. Under Connecticut statute, CL&P is entitled to recover this lost distribution revenue through its FMCC charge. Also, some of the decline in 2008 commercial sales was attributable to certain generators who, in previous periods, took station service from CL&P as retail commercial customers but now are served directly by ISO-NE as wholesale customers. These customers are interconnected to the transmission systemwere 11 percent below 2009 levels and do not contribute to distribution revenues, therefore the loss of load from these customers in 2008 did not impact our earnings.
11 percent below normal levels. Firm natural gas sales in 2008 were higher than 2007. The 2008 results reflect warmer weather in the first quarter, colder weather in the fourth quarterbenefitted from commercial and an increase in industrial sales primarily duecustomers switching from interruptible service to customer-ownedfirm service, additional gas-fired distributed generation, and favorable natural gas prices relativea large commercial customer who began to oil. Similar to our electric distribution companies,take service from Yankee Gas recovers a significant portionmid-way through the third quarter of its distribution revenues, approximately 40 percent, through charges that are not dependent on usage. Our 2009 earnings guidance reflects an estimated increase in weather normalized firm gas salesand continued to take service throughout all of approximately 2.5 percent. 2010.
Consistent with our sales results in 2008, ourOur expense related to uncollectible receivable balances (our uncollectibles expense has also beenexpense) is influenced by the adverse economic conditions of our region. Our write-offs as a percentage of revenues increased in 2008 for all our distribution companies. Similar to changes in our retail sales, changesFluctuations in our uncollectibles expense have less ofare mitigated from an impact on earnings of our distribution companies than in prior years. For example,perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is allocated for recovery to itsthe respective company's energy supply rate and recovered as a tracked expense. CL&P, PSNH and WMECO implemented their trackers for this allocated portion of uncollectibles expense on February 1, 2008, July 1, 2007, and January 1, 2007, respectively.through its tariffs. Additionally, for CL&P and Yankee Gas, write-offs of uncollectible receivable balances attributable to hardshipqualified customers under financial or medical duress (hardship customers) are tracked and fully recovered in the System Benefits Charge (SBC) as uncollectible expense and in the base distribution rate as amortization expense, respectively.through their respective tariffs. In 2008,2010, our total pre-tax uncollectibles expense that impacts earnings was $23.4 million as compared to $46.5 million in 2009.
30
The improvement in 2010 uncollectibles expense was approximately $75 million or $25 million higher than 2007. Over $13 million of the increase was attributabledue in part to hardshipcontinued accounts at CL&P. From a nontracked uncollectibles expense perspective, the 2008 expense was approximately $9 million greater than we originally expected. In 2009,receivable collection efforts and we expect our total uncollectibles expense will be slightly higher than 2008 and the nontracked portion of2011 uncollectibles expense to increase to approximately $30 million in 2009. This anticipated increase of 10 percent or $3 million is reflected in our 2009 earnings guidance.be consistent with 2010.
Competitive Businesses: NU Enterprises, which continues to manage to completion itsSelect Energy's remaining wholesale marketing contracts and managesto manage its energyelectrical contracting business and other operating and maintenance services activities,contracts, earned $8.3 million, or $0.05 per share, in 2010, compared with $15.8 million, or $0.09 per share, in 2009 and $13.1 million, in 2008, or $0.08 per share, in 2008. In 2010, NU Enterprises recorded $0.7 million of after-tax mark-to-market gains, compared with earnings of $11.7 million in 2007, or $0.08 per share, and $211.3 million, or $1.37 per share, in 2006. The 2008 results include a net after-tax reduction of earnings of $3.2 million associated with the implementation of Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements." Competitive business earnings in 2008 also included positive mark-to-market after-tax results of $4.3 million associated with Select Energy, Inc.'s (Select Energy) wholesale marketing contracts, as compared to negative mark-to-market after-tax resultsgains of $3.8 million in 2007. The higher competitive business earnings2009 and $1.1 million in 2006 were attributable to the $314 million afte r-tax gain on the sale of the competitive generation business, partially offset by $70.3 million of losses at the retail marketing business, which was sold on June 1, 2006.2008.
NU Parent and Other Companies: NU parent and other companies recorded net expenses of $4.4 million, or $0.02 per share, in 2010, compared with net expenses of $9.3 million, or $0.05 per share, in 2009 and net expenses of $41.4 million, or $0.26 per share, in 2008, compared with net income2008. The 2010 results include a fourth quarter non-recurring benefit of $6.1$15.7 million, or $0.04$0.09 per share, in 2007,associated with the settlement of tax issues and net incomea fourth quarter after-tax charge of $2$9.4 million, or $0.01$0.06 per share, associated with expenses related to NU’s proposed merger with NSTAR. Excluding these impacts, 2010 net expenses increased by $1.4 million as compared to 2009 due primarily to a $0.9 million after-tax unfavorable change in 2006.the HWP environmental reserve and a $0.6 million net after-tax charge associated with the 2010 Healthcare Act, partially offset by lower interest expense at NU parent. The net expenses in 2008 primarily relate toincluded a $2 9.8 million, or $0.19 per share, after-tax charge resulting from the payment by NU parent to Con Edison of $49.5 million made in March 2008 as part of a comprehensiveassociated with the settlement of litigation initiated in 2001 over the proposed but unconsummated merger between the two companies. The decrease in net income from 2007 was also the result of reduced interest income for NU parent on a significantly lower level of cash in 2008. NU parent carried a high level of cash in the first quarter of 2007 after the sale of our competitive generation businesses on November 1, 2006. Most of that cash was either invested in the regulated companies in 2007 to support those companies’ capita l programs or used to pay taxes due in March 2007 on the competitive generation business sales. Additionally, NU parent interest expense increased in 2008 due to the replacement of $150 million of 3.3 percent senior notes that matured on June 1, 2008 with $250 million of 5.65 percent senior notes.litigation.
Future Outlook
EarningsEPS Guidance: AFollowing is a summary of our projected 20092011 EPS by segment,business, which also reconciles consolidated fully diluted EPS to the non-GAAP financial measure of EPS by segment, is as follows:business. Non-GAAP EPS by business also excludes a $0.15 per share charge related to expected non-recurring merger costs we will incur relating to financial advisor costs, legal, accounting and consulting fees, which will affect NU parent and other companies' results.
|
| 2009 EPS Range | ||||
(Approximate amounts) |
|
| Low |
|
| High |
Fully Diluted EPS (GAAP) |
| $ | 1.80 |
| $ | 2.00 |
|
|
|
|
|
|
|
Regulated companies: |
|
|
|
|
|
|
Distribution segment |
| $ | 1.00 |
| $ | 1.10 |
Transmission segment |
|
| 0.85 |
|
| 0.90 |
Total regulated companies |
|
| 1.85 |
|
| 2.00 |
Competitive businesses |
|
| 0.00 |
|
| 0.05 |
NU parent and other companies |
|
| (0.05) |
|
| (0.05) |
Fully Diluted EPS (GAAP) |
| $ | 1.80 |
| $ | 2.00 |
|
| 2011 EPS Range | ||||
(Approximate amounts) |
|
| Low |
|
| High |
Diluted EPS (GAAP) |
| $ | 2.10 |
| $ | 2.25 |
|
|
|
|
|
|
|
Regulated Companies: |
|
|
|
|
|
|
Distribution Segment |
| $ | 1.25 |
| $ | 1.35 |
Transmission Segment |
|
| 1.05 |
|
| 1.10 |
Total Regulated Companies |
|
| 2.30 |
|
| 2.45 |
NU Parent and Other Companies |
|
| (0.05) |
|
| (0.05) |
Non-GAAP EPS |
| $ | 2.25 |
| $ | 2.40 |
|
|
|
|
|
|
|
Merger-Related Costs |
|
| (0.15) |
|
| (0.15) |
Diluted EPS (GAAP) |
| $ | 2.10 |
| $ | 2.25 |
34
This projection assumes we will operate on a stand-alone basis in 2011, although our proposed merger with NSTAR is expected to close in the issuancesecond half of between $250 million2011. We have included the impacts of the CL&P, PSNH, and $300 millionWMECO electric distribution rate case decisions received as well as an anticipated reasonable outcome in the Yankee Gas rate case decision expected in June 2011 in the assumptions used to develop our 2011 earnings guidance. The 2011 distribution and transmission earnings guidance reflects the impact of additional equitya higher rate base as well as $1.2 billion of projected capital expenditures in mid-2009. Our2011. The 2011 distribution ratessegment earnings guidance assumes that total weather-normalized retail electric sales are basedessentially unchanged from 2010 and weather-normalized firm natural gas sales, excluding special contracts as fluctuations in part on historictheir usage do not impact earnings, are approximately 4 percent higher than 2010. Offsetting these favorable items are assumed increases in pension costs and certain operation and maintenance costs, including pension and other postretirement costs and uncollectible expense. Primarily as a result of a significant decline in our pension assets due to current financial market conditions,costs.
In 2010, the NU effective tax rate was 34.8 percent. For 2011, we expectestimate that higher pension coststhe effective tax rate for NU will result in a $0.10 per share negative impact on earnings in 2009, as compared with 2008. The distribution segment earnings forecast noted above reflects our expectations of lower electric sales and higher pension and uncollectible expense than what we experienced in 2008. be approximately 35 percent.
Long-Term Growth Rate: We project that we will achieve ana compound average compounded annual EPS growth rate for the five-year period from 2011 to 2015 of between 86 percent and 119 percent over 2007using 2009 EPS of $1.59 through 2013. Based on current economic conditions,$1.91 per share as the base level. Assuming completion of our proposed merger with NSTAR in the second half of 2011, we believe we will likely be at the lower end of this range. Thisexpect to achieve an EPS growth rate assumes achieved Regulatory ROEsat the higher end of approximately 12 percent for transmission, between 9.5the range of 6 percent and 10 percent for generation and between 9 percent and 9.5 percent for distribution investments. We believe this growth will be achieved if our capital program is successfully deployed according to our plans, distribution rate cases are approved to earn reasonable Regulatory ROEs and FERC's present transmission policies remain consistent and enable us to achieve projected transmission ROEs.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, allowance for funds used during construction (AFUDC), and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors in determining rate base), totaled $1.3 billion in both 2008 and 2007 and $945.8 million in 2006. These amounts include $33.2 million, $16 million and $17.6 million in 2008, 2007 and 2006, respectively, that related to our corporate service company and other affiliated companies that support the regulated companies.
Regulated Companies: We project making up to approximately $7 billion in capital investments for the regulated companies from 2009 through 2013. This projection includes capital expenditures of approximately $525 million for our portion of the costs associated with the new transmission initiative with NSTAR and HQUS, and approximately $150 million for our corporate service companies supporting the regulated companies. Given current financial conditions, we continue to carefully examine each investment to assess customer benefits, shareholder benefits and the ability to raise necessary capital.
A summary of our projected capital expenditures for 2009 through 2013 is as follows:
|
| Year |
|
| ||||||||||||||
|
| 2009 |
| 2010 |
| 2011 |
| 2012 |
|
|
| 2009-2013 | ||||||
CL&P Transmission |
| $ | 97 |
| $ | 128 |
| $ | 267 |
| $ | 322 |
| $ | 160 |
| $ | 974 |
PSNH Transmission |
|
| 58 |
|
| 177 |
|
| 400 |
|
| 273 |
|
| 154 |
|
| 1,062 |
WMECO Transmission |
|
| 70 |
|
| 121 |
|
| 308 |
|
| 306 |
|
| 83 |
|
| 888 |
Other Transmission |
|
| - |
|
| 20 |
|
| 95 |
|
| 205 |
|
| 205 |
|
| 525 |
Totals - Transmission |
|
| 225 |
|
| 446 |
|
| 1,070 |
|
| 1,106 |
|
| 602 |
|
| 3,449 |
CL&P Distribution |
|
| 278 |
|
| 352 |
|
| 338 |
|
| 309 |
|
| 311 |
|
| 1,588 |
PSNH Distribution |
|
| 96 |
|
| 115 |
|
| 117 |
|
| 114 |
|
| 117 |
|
| 559 |
WMECO Distribution |
|
| 30 |
|
| 38 |
|
| 33 |
|
| 33 |
|
| 34 |
|
| 168 |
Totals - Electric Distribution |
|
| 404 |
|
| 505 |
|
| 488 |
|
| 456 |
|
| 462 |
|
| 2,315 |
PSNH Generation |
|
| 156 |
|
| 199 |
|
| 144 |
|
| 83 |
|
| 41 |
|
| 623 |
Yankee Gas Distribution |
|
| 66 |
|
| 90 |
|
| 92 |
|
| 74 |
|
| 77 |
|
| 399 |
Corporate service companies |
|
| 70 |
|
| 34 |
|
| 21 |
|
| 13 |
|
| 12 |
|
| 150 |
Totals |
| $ | 921 |
| $ | 1,274 |
| $ | 1,815 |
| $ | 1,732 |
| $ | 1,194 |
| $ | 6,936 |
Actual capital expenditures could vary from the projected amounts for the companies and periods above. Based on those estimated expenditures, projected transmission, distribution and generation rate base at December 31 of each year are as follows:
|
| Year | |||||||||||||
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 | |||||
CL&P Transmission |
| $ | 2,024 |
| $ | 2,033 |
| $ | 2,224 |
| $ | 2,433 |
| $ | 2,454 |
PSNH Transmission |
|
| 314 |
|
| 325 |
|
| 666 |
|
| 1,089 |
|
| 1,189 |
WMECO Transmission |
|
| 125 |
|
| 218 |
|
| 488 |
|
| 729 |
|
| 876 |
Other Transmission |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 525 |
Totals - Transmission |
|
| 2,463 |
|
| 2,576 |
|
| 3,378 |
|
| 4,251 |
|
| 5,044 |
CL&P Distribution |
|
| 2,351 |
|
| 2,557 |
|
| 2,724 |
|
| 2,851 |
|
| 2,971 |
PSNH Distribution |
|
| 774 |
|
| 865 |
|
| 954 |
|
| 1,042 |
|
| 1,095 |
WMECO Distribution |
|
| 410 |
|
| 434 |
|
| 455 |
|
| 478 |
|
| 497 |
Totals - Electric Distribution |
|
| 3,535 |
|
| 3,856 |
|
| 4,133 |
|
| 4,371 |
|
| 4,563 |
PSNH Generation |
|
| 389 |
|
| 394 |
|
| 404 |
|
| 876 |
|
| 872 |
Yankee Gas Distribution |
|
| 712 |
|
| 739 |
|
| 793 |
|
| 851 |
|
| 890 |
Totals |
| $ | 7,099 |
| $ | 7,565 |
| $ | 8,708 |
| $ | 10,349 |
| $ | 11,369 |
35
The projected capital expenditures and rate base amounts reflected above assume that PSNH’s Clean Air Project will be completed by the end of 2012 at a cost of $457 million. They also assume that $1.49 billion in transmission projects associated with NEEWS will be completed before the end of 2013. Numerous factors, some of which are beyond our control, may impact the regulated companies’ rate base amounts above, including the level and timing of capital expenditures and plant placed in service and regulatory approvals.
Transmission Segment: Transmission segment capital expenditures decreased by $47.5 million in 2008 as compared with 2007 primarily due to reduced expenditures at CL&P associated with its transmission system projects in southwest Connecticut. A summary of transmission segment capital expenditures by company in 2008, 2007 and 2006 is as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
|
| 2008 |
|
| 2007 |
|
| 2006 |
CL&P |
| $ | 586.3 |
| $ | 660.6 |
| $ | 415.6 |
PSNH |
|
| 81.9 |
|
| 80.7 |
|
| 36.1 |
WMECO* |
|
| 44.2 |
|
| 19.3 |
|
| 13.0 |
HWP* |
|
| 1.9 |
|
| 1.2 |
|
| 0.8 |
Totals |
| $ | 714.3 |
| $ | 761.8 |
| $ | 465.5 |
*
Does not include the transfer of $4 million in transmission assets from Holyoke Water Power Company (HWP) and its subsidiary, Holyoke Power and Electric Company (HP&E), to WMECO in December 2008.
Of its $586.3 million in transmission capital expenditures in 2008, CL&P invested approximately $470 million to complete its $1.6 billion series of four major transmission projects in southwest Connecticut. The first of those projects, the 21-mile 345 kilovolt (KV)/115 KV overhead and underground transmission line between Bethel, Connecticut and Norwalk, Connecticut, was placed in service in 2006. The remaining three projects that entered service in 2008 are as follows:
·
The 69-mile, 345 KV/115 KV transmission project from Middletown to Norwalk, Connecticut (Middletown-Norwalk) that was constructed jointly with UI. CL&P's portion of this project cost approximately $950 million, $100 million lower than the earlier estimate of $1.05 billion primarily due to a decrease in capitalized financing costs because of the earlier-than-expected in service date. Of the $950 million, approximately $334 million was capitalized in 2008. The 45-mile overhead section of the project entered service on August 28, 2008. The 24-mile underground section entered service on December 16, 2008.
·
The two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), which entered service ahead of schedule on November 11, 2008. This project cost approximately $239 million, which is $16 million higher than the previous estimate due to increased construction costs related to underground obstacles. Of the $239 million, approximately $102 million was capitalized in 2008.
·
The 138 KV, 11-mile undersea transmission project between Norwalk, Connecticut and Northport-Long Island, New York (Long Island Replacement Cable), which was completed in September 2008. CL&P's 51 percent portion of the project with Long Island Power Authority is estimated to be approximately $78 million, which represents a $7 million increase over the previous estimate. Of the $78 million, approximately $33 million was capitalized in 2008.
In 2008, in addition to the approximately $470 million invested in the three projects noted above, CL&P, PSNH, WMECO and HWP invested approximately $244 million in other transmission projects.
In October 2008, we commenced state regulatory filings for our next series of major transmission projects, NEEWS. That series of projects involves our construction of new overhead 345 KV lines in Massachusetts and Connecticut as well as associated substation work and 115 KV rebuilds. One of the projects will connect to a new transmission line that National Grid USA plans to build in Rhode Island and Massachusetts. On September 24, 2008, the ISO-NE issued its final technical approval of the NEEWS projects, which was a precursor to the siting application process. We estimate that CL&P’s and WMECO’s total capital expenditures for these projects will be $1.49 billion through 2013. In 2008, CL&P and WMECO capitalized approximately $19.7 million and $23.2 million, respectively, in costs associated with NEEWS.
The first of the NEEWS projects, the Greater Springfield Reliability Project, which involves a 115 KV/345 KV line from Ludlow, Massachusetts to North Bloomfield, Connecticut, is the largest and most complicated project within NEEWS. This project is expected to cost approximately $714 million if built according to our preferred route and configuration. CL&P filed its application to build the Connecticut portion of the Greater Springfield Reliability Project with the Connecticut Siting Council (Siting Council) on October 20, 2008. WMECO filed its application to build its portion of the project with the Massachusetts Energy Facilities Siting Board on October 27, 2008. The Connecticut Energy Advisory Board is currently reviewing Connecticut-based generation, demand side management and other proposed alternatives to the Greater Springfield Reliability Project, which must be submitted to the Siting Council by March 19, 2009. The Siting Council has preliminarily set dates for hearings, public comments and site visits on the Connecticut portion of the project in the second quarter of 2009. If the overall project is approved in 2010 as expected, we currently expect to commence construction in late 2010 and place the project in service in 2013.
Our second major NEEWS project is the Interstate Reliability Project, which is being designed and built in coordination with National Grid USA. CL&P's share of this project includes an approximately 40-mile, 345 KV line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing. We expect CL&P's share of this project to cost approximately $250 million. Municipal consultations concluded in November 2008, and CL&P plans to file siting
36
applications with Connecticut regulators by the third quarter of 2009 with construction beginning as early as late 2010. We currently expect the project to be placed in service as early as 2012.
The third part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut. This line would provide another 345 KV connection to move power across the state of Connecticut. The timing of this project would be six to twelve months behind the other two projects, and CL&P currently expects to file the siting application in early 2010, with construction beginning in 2011. The project is currently expected to be placed in service in 2013 at a cost of approximately $315 million. Included as part of NEEWS are approximately $210 million of associated reliability related expenditures, some of which may be incurred in advance of the three major projects.
During the siting approval process, state regulators may require changes in configuration to address local concerns that could increase construction costs. Our current design for NEEWS does not contemplate any underground lines. Building any lines underground, particularly 345 KV lines, would increase total costs, and our estimate could be increased during the siting approval process.
On December 12, 2008, NU and NSTAR submitted a joint petition for a declaratory order to the FERC. The petition requests a ruling by the FERC that would allow NU and NSTAR to enter into a bilateral transmission services agreement with HQUS, a wholly-owned subsidiary of Hydro-Québec. Under such an agreement, NU and NSTAR would sell 1,200 MW of firm electric transmission service over a newly constructed, participant-funded transmission tie line connecting New England with the Hydro-Québec system in order for HQUS to sell and deliver into New England this same amount of firm electric power from Canadian low-carbon energy resources. If FERC issues the declaratory order as we anticipate, NU and NSTAR would subsequently seek approval from FERC of the specific terms and conditions of the transmission arrangement. NU, NSTAR and HQUS have signed memoranda of understanding to develop this transmission project on an exclusive basis. This project would provide a competitive source of low-carbon power that is favorable in comparison to current alternatives and would also provide for an expansion of New England’s transmission system without raising regional transmission rates. NU, NSTAR and HQUS have also begun discussions on the specifics of a potential long-term power purchase agreement that would ensure the line is utilized to bring low-carbon power to benefit New England customers. A FERC order is expected in the first half of 2009, and if the order approves the proposal, then NU and NSTAR plan to negotiate a power purchase agreement with HQUS later in 2009. The terms of such agreement would be subject to regulatory approvals in several states.
Assuming completion of an acceptable power purchase agreement and receipt of all necessary state and federal regulatory approvals, we expect this project to be under construction between 2011 and 2014. Our portion of the costs of this project is currently estimated to be approximately $525 million. HQUS will reimburse NU and NSTAR for the total costs of this project, including an investment return to these companies, over the estimated 40-year operating life of the transmission line. NU and NSTAR’s intent is to create an agreement that approximates a typical FERC approved cost-of-service rate structure. The revenue recovery model will ultimately require FERC approval.
Distribution Segment: A summary of distribution segment capital expenditures by company in 2008, 2007 and 2006 is as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
|
| 2008 |
|
| 2007 |
|
| 2006 |
CL&P |
| $ | 296.6 |
| $ | 283.3 |
| $ | 210.3 |
PSNH |
|
| 98.2 |
|
| 88.3 |
|
| 77.5 |
WMECO |
|
| 37.8 |
|
| 34.0 |
|
| 30.0 |
Totals - Electric distribution (excluding generation) |
|
| 432.6 |
|
| 405.6 |
|
| 317.8 |
Yankee Gas |
|
| 44.0 |
|
| 63.7 |
|
| 89.9 |
Other |
|
| 0.5 |
|
| 0.4 |
|
| 2.3 |
Total distribution |
|
| 477.1 |
|
| 469.7 |
|
| 410.0 |
PSNH generation |
|
| 74.0 |
|
| 35.3 |
|
| 32.1 |
Total distribution segment |
| $ | 551.1 |
| $ | 505.0 |
| $ | 442.1 |
PSNH’s Clean Air Project is expected to cost approximately $457 million, which will be recovered through its generation rates under New Hampshire law. PSNH commenced preliminary site work for this project in 2008. The project is scheduled to be completed by the end of 2012. As of December 31, 2008, PSNH had capitalized approximately $27.5 million associated with this project, of which $24.8 million was capitalized in 2008. Refer to "Regulatory Developments and Rate Matters - New Hampshire - Merrimack Clean Air Project" for further discussion, including the status of the New Hampshire Supreme Court proceedings and their effect on this project.
On February 15, 2008, Yankee Gas and NRG Energy, Inc. (NRG) entered into a settlement agreement, which, among other things, allowed for the recovery by Yankee Gas of approximately $17.5 million of capital costs and expenses related to an NRG subsidiary's generating plant construction project that was abandoned. The 2008 capital expenditures at Yankee Gas were offset by this $17.5 million recovery, and the 2007 capital expenditures included $12 million spent on its $108 million liquefied natural gas storage and production facility in Waterbury, Connecticut, which was placed in service in July 2007. percent.
Liquidity
Consolidated: We had $89.8 million of cashCash and cash equivalents on hand attotaled $23.4 million as of December 31, 2008,2010, compared with $15.1$27 million atas of December 31, 2007. As2009.
NU subsidiaries issued a total of February 25, 2009, we had approximately $466$145 million in long-term debt in 2010. On March 8, 2010, WMECO issued $95 million of externally invested cash. Refersenior unsecured notes due March 1, 2020 carrying a coupon rate of 5.1 percent. On April 22, 2010, Yankee Gas issued $50 million of first mortgage bonds through a private placement with a maturity date of April 1, 2020 carrying a coupon rate of 4.87 percent. The proceeds from these financings were used to "Impactrepay short-term borrowings incurred in the ordinary course of Financial Market Conditions" below for further discussion.business and to fund ongoing capital investment programs.
3731
On April 1, 2010, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to a mandatory tender on April 1, 2010. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.4 percent for a one-year period and are subject to a mandatory tender for purchase on April 1, 2011, at which time CL&P expects to remarket them.
On November 1, 2010, the DPUC approved CL&P's application requesting authority to issue up to $900 million in long-term debt through 2014. Proceeds will be used to refinance CL&P's short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.
On November 10, 2010, the DPUC approved Yankee Gas’ application to issue up to $300 million in long-term debt through 2014. Proceeds will be used to refinance Yankee Gas’ short-term debt previously incurred in the ordinary course of business, to refinance its Series G first mortgage bonds due in 2014, to finance capital expenditures, to provide working capital and to pay issuance costs.
On November 12, 2010, PSNH filed an application with the NHPUC requesting authority to issue securities for the purpose of refinancing certain series of PCRBs totaling $209 million. A public hearing for this application was held February 4, 2011 and a decision is pending.
On December 17, 2010, the NHPUC authorized PSNH to issue up to $160 million of long-term debt through 2011. Proceeds will be used to refinance PSNH's short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.
On January 28, 2011, the DPU authorized WMECO to issue up to $330 million in long-term debt through December 31, 2012 to be used to refinance WMECO’s short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.
On September 24, 2010, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a three-year $400 million unsecured revolving credit facility, which expires on September 24, 2013. This facility replaced a five-year $400 million credit facility on similar terms and conditions that was scheduled to expire on November 6, 2010. CL&P and PSNH are each able to draw up to $300 million under this facility, and WMECO and Yankee Gas are each able to draw up to $200 million, subject to the $400 million maximum aggregate borrowing limit. This total commitment may be increased to $500 million at the request of the borrowers, subject to lender approval. Under this facility, each company can borrow either on a short-term or a long-term basis, subject to regulatory approval. As of December 31, 2010, PSNH had $30 million of short-term borrowings outstanding under this facility, leaving $370 million of aggregate borrowi ng capacity available. The weighted-average interest rate on these short-term borrowings as of December 31, 2010 was 2.05 percent, which is based on a variable rate plus an applicable margin based on PSNH's credit ratings.
On September 24, 2010, NU parent entered into a three-year $500 million unsecured revolving credit facility, which expires on September 24, 2013. This facility replaced a five-year $500 million credit facility on similar terms and conditions that was scheduled to expire on November 6, 2010. Like the previous facility, the new revolving credit facility allows NU parent to borrow up to $500 million at any one time on a short-term or long-term basis and allows for the issuance of LOCs up to $500 million in the aggregate (net of the amount of borrowings then outstanding) on behalf of NU or any of its subsidiaries for periods up to 364 days. This total commitment may be increased to $600 million at the request of NU parent, subject to lender approval. As of December 31, 2010, NU parent had $32.1 million of LOCs issued primarily for the benefit of PSNH and $237 million of short-term borrowings outstanding, leaving $230.9 million of borrowing capacity available. The weighted-average interest rate on these short-term borrowings as of December 31, 2010 was 2.85 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings.
Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH and WMECO, comply with certain financial and non-financial covenants as are customarily included in such agreements, including a consolidated debt to total capitalization ratio. As of December 31, 2010, all such companies were in compliance with these covenants. Refer to Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt," to our consolidated financial statements included in this Annual Report on Form 10-K for further discussion of material terms and conditions of these agreements.
In 2011, in addition to remarketing the CL&P $62 million PCRBs, we expect to issue approximately $260 million of long-term debt comprised of $160 million by PSNH and $100 million by WMECO in the second half of 2011. We had positive consolidatedhave annual sinking fund requirements of $4.3 million continuing in 2011 through 2012, the mandatory tender of $62 million of tax-exempt PCRBs by CL&P on April 1, 2011, at which time CL&P expects to remarket the bonds in the ordinary course, and no debt maturities until April 1, 2012. In light of the 2010 Tax Act and the related cash flow benefits, we are currently reevaluating the timing of our previously planned NU common equity issuance. If we complete the proposed merger with NSTAR, we would no longer need to undertake the previously planned $300 million NU common equity issuance in 2012 nor issue any additional equity in the foreseeable future.
Cash flows provided by operating activities in 2010 totaled $832.6 million, compared with operating cash flows of $745 million in 2009 and $424.1 million in 2008 (all amounts are net of $418.5 million, after RRB payments, which are included in financing activities compared with negative operatingon the accompanying consolidated statements of cash flows). The improved cash flows of $11.3 million in 2007 and positive operating cash flows of $233.7 million in 2006, both after RRB payments. The increase in 2008 operating cash flows waswere due primarily due to the absence in 20082010 of approximately $400 million in tax payments in 2007costs incurred at PSNH and WMECO related to the 2006 sale of the competitive generation business, partially offset by the litigation settlement payment to Con Edison of $49.5 million in 2008. After factoring these cash flow impacts, the increase in operating cash flows in 2008 from 2007 was primarily due to a favorable impact of approximately $118 million from tax-related matters in 2008, which included an income tax net settlement of approximately $78 million in the fourth quarter and a reduction in income tax payments of approximately $40 million during 2008 related to bonus depreciation. The cash flow benefit of our accounts payable balances increased by $122 million, excluding approximately $50 million in unpaid costs at PSNH related to a major storm in December 2008 that are deferredwere paid in the first quarter of 2009, a decrease in Fuel, Materials and expectedSupplies attributable to be recovered from customers or insurance proceeds. These factors were partially offset by a net$31.8 million reduction in other working capital itemscoal inventory levels at the PSNH generation business as ordered by the NHPUC, and increases in amortization on regulatory deferrals primarily attributable to 2009 activity within PSNH’s ES and CL&P’s CTA tracking mechanisms where such costs exceeded revenues resulting primarily fromin an unfavorable cash flow impact in 2009. Offsetting these favorable ca sh flow impacts was a net $136$45 million contribution made into our Pension Plan in September 2010. The increase in accounts receivable and unbilled revenues items, which also included investments in securitizable assets.
We project consolidated operating cash flows from 2008 to 2009 was due primarily to higher transmission revenues at CL&P after significant projects were placed in service in late 2008, as well as cost management efforts; a decrease of approximately $500$225 million related primarily to amounts spent on CL&P's
32
FMCC and GSC, the costs of which are passed on to customers; approximately $100 million less in cash expenditures on Fuel, Materials and Supplies in 2009 after RRB paymentsdue primarily to the lower cost of $244 million, which represents an increase of approximately $82 million, or 19 percent, from 2008 operating cash flows, after RRB payments. This projected increase does not include any pension plan contributions, as they are not required to be paid during 2009, and is primarily due to our major southwest Connecticut transmission projectsnatural gas being fully reflected in rates in 2009 after their completion instored by Yankee Gas for the second half of 2008winter heating season; and the absence in 2009 of the Con Edisonlitigation settlement payment. These factorspayment of $49.5 million made in 2008.
Excluding the impact of our proposed merger with NSTAR, we project 2011 cash flows provided by operating activities of approximately $950 million to $1 billion, net of RRB payments. The increase over 2010 is due primarily to the accelerated depreciation provisions of the 2010 Tax Act, which is expected to result in a cash flow benefit of approximately $250 million in 2011, and the impact of the 2010 distribution rate case decisions. Those benefits are partially offset by the payment in 2009 of major storm costs incurred in December 2008 that likely will not be fully recovered from customers in 2009. Excluding potentialprojected 2011 contributions to our Pension Plan we currently project our internally-generated cash flows to grow toof approximately $1 billion by 2013 due to ou r cash return on and recovery of capital investment program expenditures.
In 2008, NU parent, CL&P, PSNH and Yankee Gas issued a total of $760 million of long-term debt. On May 27, 2008, CL&P sold $300 million of first and refunding mortgage bonds due May 1, 2018 and carrying a coupon of 5.65 percent and PSNH sold $110 million of first mortgage bonds due May 1, 2018 and carrying a coupon of 6 percent. Proceeds from the CL&P and PSNH issuances were used to repay short-term debt, to fund each company’s ongoing capital investment programs, and for general working capital purposes. On June 5, 2008, NU parent sold $250 million of senior unsecured notes due June 1, 2013 and carrying a coupon of 5.65 percent. Most of the proceeds were used to repay $150 million of 3.3 percent notes that matured June 1, 2008. The balance of NU parent’s debt issuance was used to pay down short-term debt, a portion of which was incurred in March 2008 as a result of the $49.5 million litigation settlement payment to Con Edison. On October 7, 2008, Yankee Gas sold $100 million of privately placed first mortgage bonds due October 1, 2018 and carrying a coupon of 6.9 percent. Yankee Gas used the proceeds to repay its borrowings under the regulated companies’ credit facility, to fund capital investment programs and for general working capital purposes.$145 million.
On February 13, 2009,December 30, 2010, CL&P made its final principal and interest payment on approximately $1.4 billion of RRBs that were issued $250in 2001. As a result, CL&P will no longer recover any payments from customers associated with these RRBs. A total of $203.2 million of firstprincipal and refunding mortgage bonds due February 1, 2019 and carrying a couponinterest payments were made on these RRBs in 2010. The full amortization of 5.5 percent. Proceeds from this issuancethese RRBs in 2010 will be used to repay short-term debt and fundreduce CL&P's capital investment program. In mid-2009 or earlier depending&P’s cash flows provided by operating activities in 2011, compared with previous years, but will have no material impact on market opportunities, we expect to issue $150 million of long-term debt at PSNH, subject to regulatory approval, and between $250 million and $300 million of additional equity. These issuances will be made primarily to repay short-term debt and fund our 2009 capital investment program, which will also be funded by available short-term borrowings and the projected growth in 2009CL&P’s operating cash flows. flows net of RRB payments. PSNH and WMECO RRBs do not fully amortize until 2013, therefore the RRBs do not have an impact on their respective operating cash flows in 2011 when compared to 2010.
A summary of the current credit ratings and outlooks by Moody's, Investors Service (Moody's), Standard & Poor's (S&P)S&P and Fitch Ratings (Fitch) for NU parent's and WMECO���s senior unsecured debt of NU parent and CL&P'sWMECO and PSNH's first mortgage bondssenior secured debt of CL&P and PSNH is as follows:
|
| Moody's |
| S&P |
| Fitch | ||||||
|
| Current |
| Outlook |
| Current |
| Outlook |
| Current |
| Outlook |
NU |
| Baa2 |
| Stable |
| BBB- |
|
|
| BBB |
|
|
CL&P | A2 | Stable | BBB+ | Watch-Positive | A- | Stable | ||||||
PSNH |
| A3 |
| Stable |
| BBB+ |
|
|
|
| ||
|
|
|
|
|
| BBB+ |
| Stable | ||||
WMECO |
| Baa2 |
| Stable |
| BBB |
|
|
| BBB+ |
| Stable |
On July 29, 2008,October 18, 2010, following the announcement of the proposed merger of NU and NSTAR, Moody's changedannounced that it had reaffirmed the outlook of Yankee Gas to stable from negative and affirmed the company's Baa2 corporate credit rating. On August 8, 2008, Fitch affirmed all of its ratings and "stable" outlooks onof NU parent, CL&P, PSNH and WMECO. In late October 2008,WMECO, and S&P affirmed all of its ratings and outlooks onannounced that it had placed NU parent, CL&P, PSNH and WMECO.WMECO's ratings outlooks on credit watch with "positive" implications. On November 5, 2008, SOctober 19, 2010, also due to the announcement of the proposed merger, Fitch announced that it had reaffirmed the ratings and "stable" outlooks of CL&P, raisedPSNH and WMECO and placed NU parent's ratings outlook on credit watch with "positive" implications. Assuming completion of the proposed merger with NSTAR, we expect our credit ratings will improve.
On January 22, 2010, Fitch downgraded CL&P's unsecured debt&P’s preferred stock rating tofrom BBB fromto BBB- as a result of a comprehensive review of the unsecured ratings of United States investment grade utilities. S&P's ratings on CL&P's bonds andrevised guidelines for rating preferred stock were unaffected. and hybrid securities in general.
If NU parent’sthe senior unsecured debt ratings of NU parent were to be reduced to a sub-investmentbelow investment grade level by either Moody's or S&P, a number of Select Energy's supply contracts would require Select Energy to post additional collateral in the form of cash or letters of credit (LOCs).LOCs. If such an event were to occur,had occurred as of December 31, 2010, Select Energy would under its remaining contracts, behave been required to provide additional cash or LOCs in an aggregate amount of $23.2$24 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $10$7.4 million to two independent system operators, in each case at December 31, 2008.operators. NU parent would behave been and remains able to provide that collateral. collateral on behalf of Select Energy.
If the unsecured debt ratings for CL&P orof PSNH were to be reduced by either Moody's or S&P, a number ofcertain supply contracts wouldcould require CL&P and PSNH to post additional collateral in the form of cash or LOCs towith various unaffiliated counterparties. If theseAs of December 31, 2010, if the unsecured debt ratings were to beof PSNH had been reduced by one level or to below investment grade, PSNH had an adequate amount of collateral posted and would benot have been required to post collateral of $1 million as of December 31, 2008. If these ratings were to be reduced by two levels or below investment grade, the amount of collateral required to be posted by CL&P and PSNH would be $1.3 million and $24.5 million, respectively, at December 31, 2008. CL&P and PSNH would be able to provide these collateraladditional amounts.
38
NUWe paid common dividends of $180.5 million in 2010, compared with $162.4 million in 2009 and $129.1 million in 2008, compared with $121 million in 2007 and $112.7 million in 2006.2008. The increase in common dividends paid from 2006 to 2008 reflects a 7.17.9 percent increase in the amount of NU parent’sour common dividend rate that took effect in the thirdfirst quarter of 2006,2010, as well as a 6.7 percent increase that took effect inhigher number of shares outstanding as a result of the third quarterMarch 2009 issuance of 2007 and a 6.3 percent increase that took effect in the third quarter of 2008.nearly 19 million common shares. On February 10, 2009,8, 2011, our Board of Trustees declared a quarterly common dividend of $0.2375$0.275 per share, payable on March 31, 20092011 to shareholders of record as of March 1, 2009,2011, which represents a $0.10equates to $1.10 per share dividend on an annualized basis. This increase represented an approximately 7.3 percent increase over the previous dividend rate.
Assuming completion of our proposed merger with NSTAR and subject to the conditions in the merger agreement, our first quarterly dividend per common share declared after the completion of the proposed merger will be increased to an amount that is equivalent, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing. Based on the last quarterly dividend paid by NSTAR of $0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, that would result in NU’s quarterly dividend being increased by approximately 18 percent to approximately $0.325 per share, or 11.8 percent, increaseapproximately $1.30 per share on an annualannualized basis.
The February 2009 dividend declaration reflects our new policy, announced in November 2008, of targeting a dividend payout ratio of approximately 50 percent of earnings. Our goal is to continue increasing the dividend at a rate above industry average and to provide an attractive return to shareholders. In general, the regulated companies pay approximately 60 percent of their cash earnings to NU parent in the form of common dividends. In 2008, CL&P, PSNH, WMECO and Yankee Gas paid $106.5 million, $36.4 million, $39.7 million, and $31 million, respectively, in common dividends to NU parent. In 2008, NU parent contributed $210 million of equity to CL&P, $75.6 million to PSNH, $16.3 million to WMECO, and $20.8 million to Yankee Gas.
NU parent’s ability to pay common dividends is subject to approval by itsour Board of Trustees and to NU'sour future earnings and cash flow requirements and is not regulated under the Federal Power Act but may be limited by certain state statutes,statute, the leverage restrictions in itsour revolving credit agreement and the ability of itsour subsidiaries to pay common dividends.dividends to NU parent. The Federal Power Act does, however, limitlimits the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances unless a higher amount is approved by FERC, andFERC; PSNH is required to reserve an additional amount of retained earnings under its FERC hydroelectric license conditions. In addition, certainrelevant state statutes may impose
33
additional limitations on the regulatedpayment of dividends by the Regulated companies. CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions. We do not expect the restrictions to prevent NU from meeting its obligations under the merger agreement.
In general, the Regulated companies pay approximately 60 percent of their earnings to NU parent in the form of common dividends. In 2010, CL&P, PSNH, WMECO, and Yankee Gas paid $217.7 million, $50.6 million, $14.9 million, and $18.8 million, respectively, in common dividends to NU parent. In 2010, NU parent made equity contributions to CL&P, PSNH and WMECO of $2.5 million, $159 million and $102.5 million, respectively.
Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in the liquiditythis "Liquidity" section of this Management's Discussion and Analysis do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. OurA summary of our cash capital expenditures totaled $1.3 billion inby company for the years ended December 31, 2010, 2009 and 2008 compared with $1.1 billion in 2007 and $872.2 million in 2006. Our cash capital expenditures in 2008 included $849.5 million by CL&P, $238.9 million by PSNH, $78.3 million by WMECO, $58.3 million by Yankee Gas, and $30.4 million by other NU subsidiaries. Our cash capital expenditures in 2007 included $826.2 million by CL&P, $167.7 million by PSNH, $47.3 million by WMECO, $57.6 million by Yankee Gas, and $16 million by other NU subsidiaries. is as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
|
| 2010 |
|
| 2009 |
|
| 2008 |
CL&P |
| $ | 380.3 |
| $ | 435.7 |
| $ | 849.5 |
PSNH |
|
| 296.3 |
|
| 266.4 |
|
| 238.9 |
WMECO |
|
| 115.2 |
|
| 105.4 |
|
| 78.3 |
Yankee Gas |
|
| 82.5 |
|
| 54.8 |
|
| 58.3 |
NPT |
|
| 7.5 |
|
| - |
|
| - |
Other |
|
| 72.7 |
|
| 45.8 |
|
| 30.4 |
Total |
| $ | 954.5 |
| $ | 908.1 |
| $ | 1,255.4 |
The increase in our aggregate cash capital ex pendituresexpenditures was primarily the result of higher distribution segment capital expenditures.expenditures of $66.3 million, particularly at PSNH and Yankee Gas, and an increase in Other of $26.9 million primarily related to technology and facility projects at NUSCO, one of our corporate service companies. These increases were offset by a $46.8 million decrease in transmission segment capital expenditures primarily by CL&P.
Business Development and Capital Expenditures
NU Parent:Consolidated: NU parent has a credit lineOur consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $1 billion in a nominal aggregate amount of $5002010, $969.2 million including the commitment of LBCB (as further discussed below), which expires on November 6, 2010. At December 31,in 2009 and $1.3 billion in 2008. These amounts included $68.7 million in 2010, $52.7 million in 2009 and $33.2 million in 2008 NU parent had $87 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH)related to our corporate service companies, NUSCO and $303.5 million of borrowings outstanding under this facility. The weighted-average interest rate on these short-term borrowings at December 31, 2008 was 3.35 percent, which is based on a variable rate plus an applicable margin based on our credit ratings. We had approximately $50 million of borrowing availability on this facility as of February 25, 2009, excluding LBCB's remaining unfunded commitment. We also had approximately $466 million of externally invested cash at February 25, 2009.RRR.
Regulated Companies: The regulatedCapital expenditures for the Regulated companies maintain a joint credit facility in a nominal aggregate amount of $400totaled $967 million including the commitment of LBCB (as further discussed below), which expires on November 6, 2010. There were $315 million of borrowings outstanding under this facility at December 31, 2008 ($188412.6 million for CL&P, $45.2$310 million for PSNH, $29.9and $138.4 million for WMECO). The weighted-average interest rate on these short-term borrowings at December 31, 2008 was 3.35 percent, which is based on a variable rate plus an applicable margin based on our credit ratings. We had approximately $1 million of borrowing availability on this facility as of February 25, 2009, excluding LBCB's remaining unfunded commitment. As stated above, we also had approximately $466 million of externally invested cash at February 25, 2009. in 2010.
PriorTransmission Segment:Transmission segment capital expenditures decreased by $30.9 million in 2010, as compared with 2009, due primarily to June 30, 2008, CL&P had an arrangement with CL&P Receivables Corporation (CRC), a consolidated wholly-owned subsidiary ofreductions in expenditures at CL&P and a financial institution underPSNH, partially offset by increases at WMECO and capital expenditures incurred by NPT for the Northern Pass project. A summary of transmission segment capital expenditures by company in 2010, 2009 and 2008 is as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
|
| 2010 |
|
| 2009 |
|
| 2008 |
CL&P |
| $ | 107.2 |
| $ | 163.0 |
| $ | 586.3 |
PSNH |
|
| 49.1 |
|
| 59.4 |
|
| 81.9 |
WMECO |
|
| 95.2 |
|
| 67.7 |
|
| 46.1 |
NPT |
|
| 9.4 |
|
| 1.7 |
|
| - |
Total |
| $ | 260.9 |
| $ | 291.8 |
| $ | 714.3 |
CL&P and WMECO have received siting approvals in Connecticut and Massachusetts, respectively, for the first and largest component of our NEEWS project, GSRP, which involves the financial institution could purchase upconstruction of 115 KV and 345 KV lines from Ludlow, Massachusetts, to $100 millionBloomfield, Connecticut. We commenced substation construction in December 2010 and expect to begin overhead line construction in the first half of CL&P’s accounts receivable and unbilled revenues from CRC. On June 30, 2008, CL&P chose to terminate2011. We expect the Receivables Purchase and Sale Agreement due to the availability and lower relative cost of other liquidity sources. At this time, weGSRP to be $795 million and to place the project in service in late 2013. In June 2010, residents living near the proposed Connecticut route of the GSRP appealed the CSC approval in New Britain Superior Court, claiming that the CSC acted improperly by approving an overhead route for the line. We do not expect the appeal to have no further plans to securitizea material impact on the accounts receivable and unbilled revenuestiming of our regulated companies and will utilize our credit facilities and other financing vehicles, as necessary, to fund the daily operating activities and capital programs of these companies.construction.
Our second major NEEWS project is the Interstate Reliability Project, which is being designed and built in coordination with National Grid USA. CL&P's share of this project includes an approximately 40-mile, 345 KV all overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing in Rhode Island and Massachusetts. In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project, which is now expected to be placed in service in late 2015. This in-service date assumes that siting applications are filed in all three states in late 2011, with orders received in mid/late 2013 and construction commencing in late 2013 or early 2014. We expect CL&P's share of the costs of this project to be $301 million.
34
The third major part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut. This line would provide another 345 KV all overhead connection to move power across the state of Connecticut. The timing of this project is expected to be twelve months behind the Interstate Reliability Project. We expect the cost of this project to be $338 million. ISO-NE continues to assess the need date for the Central Connecticut Reliability Project and we expect that ISO-NE will conclude its evaluation by mid-2011.
Included as part of NEEWS are $84 million of expenditures for associated reliability related projects, all of which have received siting approval and most of which are under construction. The in-service dates for these projects range from later this year through 2013.
Since inception of NEEWS through December 31, 2010, CL&P and WMECO have capitalized approximately $105.9 million and $136.9 million, respectively, in costs associated with NEEWS, of which $38.4 million and $62.6 million, respectively, were capitalized in 2010. The total cost estimate for the NEEWS projects is $1.52 billion. As these projects are completed and put in service, actual costs may differ from these estimates.
On October 4, 2010, NPT and Hydro Renewable Energy entered into a TSA in connection with the Northern Pass transmission project. Northern Pass is comprised of a planned HVDC transmission line from the U.S./Canadian border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire that will be constructed by NPT. Northern Pass will interconnect at the U.S./Canadian border with a planned HVDC transmission line that HQ TransÉnergie, the transmission division of HQ, will construct in Québec.
Consistent with the FERC's February 11, 2011 order accepting without modification the TSA between NPT and Hydro Renewable Energy that was filed on December 15, 2010, NPT will sell to Hydro Renewable Energy 1,200 MW of firm electric transmission rights over the Northern Pass for a 40-year term and charge cost-based rates. The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project, and upon commercial operation, the ROE will be equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent. The TSA rates will be based on a deemed capital structure for NPT of 50 percent debt agreements provideand 50 percent equity. During the development and the construction phases under the TSA, NPT will be recording non-cash AFUDC earnings.
On October 13, 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and on October 14, 2010, NPT filed a presidential permit application with the DOE, which seeks permission to construct and maintain facilities that NUcross the U.S. border and certainconnect to HQ TransÉnergie's facilities in Canada. NPT anticipates filing additional state and federal permit and siting applications in 2011. Assuming timely regulatory review and siting approvals, NPT expects to commence construction of Northern Pass in 2013 and complete the line with power flowing in late 2015.
We currently estimate that NU's 75 percent share of the Northern Pass transmission project will be approximately $830 million and NSTAR’s 25 percent share of the Northern Pass transmission project will be approximately $280 million, for a combined total expected cost of approximately $1.1 billion (including capitalized AFUDC).
In July 2010, CL&P and UI entered into an agreement providing UI an option to make quarterly payments to CL&P in exchange for ownership of specific Connecticut based NEEWS transmission assets as they come into commercial operation. Under the agreement, which has received approval of the FERC and the DPUC, UI will have the right to invest up to $69 million or an amount equal to 8.4 percent of CL&P's costs for the Connecticut portion of these projects, which are expected to aggregate to approximately $828 million. On December 30, 2010, CL&P received the first of these deposits in the amount of $7.2 million. The impact of the UI transaction is reflected in the 2010 capital expenditures and our five-year capital expenditures and rate base forecasts.
On December 17, 2010, CL&P and the Connecticut Transmission Municipal Electric Energy Cooperative (CTMEEC), a non-profit municipal joint action transmission entity formed by several Connecticut municipal electric companies, filed with the DPUC and the FERC a joint application seeking regulatory approval of the transfer of a segment of high voltage transmission lines built by CL&P in the town of Wallingford, Connecticut. FERC approval for the transfer was received on January 31, 2011. The purchase price will be based on the net book value of the assets at the time of the closing of the sale, plus any additional closing adjustments. This segment of lines is projected to have a value of $42.3 million at the anticipated time of closing in May of 2011. CL&P will continue to operate and maintain the lines for CTMEEC. The transaction does not include the transfer of land or equipment not related to electric transmission service. The transaction will not impact our five-year capital plan and is already reflected in CL&P’s transmission rate base forecasts.
35
Distribution Segment: Distribution segment capital expenditures increased by $81.4 million in 2010, as compared with 2009, due to expenditures related primarily to the PSNH Clean Air Project, the WMECO solar generation project, and the Yankee Gas WWL Project.
A summary of distribution segment capital expenditures by company for 2010, 2009 and 2008 is as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
|
| 2010 |
|
| 2009 |
|
| 2008 |
CL&P: |
|
|
|
|
|
|
|
|
|
Basic business |
| $ | 126.2 |
| $ | 104.6 |
| $ | 114.7 |
Aging infrastructure |
|
| 104.0 |
|
| 104.1 |
|
| 95.4 |
Load growth |
|
| 75.2 |
|
| 74.3 |
|
| 86.5 |
Total CL&P |
|
| 305.4 |
|
| 283.0 |
|
| 296.6 |
PSNH: |
|
|
|
|
|
|
|
| |
Basic business |
|
| 41.2 |
|
| 55.5 |
|
| 41.6 |
Aging infrastructure |
|
| 19.5 |
|
| 17.8 |
|
| 19.6 |
Load growth |
|
| 23.1 |
|
| 25.5 |
|
| 37.0 |
Total PSNH |
|
| 83.8 |
|
| 98.8 |
|
| 98.2 |
WMECO: |
|
|
|
|
|
|
|
| |
Basic business |
|
| 17.5 |
|
| 21.5 |
|
| 18.1 |
Aging infrastructure |
|
| 10.5 |
|
| 12.2 |
|
| 12.9 |
Load growth |
|
| 5.1 |
|
| 4.0 |
|
| 6.8 |
Total WMECO |
|
| 33.1 |
|
| 37.7 |
|
| 37.8 |
Totals - Electric Distribution (excluding Generation) |
|
| 422.3 |
|
| 419.5 |
|
| 432.6 |
Yankee Gas |
|
| 94.6 |
|
| 59.6 |
|
| 44.0 |
Other |
|
| 2.0 |
|
| 0.6 |
|
| 0.5 |
Total Distribution |
|
| 518.9 |
|
| 479.7 |
|
| 477.1 |
PSNH Generation: |
|
|
|
|
|
|
|
|
|
Clean air project |
|
| 149.7 |
|
| 119.3 |
|
| 24.8 |
Other |
|
| 27.4 |
|
| 25.7 |
|
| 49.2 |
Total PSNH Generation |
|
| 177.1 |
|
| 145.0 |
|
| 74.0 |
WMECO Generation |
|
| 10.1 |
|
| - |
|
| - |
Total Distribution Segment |
| $ | 706.1 |
| $ | 624.7 |
| $ | 551.1 |
For the electric distribution business, basic business includes the relocation of plant, the purchase of meters, tools, vehicles, and information technology. Aging infrastructure relates to the planned replacement of overhead lines, plant substations, transformer replacements, and underground cable replacement. Load growth includes requests for new business and capacity additions on distribution lines and substation overloads. For the natural gas business, basic business includes the relocation of conflicting natural gas facilities due to municipal and state road work and the purchase of meters, tools, and information technology. Aging infrastructure relates to the planned replacement of natural gas facilities. Load growth includes requests for new natural gas service, new service mains and new distributed generation service.
PSNH's Clean Air Project is a wet scrubber project under construction at its Merrimack coal station, the cost of which will be recovered through PSNH's ES rates under New Hampshire law. Construction costs are running below their previously announced cost of $457 million and the project is expected to be completed in mid-2012, about a year ahead of schedule. We currently expect the project to cost approximately $430 million, including capitalized interest and equity returns. Since inception of the project, PSNH has capitalized $296.5 million associated with this project, of which $149.7 million was capitalized in 2010. Construction of the project was approximately 80 percent complete as of December 31, 2010.
On August 12, 2009, the DPU approved a stipulation agreement between WMECO and the Massachusetts Attorney General concerning WMECO's proposal, under the Massachusetts Green Communities Act, to install 6 MW of solar energy generation in its service territory at an estimated cost of $41 million by the end of 2012. In October 2010, WMECO completed construction of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts. The full cost of this project was approximately $9.4 million, all of which WMECO has capitalized as of December 31, 2010. On January 17, 2011, WMECO announced its plans to develop a second project on a site in Springfield, Massachusetts. WMECO believes this site is capable of accommodating a 4.2 MW solar generation facility. The major permitting and procurement activities for this project are underway and, assuming their favorable and timely completion, WMECO woul d expect to begin construction during the second quarter of 2011.
In April 2010, Yankee Gas commenced construction of its subsidiaries, including CL&P, PSNHWWL Project, a 16-mile natural gas pipeline between Waterbury and WMECO, must comply with certain financialWallingford, Connecticut and non-financial covenantsthe increase of vaporization output of its LNG plant. The project is now expected to cost $57.6 million, down from our previously announced cost of approximately $63 million. Construction during 2010, which cost $26.6 million, included the completion of Phase I, a seven-mile segment of pipeline connecting the Cheshire and Wallingford distribution systems, and four miles of Phase II. The remainder of the Phase II pipeline construction (approximately five miles) and the expansion of the vaporization capacity of the LNG facility are expected to be completed by the fourth quarter of 2011. Construction of the project was 46 percent complete as are customarily included in such agreements, including a consolidated debt to capitalization ratio. The parties to these agreementsof December 31, 2010 and is currently are and expect to remain in compliance with these covenants. Refer to Note 2, "Short-Term Debt," and Note 11, "Long-Term Debt," to our consolidated financial statements included in this Annual Report on Form 10-K for further discussion of material terms and conditions of our outstanding debt agreements.schedule.
ImpactStrategic Initiatives: We continue to evaluate a number of Financial Market Conditions: Whiledevelopment projects that will benefit our customers, some of which are detailed below.
36
Over the impactpast three years, we have participated in discussions with other utilities, policymakers, and prospective developers of continued market volatilityrenewable energy projects in the New England region regarding a framework whereby renewable power projects built in rural areas of northern New England could be connected to the electric load centers of New England. We believe there are significant opportunities for developers to build wind and biomass projects in northern New England that could help the extent and impacts of any economic downturn cannot be predicted, we currentlyregion meet its renewable portfolio standards. We believe that wea collaborative approach among project developers and transmission owners is necessary to be able to construct needed projects and bring their electrical output into the market. We have sufficient operating flexibilitynot yet included any capital expenditures associated with potential projects in our five-year capital program and accessthese discussions are continuing.
On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan that included a cost benefit analysis. CL&P concluded that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario." Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million, which are included in the Company's five-year capital program. Under CL&P's proposal, installation of meters is proposed to funding sources to maintain adequate liquidity (as evidenced by CL&P's issuance of $250 million of 10-year bondsbegin in February 2009 at 5.5 percent).late 2012 and continue through 2016. The credit outlooks for NU parent and our regulated companies are all stable, with all their ratings and outlooks affirmed by S&PDPUC procedural review began in late October 2008. Our companies have modest risk2010 and is scheduled to end in April 2011.
On October 16, 2009, WMECO filed its proposal for a dynamic pricing smart meter pilot program with the DPU. On July 27, 2010, the DPU approved a settlement agreement between WMECO, the Attorney General and other stakeholders to postpone implementation of calls for collateral duea dynamic pricing smart meter pilot program until results of smart meter pilots conducted by three other Massachusetts utilities are gathered and WMECO's meter data management system is operational. WMECO does not expect it will conduct a pilot program prior to our business model, as described further below. No cash contributions to our pension plan are required during 2009. We also have only $50 million2012.
Projected Capital Expenditures and Rate Base Estimates: Excluding the impacts of long-term debt maturing in 2009, andthe proposed merger with NSTAR, a summary of the projected capital expenditures for 2009 are significantly less than 2008. In the fourth quarterRegulated companies' electric transmission segment and their distribution segment (including generation) by company for 2011 through 2015, including our corporate service companies' capital expenditures on behalf of 2008, we an nounced athe Regulated companies, is as follows:
|
| Year |
|
| ||||||||||||||
(Millions of Dollars) |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| 2011-2015 | ||||||
CL&P transmission |
| $ | 137 |
| $ | 194 |
| $ | 169 |
| $ | 229 |
| $ | 280 |
| $ | 1,009 |
PSNH transmission |
|
| 59 |
|
| 75 |
|
| 58 |
|
| 45 |
|
| 56 |
|
| 293 |
WMECO transmission |
|
| 229 |
|
| 260 |
|
| 161 |
|
| 75 |
|
| 7 |
|
| 732 |
NPT |
|
| 19 |
|
| 23 |
|
| 241 |
|
| 298 |
|
| 241 |
|
| 822 |
Subtotal transmission |
| $ | 444 |
| $ | 552 |
| $ | 629 |
| $ | 647 |
| $ | 584 |
| $ | 2,856 |
CL&P distribution: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic business |
| $ | 135 |
| $ | 146 |
| $ | 137 |
| $ | 218 |
| $ | 276 |
| $ | 912 |
Aging infrastructure |
|
| 131 |
|
| 108 |
|
| 116 |
|
| 116 |
|
| 118 |
|
| 589 |
Load growth |
|
| 71 |
|
| 66 |
|
| 65 |
|
| 78 |
|
| 75 |
|
| 355 |
Total CL&P distribution |
|
| 337 |
|
| 320 |
|
| 318 |
|
| 412 |
|
| 469 |
|
| 1,856 |
PSNH distribution: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic business |
|
| 49 |
|
| 48 |
|
| 48 |
|
| 51 |
|
| 52 |
|
| 248 |
Aging infrastructure |
|
| 26 |
|
| 28 |
|
| 40 |
|
| 41 |
|
| 35 |
|
| 170 |
Load growth |
|
| 38 |
|
| 41 |
|
| 39 |
|
| 40 |
|
| 45 |
|
| 203 |
Total PSNH distribution |
|
| 113 |
|
| 117 |
|
| 127 |
|
| 132 |
|
| 132 |
|
| 621 |
WMECO distribution: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic business |
|
| 15 |
|
| 16 |
|
| 16 |
|
| 17 |
|
| 17 |
|
| 81 |
Aging infrastructure |
|
| 15 |
|
| 13 |
|
| 13 |
|
| 14 |
|
| 14 |
|
| 69 |
Load growth |
|
| 6 |
|
| 10 |
|
| 10 |
|
| 9 |
|
| 9 |
|
| 44 |
Total WMECO distribution |
|
| 36 |
|
| 39 |
|
| 39 |
|
| 40 |
|
| 40 |
|
| 194 |
Subtotal electric distribution |
| $ | 486 |
| $ | 476 |
| $ | 484 |
| $ | 584 |
| $ | 641 |
| $ | 2,671 |
PSNH generation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Clean air project |
| $ | 77 |
| $ | 34 |
| $ | 22 |
| $ | - |
| $ | - |
| $ | 133 |
Other |
|
| 35 |
|
| 18 |
|
| 30 |
|
| 29 |
|
| 29 |
|
| 141 |
Total PSNH generation |
|
| 112 |
|
| 52 |
|
| 52 |
|
| 29 |
|
| 29 |
|
| 274 |
WMECO generation |
|
| 22 |
|
| 9 |
|
| 5 |
|
| 5 |
|
| 5 |
|
| 46 |
Subtotal generation |
| $ | 134 |
| $ | 61 |
| $ | 57 |
| $ | 34 |
| $ | 34 |
| $ | 320 |
Yankee Gas distribution: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic business |
| $ | 37 |
| $ | 31 |
| $ | 30 |
| $ | 31 |
| $ | 33 |
| $ | 162 |
Aging infrastructure |
|
| 30 |
|
| 48 |
|
| 50 |
|
| 51 |
|
| 52 |
|
| 231 |
Load growth |
|
| 16 |
|
| 20 |
|
| 46 |
|
| 47 |
|
| 35 |
|
| 164 |
WWL project |
|
| 30 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 30 |
Total Yankee Gas distribution |
| $ | 113 |
| $ | 99 |
| $ | 126 |
| $ | 129 |
| $ | 120 |
| $ | 587 |
Corporate service companies |
| $ | 32 |
| $ | 28 |
| $ | 35 |
| $ | 34 |
| $ | 28 |
| $ | 157 |
Total |
| $ | 1,209 |
| $ | 1,216 |
| $ | 1,331 |
| $ | 1,428 |
| $ | 1,407 |
| $ | 6,591 |
Yankee Gas determines the amount of capital spending by category based on business needs and opportunities. Future capital spending will likely be affected by price differences between the cost of natural gas with respect to home heating oil, natural gas supply, new common dividend policy that targets a payout ratio of approximately 50 percent of earnings. While this new policy may require additional cashhome construction, road reconstruction, regulatory mandates and business requirements.
3937
to fund common dividends,Actual capital expenditures could vary from the incremental cash increase is relatively smallprojected amounts for the companies and we continue to have a modest payout ratio relative to peer companies. periods above. Economic conditions in the northeast could impact the timing of our major transmission projects. Most of these capital investment projections, including those for NPT, assume timely regulatory approval, which in most cases requires extensive review. Delays in or denials of those approvals could reduce the levels of expenditures, associated rate base, and anticipated EPS growth.
We successfully completed our planned long-term debt financings in 2008, as well as a CL&P bond issuance in early 2009, and we continue to have access to our two revolving credit facilities described above in a nominal aggregate amount of $900 million. The lenders under these facilities are: Bank of America, N.A.; Barclays Bank PLC; BNY Mellon, N.A.; Citigroup Inc.; HSBC Bank USA, N.A.; JPMorgan Chase Bank, N.A.; LBCB; Sumitomo Mitsui Banking Corporation; Toronto Dominion (Texas) LLC; Union Bank of California, N.A.; Wachovia Bank, N.A.; and Wells Fargo Bank, N.A. Borrowing capacity under the facility has not been reduced as a result of the 2008 merger of Wachovia and Wells Fargo. Lehman Brothers Holdings Inc., the parent of LBCB, filed for Chapter 11 bankruptcy protection in September 2008. LBCB's original aggregate lending commitment under the facilities was $85 million, $30 million of which was assigned to Sumitomo Mitsui Banking Corporation in late September, at which time LBCB had advanced approximately $23.5 million under the facilities. LBCB subsequently declined to fund the remainder of its commitment. As a result, when current loans from LBCB are repaid, we will be limited to an aggregate of $845 million of borrowing capacity under our credit facilities, which we believe will provide sufficient operating flexibility to maintain adequate liquidity. We have no other exposure to Lehman Brothers Holdings Inc. or any of its affiliates. As of December 31, 2008, we had borrowings and LOCs outstanding of approximately $706 millionunder the credit facilities, and approximately $793 million as of February 25, 2009, including $19.2 million remaining outstanding from LBCB. As of February 25, 2009, we also had approximately $466 million of externally invested cash.
In addition to the revolving credit facilities described above, we intend to access the capital markets, as appropriate, to fund our capital projects or otherwise meet funding needs. The availability and cost of external financings, including our expected financings in 2009 described below, will be affected by our financial condition and the then-current financial market conditions. There can be no assurance that the cost or availability of future borrowings, if any, will not be impacted by recent or future capital market disruptions. Refer to Item 1A, "Risk Factors," in this Annual Report on Form 10-K for further discussion.
PSNH has outstanding $407.3 million of Pollution Control Revenue Bonds (PCRBs), one series of which, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. Since March 2008, a significant majority of this series of PCRBs has been held by remarketing agents as the result of failed auctions due to general market concerns. The interest rate on these PCRBs has been reset by formula under the applicable documents every 35 days and has ranged between 0.2 percent and 4 percent since March 2008. The formula is based on a combination of the ratingsBased on the PCRBs2010 actual and an index rate, which provides for a current interest rate of 0.3 percent. We are not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agents. In addition, CL&P has outstanding $423.9 million of PCRBs, one series of which, in the aggregate principal amoun t of $62 million, had a fixed interest rate for a five-year period that expired on September 30, 2008. As a result of poor liquidity in the tax-exempt market, CL&P chose to acquire this series of PCRBs on October 1, 2008. These PCRBs, which mature in 2031, have not been retired and are being held temporarily by CL&P in a flexible interest rate mode with one-day resets. CL&P expects to remarket the PCRBs when market conditions improve.
We project that our cash2011 through 2015 projected capital expenditures, will be approximately $880 million in 2009, which is significantly less than 2008. We also project that cash flows from operations after RRB payments will increase by approximately $82 million from 2008 to 2009 due to our southwest Connecticutthe 2010 actual and 2011 through 2015 projected transmission, projects being reflected fully in rates in 2009, lower refunds of the previous year’s overcollections, a $20 million retaildistribution and generation rate increase at CL&P, and the absence in 2009 of the 2008 Con Edison settlement. Also, only one series of our bonds matures prior to 2012, which is Yankee Gas' $50 million that mature in the second quarter of 2009. Due to these factors, we expect to require significantly less debt financing in 2009 than in 2008 (approximately $400 million, including the $250 million issued by CL&P in February 2009, compared to $760 million in 2008). We also continue to expect an equity issuance o f approximately $250 million to $300 million in mid-2009 (or earlier depending on market opportunities). The proceeds from these financings would be primarily used to repay short-term borrowings and fund our capital programs. We will monitor market conditions to determine the appropriate timing and amount of further 2009 financings.
Our regulated standard offer type contracts do not require us to post collateral. The regulated companies continue to solicit bids on wholesale power contracts, the collateral terms of which we expect to be consistent with existing contracts. In other regulated contracts that do contain collateral posting requirements, the counterparties are generally exposed to us at this time, and these counterparties have been posting the necessary collateral when required. As of December 31, 2008, PSNH had posted $75 million in related collateral in the form of LOCs with counterparties, as compared to $14 million at December 31, 2007.
An affiliate of Constellation Energy Group, Inc. (Constellation), whose credit ratings were downgraded in 2008 due to liquidity and other concerns, provides energy under CL&P’s standard offer contracts. As of December 31, 2008, CL&P is not exposed to Constellation in terms of credit risk, and Constellation is performing on specific contracts. In the event of Constellation’s default, CL&P would be required to provide standard offer type services directly to customers until a substitute supplier could be arranged. Any additional costs incurred by CL&P in such a case would be recoverable from customers. If Constellation were to default under existing contracts within the next 12 months, CL&P could be required to temporarily post additional collateral of between $15 million and $25 million with ISO-NE based on forward market pricesbase as of December 31 2008.of each year are as follows:
Our collateral requirements for Select Energy’s few remaining wholesale contracts are modest as we continue to wind down this business. Select Energy’s largest remaining contract does not contain any collateral posting requirements. In addition, we have not experienced any significant performance difficulties with suppliers on Select Energy’s remaining sourcing contracts. Select Energy is required to post collateral, primarily with its New York Mercantile Exchange (NYMEX) broker, based on the market prices and status of its sourcing contracts. As of December 31, 2008, Select Energy had posted $26.3 million in related collateral, as compared to $18.9 million at December 31, 2007. Refer to "NU Enterprises Contracts - Counterparty Credit Risk" in this Management’s Discussion and Analysis for further discussion.
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|
| Year | ||||||||||||||||
(Millions of Dollars) |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 | ||||||
CL&P transmission |
| $ | 2,149 |
| $ | 2,114 |
| $ | 2,178 |
| $ | 2,234 |
| $ | 2,394 |
| $ | 2,552 |
PSNH transmission |
|
| 341 |
|
| 360 |
|
| 406 |
|
| 406 |
|
| 505 |
|
| 540 |
WMECO transmission |
|
| 269 |
|
| 459 |
|
| 650 |
|
| 730 |
|
| 834 |
|
| 803 |
NPT |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 830 |
Total transmission |
|
| 2,759 |
|
| 2,933 |
|
| 3,234 |
|
| 3,370 |
|
| 3,733 |
|
| 4,725 |
CL&P distribution |
|
| 2,273 |
|
| 2,382 |
|
| 2,540 |
|
| 2,736 |
|
| 3,007 |
|
| 3,297 |
PSNH distribution |
|
| 803 |
|
| 866 |
|
| 947 |
|
| 1,006 |
|
| 1,070 |
|
| 1,143 |
WMECO distribution |
|
| 412 |
|
| 422 |
|
| 425 |
|
| 429 |
|
| 439 |
|
| 453 |
Total electric distribution |
|
| 3,488 |
|
| 3,670 |
|
| 3,912 |
|
| 4,171 |
|
| 4,516 |
|
| 4,893 |
PSNH generation |
|
| 394 |
|
| 399 |
|
| 727 |
|
| 742 |
|
| 740 |
|
| 728 |
WMECO generation |
|
| 11 |
|
| 27 |
|
| 31 |
|
| 31 |
|
| 33 |
|
| 35 |
Total generation |
|
| 405 |
|
| 426 |
|
| 758 |
|
| 773 |
|
| 773 |
|
| 763 |
Yankee Gas distribution |
|
| 682 |
|
| 743 |
|
| 756 |
|
| 790 |
|
| 847 |
|
| 969 |
Total |
| $ | 7,334 |
| $ | 7,772 |
| $ | 8,660 |
| $ | 9,104 |
| $ | 9,869 |
| $ | 11,350 |
At December 31, 2007 our pension plan funded ratio (pension plan assets divided by the accumulated pension plan benefit obligation) was 123 percent. Our pension plan has historically been well funded, and we have not been required to make a contribution to the plan since 1991. Due to the negative financial market conditions experienced in 2008, the fair value of our pension plan assets dropped by approximately $900 million to $1.56 billion as of December 31, 2008, and our plan’s funded ratio is now 76 percent. Based on this 2008 plan year valuation and unless there is a change in current funding requirements, we will be required to make an estimated pre-tax contribution to the plan of approximately $150 million to meet minimum funding requirements. This contribution would be paid just prior to the 2009 federal income tax return filing, which will likely occur in the third quarter of 2010.No ca sh contributions to the plan will be required to be made in 2009.
For the 2009 pension plan year, it is likely that we will also be required to make a pension plan contribution unless there is a change in current funding requirements or a very significant recovery in the financial markets. Also, assuming that the pension plan assets earn the long-term rate of return of 8.75 percent and discount rates remain constant, we currently estimate that we could be required to make an additional pre-tax contribution for the 2009 plan year in 2010 of between $150 million and $200 million. Contributions for the 2009 plan year would be made quarterly beginning in the second quarter of 2010. If significant contributions for 2009 or future pension plan years are required and there is no change in regulatory recovery mechanisms, then there will likely be an impact on the timing and amount of our future debt and equity financings. The majority of our pension expense is included in rates charge d to customers of our regulated companies.
Transmission Rate Matters and FERC Regulatory Issues
CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the rules by which these parties participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission OrganizationRTO for New England since February 1, 2005. ISO-NE works to ensure the reliability of the New England transmission system, administers the independent system operator tariff, subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines the portion of the costs of our major transmission facilities that are regionalized throughou tthroughout New England.
Transmission - Wholesale Rates: WholesaleNU's transmission revenues are based on formula rates that are approved by the FERC. Most of our wholesale transmission revenues are collected under the ISO-NE FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3). Tariff No. 3 includes Regional Network Service (RNS) and Schedule 21 - NU rate schedules to recover fees for transmission and other services. The RNS rate, administered by ISO-NE and billed to all New England transmission users, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The Schedule 21 - NU rate, which we administer, is reset on January 1st and June 1st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not r ecovered under the RNS rate, including 100 percent of the CWIP that is included in rate base on the NEEWS projects discussed below. The Schedule 21 - NU rate calculation recovers total transmission revenue requirements, net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that we recover all regional and local revenue requirements as prescribed in Tariff No. 3. Both the RNS and Schedule 21 - NUrequirements. These rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from, or refund to, customers. AtAs of December 31, 2008, the Schedule 21 -2010, NU rates werewas in a total underrecoveryoverrecovery position of $4.6$40.9 million ($3.837.2 million for CL&P)&P, $3 million for PSNH, and $0.7 million for WMECO), which will be collected fromrefunded to customers in mid-2009.June 2011.
FERCPursuant to a series of orders involving the ROE Decision: On March 24, 2008,for regionally planned New England transmission projects, the FERC issued a rehearing order confirming its initial decision settingset the base ROE for transmission projects for the New England transmission owners. Including a final adjustment, the order provides a base ROE ofat 11.14 percent and approved incentives that increased the ROE to 12.64 percent for the period beginning November 1, 2006. The order also affirmed FERC's earlier decision granting a 100 basis point adder for transmissionthose projects that are part of the ISO-NE Regional System Plan and are completed and on line by December 31, 2008. In 2008, we added $6 million ($4.9 million for CL&P) in transmission segment earnings related to this order. This order has been appealed to the D.C. Circuit Court of Appeals by numerous state regulators and consumer advocates. The Court has set a schedule for briefing to concludewere in-service by the end of the second quarter of 2009. No date has been set for arguments.
On May 16, 2008,2008. In addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy. As a result, CL&P filed an application withearns between 12.64 percent and 13.1 percent on its major transmission projects. All appeals of FERC's orders on the FERC to receive ROE incentives for its Middletown-Norwalk project and to seek a waiver of the "completed and on line" date of December 31, 2008 to earn incentives, pursuant to the FERC’s March 24, 2008 order on rehearing. Alternatively, we requested the FERC to find that this project met the nexus test requirements for incentives under FERC’s guidelines for new projects, and requested an additional 50 basis point adder for advanced technology used in the project.
The FERC subsequently granted the waiver request and approved the 100 basis point incentive for the entire Middletown-Norwalk project. The FERC also found that the project met the nexus test and granted an additional 50 basis point adder for the advanced technology aspects of the 24-mile underground portion of the project, ordering us to file more details regarding the advanced technology. The 50 basis point adder results in a total ROE for the underground portion of the Middletown-Norwalk project of 13.1 percent, which represents the overall ROE limit established by the FERC. Certain state regulators and municipal utilities sought rehearing, which were denied by the FERC, and Connecticut state regulatorsNew England transmission owners have since taken an appeal to the D.C. Circuit Court of Appeals. A schedule for the appeal has not yet been set. The technology adder increases CL&P's annual earnings beginning in 2009 by approximatel y $0.9 million.
On August 18, 2008, CL&P made a compliance filing with the FERC detailing the costs associated with the underground cables and supporting facilities of the Middletown-Norwalk project, which qualified as advanced technology. On September 8, 2008, the DPUC
41
filed a motion to reject and protest our compliance filing, stating we did not provide sufficient information. There is no specific deadline for the FERC to respond to this motion. Our response to the protest has been filed at the FERC.denied.
NEEWS Incentives: On November 17, 2008, the FERC issued an order granting incentives and rate amendments to us and National Grid USA and us for the NEEWS projects. The approved incentives include:
·
Anincluded (1) an ROE of 12.89 percent, representing an incentive of 125 basis points, 25 basis points lower than requested;
·
points; (2) 100 percent inclusion of prudently incurred CWIP in rate base; and
·
Full (3) full recovery of prudently incurred costs if NEEWS, or any portion thereof, is cancelled as a result of factors beyond NU's or National Grid USA's control.
Our share of NEEWS is estimated to cost $1.49 billion, and we received incentives on a portion of the transmission upgrades with a current estimated cost to NU of $1.41 billion. Several parties have sought rehearing of thethis yet to be acted upon FERC order granting incentives for NEEWS, which have not yet been acted on by the FERC. order.
Legislative Matters
Environmental2010 Federal Legislation:On March 23, 2010, President Obama signed into law the 2010 Healthcare Act. The Regional Greenhouse Gas Initiative (RGGI) is2010 Healthcare Act was amended by a cooperative effort by ten northeastern and mid-Atlantic states, including Connecticut, New Hampshire and Massachusetts,Reconciliation Bill signed into law on March 30, 2010. The 2010 Healthcare Act includes a provision that eliminated the tax deductibility of certain PBOP contributions equal to develop a regional program for stabilizing and reducing carbon dioxide (CO2) emissions from fossil fuel-fired electric generating plants. RGGI proposes to stabilize CO2emissions at 2009 levels and reduce them by 10 percent from these levels by 2018. RGGI is composed of individual CO2 budget trading programs in eachthe amount of the participating states. Each participating state’s CO2 budget trading program establishes its respective share of the regional cap, and each state will issue CO2 allowances infederal subsidy received by companies like NU, which sponsor retiree health care benefit plans with a numberprescription drug benefit that is actuarially equivalent to itsMedicare Part D. The tax deduction eliminated by this legislation represented a loss of previously recognized deferred income tax assets established through 2009 and as a result, these assets were written down by approximately $18 million in the first quarter of 2010. Since the electric and natural gas distribution companies are cost-of-service and rate-regulated, a portion of the regional cap. Each CO2 allowance represents a permit to emit one ton of CO2 in a specifi c year. The RGGI states will distribute CO2 allowances primarily through regional auctions. Regulated power generators are$18 million was able to purchase CO2 allowances issuedbe deferred and recovered th rough future rates. For the year ended December 31, 2010, NU deferred approximately $15 million of recoverable write-offs related to these businesses and reduced 2010 earnings on a net basis by anyapproximately $3 million of non-recoverable costs. In addition, as a result of the participating states to demonstrate compliance with the RGGI programelimination of the state governing their generating plants. Taken together, the individual participating state programs will function as a single regional compliance market for carbon emissions.tax deduction in 2010, NU was not able to recognize approximately $2 million of net annual benefits.
38
Connecticut adopted regulations in July 2008,
On September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010, which established an auction clearing price threshold of $5 per CO2 allowance, above which price all auction proceeds will be rebated to customers. For proceeds up toextends the clearing price threshold, 69.5 percent will be directed to the conservation and load management programs managed by the state’s utilities in conjunction with the Energy Conservation Management Board. Seventy-five percentbonus depreciation provisions of the RGGI auction proceeds directedAmerican Recovery and Reinvestment Act of 2009 to conservationsmall and load management programs will be allocated to CL&P’s programs. Because CL&P does not own any generating assets, it is not required to acquire CO2 allowances; however, CO2 allowance costs will likely be included in wholesale rates charged to CL&P in standard offer type contracts.large businesses through 2010. This extended stimulus provided NU with cash flow benefits of approximately $100 million.
Massachusetts passed legislation in July 2008 that did not set an auction clearing price threshold for RGGI auctions. This law requires 80 percent of RGGI auction proceeds to be allocated to utility energy efficiency and demand response programs. Because WMECO does not own any generation assets, it is not required to acquire any CO2 allowances; however, CO2 allowance costs will likely be included in wholesale rates charged to WMECO in standard offer type contracts.
New Hampshire passed legislation in June 2008 that set an auction clearing price threshold of $6 per CO2 allowance in 2009, above which all auction proceeds will be rebated to customers. Proceeds below the threshold are to be used for demand response and energy efficiency programs.
The first regional auction of RGGI CO2 allowances took place on September 25, 2008. At the auction, more than 12.5 million CO2 allowances were sold at the clearing price of $3.07 per CO2 allowance. The second regional auction was held onOn December 17, 2008,2010, President Obama signed into law the 2010 Tax Act, which, among other things, provides 100 percent bonus depreciation for tangible personal property placed in service after September 8, 2010, and more than 31.5through December 31, 2011. For tangible personal property placed in service after December 31, 2011, and through December 31, 2012, the 2010 Tax Act provides for 50 percent bonus depreciation. We expect the 2010 Tax Act to provide NU with cash flow benefits of approximately $250 million allowances were sold at a clearing price of $3.38 per CO2 allowance. Auctions are scheduled for March, June, Septemberin 2011 and December 2009.
PSNH anticipates that its generating units will emit between 4approximately $450 million and 5to $550 million tons of CO2 per year after taking into accountover the operation of PSNH’s Northern Wood Power wood-burning generating plant, which under the RGGI formula, decreased PSNH’s responsibility for reducing fossil-fired CO2 emissions by approximately 425,000 tons per year, or almost ten percent. New Hampshire legislation provides up to 2.5 million banked CO2 allowances per year for PSNH’s fossil fueled generating plants during the 2009 toperiod 2011 compliance period. These banked CO2 allowances will initially comprise approximately one-half of the yearly CO2 allowances required for PSNH’s generating plants to comply with RGGI, and such banked allowances will decrease over time. PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2 allowances at auction or in the market and has purchased allowances in the first two auctions. The cost of complying with RGGI requirements is recoverable from PSNH customers.through 2013.
New Hampshire2010 Connecticut Legislation: :In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds that would be amortized over eight years. These bonds will be repaid through a charge on the bills of customers of CL&P and other Connecticut electric distribution companies. For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would have otherwise ended by December 31, 2010 with the final principal and interest payment on its RRBs, and the diversion of about one-third of the annual funding for C&LM programs beginning in April 2012. On September 29, 2010, the DPUC approved a financing order for the bonds. A lawsuit fil ed by a state senator against the DPUC could delay the issuance. By order dated December 21, 2010, the trial court dismissed the state senator’s suit on jurisdictional grounds, and the state senator promptly appealed that order to the Connecticut Appellate Court. The DPUC has requested that the case be transferred to the Connecticut Supreme Court and decided on an expedited schedule. In addition, several bills have been introduced by the state senator and other state lawmakers to rescind the law authorizing these bonds. Unlike the RRBs issued in 2001, the revenues, interest expense and amortization expense associated with these bonds, should they be issued, will not be reflected on CL&P’s financial statements.
2008 Legislation: In July 2008, New Hampshire passed a law establishing a transmission commission responsible for developing a proposal to expand the electric transmission system in northern New Hampshire to encourage the development of new renewable generation sources. On December 1, 2008, the transmission commission submitted its progress report, which concluded that New Hampshire should continue to pursue the upgrade of transmission capacity in its northern region to allow development of its native renewable energy resources. Also, the transmission commission should continue to pursue both local and regional cost allocation issues related to the transmission expansion. The northern New Hampshire region has the potential for over 500 MW of new renewable resources. PSNH has included $130 million in its 2009 to 2013 capital plan for transmission upgrades in this region, which assumes that these proj ects are built and that a cost allocation solution can be agreed to by relevant parties.
42
In July 2008, New Hampshire passed a law authorizing rate recovery by electric public utilities of investments made in distributed energy resources up to 5 MW, such as renewable energy generation. The total investment is limited to resources having a capability equal to 6 percent of a distribution utility’s peak load. PSNH has not yet included any distributed energy resource investment opportunities in its capital expenditure plans.
Massachusetts:
2008 Legislation:As referenced above, in July 2008, Massachusetts enacted "The Green Communities Act of 2007." Aimed at increasing energy efficiency (EE) and the use of renewable resources in the state, the Act contains many provisions important to the state’s utilities. In addition to adopting RGGI requirements, the Act:
·
Removes the cap on utility expenditures for EE and demand response (DR). Requires utilities to file three-year EE and DR plans with a newly created Energy Efficiency Council;
·
Requires utilities to sign long-term contracts for renewable resources;
·
Allows each utility to own and operate up to 50 MW of solar generation;
·
Requires utilities to file a plan with the DPU for a smart grid pilot; and
·
Increases penalties for failure to meet service quality standards from 2 percent of transmission and distribution revenues to 2.5 percent.
By April 30, 2009, WMECO is required to prepare a three-year EE and DR investment plan related to the cost of EE and DR programs established by the Act for review by the Energy Efficiency Council and, ultimately, the DPU. Under the Act, utilities are authorized to own up to 50 MW of solar generating facilities, if part of a DPU approved plan. WMECO filed a program with the DPU on February 12, 2009 providing for a three-phase program with DPU authorization prior to each phase. The initial phase calls for 6 MW to be installed at eight host sites in WMECO's service territory upon receipt of DPU approval. This phase of the project is expected to be completed as early as 2010 at a cost of approximately $42 million. The second phase includes an additional 9 MW extending through 2012, and the third and final phase could increase total capacity to the 50 MW maximum. The DPU has six months to issue a decision on WMECO's plan. WMECO is otherwise precluded from making new generation investments, but has not yet included any solar generation investment opportunities in its capital expenditure plans.
Corporate Excise Tax: On July 3, 2008, Massachusetts amended its corporate excise tax provisions, which are effective for tax years beginning on or after January 1, 2009. Companies must account for the impact of income tax law changes in the period that includes the enactment date of the law change. As a result, WMECO recorded an estimate of the impact of the new legislation as a $11.9 million decrease to deferred tax liabilities and a decrease to regulatory assets on its consolidated balance sheet as of December 31, 2008.
Regulatory Developments and Rate Matters
Regulated Distribution Companies: We are currently evaluating the rate case strategies of our distribution companies. Based on 2008 earnings, cost trends, sales trends and the impact of the December 11, 2008 ice storm, it is probable that PSNH will file a distribution rate case in 2009 seeking temporary rates effective by July 1, 2009, and permanent rates effective by July 1, 2010. CL&P has determined that it will not file a distribution rate case in mid-2009. CL&P will continue to consider the possibility of filing a rate case later in 2009 or in 2010, based on the economic, political and regulatory climate in Connecticut. In response to the July 2008 rate decoupling decision in Massachusetts, WMECO notified the DPU in September 2008 that it intends to file a distribution rate case seeking authority for full decoupling in mid-2010 to be effective in January 2011. We have no immed iate plans to file a distribution rate case for Yankee Gas.
Regulated Companies’ Transmission Revenues - Retail Rates: A significant portion of our transmission segment revenue comes from ISO-NE charges to the distribution segments of CL&P, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers. Each of these companies has a retail transmission cost tracking mechanism as part of its rates, which allows them to charge their retail customers for transmission costs on a timely basis.
Forward Capacity Market: On December 1, 2006, a FERC-approved settlement agreement providing for an auction-based forward capacity market (FCM) mechanism was implemented and the payment of fixed compensation to generators through May 31, 2010 began. The first forward capacity auction concluded in early February 2008 for the capacity year of June 2010 through May 2011. The bidding reached the established minimum of $4.50 per kilowatt-month with 2,047 MW of excess remaining capacity, which resulted in an effective capacity price of $4.25 per kilowatt-month compared to the previously established price of $4.10 per kilowatt-month for the capacity year preceding June 2010. The second auction concluded on December 10, 2008 for the capacity year of June 2011 through May 2012. The bidding reached the established minimum of $3.60 per kilowatt-month with 4,755 MW of excess remaining capacity, which resulted in an effective capacity price of $3.12 per kilowatt-month. These costs are recoverable in all jurisdictions through the currently established rate structures.
Connecticut - CL&P:
Distribution Rates:On January 28, 2008,8, 2010, CL&P filed an application with the DPUC to raise distribution rates by $133.4 million (later revised to $129 million) to be effective July 1, 2010 and by an additional $44.2 million (later revised to $41.4 million) to be effective July 1, 2011. On June 30, 2010, the DPUC issued a final decisionorder in athe distribution rate case, CL&P filed onwhich approved annualized rate increases of $63.4 million effective July 30, 2007. As a result of the decision, CL&P implemented a $77.8 million annualized distribution rate increase effective February 1, 20082010 and an incremental $20.1additional $38.5 million annualized distribution rateeffective July 1, 2011. The 2010 increase effective Februarywas deferred from customer bills until January 1, 2009.
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Peaking Generation Filing: In 2007, Connecticut passed "An Act Concerning Electricity and Energy Efficiency" (Energy Efficiency Act). Among other provisions, the Energy Efficiency Act required electric distribution companies, including CL&P,2011 to file proposalscoincide with the DPUC to build cost-of-service peaking generation facilities. In 2008, the DPUC selected three projects, none of which were proposals submitted by CL&P, to provide peaking generation totaling approximately 500 MW. CL&P entered into CfDs with the developers of the three selected peaking generation units (Peaker CfDs). The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. As directed by the DPUC, CL&P and UI entered into a cost sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 p ercent of the net costs or benefits of these CfDs. CL&P’s portion of the costs and benefits will be paid by or refunded to its customers.
Renewable Energy Contracts: In 2008, pursuant to Connecticut's "Act Concerning Energy Independence," (Energy Independence Act), CL&P signed five contracts, and UI signed two contracts each to purchase energy, capacity and renewable energy credits from planned renewable energy plants, including biomass and fuel cell projects approved by the DPUC, comprising a total of 109 MW of capacity. CL&P signed one contract with a biomass projectdecline in 2007 to purchase 15 MW of its output. Purchases under the contracts are scheduled to begin between 2009 and 2011 and will extend for periods ranging from 15 to 20 years. As directed by the DPUC, CL&P and UI have also signed a sharing agreement under which they will share the costs and benefits of these contracts, with 80 percent to CL&P and 20 percent to UI. On January 16, 2009, the DPUC issued a draft decision selecting two additional renew able energy projects for a total of 6 MW with which CL&P or UI will sign similar contracts. The DPUC’s final decision on these projects is scheduled for March 11, 2009. Additional projects are expected to be selected by the DPUC to achieve a total of 150 MW of renewable energy sources in Connecticut in accordance with the Energy Independence Act. CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.
AMI Filing: On December 19, 2007, the DPUC issued a final decision on CL&P’s compliance plan that requires a pilot program to test customer interest in, and response to, peak-time based rates and technical capabilities of an advanced metering infrastructure (AMI). On May 2, 2008, the DPUC approved CL&P's revised pilot plan, which was subsequently modified to provide for a summer 2009 rate pilot supported by meters for 3,000 voluntary rate pilot customers. The restriction of meters to only rate pilot participants decreased the required number of meters from10,000 to the current 3,000. The rate pilot customer enrollment campaign began in November 2008. CL&P is required to submit a report on the customer response to the pilot, including technical capabilities of AMI meters and customer response to peak-time based rates by December 1, 2009. The estimated incremental cost o f the program currently has a range of $10.6 million to $13 million. The incremental costsrevenue requirements associated with the pilot are authorizedamortization of the aforementioned CL&P RRBs, which more than offset the revenue requirements associated with the January 1, 2011 distribution rate increase. While CL&P’s earnings benefitted in the second half of 2010 from the rate decision as a resul t of declines in depreciation and maintenance expense, cash flow benefits will not begin until early 2011 when customer bills begin to be recoveredreflect an approximately $110 million increase in distribution rates. That $110 million increase reflects the two distribution rate increases and the recovery of approximately $32 million in maintenance expense that was deferred for recovery from customers, initially through CL&P’s FMCC. The non-incremental costs are projectedthe second half of 2010 to be less than $2 million.
FMCC Filing:2011 and the first half of 2012. In September 2008,its decision, the DPUC approvedalso maintained CL&P’s semi-annual FMCC filing, which reconciled actual FMCC revenues and charges (including Energy Independence Act charges), and generation service charge (GSC) revenues and expenses for the full year period January 1, 2007 through December 31, 2007, and that identified a total overrecoveryauthorized distribution segment regulatory ROE of $105.4 million at December 31, 2007. The majority of this overrecovery was returned to customers in 2008 through credits included in 2008 rates that were determined in separate rate proceedings. On August 5, 2008, CL&P filed with the DPUC its semi-annual FMCC filing for the period January 1, 2008 through June 30, 2008. This filing identified a net overrecovery totaling $30.9 million including the remaining unamortized overrecovery from 2007. In December 2008, the DPUC issued a final decision covering this period that approved all costs as filed.
On February 6, 2009, CL&P filed with the DPUC its semi-annual FMCC filing for the year ended December 31, 2008, which identified an underrecovery totaling approximately $31.9 million, which has been recorded as a regulatory asset on the accompanying consolidated balance sheet. A decision schedule has not yet been set at this time. We do not expect the outcome of the DPUC's review of this filing to have a material adverse effect on CL&P's net income, financial position or cash flows.9.4 percent.
Standard Service and Last Resort Service Rates: CL&P's residential and small commercial customers who do not choose competitive suppliers are served under Standard Service (SS)SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under Last Resort Service (LRS)LRS rates. CL&P is fully recovering from customers the costs of its SS and LRS services. Effective January 1, 2009,2011, the DPUC approved an increasea decrease to CL&P's&P’s total average SS rate of approximately 2.47.8 percent and a decreaseslight increase to CL&P's&P’s total average LRS rate of approximately 5.90.8 percent. The energy supply portion of the total average SS rate increaseddecreased from 11.85211.282 cents per KWHKWh to 12.3169.732 cents per KWH. TheKWh while the energy supply portion of the total average LRS rate decreasedincreased from 12.6677.062 cents per KWHKWh to 11.7387.193 cents per KWH. Effective April 1, 2009, the DPUC approved a decrease to CL&P’s total average LRS rate of approximately 22 percent, which was a resu lt of the energy supply portion decreasing to 8.207 cents per KWH from January 1, 2009. CL&P is fully and timely recovering the costs of its SS and LRS services.KWh.
CTA and SBC Reconciliation: On March 31, 2008,2010, CL&P filed with the DPUC its 2007 Competitive Transition Assessment (CTA)2009 CTA and SBC reconciliation, which compared CTA and SBC revenues charged to customers to revenue requirements and allows for full recovery of revenue requirements. For the 12 months ended December 31, 2007,2009, total CTA revenues exceeded CTA revenue requirements exceeded CTA revenues by $26.1 million, which has been recorded as a decrease to the CTA regulatory asset on the accompanying consolidated balance sheet.$46.9 million. For the 12 months ended December 31, 2007,2009, the SBC cost of servicerevenues exceeded SBC revenue requirements by $23.7 million.
On November 10, 2010, a decision in the 2009 CTA and SBC docket was issued approving the 2009 CTA and SBC reconciliations as filed. The decision stated that the CTA and SBC rates would need to be reset effective January 1, 2011 based on current projections. On December 22, 2010, the DPUC approved new CTA and SBC rates, effective January 1, 2011, using updated information provided by CL&P. Based on that updated information, the CTA rate decreased from 1.054 cents per KWh to 0.332 cents per KWh and the SBC rate decreased from 0.207 cents per KWh to 0.037 cents per KWh.
FMCC Filing: On February 5, 2010, CL&P filed with the DPUC its semi-annual filing, which reconciled actual FMCC revenues by $39.4and charges and GSC revenues and expenses, for the period July 1, 2009 through December 31, 2009, and also included the previously filed revenues and expenses for the January 1, 2009 through June 30, 2009 period. The filing identified a total net underrecovery of $6.5 million, which has been recorded as a regulatory asset onincludes the accompanying consolidated balance sheet.remaining uncollected portions from previous filings. On December 3, 2008,November 10, 2010, the DPUC issued a final decision in this docket that approvedaccepting CL&P's calculations of GSC, bypassable FMCC and nonbypassable FMCC revenues and expenses for the 2007 CTA and SBC reconciliation with minor modifications. The decision referred to a potential change in the CTA rate effective Januaryperiod July 1, 2009 when new rates were to be determined for allthrough December 31, 2009. On August 5, 2010, CL&P rate components. By letter dated December 23, 2008, the DPUC approved CL&P’s recommendation to slightly decrease the base CTA rate and to establish a separate CTA refund credit beginning January 1, 2009. The CTA refund credit is intended to return to customers over a twelve month period a projected 2008 CTA overrecovery of $46.2 million, plus $1.8 million of incremental distribution revenues attributable to accelerating CL&P’s previously allowed 2009 distribution rate increase from a start date of February 1, 2009 to January 1, 2009. The DPUC also approved an increase in the SBC rate to bill an
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additional $11.7 million in 2009, which should enable CL&P to fully recover 2009 SBC expenses plus expenses that were underrecovered in prior periods.
Transmission Adjustment Clause:On June 16, 2008, CL&P filed a transmission adjustment clause (TAC) with the DPUC requesting an increase in its retail transmission rate effective July 1, 2008 to collect $67.9 million of additional revenues over the second half of the year. The increase in the TAC was attributable to the additional investment in regional transmission reliability projects. The DPUC approved CL&P'ssemi-annual FMCC filing on June 25, 2008. On December 8, 2008, CL&P filed a TAC with the DPUC requesting no change to the retail transmission rate to be effective January 1, 2009, which coversfor the period January 1, 2010 through June 30, 2009.2010. The filing identified a total net underrecovery of $7 million for the period, which includ es the remaining uncollected portions from previous filings. On January 6, 2011, the DPUC approvedissued a decision accepting CL&P’s filing on December 23, 2008.&P's calculations of GSC, bypassable FMCC and nonbypassable FMCC revenues and expenses for the period January 1, 2010 through June 30, 2010.
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On February 4, 2011, CL&P filed with the DPUC its semi-annual filing, which reconciled actual FMCC revenues and charges and GSC revenues and expenses, for the period July 1, 2010 through December 31, 2010, and also included the previously filed revenues and expenses for the January 1, 2010 through June 30, 2010 period. The filing identified a total net overrecovery of $0.3 million, which includes the remaining uncollected portions from previous filings. We do not expect the outcome of the DPUC's review of this filing to have a material adverse impact on CL&P's financial position, results of operations or cash flows.
Procurement Fee Rate Proceedings:In prior years,CL&P submitted to the DPUC its proposed methodology to calculate the variable incentive portion of its transition service procurement fee, which was effective throughfor the years 2004, 2005 and 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee. CL&P has not recorded amounts related to the 2005 orand 2006 procurement fee in earnings.CL&P recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings, through thea CTA reconciliation process. On January 15, 2009, the DPUC issued a final decision in this docket reversing its December 2005 draft decision and stated that CL&P was not eligible for the procurement incentive compensation for 2004. A $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of CL&P, and an obligation to refund the $5.8 million to customers has beencust omers was established as of December 31, 2008. CL&P filed an appeal of this decision on February 26, 2009. On February 4, 2010, the Connecticut Superior Court reversed the DPUC decision. The Court remanded the case back to the DPUC for the correction of several specific errors. On February 22, 2010, the DPUC appealed the Connecticut Superior Court’s February 4, 2010 decision to the Connecticut Appellate Court, which then transferred the appeal to the Connecticut Supreme Court. A decision is expected from the Connecticut Supreme Court in late 2011 or early 2012.
Customer Service and Metering Dockets: In 2008, the DPUC issued final decisions in a docket examining the manner of operation and accuracy of CL&P's electric meters and in a docket investigating CL&P billing errors involving approximately 2,000 customers on time of use rates. In the metering docket the DPUC did not fine CL&P, but the metering decision held that possibility open if CL&P fails to meet benchmarks to be established in the docket. The decision in the time of use docket disallowed recovery from customers of the incremental costs associated either directly or indirectly with the billing errors. These incremental costs are not material and have been expensed as incurred.
2008 Management Audit: On August 18, 2008, a consulting firm hired by the DPUC began an on-site management audit of CL&P, which is required to be conducted every six years by statute and requires a diagnostic review of all functions of the company. The audit has been completed, and a final audit report is scheduled to be filed with the DPUC in the first quarter of 2009. We do not expect a material impact to CL&P's financial position or results of operations from results of this audit.
Connecticut-Yankee Gas:Connecticut—Yankee Gas
PurchasedDistribution Rates: On January 7, 2011, Yankee Gas Adjustment: In 2005 and 2006,filed an application with the DPUC issued decisions regardingto increase its distribution rates by $32.8 million, or 7.3 percent, to be effective July 1, 2011, and by an additional $13 million, or 2.8 percent, to be effective July 1, 2012. Among other items, Yankee Gas’ PGA clause charges and required an auditGas requested to maintain its current authorized regulatory ROE of previously recovered PGA revenues10.1 percent, that $57.6 million of approximately $11 millioncosts associated with unbilled salesthe WWL Project be placed into rates, and revenue adjustments for the period of September 1, 2003 through August 31, 2005. Ona substantial increase in capital funding to replace bare steel and cast iron pipe throughout its natural gas distribution system. A final decision is expected in June 11, 2008, the DPUC issued a final order requiring Yankee Gas to refund approximately $5.8 million in previous recoveries to its customers. The $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of Yankee Gas.2011.
New Hampshire:
Merrimack Clean Air ProjectDistribution Rates:: In 2006, On June 28, 2010, the New Hampshire legislature enacted legislation requiring PSNH to reduce the mercury emissions from its coal-fired stations by at least 80 percent through the installationNHPUC approved a joint settlement agreement of wet scrubber technology at its Merrimack Station in Bow, New Hampshire no later thanPSNH’s permanent distribution rate case, effective July 1, 2013. Following an August 2008 announcement by2010, reached in April 2010 among PSNH, that the cost of this installation would be increasing from the original estimate of $250 million to $457 million, the New Hampshire Public Utilities Commission (NHPUC) opened an inquiry to determine its authority to find whether the project is in the public interest. On September 19, 2008, the NHPUC ruled that its authority is limited to determining at a later time the prudence of the costs of complying with the requirements of the scrubber legislation. In October 2008, several parties filed motions with the NHPUC requesting a reconsideration of its r uling. On November 12, 2008, the NHPUC issued an order denying the motions for rehearing. On December 11, 2008, several parties involved in the filing of the October 2008 motion for rehearing filed an appeal with the New Hampshire Supreme Court requesting that the Court overturn the NHPUC's finding that it lacked present authority over this matter. The Supreme Court has indicated that it will hear this appeal, but has not yet issued a schedule for oral arguments. PSNH has begun site work for this project and has capitalized approximately $27.5 million as of December 31, 2008. While PSNH does not expect the outcome of this appeal to adversely impact its ability to recover incurred costs from customers, should the Clean Air Act project be canceled for any reason, resulting contract cancellation payments and termination costs would likely amount to a substantial portion of the approximately $250 million of contractual commitments expected to be entered into by March 31, 2009. The actual total would depend on the timing of a cancellation, if it were to occur, and related negotiations with vendors.
Delivery Service Rates: On January 1, 2008, PSNH’s distribution rates increased by approximately $3 million annually, pursuant to the NHPUC’s May 2007 approval of PSNH’s distribution and transmission rate case settlement agreement with NHPUC staff and the New Hampshire Office of Consumer Advocate. On July 1, 2008, PSNH’sUnder the agreement, the settling parties agreed to a net annualized distribution rates decreased by $0.4 million annually. This amount consisted of a $3.4 million rate reduction related to the full recovery of a rate differential recoupment, offset by an annual increase of $3$45.5 million, for additional funding of the Major Storm Costs Reserve (MSCR) for a two-year period effective July 1, 20082010, and annualized distribution rate adjustments projected to eliminatebe a negative balancedecrease of $2.9 million and increases of $9.5 million and $11.1 million on July 1 of each of the three subsequent years. The $45.5 million increase was in addition to the $25.6 million temporary increase that became effective August 1, 2009 and includes $13.7 million to reconcile the difference between the temporary rates and the permanent rates back to August 1, 2009. The projected decrease of $2.9 million on July 1, 2011 reflects primarily the end of the one ye ar recovery of the $13.7 million reconciliation on that date. PSNH also agreed not to file a new distribution rate request prior to July 1, 2015. During the term of the settlement, PSNH’s ability to propose changes to its permanent distribution rate level will be limited to situations where its 12-month distribution ROE falls below 7 percent for two consecutive quarters or certain specified external events occur, as described in the MSCRsettlement. If PSNH's 12-month distribution ROE rolling average is greater than 10 percent, anything over the 10 percent level will be allocated 75 percent to customers and restore25 percent to PSNH. The settlement also provided that the intended reserveauthorized regulatory ROE on distribution only plant will continue at the previously allowed level of $1 million. 9.67 percent.
ES and SCRC ReconciliationFilings: On June 11, 2010, PSNH petitioned the NHPUC to change the 2010 ES and Rates:SCRC rates. On June 28, 2010, the NHPUC issued orders approving ES and SCRC rates of 8.78 cents per KWh and 1.20 cents per KWh, respectively, effective July 1, 2010. On September 21, 2010, PSNH filed petitions with the NHPUC requesting changes in both its ES and SCRC annual rates for the period January 1, 2011 through December 31, 2011. On December 16, 2010, PSNH submitted final proposed ES and SCRC rates of 8.67 cents per KWh and 1.17 cents per KWh, respectively. On December 29, 2010, the NHPUC issued orders approving the ES and SCRC rate petitions as filed.
TCAM Filing: On June 3, 2010, PSNH filed a petition with the NHPUC requesting reconciliation of the TCAM revenues and costs for 2009, and recovery of forecasted retail transmission costs for the period July 1, 2010 through June 30, 2011. On June 11, 2010, PSNH petitioned the NHPUC for a TCAM rate of 1.501 cents per KWh. On June 28, 2010, the NHPUC issued an order approving the TCAM rate as filed.
ES and SCRC Reconciliation: On May 1, 2008,an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year. On April 30, 2010, PSNH filed its 2007 default energy service (ES) and stranded cost recovery charge (SCRC)2009 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation and power purchase activities. During 2007,As of December 31, 2009 PSNH had an ES regulatory asset and an SCRC revenues exceeded ES and SCRC costs by $1.4regulatory asset of $4.4 million and $6.8$3.9 million, respectively, and were deferredwhich is being recovered from customers in the 2010 ES/SCRC rate period.
Merrimack Clean Air Project: On July 7, 2009, the New Hampshire Site Evaluation Committee determined that PSNH's Clean Air Project to install wet scrubber technology at its Merrimack Station was not subject to the Committee's review as a
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regulatory liability "sizeable" addition to be refunded to customers. On November 19, 2008, PSNH and the NHPUC Staff submitted a settlement agreement that resolved all outstanding issues. The NHPUC issuedpower plant under state law. That Committee upheld its decision in an order dated January 16, 200915, 2010, denying requests for rehearing. This order was appealed on February 23, 2010. On April 15, 2010, the New Hampshire Supreme Court determined that acceptedit would accept the settlement as filed. The settlement agreementappeal. Briefs have been filed and subsequent order did not have a material adverse impact on PSNH's financial position or results of operations. PSNH expects to file its 2008 ES and SCRC reconciliation with the NHPUC by May 1, 2009.Court has scheduled oral arguments for March 10, 2011. We do not expectbelieve that the outcome of the NHPUC review to have a material adverse impact on PSNH's financial position or results of operations.
On June 27, 2008, the NHPUC issued orders increasing the ES rate from 8.82 cents per KWH to 9.57 cents per KWH and lowering the SCRC rate from 0.72 cents per KWH to 0.65 cents per KWH, effective from July 1, 2008 through December 31, 2008. In December 2008, the NHPUC issued orders that increased the ES rate to 9.92 cents per KWH and the SCRC rate to 0.98 cents per KWH. These ratesappeal will be effective from January 1, 2009 through December 31, 2009.
TCAM Reconciliation and Rates: On May 13, 2008, PSNH filed a July 1, 2007 through June 30, 2008 transmission cost adjustment mechanism (TCAM) reconciliation and a projected TCAM rate to be billed effective July 1, 2008 and continuing through June 30, 2009. Under the terms of an NHPUC rate order issued on June 27, 2008, PSNH’s TCAM rate was increased from 0.752 cents per KWH to 0.935 cents per KWH, effective July 1, 2008.
Major Storm Costs Reserve: On December 11, 2008, a major ice storm struck portions of New England, severely damaging PSNH’s distribution system. This was the most severe ice storm in PSNH’s history. Of the 440,000 New Hampshire homes and businesses that lost power, 322,000 were served by PSNH. Restoration operations commenced on December 11, 2008 and were substantially completed by December 25, 2008. PSNH utilized its own line crews, local contractors, line crews from other NU subsidiaries and numerous other line crews from the eastern United States and Canada.
The operating cost of storm restorations that meet a NHPUC specified criteria are funded through the MSCR. Capital costs for any storm work are charged to property, plant and equipment and recovered through the normal distribution ratemaking process. As the December 2008 ice storm met the MSCR criteria, $62.7 million of total estimated repair costs of $75 million associated with this storm were charged to the MSCR at December 31, 2008. PSNH intends to recover these costs as part of its next delivery rates proceeding with the NHPUC. Out of the remaining total storm costs incurred through December 31, 2008, $6.5 million of non-incremental costs has been expensed and $5.6 million has been capitalized to plant and equipment. PSNH expects to recognize an additional $10 million in 2009 when the weather is warmer and additional clean-up and repairs can be performed. We carry $15 million of storm-related ins urance system-wide and to the extent that any insurance proceeds are received, a portion would be allocated to PSNH to reduce the amount of deferred or expensed storm costs. The NHPUC scheduled public hearings in March and April of 2009 as part of its review of state and utility operational responses to the storm. The costs of the December 11, 2008 storm did not have a material impact on PSNH's 2008 net income.the timing or costs of the project. PSNH is continuing with construction of this project and has capitalized $296.5 million since inception of the project through December 31, 2010.
Renewable Portfolio Standards: On May 11, 2007, Governor Lynch signed into law the "Renewable Energy Act," establishing renewable portfolio standards (RPS) that requires annual increases in the percentage of electricity with direct ties to renewable sources sold to New Hampshire retail customers. The renewable sourcing requirements began in 2008 and increase each year to reach 23.8 percent in 2025. PSNH plans to meet these standards, in part, through the purchase of renewable energy certificates (RECs) from qualified renewable energy resources. For each MWH of energy produced from a qualifying resource, the producer will receive one REC. Energy suppliers, like PSNH, will purchase these RECs from the producers and will use them to satisfy the RPS requirements. To the extent that PSNH is unable to purchase sufficient RECs, it will be required to make up the difference between the RECs purchased and its total obligation by making an alternative compliance payment (ACP) for each REC requirement for which PSNH is deficient. The $8.7 million in 2008 costs for the RPS obligation did not impact earnings, as these costs are being recovered by PSNH through its ES rates.40
Massachusetts:
Distribution Rates: On July 16, 2010, WMECO filed an application with the DPU, requesting approval of a $28.4 million increase in distribution rates and a decoupling plan to be effective February 1, 2011. Among other items, WMECO sought a distribution segment regulatory ROE of 10.5 percent, recovery over five years of its remaining deferred December 2008 and 2010 major storm costs and recovery of its hardship receivable costs. On January 1, 2008, WMECO’s distribution rates increased by $3 million annually as approved by31, 2011, the DPU in December 2006. WMECO adjusted its rates to include theissued a final decision approving an annualized rate increase of $16.8 million effective February 1, 2011, an authorized distribution increase, newsegment regulatory ROE of 9.6 percent, a decoupling plan with no inflation adjustment, recovery of certain 2008 and 2010 major storm costs over five years, and recovery of certain hardship receivable costs.
Basic Service Rates: In 2010, fixed basic service contracts, and changes in several tracking mechanisms. On December 29 and 30, 2008, the DPU approved WMECO’s proposed rate changes effective January 1, 2009. The rate changes were made in accordance with WMECO’s various tracking mechanisms. The overall impact on customers’ bills was a 0.5 percent increaserates ranged from 7.647 cents per KWh to 8.237 cents per KWh for residential customers, a 2 percent decrease8.44 cents per KWh to 8.972 cents per KWh for small commercial and industrial customers, and a 3 percent decrease7.052 cents per KWh to 8.893 cents per KWh for medium and large commercial and industrial customers.
Basic Service Rates: Effective July 1, 2008, the rates for basic service customers increased due to the rise in the cost of energy reflected in WMECO's basic service solicitations. Basic service rates for residential customers increased from 10.8 cents per KWH to 12.1 cents per KWH, small commercial and industrial customers increased from 11.5 cents per KWH to 12.8 cents per KWH and rates for medium and large commercial and industrial customers increased from 10.5 cents per KWH to 14.6 cents per KWH. Effective October 1, 2008, the rates for WMECO's medium and large commercial and industrial basic service customers decreased from 14.6 cents per KWH to 11.1 cents per KWH due to the decline in the cost of energy, as reflected in its basic service solicitations. Effective January 1, 2009,2011, the rates for all basic service customers decreased duechanged to reflect the decline in the cost of energy, as reflected in WMECO 's basic service solicitations. Basicsolicitations conducted by WMECO in November 2010. Fixed basic service rates for residential customers decreased from 12.1to 6.993 cents per KWH to 11.8 cents per KWH,KWh, rates for small commercial and industrial customers decreased from 12.8to 8.006 cents per KWH to 12.1 cents per KWHKWh and rates for medium and large commercial and industrial customers decreased from 11.1to 7.405 cents per KWH to 10.2KWh. The fixed price increased by 0.063 cents per KWH.KWh for street lighting customers to 5.822 cents per KWh.
Transition Cost Reconciliations: Reconciliation: On June 20, 2008, the DPU issued its final decision on WMECO’s 2005 and 2006 transition cost reconciliations, which resulted in a pre-tax charge of $1.6 million to WMECO’s 2008 consolidated statements of income. The DPU ordered WMECO to use a ROE of 11 percent, and not the allowed ROE of 9.85 percent in 2005 and 2006, for purposes of calculating
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carrying cost credits for customers on the stranded cost deferrals. In addition, the DPU ordered WMECO not to combine certain overrecoveries and underrecoveries but instead to keep them separate and to calculate carrying costs on certain balances using a ROE of 11 percent and to use customer deposit rates on other balances. The impacts of this order on WMECO's calculations of the 2007 and year to date 2008 transition cost reconciliations were recorded in the second quarter of 2008.
Decoupling Decision: On July 16, 2008, the DPU issued a decision in its decoupling generic docket requiring all gas and electric utilities to file full decoupling proposals with their next general rate case. The decision rejected calls for partial decoupling or decoupling by rate design in favor of full decoupling by rate class. Actual revenues are to be reconciled to target revenues, as established in litigated rate cases, on an annual basis. Adjustments per the reconciliation will be made to the distribution component of rates. The decision also determined that the DPU will honor existing long-term rate plans, performance-based regulation plans and settlements. On September 2, 2008, WMECO notified the DPU that it expects to file its next distribution rate case in mid-2010 to be effective January 1, 2011. The distribution rate case will include a proposal to fully decouple distribution revenues from KWH sales.
Service Quality Performance Assessment: As part of the December 2006 rate case settlement agreement approved by the DPU, WMECO became subject to service quality (SQ) metrics that measure safety, reliability and customer service. Any charges incurred are paid to customers through a method approved by the DPU. WMECO will likely be required to pay an assessment charge for its 2008 reliability performance against the metrics established for 2008, primarily as a result of significant storm activity. WMECO has performed at target for other non-storm related reliability metrics. WMECO will file its 2008 SQ results and assessment calculation with the DPU in March 2009. In 2008, WMECO recorded an estimated pre-tax charge and a regulatory liability of approximately $1.3 million for this assessment.
Storm Costs Reserve: The December 11, 2008 ice storm also impacted areas served by WMECO. As this storm met the storm costs reserve criteria approved in WMECO's last distribution rate case settlement, $11.3 million of the total $13.8 million estimated repair costs associated with this storm were recognized as a deferred asset at December 31, 2008. WMECO expects to begin recovery of these costs in its next distribution rate proceeding. Out of the remaining total storm costs, $1.4 million has been expensed, including a significant portion of non-incremental costs, and $1.1 million has been capitalized to plant and equipment. We carry $15 million of storm-related insurance system-wide and to the extent that any insurance proceeds are received, a portion would be allocated to WMECO to reduce the amount of deferred or expensed storm costs. The DPU has opened a formal docket to review storm res toration efforts by the state's utilities and held public hearings in February 2009.The costs of the December 11, 2008 storm did not have a material impact on the 2008 earnings of WMECO.
Transfer of Transmission Assets: On December 15, 2008, the FERC approved the transfer of $4 million in transmission related assets of our wholly owned subsidiaries' HWP and HP&E to WMECO, which occurred on December 31, 2008. After certain routine regulatory filings, HWP and HP&E will no longer be FERC-regulated entities.
Contingent Matters:
The items summarized below contain contingencies that may have an impact on our net income, financial position or cash flows. See Note 7A, "Commitments and Contingencies - Regulatory Developments and Rate Matters," to the consolidated financial statements for further information regarding these matters.
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Transition Cost Reconciliation: On July 18, 2008,May 12, 2010, WMECO filed its 20072009 cost reconciliation for transition, cost (TC) reconciliation with the DPU, which compared TC revenuetransmission, basic/default service, basic/default service adder, and revenue requirements. For the twelve months ended December 31, 2007, total TC revenues along with carrying charges exceeded TC revenue requirements by $2.6 million, which has been recorded as a regulatory liability on the accompanying consolidated balance sheets.capital projects scheduling list. A public hearing and procedural conferencewas held on July 12, 2010. An evidentiary hearing was held on November 20, 2008. On December 22, 2008, the Massachusetts Attorney General filed testimony on two topics: the deferred return and carrying charges on the Capital Project Scheduling List; and the recovery of Northeast Nuclear Company pension/postretirement benefits other than pension (PBOP) costs. WMECO filed rebuttal testimony12, 2010. The briefing period ended on December 30, 2008. A hearing was held on January 29, 2009. The briefing p eriod ended on February 26, 2009. There is no timeline for a DPU decision.17, 2010. We do not expect the outcome of the DPU's review of this filing to have a material adverse effectimpact on WMECO's net income, financial position, results of operations or cash flows.
Pension Factor Reconciliation Filing: On July 2, 2009, WMECO filed the 2008 reconciliation for its pension factor revenues and expenses. An evidentiary hearing was held on March 26, 2010 and the briefing period ended on May 20, 2010. On August 31, 2010, the DPU issued an approval order. The order did not have a material adverse impact on WMECO's financial position, results of operations or cash flows.
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C2 Prudency Audit: Pursuant to the decision in CL&P's 2007 rate case, the DPUC has hired a consulting firm to perform a prudency audit of certain costs incurred in the implementation of a new customer service system (C2) at CL&P. The audit began on December 1, 2008 and will be ongoing through early 2009, with a final report to the DPUC due March 31, 2009. The DPUC has stated its intentions to open a docket to review the findings of the audit after completion. We continue to believe that our C2 expenses were prudent and will be recovered in rates.
Deferred Contractual Obligations
We have decommissioning and plant closure cost obligationsRefer to Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including our electric utility subsidiaries. These companies recover these costs through state regulatory commission-approved retail rates. A summary of each of our subsidiary’s ownership percentage in the Yankee Companies at December 31, 2008 is as follows:
47
|
| CYAPC |
| YAEC |
| MYAPC | |||
CL&P |
|
| 34.5% |
|
| 24.5% |
|
| 12.0% |
PSNH |
|
| 5.0% |
|
| 7.0% |
|
| 5.0% |
WMECO |
|
| 9.5% |
|
| 7.0% |
|
| 3.0% |
Totals |
|
| 49.0% |
|
| 38.5% |
|
| 20.0% |
Our percentage share of the obligation to support the Yankee Companies under FERC-approved rate tariffs is the same as the ownership percentages above.
CYAPC, YAEC and MYAPC are currently collecting amounts that we believe are adequate to recover the remaining decommissioning and closure cost estimates for their respective plants. We believe CL&P and WMECO will recover their shares of these decommissioning and closure obligations from their customers. PSNH has recovered its share of these costs from its customers.
Spent Nuclear Fuel Litigation: In 1998, CYAPC, YAEC and MYAPC filed separate complaints against the United States Department of Energy (DOE) in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE. In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. In December 2007, the Yankee Companies filed lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001/2002.
In December 2006, the DOE appealed the ruling, and the Yankee Companies filed a cross-appeal. The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court’s findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages. The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.
The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE will be realized through the Yankee Companies' FERC-approved rate settlement agreements, subject to final determination of the FERC.CL&P, PSNH and WMECO cannot at this time determine the timing or amount of any ultimate recovery from the DOE, through the Yankee Companies, on this matter.However, we believe that any net settlement proceeds we receive would be incorporated into FERC-approved recoveries, which would be passed on to our customers through reduced charges.
NU Enterprises Divestitures
We have exited most of our competitive businesses. NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and manages its energy services activities.
Wholesale Marketing: During 2008 Select Energy continued to manage its remaining PJM power pool wholesale sales contract and its related supply contracts, which expired on May 31, 2008, and its long-term wholesale sales contract with the New York Municipal Power Agency (NYMPA), an agency comprised of municipalities, and related supply contracts, that expires in 2013. These contracts are derivatives that have been marked to market through earnings. In addition to the NYMPA-related contracts, Select Energy's only other long-term wholesale obligation is a non-derivative contract to purchase and operate the output of a certain generating facility in New England through 2012. As a non-derivative contract, the fair value of the contract has not been reflected on the balance sheet, and the contract has not been marked to market.
Retail Marketing Business: On June 1, 2006, Select Energy sold its retail marketing business and paid $24.4 million in 2006 and $14.7 million in 2007 to the purchaser, which completed our obligation.
Competitive Generation Business: We completed the sale of NU Enterprises' competitive generation assets on November 1, 2006.
Energy Services: Most of NU Enterprises' energy services businesses were sold in 2005 and 2006. Certain other businesses were wound down in 2007 and we continue to wind down minimal activity at the other energy services businesses. However, we continue to own and manage one energy services business, E.S. Boulos Company (Boulos), which is an electrical contractor based in Maine.
In connection with the sale of the retail marketing business, the competitive generation business and certain of the energy services businesses, we provided various guarantees and indemnifications to the purchasers of those businesses. See Note 7F,12D, "Commitments and Contingencies - Guarantees and Indemnifications," to the consolidated financial statements for information regarding these items.
NU Enterprises Contracts
Wholesale Derivative Contracts: On January 1, 2008, we implemented SFAS No. 157. For further information on SFAS No. 157, see Note 1F, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 4, "Fair Value Measurements,– Deferred Contractual Obligations," to the consolidated financial statements and the "Critical Accounting Policies and Estimates" sectionalso Part I, Item 3, "Legal Proceedings," for discussion of this Management’s Discussion and Analysis.
48
At December 31, 2008 and 2007, the fair value of NU Enterprises' wholesale derivative assets and derivative liabilities (through its subsidiary Select Energy), which are subject to mark-to-market accounting, are as follows:
|
| December 31, | ||||
(Millions of Dollars) |
| 2008 |
| 2007 | ||
Current wholesale derivative assets |
| $ | - |
| $ | 36.2 |
Long-term wholesale derivative assets |
|
| - |
|
| 7.2 |
Current wholesale derivative liabilities |
|
| (14.5) |
|
| (64.9) |
Long-term wholesale derivative liabilities |
|
| (49.4) |
|
| (72.5) |
Portfolio position |
| $ | (63.9) |
| $ | (94.0) |
Numerous factors could either positively or negatively affect the realization of the wholesale derivative net fair value amounts in cash. These factors include the volatility of commodity prices until the derivative contracts are exited or expire, differences between expected and actual volumes, the performance of counterparties, and other factors.
Select Energy has policies and procedures requiring all of its wholesale derivative energy positions to be valued daily and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office). The middle office is responsible for determining the portfolio's fair value independent from the front office.
The methods Select Energy used to determine the fair value of its wholesale derivative contracts are identified and segregated in the table of fair value of wholesale derivative contracts at December 31, 2008 and 2007. A description of each method is as follows: 1) prices actively quoted primarily represent NYMEX futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity, and are marked to the mid-point of bid and ask market prices. The mid-points of market prices are adjusted to include all applicable market information, such as historical experience with intramonth price volatility and bilateral contract prices in illiquid periods. Currently, Select Energy also has a derivative contract for which a portion of the contract's fair value is determin ed based upon a model. The model utilizes natural gas prices and a heat rate conversion factor to determine off-peak electricity prices for one New York routinely quoted hub zone for 2013. For the balance of hub zones, broker quotes for electricity prices are generally available on-peak through 2013 and off-peak through 2012.
Generally, valuations of short-term derivative contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term derivative contracts are less certain. Accordingly, there is a risk that derivative contracts will not be realized at the amounts recorded.
The tables below disaggregate the estimated fair value of the wholesale derivative contracts. Valuations of individual contracts are broken into their component parts based upon prices actively quoted, prices provided by external sources and model-based amounts. Under SFAS No. 157, contracts are classified in their entirety according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, these contracts are classified as Level 3 under SFAS No. 157. At December 31, 2008 and 2007, the sources of the fair value of wholesale derivative contracts are included in the following tables:
(Millions of Dollars) |
| Fair Value of Wholesale Contracts at December 31, 2008 | ||||||||||
|
| Maturity Less |
| Maturity of One |
| Maturity in |
|
| ||||
Prices actively quoted |
| $ | (10.1) |
| $ | (7.3) |
| $ | (1.2) |
| $ | (18.6) |
Prices provided by external sources |
|
| (2.7) |
|
| (21.2) |
|
| (10.0) |
|
| (33.9) |
Model-based(1) |
|
| (1.7) |
|
| (6.7) |
|
| (3.0) |
|
| (11.4) |
Totals |
| $ | (14.5) |
| $ | (35.2) |
| $ | (14.2) |
| $ | (63.9) |
(1)
The model-based amounts include the effects of implementing SFAS No. 157.
(Millions of Dollars) |
| Fair Value of Wholesale Contracts at December 31, 2007 | ||||||||||
|
| Maturity Less |
| Maturity of One |
| Maturity in |
|
| ||||
Prices actively quoted |
| $ | (4.7) |
| $ | (0.2) |
| $ | 1.4 |
| $ | (3.5) |
Prices provided by external sources |
|
| (24.0) |
|
| (38.8) |
|
| (13.4) |
|
| (76.2) |
Model-based |
|
| - |
|
| 4.3 |
|
| (18.6) |
|
| (14.3) |
Totals |
| $ | (28.7) |
| $ | (34.7) |
| $ | (30.6) |
| $ | (94.0) |
49
For the years ended December 31, 2008 and 2007, therecent changes in fair value of these derivative contracts are included in the table:
|
| Total Portfolio Fair Value | ||||
|
| 2008 |
|
| 2007 | |
(Millions of Dollars) |
|
|
|
|
|
|
Fair value of wholesale contracts outstanding at the beginning of the year |
| $ | (94.0) |
| $ | (126.5) |
Pre-tax effects of implementing SFAS No. 157 ($3.2 million after-tax) (1) |
|
| (6.1) |
|
| - |
Contracts realized or otherwise settled during the year(2) |
|
| 29.2 |
|
| 38.9 |
Change in unrealized gains/(losses) included in earnings |
|
| 7.0 |
|
| (6.4) |
Fair value of wholesale contracts outstanding at the end of the year |
| $ | (63.9) |
| $ | (94.0) |
(1)
Pre-tax effect recorded in fuel, purchased and net interchange power on the consolidated statement of income.
(2)
The 2008 amount includes purchases, issuances and settlements of $24.2 million and realized intra-month gains of $5 million.
For further information regarding Select Energy's derivative contracts, see Note 3, "Derivative Instruments," to the consolidated financial statements.
Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs,the CYAPC, YAEC, and parent guarantees), andMYAPC litigation against the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in Select Energy establishing credit limits prior to entering into contracts. The appropriateness of these limits is subject to our continuing review. Concentrations among these counterparties may affe ct Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. At December 31, 2008, approximately 99 percent of Select Energy's counterparty credit exposure to wholesale counterparties was non-rated, and approximately one percent was collateralized. The bulk of the non-rated credit exposure is comprised of one counterparty, which is a non-rated public entity that we have assessed as creditworthy. To date, this counterparty has met all of its contractual obligations.DOE.
Off-Balance Sheet Arrangements
Letters of Credit: PSNH has LOCs posted as collateral with counterparties and ISO-NE. At December 31, 2008, PSNH had $85 million in LOCs outstanding. In addition, Select Energy has a $2 million LOC posted at December 31, 2008.
Competitive Businesses: We have various guarantees and indemnification obligations outstanding on behalf of former subsidiaries in connection with the exit from our competitive businesses. See Note 7F, "Commitments and Contingencies - Guarantees and Indemnifications," to the consolidated financial statements for information regarding the maximum exposure and amounts recorded under these guarantees and indemnification obligations.
Enterprise Risk Management
We have implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks toof the company. ERMCompany. Enterprise Risk Management involves the application of a well-defined, enterprise-wide methodology that will enableenables our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the ERMEnterprise Risk Management process will identify or manage every risk or event that could impact our financial condition, or results of operations.operations or cash flows. The findings of this process are periodically discussed with our Board of Trustees.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, or results of operations.operations or cash flows. Our management communicates to and discusses with our Audit Committee of the Board of Trustees significant matters relating to critical accounting policies and estimates. The following are theOur critical accounting policies and estimates that we believe are discussed below. See the most critical in nature. See Note 1, "Summary of Significant Accounting Policies,"combined notes to our consolidated financial statements for further discussions of these policies and estimates as well as otherinformation concerning the accounting policies, estimates and assumptions used in the preparation of our consolidated financial statements.
Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental reserves could have a significant effect on earnings. Our approach estimates these liabilities based on the most likely action plan from a variety of available options, ranging from no action to establishing institutional controls, full site remediation and long-term monitoring. The estimates associated with each possible action plan are based on findings through various phases of site assessments.
These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from third-party engineering and remediation contractors. These estimates also take into
50
consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations. These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revision in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the consolidated balance sheets represent our best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are recorded on an undiscounted basis.
HWP, a subsidiary of NU, continues to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a manufactured gas plant, which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902. HWP is at least partially responsible for this site, and has already conducted substantial investigative and remediation activities. HWP first established a reserve for this site in 1994. A pre-tax charge of approximately $3 million was recorded in 2008 to reflect the estimated cost of further tar delineation and site characterization studies, as well as certain remediation costs that are considered to be probable and estimable as of December 31, 2008. The cumulative expense recorded to this reserve through December 31, 2008 was approximately $15.9 million, of which $13.9 million had been spent, leaving approximately $2 million in t he reserve as of December 31, 2008.
The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, which share responsibility for the site, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 reports and proposals for further investigations. MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation. This letter represents guidance from the MA DEP, rather than mandates. HWP has developed and begun to implement plans for additional investigations in conformity with MA DEP’s guidance letter, including estimated costs and schedules. These matters are subject to ongoing discussions with MA DEP and HG&E and may change from time to time.
At this time, we believe that the $2 million remaining in the reserve is at the low end of a range of probable and estimable costs of approximately $2 million to $2.7 million and will be sufficient for HWP to conduct the additional tar delineation and site characterization studies, evaluate its approach to this matter and conduct certain soft tar remediation. The additional studies are expected to occur through 2009.
There are many outcomes that could affect our estimates and require an increase to the reserve, or range of costs, and a reserve increase would be reflected as a charge to pre-tax earnings. However, we cannot reasonably estimate the range of additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time. Further developments may require a material increase to this reserve.
HWP's share of the remediation costs related to this site is not recoverable from customers.
Fair Value Measurements: We adopted SFAS No. 157 as of January 1, 2008. SFAS No. 157 defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). It establishes a framework for measuring fair value, using a three level hierarchy based upon the observability of inputs to the valuations. See Note 1F, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 4, "Fair Value Measurements," to the accompanying consolidated financial statements for further information.
As of January 1, 2008, we applied SFAS No. 157 to our regulated and unregulated companies’ derivative contracts that are recorded at fair value and to the marketable securities held in our supplemental benefit trust and WMECO’s spent nuclear fuel trust. We have also applied SFAS No. 157 to valuations of investments in our pension and PBOP plans as of December 31, 2008. Implementing SFAS No. 157 for our marketable securities expanded our financial statement disclosures, but did not affect the recorded fair value of investments.
For the year ended December 31, 2008, we recorded a net after-tax reduction of earnings of $3.2 million as a result of applying SFAS No. 157 to derivative liabilities for Select Energy’s remaining wholesale marketing contracts.
As a result of implementing SFAS No. 157, we also recorded changes in fair value of certain derivative contracts of CL&P. Because CL&P is a cost-of-service, rate regulated entity, the cost or benefit of the contracts is expected to be fully recovered from or refunded to CL&P's customers, and an offsetting regulatory asset or liability was recorded to reflect these changes. Implementing SFAS No. 157 resulted in a total increase to CL&P's derivative liabilities, with an offset to regulatory assets, of approximately $590 million and a total decrease to derivative assets, with an offset to regulatory liabilities, of approximately $30 million. The increase to CL&P's derivative liabilities primarily resulted from an increase in the negative fair value of a CfD with a generating plant to be built to reflect the estimated cost to exit this contract, reflecting an increase in the probability that the plant will be built and the recognition of a loss at the inception of the contract of approximately $100 million that was deferred under previous accounting guidance.
If we do not exit but rather serve out our derivative liability contracts, we will not make payments for some portion of the negative fair value recorded for the contracts. Likewise, we could receive more cash for derivative assets than the fair value recorded.
We use quoted market prices when available to determine fair values of financial instruments and classify those valuations as Level 1 within the fair value hierarchy.
51
If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations in which all significant inputs are observable. These valuations are classified as Level 2 within the fair value hierarchy.
Many of our derivative contracts that are recorded at fair value are classified as Level 3 within the hierarchy and are valued using models that incorporate both observable and unobservable inputs. Contracts valued using models are classified according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, an item may be classified as Level 3 even though there may be some significant inputs that are readily observable.
Contracts are valued using models when quoted prices in active markets for the same or similar instruments are not available. Fair value is modeled using techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price and the Black-Scholes option pricing model, incorporating the terms of the contracts. Significant unobservable inputs utilized in the valuations include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. The observable inputs into the valuation include contract purchase prices and future energy prices for the near term. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect nonperformance risk, including credit risk.
Changes in fair value of the remaining wholesale marketing contracts of our unregulated businesses are recorded in fuel, purchased and net interchange power on the accompanying consolidated statements of income. For the year ended December 31, 2008, there were net unrealized gains of $4.3 million ($7 million pre-tax), related to the valuation of these contracts. There were net realized gains of $3 million ($5 million pre-tax) for the year ended December 31, 2008. Key drivers of variability in fair values include changes in energy prices and expected volumes under the contractsWe utilize judgments in estimated expected volumes that are dependent on a number of factors including options exercised, customer utilization, weather and availability of other power sources to our counterparty.The valuations of our derivative contracts are highly sensitive to changes in market prices of commodities. See Item 7a, "Quantitative and Qualitative Disclosures about Market Risk," included in this Annual Report on Form 10-K for a sensitivity analysis of how changes in the prices of commodities would impact earnings.
Changes in fair value of the regulated company derivative contracts are recorded as regulatory assets or liabilities, as we expect to recover these costs in rates. These valuations are sensitive to the prices of energy and energy related products in future years for which markets have not yet developed. Assumptions made to implement SFAS No. 157 had a significant effect on derivative values, and changes in assumptions may continue to have significant effects.
Total Level 3 derivative assets were 66 percent of our total assets measured at fair value, and Level 3 derivative liabilities were 91 percent of our total liabilities measured at fair value at December 31, 2008. A significant portion of our Level 3 derivative liabilities relate to the regulated company derivative contracts for which changes in fair value do not affect our earnings due to our use of regulatory accounting. Changes in fair value of these contracts are not material to our liquidity or capital resources because the costs and benefits of the contracts are recoverable from or refundable to customers on a timely basis.
Our regulated and unregulated business activities that result in the recognition of derivative assets create exposures to credit risk of energy marketing and trading counterparties. At December 31, 2008, we had $273.2 million ($245.8 million related to CL&P) of regulated company and NU parent derivative assets that are contracted with multiple entities, of which $125.5 million ($104.7 million related to CL&P) is contracted with investment grade entities, $4.6 million is contracted with a government-backed entity, $131.4 million related to CL&P is contracted with a non-rated subsidiary of an investment grade company and the remainder are contracted with multiple other counterparties. We consider the credit ratings of these companies in our valuation of derivative assets and we use published probability of default indices based on the credit ratings of the counterparties to discount the value of the derivative ass et. Changes in our counterparties’ credit impact our ability to collect the derivative asset. Our derivative assets are primarily related to our regulated companies. Credit losses on regulated company contracts would not affect our earnings because these entities are cost-of-service regulated companies and costs of these contracts are recoverable from our customers. In addition, we consider our own credit rating in the valuation of derivative liabilities. Adjusting our unregulated derivative liabilities to incorporate our credit risk had an after-tax impact of $0.7 million on the fair value of our derivative liability and net income for the year ended December 31, 2008. Our regulated companies derivative assets and liabilities were also reduced to reflect the impact of our counterparties’ credit risk and our own credit risk on fair values, with no effect on net income.
NU has a policy of margining counterparties in the event that the fair value of a derivative contract exceeds a pre-determined threshold. Depending on the credit rating of the counterparty, an unsecured credit line is granted to counterparties. In the event the fair value exceeds the unsecured credit line, NU requires cash collateral for those open positions. There are exceptions to this policy for contracts whose terms are determined by regulators.
We review and update our fair value hierarchy classifications on a quarterly basis. As of December 31, 2008, we hold $53.5 million of investment securities in our supplemental benefit trust for non-pension retirement benefits and $55.7 million of investment securities in our WMECO spent nuclear fuel trust. These investments are classified in Levels 1 and 2. Classification of an investment security or group of investment securities into Level 3 may occur if a significant amount of inputs to their valuation is no longer observable due to a decline in market activity or liquidity. We have assessed the impact of recently increasing market illiquidity on the valuation of our investments. Observable inputs remain available to value the classes of securities we own. We continue to monitor the liquidity of our securities and review our valuations to ensure proper classification within the fair value hierarch y.
52
We consider unrealized losses on investment securities in the trusts to be other than temporary by nature and recognize them as realized losses because investment decisions are made by our trustee and we do not have the ability to hold securities until unrealized losses are recovered. Therefore, unrealized losses incurred on our supplemental benefit trust are recorded as realized losses in our consolidated statements of income. In 2008, we recorded $9.2 million of after-tax unrealized losses incurred on our supplemental benefit trust in other income, net on the consolidated statement of income. These amounts were partially offset by $0.4 million of after-tax net realized gains on sales of investment securities. Losses related to the WMECO spent nuclear fuel trust are recorded as an offset to the spent nuclear fuel obligation and do not impact earnings.
We believe that current market conditions were the key driver of losses recognized on our investment securities. As of December 31, 2008, our supplemental benefit trust invested in equity securities and investment grade fixed income securities (BBB- and above or equivalent). Our spent nuclear fuel trust invested in short-term investments and investment grade fixed income securities. We have $0.3 million of mortgage-backed and asset-backed securities collateralized by sub-prime debt or Alt-B debt held in the supplemental benefit trust and $0.2 million of mortgage-backed securities collaterized by Alt-A debt in the spent nuclear fuel trust. A significant portion of our mortgage-backed securities are U.S. Agency notes collateralized by residential mortgages. The underlying collateral of our corporate-asset backed securities includes residential home equity loans, auto and equipment loans, commercial mort gage-backed securities and credit card receivables.
For further information on derivative contracts and marketable securities, see Note 1E, "Summary of Significant Accounting Policies - Derivative Instruments," Note 3, "Derivative Instruments," and Note 9, "Marketable Securities," to the consolidated financial statements.
Pension and PBOP: Our subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all our regular employees. In addition to the Pension Plan, we also participate in the PBOP Plan to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting changes in benefit obligations, fair values of plan assets, funded status and net periodic expense could have a material impact on our financial position or results of operations.
Pre-tax periodic pension expense for the Pension Plan was $2.4 million, $17.4 million and $52.7 million for the years ended December 31, 2008, 2007 and 2006, respectively. The pension expense amounts exclude one-time items such as Pension Plan curtailments and termination benefits. The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, was $36.2 million, $38.4 million and $50.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Long-Term Rate of Return Assumptions: In developing our expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, we evaluated input from actuaries and consultants, as well as long-term inflation assumptions and our historical 25-year compounded return of 11 percent. Our expected long-term rates of return on assets are based on certain target asset allocation assumptions. We believe that 8.75 percent is an appropriate aggregate long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax, for 2008. We will continue to evaluate these actuarial assumptions, including the expected rate of return, at least annually and will adjust the appropriate assumptions as necessary. The Pension Plan’s and PBOP Plan’s target asset allocation assumptions and expected long-term rates of return assumptions by asset category are as follows:
|
| At December 31, | ||||||
|
| Pension Benefits |
| Postretirement Benefits | ||||
|
| 2008 and 2007 |
| 2008 and 2007 | ||||
|
| Target |
| Assumed |
| Target |
| Assumed |
Equity Securities: |
|
|
|
|
|
|
|
|
United States |
| 40% |
| 9.25% |
| 55% |
| 9.25% |
Non-United States |
| 17% |
| 9.25% |
| 11% |
| 9.25% |
Emerging markets |
| 5% |
| 10.25% |
| 2% |
| 10.25% |
Private |
| 8% |
| 14.25% |
| - |
| - |
Debt Securities: |
|
|
|
|
|
|
|
|
Fixed income |
| 25% |
| 5.50% |
| 27% |
| 5.50% |
High yield fixed income |
| - |
| - |
| 5% |
| 7.50% |
Real Estate |
| 5% |
| 7.50% |
| - |
| - |
The actual asset allocations at December 31, 2008 and 2007 approximated these target asset allocations. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate. For information regarding actual asset allocations, see Note 5A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
Pension and other postretirement benefit funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and postretirement benefit payments. Investment securities are exposed to various risks, including interest rate, credit and overall market volatility. As a result of these risks, it is reasonably probable that the market values of investment securities could increase or decrease in the near term, resulting in a material impact on the value of our pension assets. Increases or decreases in the market values could materially affect the current value of the trusts and the future level of pension and
53
other postretirement benefit expense. The current conditions in the credit market could negatively impact the assets in our trusts, but at this time we still believe that the 8.75 percent rate and the 6.85 percent rate for respective Pension and PBOP Plan assets are appropriate long-term rate of return assumptions.
Actuarial Determination of Expense: Pension and PBOP expense consists of the service cost and prior service cost determined by our actuaries, the interest cost based on the discounting of the obligations and the amortization of the net transition obligation, offset by the expected return on plan assets. Pension and PBOP expense also includes amortization of actuarial gains and losses, which represent differences between assumptions and actual or updated information.
We calculate the expected return on plan assets by applying our assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. This calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return based on the change in the fair value of assets during the year. At December 31, 2008, total investment losses to be reflected in the four-year rolling average of plan assets over the next four years were $672.3 million and $73.9 million,for the Pension Plan and the PBOPPlan, respectively. As these asset losses are reflected in the average plan asset fair values, they will be subject to amortization with other unrecognized gains/losses. The Plans currently amortize unrecognize d gains/losses as a component of pension and PBOP expense over approximately 12 years, which were the average future service period of the employees at December 31, 2008.
At December 31, 2008, the net actuarial loss subject to amortization over the next 12 years was $237.2 million and $104.9 million for the Pension Plan and PBOP Plan, respectively, which excludes the $672.3 million and $73.9 million of previous investment losses not currently reflected in the calculation of the fair value of Pension Plan and PBOP Plan assets, respectively.
Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension Plan or PBOP Plan liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow. The yield curve is developed from the top quartile of AA rated Moody’s and S&P’s bonds without callable features outstanding at December 31, 2008. This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows. The discount rates determined on this basis are 6.89 percent for the Pension Plan and 6.90 percent for the PBOP Plan at December 31, 2008. Discount rates used at December 31, 2007 were 6.60 percent for the Pension Plan and 6.35 percent for the PBOP Plan.
Forecasted Expenses and Expected Contributions: Due to the effect of the unrecognized actuarial gains/losses and based on the long-term rate of return assumptions and discount rates as noted above as well as various other assumptions, we estimate that expected forecasted expense for the Pension Plan and PBOP Plan will be $40.3 million and $37.3 million, respectively, in 2009, which is included in our guidance.
Future actual Pension and PBOP expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized. We expect to continue with our policy to contribute to the PBOP Plan at the amount of PBOP expense, excluding curtailments and special benefit amounts. Beginning in 2007, we made additional contributions to the PBOP Plan for the amounts received from the federal Medicare subsidy. This amounted to $3.7 million in 2008 and is estimated to be $3.4 million in 2009.
We have not contributed to the Pension Plan since 1991. However, as discussed below, the fair value of Pension Plan assets declined significantly during 2008. This decline, and the resulting asset level compared to the Pension Plan obligation, resulted in a required pre-tax contribution for the 2008 Pension Plan year that we currently estimate to be $150 million (assuming there is no change in current funding requirements). This contribution would be made just prior to the filing of the 2009 federal income tax return, which will likely be filed in the third quarter of 2010.
For the 2009 pension plan year, it is likely that we will also be required to make a contribution unless there is a change in current funding requirements or a very significant recovery in the financial markets. Also assuming that the pension plan assets earn the long-term rate of return of 8.75 percent and discount rates remain constant, we could be required to make an additional pre-tax contribution for the 2009 plan year in 2010 of between $150 million and $200 million. Contributions for the 2009 plan year would be made quarterly starting in the second quarter of 2010.
Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan’s and PBOP Plan’s reported cost as a result of a change in the following assumptions by 50 basis points (in millions):
|
| At December 31, | ||||||||||
|
| Pension Plan Cost |
| Postretirement Plan Cost | ||||||||
Assumption Change |
|
| 2008 |
|
| 2007 |
| 2008 |
| 2007 | ||
Lower long-term rate of return |
| $ | 11.8 |
| $ | 11.1 |
| $ | 1.3 |
| $ | 1.1 |
Lower discount rate |
| $ | 11.6 |
| $ | 12.9 |
| $ | 1.4 |
| $ | 1.4 |
Lower compensation increase |
| $ | (6.2) |
| $ | (6.9) |
|
| N/A |
|
| N/A |
Plan Assets: The fair value of the Pension Plan assets decreased by $902.6 million to $1.56 billion at December 31, 2008. This decrease includes benefit payments of $127.6 million in 2008. The Projected Benefit Obligation (PBO) for the Pension Plan increased by $40.8 million to $2.3 billion at December 31, 2008. These changes have changed the funded status of the Pension Plan on a PBO
54
basis from an overfunded position of $202.5 million at December 31, 2007 to an underfunded position of $740.9 million at December 31, 2008. The PBO includes expectations of future employee compensation increases.
The accumulated benefit obligation (ABO) of the Pension Plan was approximately $490 million greater than Pension Plan assets at December 31, 2008 and approximately $454 million less than Pension Plan assets at December 31, 2007. The ABO is the obligation for employee service and compensation provided through December 31, 2008.
The value of PBOP Plan assets has decreased by $82.5 million to $195.6 million at December 31, 2008. The benefit obligation for the PBOP Plan has decreased by $23.6 million to $436 million at December 31, 2008. These changes have increased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $181.5 million at December 31, 2007 to $240.4 million at December 31, 2008. We have made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits.
The Pension Plan assets include certain investments that are not regularly priced in an active market. These investments include private equity interests and real estate fund assets, comprising approximately 15 percent of total plan assets as of December 31, 2008. In determining the fair value of Pension Plan assets as of December 31, 2008, we obtained the most recent financial statements and requested updated values as of December 31st from the fund managers in order to obtain the best possible estimate of fair values. For the private equity and many real estate funds, the fund managers were able to provide year-end estimates of value. After discussion with various fund managers, we obtained information about conditions in the real estate markets and concluded on appropriate real estate fund values where manager estimates had not been given. The valuation of these investments requires significant jud gment. These values reflect management's best estimate as of December 31, 2008.
Health Care Cost: The health care cost trend assumption used to project increases in medical costs was 8.5 percent for 2008, decreasing one half percentage point per year to an ultimate rate of 5 percent in 2015. The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $1 million in 2008 and $1 million in 2007. Changes in the long-term health care cost trend assumption could have a material impact on our financial position or results of operations.
Goodwill and Intangible Assets: SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill balances be reviewed for impairment at least annually by applying a fair value-based test. The testing of goodwill for impairment requires us to use estimates and judgment. We have selected October 1st of each year as the annual goodwill impairment testing date. Management reviews triggering events as defined under SFAS No. 142 throughout the year and has determined that no triggering events occurred in 2008 that would have required interim testing before or after October 1st. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill. If goodwill is d eemed to be impaired, it is written off in the current period to the extent it is impaired.
We completed our impairment analysis as of October 1, 2008 for the Yankee Gas goodwill balance of $287.6 million and determined that no impairment exists. In performing the required impairment evaluation, we estimated the fair value of the Yankee Gas reporting unit and compared it to the carrying amount of the reporting unit, including goodwill. We estimated the fair value of Yankee Gas using discounted cash flow methodologies and an analysis of comparable companies or transactions. We review the outcome of each of the approaches annually and weight them appropriately to determine the fair value of Yankee Gas. This analysis requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, and long-term earnings and merger multiples of comparable companies.
We determined the discount rate using the capital asset pricing model methodology. This methodology uses a weighted average cost of capital in which the ROE is calculated using risk-free rates, stock premiums and a beta representing Yankee Gas' volatility relative to the overall market. The discount rate fluctuates from year to year as it is based on external market conditions. In 2008, the discount rate decreased because the risk-free rate and the beta were much lower in 2008 than in 2007 due to the current market conditions and the stability of the natural gas industry in this market. All of these assumptions are critical to the estimate and can change from period to period.
Updates to these assumptions in future periods, particularly changes in discount rates, could result in future impairments of goodwill. Although our evaluations since adopting SFAS No. 142 have not resulted in impairment, the estimated fair value of Yankee Gas is sensitive to changes in assumptions. For example, if the risk adjusted discount rate increased from approximately 5.95 percent to approximately 6.52 percent or the merger multiple of comparable companies decreased from approximately 10.5 to approximately 9.7 and the weighting of our valuation methodologies remained the same, then the estimated fair value of Yankee Gas would be lower than its carrying value.
Income Taxes: Income tax expense is estimated annually for each of the jurisdictions in which we operate. This process involves estimating current and deferred income tax expense or benefit as impacted by earnings and the impact of temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses, for tax and book accounting purposes, as well as, any impact of permanent differences resulting from tax credits, flow-through items, non-tax deductible expenses, etc. The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the consolidated balance sheets. The income tax estimation process impacts all of our segments. In accordance with the provisions of Accounting Principles Board (APB) No. 28, "Interim Financial Reporting," we record income tax expense quarterly using an estimated annualize d effective tax rate. Adjustments to these estimates can significantly affect our consolidated financial statements.
55
Part of the annual process in making adjustments to these estimates, as needed, is a reconciliation of the actual tax positions and amounts included on our income tax returns as filed in the fall of each year for the previous tax year to the estimates or provisions made during the income tax estimation process described above. In the third quarter of 2008, the impact of these return to provision adjustments on income tax expense was benefits of $3.2 million and $1 million for NU and CL&P, respectively.
A reconciliation of expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.
Effective on January 1, 2007, we implemented Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." FIN 48 applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties.
The determination of whether a tax position meets the recognition threshold under FIN 48 is based on facts, circumstances and information available to us. Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment. Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods could change previous conclusions used to measure the tax position estimate. This requires significant judgment. New information or events may include tax examinations or appeals, developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations. Such information or events may have a significant impact on our net income, financial position and cash flows.
Derivative Accounting: Certain regulated companies’ contracts for the purchase or sale of energy or energy related products are derivatives, along with all but one of Select Energy’s remaining wholesale marketing contracts.
The application of derivative accounting under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, is complex and requires our judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the normal purchases and sales exception, identifying, electing and designating hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on our consolidated financial statements.
The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the company determines whether it is a derivative by using amounts referenced in default provisions and other relevant sections of the contract. The estimated quantities to be served are updated during the term of the contract, and such updates can have a material impact on mark-to-market amounts. The fair value of derivative assets and liabilities with the same counterparty are offset as permitted under FIN 39, "Offsetting of Amounts Related to Certain Contracts - an Interpretation of APB Opinion No. 10 and FASB Statement No. 105." The actual experience on our derivative contracts as they are settled has not resulted in a material impact on earnings. For the year ended December 31, 2008, the realized gains on the wholesale derivative contracts of Select Energy at settlement date were $3 million ($5 million pre-tax).
The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business. We currently have elected normal on many regulated company derivative contracts. If facts and circumstances change and we can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied prospectively.
In 2007, CL&P entered into CfDs with owners of plants to be built or modified. The CfDs are derivatives that are required to be marked to market on the balance sheet. However, due to the significance of the non-observable capacity prices associated with modeling the fair values of these contracts, their initial fair values were not recorded in CL&P’s financial statements pursuant to EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." This guidance applies to initial fair values only, and not to subsequent changes in value. Subsequent changes in the values of these contracts were substantial, primarily due to reductions in the expected market prices of capacity. The value of CfDs at December 31, 2008 included approximately $100 million of initial gains and losse s, previously deferred due to the use of significant unobservable inputs in the valuation that were recorded upon adoption of SFAS No. 157 on January 1, 2008. The changes in CfD values since inception were recorded as a regulatory asset as the costs of the contracts are recoverable from CL&P’s customers. Significant judgment was involved in estimating the fair values of the contracts, including projections of capacity prices and reflecting the probabilities of cash flows considering the risks and uncertainties associated with the contracts.
Our regulated companies, particularly CL&P and PSNH, have entered into agreements that are derivatives and do not meet the normal purchases and sales exception. These contracts are marked to market and included in derivative assets and liabilities on the accompanying consolidated balance sheets. The offset to these derivatives are generally recorded as regulatory assets or liabilities as these amounts are recoverable from or refunded to our customers as they are incurred. The measurement of many of these contracts is extremely complex, as contracts are long-dated and many of the variables, such as discount rates, future energy and energy-related product prices, and the risk associated with projects that have not been completed, require significant management judgment.
For further information, see Note 1E, "Summary of Significant Accounting Policies - Derivative Accounting,"and Note 3, "Derivative Instruments," to the consolidated financial statements.
56
Revenue Recognition: The determination of energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month. Billed revenues are based on these meter readings and the bulk of recorded revenues is based on actual billings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is also recorded.
Unbilled revenues represent an estimate of electricity or gas delivered to customers for which the customers have not yet been billed. Unbilled revenues are included in revenue on the statement of income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances. There were no changes in estimating methodology in 2008.
The regulated companies estimate unbilled revenues monthly using the daily load cycle (DLC) method. The DLC method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total calendar month sales to estimate unbilled sales. Unbilled revenues are estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.
The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires our judgment. The estimate of unbilled revenues is important to our consolidated financial statements, as adjustments to that estimate could significantly impact operating revenues and earnings.
For further information, see Note 1D, "Summary of Significant Accounting Policies - Revenues," to the consolidated financial statements and "Transmission Rate Matters and FERC Regulatory Issues" to this Management’s Discussion and Analysis.
Regulatory Accounting: The accounting policies of the regulatedRegulated companies conform to GAAP applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." process.
The application of SFAS No. 71accounting guidance applicable to rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any potential new legislation.precedent. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.
We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that the regulatedRegulated companies will recover the regulatory assets that have been recorded. If we determined that we could no longer apply SFAS No. 71the accounting guidance applicable to rate-regulated enterprises to our operations, or if we could not
41
conclude that it is probable that revenues or costs would be recovered or reflected in future rates, the revenues or costs would be charged to incomeearnings in the period in which they were incurred. If we determine that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that we would record the charge in earnings at that time.
For further information, see Note 1G, "Summary of Significant Accounting Policies - Regulatory2, "Regulatory Accounting," to the consolidated financial statements.
Presentation:Unbilled Revenues: The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs on a systematic basis throughout the month. Billed revenues are based on these meter readings and the majority of recorded revenues is based on actual billings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.
Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed. Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances. There were no changes in estimating methodology in 2010.
The Regulated companies estimate unbilled revenues monthly using the daily load cycle (DLC) method. The DLC method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total calendar month sales to estimate unbilled sales. Unbilled revenues are estimated by first allocating sales to the respective rate classes and then applying an average rate to the estimate of unbilled sales. The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes, that can significantly impact the amount of revenues recorded.
For further information, see Note 1M, "Summary of Significant Accounting Policies - Revenues," to the consolidated financial statements.
Pension and PBOP: Our subsidiaries participate in a Pension Plan covering certain of our regular employees and in a PBOP Plan to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit cost is based on several significant assumptions. We evaluate these assumptions at least annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.
Pre-tax net periodic pension expense for the Pension Plan was $80.4 million, $39.7 million and $2.4 million for the years ended December 31, 2010, 2009 and 2008, respectively. The pre-tax net PBOP Plan expense was $41.6 million, $37.2 million and $36.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.
We develop key assumptions for purposes of measuring the plans’ liabilities as of December 31 and expenses for the subsequent year. These assumptions include the long-term rate of return on plan assets, discount rate, compensation/progression rate, and health care cost trend rates and are discussed below.
Long-Term Rate of Return on Plan Assets: In developing this assumption, we consider historical and expected returns and input from our actuaries and consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate. We used aggregate expected long-term rate of return assumptions of 8.25 percent and 8.75 percent on Pension Plan assets and PBOP Plan life and non-taxable health assets and a 6.45 percent and 6.85 percent for PBOP taxable health assets as of December 31, 2010 and 2009, respectively.
Discount Rate: Payment obligations related to the Pension Plan and PBOP Plan are discounted at interest rates applicable to the timing of the plans’ cash flows. The discount rate that is utilized in determining the pension and PBOP obligations is based on a yield-curve approach. The yield curve is developed from the top quartile of "AA-rated" Moody’s and S&P’s bonds without callable features outstanding as of December 31, 2010. The discount rates determined on this basis are 5.57 percent for the Pension Plan and 5.28 percent for the PBOP Plan as of December 31, 2010 and 5.98 percent and 5.73 percent for the respective plans as of December 31, 2009.
Compensation/Progression Rate: This assumption reflects the expected long-term salary growth rate, which impacts the estimated benefits that pension plan participants receive in the future. We used a compensation/progression rate of 3.5 percent and 4.0 percent as of December 31, 2010 and 2009, respectively. The 3.5 percent rate reflects our current expectation of future salary increases and promotions, including consideration of the levels of increases built into union contracts.
Actuarial Determination of Expense: Pension and PBOP expense are determined by our actuaries and consist of service cost and prior service cost, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses and amortization of the net transition obligation, offset by the expected return on plan assets. Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.
We determine the expected return on plan assets by applying our assumed rate of return to a calculation of plan assets that recognizes investment gains or losses over a four-year period after the year in which they occur, which reduces year-to-year volatility. Investment gains or losses for this purpose are the difference between the calculated expected return using our long-term rate of return assumption
42
and the actual return or loss based on the change in the fair value of assets during the year. As of December 31, 2010, investment losses that remain to be reflected in the calculation of plan assets over the next four years were $238.9 million and $1.8 millionfor the Pension Plan and PBOPPlan, respectively. These asset losses will be subject to amortization with other unrecognized actuarial gains or losses as they are reflected in the calculation of plan assets. The plans currently amortize unrecognized actuarial gains or losses as a component of pension and PBOP expense over the average future employee service period of approximately 10 and 9 years, respectively. As of December 31, 2010, the net unrecognized actuarial losses on the Pension and PBOP Plan liabilities, subject to amortization, were $676.7 million and $171.3 million, respectively.
Forecasted Expenses and Expected Contributions: Based upon the assumptions and methodologies discussed above, we estimate that forecasted expense for the Pension Plan and PBOP Plan will be $124.9 million and $42.8 million, respectively, in 2011, which is included in our earnings guidance. Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans. Pension and PBOP expense charged to earnings is net of the amounts capitalized.
We expect to continue our policy to contribute to the PBOP Plan at the amount of PBOP expense, excluding curtailments and special benefit amounts and adding contributions for the amounts received from the federal Medicare subsidy. NU's policy is to annually fund the Pension Plan in an amount at least equal to what will satisfy the requirements of ERISA and the Internal Revenue Code. NU's Pension Plan has historically been well funded, and a contribution was not required to be made from 1991 until the third quarter of 2010, when PSNH made a contribution to the plan of $45 million. Using the segment rate approach as allowed under PPA guidelines, our Pension Plan funded ratio (the value of plan assets divided by the funding target in accordance with GAAP, ourthe requirement of the PPA) was 92 percent as of January 1, 2010. We currently estimate that quarterly contributions aggregating to a total of approximately $145 million will be made in 2011.
Sensitivity Analysis: The following represents the increase to the Pension Plan’s and PBOP Plan’s reported cost as a result of a change in the following assumptions by 50 basis points (in millions):
|
| As of December 31, | ||||||||||
|
| Pension Plan Cost |
| Postretirement Plan Cost | ||||||||
Assumption Change |
|
| 2010 |
|
| 2009 |
| 2010 |
| 2009 | ||
Lower long-term rate of return |
| $ | 10.7 |
| $ | 11.1 |
| $ | 1.2 |
| $ | 1.7 |
Lower discount rate |
| $ | 13.4 |
| $ | 12.0 |
| $ | 2.2 |
| $ | 1.5 |
Higher compensation increase |
| $ | 6.1 |
| $ | 6.0 |
|
| N/A |
|
| N/A |
Health Care Cost: The health care cost trend assumption used to project increases in medical costs was 7.5 percent for determining 2010 PBOP Plan expense. For 2011 through 2013, the rate is 7 percent, subsequently decreasing one half percentage point per year to an ultimate rate of 5 percent in 2017. The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of PBOP Plan expense by $1.2 million in 2010, with a $14.5 million impact on the postretirement benefit obligation.
See Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements include all subsidiaries over which controlfor more information.
Goodwill and Intangible Assets: We are required to test goodwill balances for impairment at least annually by applying a fair value-based test that requires us to use estimates and judgment. We have selected October 1st of each year as the annual goodwill impairment testing date. Goodwill impairment is maintained and would include any variable interest entities (VIEs) for which we aredeemed to exist if the primary beneficiary as defined in FIN 46(R), "Consolidation of Variable Interest Entities." Determining whether we are the primary beneficiarynet book value of a VIE is complexreporting unit exceeds its estimated fair value and subjective, and requires our judgment. There are a varietyif the implied fair value of facts and circumstances and a number of variables taken into consideration to determine whether we are considered the primary beneficiary of a VIE. We need to determine whether the entity is a VIE and whether our interest in the entity is a variable interest. For each VIE in which we have determined we hold a variable interest, we perform a qualitative analysis that considers the nature of the VIE’s risks and determine the variability created by these risks that the VIE is designed to create and pass along to its interest holders. We evaluate the degree to which the VIE is designed to pass along risks to NU or its subsidiaries. In addition, when considered necessary to identify the primary beneficiary of the VIE, we perform modeling of the potential results of the VIE under various scenarios to quantify the degree to which it passes variability to parties that hold variable interests, including NU or one of its subsidiaries. If the majority of the variability were determined to be passed along to us, then we would be required to consolidate that VIE. A change in facts and circumstances or a change in accounting guidance could require us to reconsider whether or not we are the primary beneficiary of the VIE.
The Energy Independence Act required the DPUC to consider the impact on distribution companies of entering into long-term contracts for capacity and contracts to purchase renewable energy products from new generating plants. We reviewed each contract to determine the appropriate accounting treatmentgoodwill based on the termsestimated fair value of the contracts, which included variable and fixed pricing elements. In 2007, CL&P entered into a 15-year agreement beginning in 2010 to purchase energy, capacity and renewable energy credits from a biomass energy plant yetreporting unit is less than the carrying amount of the goodwill. If goodwill is deemed to be built.impaired, it is written down in the current period to the extent of the impairment.
We performed an impairment analysis as of October 1, 2010 for the Yankee Gas goodwill balance of $287.6 million. We determined that this contract was a variable interestno triggering events occurred in a VIE. In 2008, CL&P and UI entered into seven additional long-term agreements with proposed renewable energy plants, of which four were determined to
57
be variable interests in VIEs and the other three were concluded not to be variable interests because of their fixed pricing elements. As directed by the DPUC, CL&P has an agreement with UI under which it will share the costs and benefits of these contracts with 80 percent to CL&P and 20 percent to UI (cost sharing agreement). We utilized qualitative and quantitative analyses to evaluate whether entering into the renewable energy contracts and cost sharing agreement2010 that would require CL&P to consolidate the projects and determined that consolidation would not be required. The review of these contractshave required significant management judgment and incorporated quantitative modeling of the projections of each plant under a variety of possible scenarios in order to determine the allocation of risk between variable interest holders including the developers, equity investors, financing institutions and CL&P. The primary variable factors considered in these analyses were the plants’ operating performance and the projected market prices of energy, capacity and renewable energy credits.
In 2007, CL&P entered into two Capacity CfDs associated with the capacity of two generating projects to be builttesting before or modified, and UI entered into two capacity-related CfDs, one with a generating project to be built and one with a new demand response project. The contracts, referred to as Capacity CfDs, obligate the utilities to pay the difference between a set capacity price and the value that the projects receive in the ISO-NE capacity markets for periods of up to 15 years beginning in 2009. As directed by the DPUC, CL&P has a cost sharing agreement with UI under which it will share the costs and benefits of these four Capacity CfDs with 80 percent to CL&P and 20 percent to UI.after October 1st. We determined that the Capacity CfDsfair value of Yankee Gas substantially exceeds its carrying value and no impairment exists. In performing the evaluation, we estimated the fair value of the Yankee Gas reporting unit and compared it to the carrying amount of the reporting unit, including goodwill. We estimated the fair value of Yankee Gas using a discounted cash flow methodology and two market approaches that analyze comparable companies or transactions. This evaluation requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, long-term earnings and merger multiples of comparable companies.
We determined the discount rate using the capital asset pricing model methodology. This methodology uses a weighted average cost of capital in which the ROE is developed using risk-free rates, equity premiums and a beta representing Yankee Gas' volatility relative to the overall market. The resulting discount rate is intended to be comparable to a rate that would be applied by a market participant. The discount rate may change from year to year as it is based on external market conditions. The discount rate decreased in 2010, as compared to 2009, as a result of lower beta and risk-free treasury rates.
Income Taxes: Income tax expense is estimated annually for each of the jurisdictions in which we operate. This process involves estimating current and deferred income tax expense or benefit and the related cost sharing agreementimpact of temporary differences resulting from differing treatment of items. Such differences are derivatives and that the projects do not require consolidation. Quantitative modeling was not required for these contracts because we concluded t hat the derivative contracts are not variable interests in the projects.
The Energy Efficiency Act required electric distribution companies, including CL&P, and allowed others to file proposals with the DPUC to build cost-of-service peaking generation facilities. In 2008, CL&P entered into three CfDs with developersresult of peaking generation units approved by the DPUC (Peaker CfDs). As directed by the DPUC, CL&P and UI have entered into a cost sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percenttiming of the net costs or benefits of these Peaker CfDs. The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment streamdeduction for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. Amounts paid or received under the Peaker CfDs will be recoverable from or refunded to customers. We used both qualitative and quantitative analyses to evaluate whether these contracts are variable interests in VIEs that require CL&P to consolidate the projects. CL&P determined that, while the contracts represent variable interests in VIEs, CL&P is not required to consolidate any of these projects as of December 31, 2008. For two of the projects, UI has an obligation to absorb 20 percent of the net costs or benefits of the projects through the cost sharing agreement and also holds ownership in the projects jointly with the developer. We concluded that UI is the party that is most closely associated with the VIEs due to its related party relationships with the projects and the cost sharing agreement. We performed quantitative modeling for these two projects and our qualitative analysis of UI’s interests in the projects, which led us to conclude that CL&P is not required to consolidate these projects. The third peaker project is not currently held in a VIE. We utilized a quantitative model to determine the variability that CL&P would absorb if the project is transferred into a VIE and the Peaker CfD thus becomes a variable interest in a VIE. The primary variable factors considered in our quantitative analyses of the peaker projects were their projected capital costs, operating costs and operating performanceexpenses, as well as projected market revenuesany impact of permanent differences resulting from tax credits, non-tax deductible expenses, in addition to various other items, including items that directly impact our tax return as a result of a regulatory activity (flow-through items). The temporary differences and flow-through items result in
43
deferred tax assets and liabilities that are included in the capacity markets. Based uponconsolidated balance sheets. The income tax estimation process impacts all of our quantitative analysis, we determined thatsegments. We record income tax expense quarterly using an estimated annualized effective tax rate. Adjustments to these estimates can significantly impact our consolidated financial statements.
A reconciliation of expected tax expense at the third project will likely require consolidation ifstatutory federal income tax rate to actual tax expense recorded is included in Note 11, "Income Taxes," to the consolidated financial statements.
We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future periodtax return that have been reflected on our balance sheets. We follow generally accepted accounting principles to address the methodology to be used in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties. The determination of whether a tax position meets the recognition threshold under this guidance is based on facts, circumstances and information available to us. Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment. Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgm ent and could change previous conclusions used to measure the tax position estimate. New information or events may include tax examinations or appeals, developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations. Such information or events may have a significant impact on our financial position, results of operations and cash flows.
Accounting for Environmental Reserves:
Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate that it is transferred intoprobable that a VIE. Consolidation of that project would not impact CL&P's net income, but could add approximately $140 million of plant, $85 million of nonrecourse debtliability has been incurred and $55 million of equity (noncontrolling interest)an amount can be reasonably estimated. Adjustments made to CL&P’s balance sheet by the time the plant is placed in service (scheduled for June 2012). Any d emonstrated increases in financing or other costs that might result from consolidation of the project would be recoverable from CL&P's customers.
The FASB is in the process of reinterpreting the consolidation requirements of FIN 46(R) and expects to issue revised guidance in the second quarter of 2009. If the proposed guidance were finalized in its current form, it would likely eliminate the requirement for consolidation when we do not have the power to direct matters that significantly impact the VIE's activities. CL&P would not likely be required to consolidate the peaker project if and when the new guidance becomes effective. The FASB reinterpretation of FIN 46(R), as drafted, would become effective on January 1, 2010. Changes in facts and circumstances and changes in accounting guidance resulting in reevaluation of the accounting treatment of these contractsenvironmental reserves could have a significant impact on earnings. We estimate these liabilities based on findings through various phases of the accompanyingassessment, considering the most likely action plan from a variety of available options (ranging from no action to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. Our estimates incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations. The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site.
For further information, see Note 12A, "Commitments and Contingencies- Environmental Matters," to the consolidated financial statements.
In December 2008,Fair Value Measurements: We follow fair value measurement guidance that defines fair value as the FASB issued FASB Staff Position (FSP) FIN 46(R)-8, "Disclosures by Public Entities about Transfersprice that would be received for the sale of Financial Assetsan asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to the Company's derivative contracts that are recorded at fair value, marketable securities held in NU’s supplemental benefit trust and InterestsWMECO’s spent nuclear fuel trust, our valuations of investments in Variable Interest Entities," requiring additional disclosures about significant variable interestsour pension and PBOP plans, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.
Derivative assets are a large portion of our total assets measured at fair value (excluding assets held in variable interest entities (VIEs) effective forour external pension and PBOP trusts), and derivative liabilities comprise almost all of our total liabilities measured at fair value as of December 31, 2008 financial reporting. We2010. Changes in fair value of the regulated company derivative contracts are recorded as Regulatory assets or liabilities, as we expect to recover the costs of these contracts in rates. These valuations are sensitive to the prices of energy and energy related products in future years for which markets have not yet developed and assumptions are made. A significant portion of our derivative liabilities relate to the Regulated companies, for which changes in fair value do not have any significant variable interestsaffect our earnings and are not material to our liquidity or capital resources because the costs and benefits of the contracts are recoverable from or refundable to customers on a timely basis.
We use quoted market prices when available to determine fair values of financial instruments. If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in VIEsactive markets, quoted prices for identical or similar instruments that are not active and model-derived valuations. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to be disclosed becausearrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.
For further information see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," included in this Annual Report on Form 10-K for a sensitivity analysis of how changes in the prices of energy and energy related products would impact earnings.
For further information on derivative contracts do not materially impact our financial statements dueand marketable securities, see Note 1J, "Summary of Significant Accounting Policies - Derivative Accounting," Note 4, "Derivative Instruments," and Note 5, "Marketable Securities," to the pass-through to our customers of contract costs and benefits and because we are not currently the primary beneficiary of any VIE. consolidated financial statements.
44
Other Matters
Consolidated Edison, Inc. Merger LitigationEnvironmental Matter: : On March 13, 2008, we entered intoHWP, a settlement agreementsubsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with Con Edison, which settled all claimsan MGP site that HWP sold to HG&E, a municipal utility, in 1902. As of December 31, 2010, HWP has a $2.9 million reserve for estimated costs that HWP considers probable over the civil lawsuit between both parties relatingremaining life of the project. Although a material increase to the proposed but unconsummated merger. Under the terms of the settlement agreement, we paid Con Edison $49.5 million on March 26, 2008, which resulted in an after-tax charge of $29.8 million. This amountreserve is not recoverable from ratepayers.presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend, among other things, on the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.
Accounting Standards Issued But Not Yet Adopted:
In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements,For further information, see Note 12A, "Commitments and Contingencies- Environmental Matters," which is effective January 1, 2009. SFAS No. 160 requires ownership interests in subsidiaries held by third parties (noncontrolling interests) to be
58
presented within equity and clearly identified and labeled. It sets forth requirements for income statement presentation related to the activities of noncontrolling interests and for accounting for changes in ownership interests and provides guidance for deconsolidation. Implementation of SFAS No. 160 is not expected to have a material impact on our consolidated financial statements or the consolidated financial statements of CL&P, PSNH or WMECO.
In June 2008, the FASB issued FASB Staff Position (FSP) EITF 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities," which is effective January 1, 2009 and is required to be applied retrospectively. As a result of this FSP, our restricted stock awards that were not vested in 2007 and the first quarter of 2008 are considered participating securities in calculating EPS for these periods using the two-class method. Our restricted stock awards were completely vested during the first quarter of 2008 and are no longer awarded. FSP EITF 03-6-1 is not expected to impact our EPS for any period.
SFAS No. 157, which establishes a framework for identifying and measuring fair value, was issued in 2006 and applied in 2008 to the fair value measurements of financial assets and liabilities of NU and its subsidiaries. The statement defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. SFAS No. 157 is required to be applied to nonrecurring fair value measurements of non-financial assets and liabilities beginning in 2009, including asset retirement obligations (ARO) and goodwill and other impairment analyses. Implementation of SFAS No. 157 to non-financial assets and liabilities is not expected to have a material impact on our consolidated financial statements or the consolidated financial statements of CL&P, PSNH or WMECO. statements.
Contractual Obligations and Commercial Commitments:
Information regarding our contractual obligations and commercial commitments atas of December 31, 20082010 is summarized annually through 20132015 and thereafter as follows:
NU |
|
| ||||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter |
| Totals |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| Thereafter |
| Total | ||||||||||||||
Long-term debt maturities(a) (b) |
| $ | 54.3 |
| $ | 4.3 |
| $ | 4.3 |
| $ | 267.3 |
| $ | 305.0 |
| $ | 3,207.8 |
| $ | 3,843.0 |
| $ | 66.3 |
| $ | 267.3 |
| $ | 305.0 |
| $ | 275.0 |
| $ | 150.0 |
| $ | 3,327.9 |
| $ | 4,391.5 |
Estimated interest payments on existing debt(c) |
|
| 222.7 |
| 219.2 |
| 218.9 |
| 210.1 |
| 194.4 |
| 2,114.8 |
| 3,180.1 |
|
| 236.2 |
|
| 231.8 |
| 220.6 |
| 208.9 |
| 194.8 |
| 1,871.4 |
| 2,963.7 | |||||||||||
Capital leases(d) |
|
| 2.4 |
| 2.4 |
| 2.5 |
| 2.6 |
| 2.4 |
| 15.5 |
| 27.8 |
|
| 2.5 |
|
| 2.6 |
| 2.4 |
| 2.0 |
| 2.0 |
| 11.4 |
| 22.9 | |||||||||||
Operating leases(e) |
|
| 24.6 |
| 18.9 |
| 7.1 |
| 6.1 |
| 5.9 |
| 23.9 |
| 86.5 |
|
| 7.9 |
|
| 7.0 |
| 6.8 |
| 4.9 |
| 4.5 |
| 19.1 |
| 50.2 | |||||||||||
Required funding of pension obligations(e) (f) |
|
| - |
| 150.0 |
| - |
| - |
| - |
| - |
| 150.0 | |||||||||||||||||||||||||||
Required funding of other postretirement benefit obligations(e) |
|
| 37.3 |
| 38.7 |
| 40.9 |
| 42.8 |
| 29.3 |
| N/A |
| 189.0 | |||||||||||||||||||||||||||
Estimated future annual regulated company costs (g) |
|
| 791.6 |
| 723.9 |
| 779.7 |
| 715.0 |
| 523.6 |
| 2,855.2 |
| 6,389.0 | |||||||||||||||||||||||||||
Estimated future annual NU Enterprises costs (g) |
|
| 40.3 |
| 41.9 |
| 42.9 |
| 38.8 |
| 44.7 |
| - |
| 208.6 | |||||||||||||||||||||||||||
Funding of pension obligations(e) (j) |
|
| 145.0 |
|
| 160.0 |
| 100.0 |
| 90.0 |
| 40.0 |
| - |
| 535.0 | ||||||||||||||||||||||||||
Funding of other postretirement benefit obligations(e) |
|
| 42.8 |
|
| 41.9 |
| 24.2 |
| 21.7 |
| 20.2 |
| - |
| 150.8 | ||||||||||||||||||||||||||
Estimated future annual companies costs (f) |
|
| 641.2 |
|
| 719.4 |
| 596.9 |
| 550.5 |
| 478.6 |
| 3,404.1 |
| 6,390.7 | ||||||||||||||||||||||||||
Other purchase commitments(e) (h) |
|
| 3,162.3 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 3,162.3 |
|
| 1,570.4 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 1,570.4 |
Totals(i) (j) |
| $ | 4,335.5 |
| $ | 1,199.3 |
| $ | 1,096.3 |
| $ | 1,282.7 |
| $ | 1,105.3 |
| $ | 8,217.2 |
| $ | 17,236.3 | |||||||||||||||||||||
Total(g) (i) |
| $ | 2,712.3 |
| $ | 1,430.0 |
| $ | 1,255.9 |
| $ | 1,153.0 |
| $ | 890.1 |
| $ | 8,633.9 |
| $ | 16,075.2 |
CL&P |
|
| ||||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter |
| Totals |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| Thereafter |
| Total | ||||||||||||||
Long-term debt maturities(a) (b) |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 2,031.7 |
| $ | 2,031.7 |
| $ | 62.0 |
| $ | - |
| $ | - |
| $ | 150.0 |
| $ | 100.0 |
| $ | 2,031.7 |
| $ | 2,343.7 |
Estimated interest payments on existing debt (c) |
|
| 119.2 |
| 119.2 |
| 119.2 |
| 119.2 |
| 119.2 |
|
| 1,548.8 |
| 2,144.8 |
|
| 133.8 |
| 133.8 |
| 133.8 |
| 133.8 |
| 124.1 |
| 1,381.7 |
| 2,041.0 | |||||||||||
Capital leases(d) |
|
| 1.9 |
| 1.9 |
| 1.9 |
| 2.0 |
| 1.9 |
|
| 14.9 |
| 24.5 |
|
| 1.9 |
| 2.0 |
| 2.0 |
| 1.8 |
| 1.8 |
| 11.3 |
| 20.8 | |||||||||||
Operating leases(e) |
|
| 14.4 |
| 12.5 |
| 3.9 |
| 3.4 |
| 3.3 |
|
| 19.7 |
| 57.2 |
|
| 7.2 |
| 6.8 |
| 6.7 |
| 6.5 |
| 6.5 |
| 23.0 |
| 56.7 | |||||||||||
Required funding of other postretirement benefit obligations(e) |
|
| 15.5 |
| 15.9 |
| 16.6 |
| 17.4 |
| 10.6 |
|
| N/A |
| 76.0 | ||||||||||||||||||||||||||
Estimated future annual costs(g) |
|
| 367.9 |
| 400.9 |
| 512.6 |
| 533.7 |
| 442.0 |
|
| 2,478.5 |
| 4,735.6 | ||||||||||||||||||||||||||
Funding of other postretirement benefit obligations(e) |
|
| 17.0 |
| 16.6 |
| 8.1 |
| 7.3 |
| 6.8 |
| 6.4 |
| 62.2 | |||||||||||||||||||||||||||
Estimated future annual long-term contractual costs(f) |
|
| 284.2 |
| 415.1 |
| 436.5 |
| 451.5 |
| 397.7 |
| 3,129.5 |
| 5,114.5 | |||||||||||||||||||||||||||
Other purchase commitments(e) (h) |
|
| 573.4 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 573.4 |
|
| 598.2 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 598.2 |
Totals(i) (j) |
| $ | 1,092.3 |
| $ | 550.4 |
| $ | 654.2 |
| $ | 675.7 |
| $ | 577.0 |
| $ | 6,093.6 |
| $ | 9,643.2 | |||||||||||||||||||||
Total(g) (i) |
| $ | 1,104.3 |
| $ | 574.3 |
| $ | 587.1 |
| $ | 750.9 |
| $ | 636.9 |
| $ | 6,583.6 |
| $ | 10,237.1 |
(a)
Included in our debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal payments in the absence of receipt by us of a waiver or amendment. Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.
(b)
Long-term debt maturities exclude $298.6$301 million and $243$243.8 million for NU and CL&P, respectively, of fees and interest due for spent nuclear fuel disposal costs, a positive $20.8$11.8 million for NU of net changes in fair value of hedged debt and a negative $4.9$5.1 million and $4.3$4.4 million for NU and CL&P, respectively, of net unamortized premium and discount as of December 31, 2008.2010.
(c)
Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement. Estimated interest payments on floating-rate debt are calculated by multiplying the average of the 20082010 floating-rate resets on the debt by its scheduled notional amount outstanding for the period of measurement. This same rate is then assumed for the remaining life of the debt. Interest payments on debt that have an interest rate swap in place are estimated using the effective cost of debt resulting from the swap rather than the underlying interest cost on the debt, subject to the fixed and floating methodologies.
(d)
The capital lease obligations include imputed interest of $14.4$10.7 million and $13.3$10.2 million for NU and CL&P, respectively, as of December 31, 2008.2010.
(e)
Amounts are not included on our consolidated balance sheets.
59
(f)
The fair value of Pension Plan assets declined significantly during 2008. This decline resulted in a required contribution for the 2008 Pension Plan year. This contribution would be made just prior to the 2009 federal income tax return filing, which will likely be filed in the third quarter of 2010. We cannot determine at this time the amount of contributions that would be required for the 2009 Pension Plan year or future years.
(g)
Other than the net mark-to-market changes on respective derivative contracts held by both the regulatedRegulated companies and NU Enterprises, these obligations are not included on our consolidated balance sheets. On February 7, 2010, an explosion occurred at the construction site of Kleen Energy Systems, LLC’s 620 MW generation project with which CL&P has a Contract for Differences (CfD) contract. This event could delay or change CL&P’s estimated payments under the CfD contract. For further information, on these estimated future annual costs, see Note 7D,12C, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the consolidated financial statements.
(h)(g)
Excludes FIN 48Does not include unrecognized tax benefits of $156.3$101.2 million for NU and $106.4$80.8 million for CL&P as of December 31, 2008,2010, as we cannot make reasonable estimates of the periods or the potential amounts of cash settlement with the respective taxing authorities. Also does not include an NU $50 million contingent commitment to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.
45
(i)
(h)
Amount represents open purchase orders, excluding those obligations that are included in the capital leases, operating leases, estimated future annual regulated company costs and the estimated future annual NU Enterprises costs. These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined. Because payment timing cannot be determined, we include all open purchase order amounts in 2009.2011.
(j)(i)
For NU, excludes other long-term liabilities, including a significant portion of the FIN 48 unrecognized tax benefits described above, deferred contractual obligations ($133.1 million), environmental reserves ($26.837.1 million), various injuries and damages reserves ($35.435.1 million), employee medical insurance reserves ($6.66.9 million), long-term disability insurance reserves ($12 million) and the ARO liability reserves ($50.653.3 million) as we cannot make reasonable estimates of the periods.timing of payments. For CL&P, excludes FIN 48 unrecognized tax benefits described above, deferred contractual obligations ($91.7 million) environmental reserves ($2.8 million), various injuries and damages reserves ($24.223.5 million), employee medical insurance reserves ($22.2 million), long-term disability insurance reserves ($3.63.8 million) and the ARO liability reserves ($28.729.3 million).
(j)
These amounts represent NU's estimated minimum pension contributions to its qualified Pension Plan required under ERISA and the Internal Revenue Code. Contributions in 2012 through 2015 will vary depending on many factors, including the performance of existing plan assets, valuation of the plan's liabilities and long-term discount rates, and are subject to change.
RRB amounts are non-recourse to us, have no required payments over the next five years and are not included in this table. The regulatedRegulated companies' standard offer service contracts and default service contracts are also are not included in this table. The estimated payments under interest rate swap agreements are not included in this table as the estimated payment amounts are not determinable. For further information regarding our contractual obligations and commercial commitments, see the consolidated statements of capitalization and Note 2,8, "Short-Term Debt," Note 5A,9, "Long-Term Debt," Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 7D,12C, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 10, "Leases," and Note 11, "Long-Term Debt,13, "Leases," to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth or other statements that are not historical facts. These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify these "forward looking statements" through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward look ing statements. Factors that may cause actual results to differ materially from those included in the forward looking statements include, but are not limited to, actions or inactions by local, state and federal regulatory bodies; changes in business and economic conditions, including their impact on interest rates, bad debt expense and demand for our products and services; changes in weather patterns; changes in laws, regulations or regulatory policy; changes in levels and timing of capital expenditures; disruptions in the capital markets or events that make our access to necessary capital more difficult or costly; developments in legal or public policy doctrines; technological developments; changes in accounting standards and financial reporting regulations; fluctuations in the value of our remaining competitive electricity positions; actions of rating agencies; and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the Securities and Exc hange Commission. We undertake no obligation to update the information contained in any forward looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events.
Web Site: Additional financial information is available through our web site atwww.nu.com.
6046
RESULTS OF OPERATIONS - NU CONSOLIDATED– NORTHEAST UTILITIES AND SUBSIDIARIES
The components of significant income statementfollowing table provides the amounts and variances in operating revenues and expense line items for the past twoconsolidated statements of income for NU included in this Annual Report on Form 10-K for the years are provided in the table below (millions of dollars). ended December 31, 2010, 2009 and 2008:
Income Statement Variances | 2008 over/(under) 2007 |
|
| 2007 over/(under) 2006 |
| ||||||
| Amount |
| Percent |
|
| Amount |
| Percent |
| ||
Operating Revenues | $ | (22) |
| - | % |
| $ | (1,055) |
| (15) | % |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
Fuel, purchased and net interchange power |
| (354) |
| (11) |
|
|
| (1,280) |
| (28) |
|
Other operation |
| 60 |
| 6 |
|
|
| (160) |
| (14) |
|
Maintenance |
| 43 |
| 20 |
|
|
| 18 |
| 9 |
|
Depreciation |
| 13 |
| 5 |
|
|
| 25 |
| 10 |
|
Amortization of regulatory assets, net |
| 146 |
| (a) |
|
|
| 24 |
| (a) |
|
Amortization of rate reduction bonds |
| 4 |
| 2 |
|
|
| 13 |
| 7 |
|
Taxes other than income taxes |
| 15 |
| 6 |
|
|
| 1 |
| 1 |
|
Total operating expenses |
| (73) |
| (1) |
|
|
| (1,359) |
| (20) |
|
Operating income |
| 51 |
| 10 |
|
|
| 304 |
| (a) |
|
Interest expense, net |
| 29 |
| 12 |
|
|
| 2 |
| 1 |
|
Other income, net |
| (11) |
| (18) |
|
|
| (3) |
| (4) |
|
Income from continuing operations before |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense/(benefit) |
| (4) |
| (3) |
|
|
| 186 |
| (a) |
|
Preferred dividends of subsidiary |
| - |
| - |
|
|
| - |
| - |
|
Income from continuing operations |
| 15 |
| 6 |
|
|
| 113 |
| 85 |
|
Income/(loss) from discontinued operations |
| (1) |
| (100) |
|
|
| (337) |
| (100) |
|
Net income/(loss) | $ | 14 |
| 6 | % |
| $ | (224) |
| (48) | % |
Comparison of 2010 to 2009:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 4,898.2 |
| $ | 5,439.4 |
| $ | (541.2) |
| (9.9) | % |
Operating Expenses: |
|
|
|
|
|
|
|
| & nbsp; |
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 1,985.6 |
|
| 2,629.6 |
|
| (644.0) |
| (24.5) |
|
Other Operating Expenses |
|
| 958.4 |
|
| 1,001.2 |
|
| (42.8) |
| (4.3) |
|
Maintenance |
|
| 210.3 |
|
| 234.2 |
|
| (23.9) |
| (10.2) |
|
Depreciation |
|
| 300.7 |
|
| 309.6 |
|
| (8.9) |
| (2.9) |
|
Amortization of Regulatory Assets, Net |
|
| 95.7 |
|
| 13.3 |
|
| 82.4 |
| (a) |
|
Amortization of Rate Reduction Bonds |
|
| 232.9 |
|
| 217.9 |
|
| 15.0 |
| 6.9 |
|
Taxes Other Than Income Taxes |
|
| 314.7 |
|
| 282.2 |
|
| 32.5 |
| 11.5 |
|
Total Operating Expenses |
|
| 4,098.3 |
|
| 4,688.0 |
|
| (589.7) |
| (12.6) |
|
Operating Income |
| $ | 799.9 |
| $ | 751.4 |
| $ | 48.5 |
| 6.5 | % |
(a)
Percent greater than 100.
Net income was $14 million higher in 2008100 percent not shown as compared to 2007, primarily due to the growth in the company's transmission segment, partially offset by a $29.8 million after-tax charge associated with the settlement of litigation with Con Edison. Net income was $224 million lower in 2007 as compared to 2006 primarily due to the 2006 $314 million after-tax gain on the sale our competitive generation business.
Comparison of 2008 to 2007it is not meaningful.
Operating Revenues
|
| For the Twelve Months Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| Variance | |||
Electric distribution |
| $ | 4,714 |
| $ | 4,927 |
| $ | (213) |
Gas distribution |
|
| 577 |
|
| 514 |
|
| 63 |
Total distribution |
|
| 5,291 |
|
| 5,441 |
|
| (150) |
Transmission |
|
| 396 |
|
| 283 |
|
| 113 |
Regulated companies |
|
| 5,687 |
|
| 5,724 |
|
| (37) |
Competitive businesses |
|
| 113 |
|
| 98 |
|
| 15 |
NU consolidated |
| $ | 5,800 |
| $ | 5,822 |
| $ | (22) |
|
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Electric Distribution |
| $ | 3,802.0 |
| $ | 4,358.4 |
| $ | (556.4) |
| (12.8) | % |
Natural Gas Distribution |
|
| 434.3 |
|
| 449.6 |
|
| (15.3) |
| (3.4) |
|
Total Distribution |
|
| 4,236.3 |
|
| 4,808.0 |
|
| (571.7) |
| (11.9) |
|
Transmission |
|
| 625.6 |
|
| 577.9 |
|
| 47.7 |
| 8.3 |
|
Total Regulated Companies |
|
| 4,861.9 |
|
| 5,385.9 |
|
| (524.0) |
| (9.7) |
|
Competitive Businesses |
|
| 80.3 |
|
| 81.3 |
|
| (1.0) |
| (1.2) |
|
Other and Eliminations |
|
| (44.0) |
|
| (27.8) |
|
| (16.2) |
| (58.3) |
|
NU |
| $ | 4,898.2 |
| $ | 5,439.4 |
| $ | (541.2) |
| (9.9) | % |
A summary of our retail electric sales and firm natural gas sales were as follows:
| For the Years Ended December 31, |
| ||||||
| 2010 |
| 2009 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 34,230 |
| 33,645 |
| 585 |
| 1.7 | % |
Firm Natural Gas Sales in Million Cubic Feet | 43,251 |
| 42,450 |
| 801 |
| 1.9 | % |
Our Operating revenuesRevenues decreased $22 million in 20082010, as compared to 2009, due primarily due to lower revenues from the regulated companies ($37 million), partially offset by higher revenues from competitive businesses ($15 million). The lower regulated companies revenues were primarily due to the recovery of a lower level of CL&P distribution related expenses passed through to customers through regulatory tracking mechanisms. Competitive businesses revenues increased $15 million despite our continued exit from components of the competitive businesses due to higher Boulos revenues resulting from increased contractor billings ($10 million) and higher market prices for the remaining Select Energy wholesale contracts. Certain Select Energy contracts expired during 2008.to:
Revenues from the regulated companies decreased $37 million due to lower distribution segment revenues ($150 million), partially offset by higher transmission segment revenues ($113 million). Distribution segment revenues decreased $150 million primarily due to lower·
Lower electric distribution revenues ($213 million), partially offset by higher gas distribution revenues ($63 million). Transmission segment revenues increased $113 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses that are passed through to customers under FERC-approved transmission tariffs.
Electric distribution revenues decreased $213 million primarily duerelated to the portion of revenues that does not impact earnings ($281 million) as a result of distribution revenue being included in regulatory tracking mechanisms and consolidation eliminations of transmission segment intracompany billings to the distribution segment, partially offset by the component of revenues that flows through to earnings ($68 million). The portion of the electric distribution segment revenues that flows through to earnings increased $68 million primarily due to increases in retail rates at each of the regulated companies ($89 million), partially offset by lower retail
61
electric sales ($16 million). Retail electric sales decreased 3.5 percent in 2008 compared with 2007. Gas distribution revenues increased $63 million primarily due to increased recovery of higher gas costs, the rate increase effective July 1, 2007 and higher firm gas sales. Firm gas sales increased 2.1 percent in 2008 compared with 2007.
The $281 million electric distribution revenue decrease that does not impact earnings is due to the components of CL&P, PSNH and WMECO retail revenuesportions that are included in regulatory commission approved tracking mechanisms that track the recovery ofrecover certain incurred costs ($179 million) and do not impact earnings. The tracked electric distribution revenues that are eliminated in consolidation ($102 million). The distribution revenue tracking components decreased $179 milliondue primarily due to revenues associated with the recovery oflower generation service and related congestion charges ($233574 million) and lower CL&P delivery-related FMCC ($75 million) and lower PSNH SCRC ($5539 million), partially offset by higher CL&P wholesaleretail transmission revenues primarily due to an increase in the market price of energy related to sales of IPP generation to ISO-NE ($5966 million) and higher CL&P and PSNH retail transmission revenuestransition cost recoveries ($82 million) mainly as a result of the higher 2008 rates and higher CL&P S BC revenue ($3648 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. In addition, Regulated companies revenues that eliminate in consolidation decreased by $92 million.
·
The portion of electric distribution revenues that impacts earnings increased $40 million due primarily to a 1.7 percent increase in retail electric sales due to warmer than normal summer weather and PSNH's rate changes that were effective July 1, 2010. A decrease in natural gas revenues was due primarily to lower cost of fuel, as fuel costs are fully recovered in revenues from sales to our customers, offset by an increase in sales volume. Firm natural gas sales increased 1.9 percent in 2010 compared to 2009.
·
Improved transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
47
Fuel, Purchased and Net Interchange Power
Fuel, purchasedPurchased and net interchangeNet Interchange Power decreased in 2010, as compared to 2009, due primarily to the following:
(Millions of Dollars) | 2010 Increase/(Decrease) | |
Lower GSC supply costs, deferred fuel costs and other | $ (437.4) | |
An increased level of ES customer migration to third party | (157.4) | |
Lower basic/default service supply costs at WMECO | (34.9) | |
Lower prices on purchased natural gas, partially offset by a | (19.7) | |
Increased competitive businesses' expenses due primarily to | 5.4 | |
$ (644.0) |
Other Operating Expenses
Other Operating Expenses decreased in 2010, as compared to 2009, due primarily to:
·
Lower distribution and transmission segment expenses decreased $354of $66 million in 2008were due primarily to lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($65 million), such as retail transmission, RMR and customer service expenses, and lower uncollectibles expense at the regulated companiesYankee Gas ($36416 million), partially offset by higher competitive businesseselectric distribution and natural gas expenses ($922 million and $3 million, respectively), including higher pension costs and storm restoration costs, and higher transmission segment expenses ($4 million). Fuel expense from the regulated companies decreasedIn addition, amounts that eliminate in consolidation primarily at CL&P due to lower GSC supply costs, a decrease in deferred fuel costs and lower other purchased power costs. The decrease in GSC supply costs was primarily due to a reduction in load caused primarily by customer migration to third party suppliers and lower retail sales ($432 million), partially offset by higher Yankee Gas expenses ($41 million) primarily due to higher fuel prices in 2008 and higher PSNH fuel expense ($28 million) primarily due to higher forward energy market prices, partially offset by a decrease in payments to higher priced IPPs in 2008 as contracts expired. Competitive businesses' expenses increased due to higher Selec t Energy purchased power expenses related to the remaining wholesale contracts.service company charges decreased by $45 million.
Other Operation·
Other operation increased $60 million in 2008 primarily due to higherHigher NU parent and other companies’companies expenses ($54 million), higher competitive businesses' expenses ($6 million)of $22 million due primarily to costs incurred in 2010 related to NU's proposed merger with NSTAR and higher regulated companies’ distributionpension and transmission segment expenses ($1 million).
NU parent and other companies' expenses are higher by $54 million in 2008 primarily due to the $49.5 million payment to Con Edison resulting from the settlement of litigation. Competitive businesses' expenses are higher by $6 million primarily due to higher operating costs at the remaining services businesses.
Higher regulated companies' distribution and transmission segment expenses of $1 million are primarily due to higher transmission segment expenses ($8 million), expenses at Yankee Energy System, Inc. ($6 million) and higher electric distribution segment expenses ($4 million), partially offset by consolidation eliminations of transmission segment intracompany billings to the distribution segment, and further eliminations for NU consolidations and costs that are tracked and recovered through distribution tracking mechanisms ($18 million).environmental costs.
Maintenance
Maintenance expenses increased $43decreased in 2010, as compared to 2009, due primarily to the allowed regulatory deferral of approximately $32 million as a result of the June 30, 2010 CL&P rate case decision, of which $29.5 million was recognized as a deferral in 2008 primarily due tomaintenance expense, lower boiler and maintenance costs at PSNH’s generation business ($12 million), offset by higher regulated companies' distribution segment overhead line expenses ($3813 million), higher distribution segment vegetation management costs ($2 million) and higher transmission line expenses ($4 million). Distribution expenses are $38 million higher primarily due to higher PSNH generation expenses that are tracked and recovered through NHPUC approved tracking mechanisms ($15 million) mainly related to the Merrimack Station maintenance outages, higher tree trimming ($9 million), higher overhead linesegment routine station maintenance expenses ($5 million), substation equipment ($3 million) and line transformers ($2 million).
Depreciation
Depreciation increased $13 milliondecreased in 20082010, as compared to 2009, due primarily due to a lower depreciation rate being used at CL&P as a result of the distribution rate case decision that was effective July 1, 2010, partially offset by higher regulated transmission and distributionutility plant balances resulting from completed construction programs putprojects placed into service.service in 2010.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, netRegulatory Assets, Net increased $146 million in 2008 for the distribution segment2010, as compared to 2009, due primarily due to higher amortization at CL&P ($144 million) resulting from a higher recovery of transitionCTA costs at CL&P ($6239 million), higher PSNH amortization of SBCon the ES deferral and TCAM ($5042 million and $11 million, respectively), and previously deferred unrecovered stranded generation costs at WMECO ($11 million) and a credit in 2007 pertaining to the refund of the GSC overrecovery ($29 million).
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $4 million in 2008. The higher portion of principal within the RRB payments results in a corresponding increase in the amortization of RRBs. This increase was, partially offset by a decrease at PSNH resulting from the retirementimpact of $50 millionthe 2010 Healthcare Act related to the deferral of RRBslost tax benefits that we believe are probable of recovery in the first quarter of 2008.future electric and natural gas distribution rates ($26 million).
Taxes Other thanThan Income Taxes
(Millions of Dollars) | 2010 | |
Connecticut Gross Earnings Tax | $ | 8.9 |
Property Taxes |
| 12.5 |
Use Taxes |
| 10.4 |
Other |
| 0.7 |
| $ | 32.5 |
The increase in Taxes other than incomeOther Than Income Taxes was due primarily to an increase in property taxes increased $15 million in 2008 primarily due to higher Connecticut gross earnings tax ($16 million) mainly as a result of higher CL&Pan increase in Property, Plant and Yankee Gas revenues that are subjectEquipment related to gross earnings tax and higher property taxes at CL&P and PSNH ($5 million)our capital programs. The Connecticut Gross Earnings Tax increased primarily as a result of higher plant balancesan increase in the transmission segment revenues and an increase in distribution segment revenues primarily related to retail transmission and higher local municipaltransition cost recoveries in 2010, as compared to 2009. The increase in use taxes was due primarily to the absence in 2010 of a Connecticut state use tax rates, partially offset by lower payroll taxes charged to expense ($5 million).refund.
6248
Interest Expense Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Interest on Long-Term Debt | $ | 231.1 |
| $ | 224.7 |
| $ | 6.4 |
| 2.8 | % |
Interest on RRBs |
| 20.6 |
|
| 36.5 |
|
| (15.9) |
| (43.6) |
|
Other Interest |
| (14.4) |
|
| 12.4 |
|
| (26.8) |
| (a) |
|
| $ | 237.3 |
| $ | 273.6 |
| $ | (36.3) |
| (13.3) | % |
(a)
Percent greater than 100 percent not shown as it is not meaningful.
Interest expense, net increased $29 millionExpense decreased in 20082010, as compared to 2009, due primarily due to higher long-term debt interest ($31 million) resulting from the issuancesettlement of new long-term debtvarious state tax matters in 2007the fourth quarter of 2010, which resulted in a reduction in Other Interest and 2008 and higher other interest ($9 million) mostly related to short-term debt, partially offset by lower RRB interestInterest on RRBs resulting from lower principal balances outstanding, ($11 million).offset by higher Interest on Long-Term Debt as a result of $145 million in new long-term debt issuances in the first half of 2010 and $400 million in 2009, $150 million of which was issued by PSNH in December 2009.
Other Income, Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Other Income, Net | $ | 41.9 |
| $ | 37.8 |
| $ | 4.1 |
| 10.8 | % |
Other income, net decreased $11Income, Net increased in 2010, as compared to 2009, due primarily to higher AFUDC related to equity funds ($7 million), higher C&LM and EIA incentives ($3 million in 2008 primarily due toand $2 million, respectively), offset with lower investment income ($16 million) primarily due to the absence of the higher NU investment income interest earned in 2007 on cash the parent received from the November 2006 sale of NU's competitive generation, higher investment losses ($14 million) primarily due to the supplemental benefit trust and lower equity in earnings of regional nuclear generating and transmission companies ($2 million), partially offset by higher AFUDC equity income ($12 million) and interest income related to the 2008 tax settlement ($10 million)4 million and $2 million, respectively).
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 210.4 |
| $ | 179.9 |
| $ | 30.5 |
| 17.0 | % |
Income tax expense decreased $4 millionTax Expense increased in 20082010, as compared to 2009, due primarily due to the Con Edison settlementimpacts of the 2010 Healthcare Act ($2030 million), temporary flow through plant differences and higher pre-tax earnings ($610 million), partially offset by lower impacts associated with higher pre-tax earningsrelated to items that directly impact our tax return as a result of a regulatory activity ("flow-through") and other impacts ($225 million) and adjustments for prior years' taxes including adjustments to reconcile estimated taxes accrued to actual amounts reflected in our filed tax returns ($5 million).
Comparison of 20072009 to 20062008:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 5,439.4 |
| $ | 5,800.1 |
| $ | (360.7) |
| (6.2) | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 2,629.6 |
|
| 2,996.2 |
|
| (366.6) |
| (12.2) |
|
Other Operating Expenses |
|
| 1,001.2 |
|
| 1,021.7 |
|
| (20.5) |
| (2.0) |
|
Maintenance |
|
| 234.2 |
|
| 254.0 |
|
| (19.8) |
| (7.8) |
|
Depreciation |
|
| 309.6 |
|
| 278.6 |
|
| 31.0 |
| 11.1 |
|
Amortization of Regulatory Assets, Net |
|
| 13.3 |
|
| 186.4 |
|
| (173.1) |
| (92.9) |
|
Amortization of Rate Reduction Bonds |
|
| 217.9 |
|
| 204.9 |
|
| 13.0 |
| 6.3 |
|
Taxes Other Than Income Taxes |
|
| 282.2 |
|
| 267.5 |
|
| 14.7 |
| 5.5 |
|
Total Operating Expenses |
|
| 4,688.0 |
|
| 5,209.3 |
|
| (521.3) |
| (10.0) |
|
Operating Income |
| $ | 751.4 |
| $ | 590.8 |
| $ | 160.6 |
| 27.2 | % |
49
Operating Revenues
|
| For the Twelve Months Ended December 31, | |||||||
(Millions of Dollars) |
| 2007 |
| 2006 |
| Variance | |||
Electric distribution |
| $ | 4,927 |
| $ | 5,332 |
| $ | (405) |
Gas distribution |
|
| 514 |
|
| 453 |
|
| 61 |
Total distribution |
|
| 5,441 |
|
| 5,785 |
|
| (344) |
Transmission |
|
| 283 |
|
| 200 |
|
| 83 |
Regulated companies |
|
| 5,724 |
|
| 5,985 |
|
| (261) |
Competitive businesses |
|
| 98 |
|
| 892 |
|
| (794) |
NU consolidated |
| $ | 5,822 |
| $ | 6,877 |
| $ | (1,055) |
|
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) |
| 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Electric Distribution |
| $ | 4,358.4 |
| $ | 4,716.1 |
| $ | (357.7) |
| (7.6) | % |
Natural Gas Distribution |
|
| 449.6 |
|
| 577.4 |
|
| (127.8) |
| (22.1) |
|
Total Distribution |
|
| 4,808.0 |
|
| 5,293.5 |
|
| (485.5) |
| (9.2) |
|
Transmission |
|
| 577.9 |
|
| 424.8 |
|
| 153.1 |
| 36.0 |
|
Total Regulated Companies |
|
| 5,385.9 |
|
| 5,718.3 |
|
| (332.4) |
| (5.8) |
|
Competitive Businesses |
|
| 81.3 |
|
| 114.1 |
|
| (32.8) |
| (28.7) |
|
Other and Eliminations |
|
| (27.8) |
|
| (32.3) |
|
| 4.5 |
| 13.9 |
|
NU |
| $ | 5,439.4 |
| $ | 5,800.1 |
| $ | (360.7) |
| (6.2) | % |
Net income is $224 million lower in 2007 due to the two significant gains in 2006 that did not occur in 2007. These gainsA summary of our retail electric sales and firm natural gas sales were an after-tax gain of $314 million associated with the sale of the competitive generation business and the CL&P $74 million income tax reduction associated with the PLR. The negative impact on net income of the 2006 gains was partially offset by the $107 million higher earnings of NU Enterprises due to the $96 million loss in 2006.as follows:
| For the Years Ended December 31, |
| ||||||
| 2009 |
| 2008 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 33,645 |
| 34,883 |
| (1,238) |
| (3.5) | % |
Firm Natural Gas Sales in Million Cubic Feet | 42,450 |
| 39,717 |
| 2,733 |
| 6.9 | % |
Operating Revenues
Operating revenues decreased $1.06 billion in 20072009, as compared to 2008, due primarily due to lower distribution segment revenues from NU Enterprises ($794485 million) and lower revenues from the regulated companies ($261 million). NU Enterprises' revenues decreased $794 million due to the exit from componentsas a result of the competitive businesses during the latter part of 2006. The lower regulated revenues are being driven by the recovery of a lower level of CL&Pelectric and natural gas distribution relatedfuel and other expenses passed through to customers through regulatory tracking mechanisms.
Revenues fromElectric distribution revenues decreased due primarily to a decrease in the regulated companies decreased $261 million due to lowerportion of electric distribution segment revenues that does not impact earnings ($344395 million), partially offset by higher transmission segmentan increase in the component of revenues that impacts earnings ($8337 million). Distribution segment revenues decreased $344 million primarily due to lowerThe portion of electric distribution revenues ($405 million),that impacts earnings increased $37 million due primarily to higher CL&P and PSNH retail rates, partially offset by lower retail electric sales. Retail electric sales for the Regulated companies decreased 3.5 percent. Natural gas distribution revenues decreased $128 million due primarily to decreased recovery of fuel costs primarily as a result of lower prices, partially offset by higher sales volumes. Firm natural gas distribution revenues ($61 million). Transmission segment revenuessales increased $83 million primarily due to a higher transmission investment base and higher operating expenses that are recovered under FERC-approved transmission tariffs. 6.9 percent in 2009 compared with 2008.
LowerThe $395 million decrease in electric distribution revenues includethat does not impact earnings consists of the componentsportions of CL&P, PSNH and WMECO retaildistribution revenues that are included in regulatory commission approved tracking mechanisms that track the recovery ofrecover certain incurred costs ($447356 million) and revenues that are eliminated in consolidation of the Regulated companies ($39 million). The distribution revenue tracking components decreasedecreased $356 million due primarily to lower recovery of $447 million is primarily due to the pass through of lower energy supply costsgeneration service and related congestion charges ($305331 million), and lower CL&P revenue associated with the recovery of delivery-related FMCC ($104 million), a decrease in PSNH’s SCRCwholesale revenues mainly as a result of a rate decrease that went into effect July 1, 2006decreased market revenue related to sales of IPP purchased generation output ($76 million) and lower wholesale revenues ($28163 million), partially offset by higher retail transmission revenues ($43104 million) mainly as a result of the higher 2009 retail rates. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from cu stomers in future periods.
Transmission segment revenues increased due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008 and higher overall expenses. Competitive businesses' revenues decreased $33 million due primarily to lower Boulos revenues as a result of less work on transmission projects and a lower level of work in other areas.
Fuel, Purchased and Net Interchange Power
Fuel, Purchased and Net Interchange Power decreased in 2009, as compared to 2008, due primarily to the following:
(Millions of Dollars) | 2009 Increase/(Decrease) | |
Lower GSC supply costs and other purchased power costs, | $ (154.7) | |
Lower prices on purchased natural gas at Yankee Gas | (132.6) | |
An increased level of ES customer migration to third party | (37.8) | |
Lower basic/default service supply costs at WMECO | (45.2) | |
Increased competitive businesses' expenses due primarily to | 3.7 | |
$ (366.6) |
50
Other Operating Expenses
Other Operating Expenses decreased in 2009, as compared to 2008, due primarily to lower NU parent and other companies' expenses ($49 million) and lower competitive businesses' expenses ($39 million), WMECO’spartially offset by higher distribution and transmission segment expenses ($68 million).
NU parent and other companies' expenses were lower by $49 million in 2009 due primarily to the absence of the $49.5 million payment resulting from the settlement of litigation made in 2008 ($29.8 million after-tax). Competitive businesses' expenses were lower by $39 million due primarily to lower Boulos expenses as a result of a lower level of work.
Higher distribution and transmission segment expenses of $68 million were due primarily to higher electric distribution segment expenses ($49 million), higher expenses at Yankee Gas ($18 million), and higher transmission segment expenses ($15 million), partially offset by lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($8 million), and all other operating costs ($6 million). The higher operations expenses impacting earnings include higher uncollectible and pension expenses.
Maintenance
Maintenance decreased in 2009, as compared to 2008, due primarily to lower distribution segment expenses ($21 million), partially offset by higher transmission line expenses ($1 million). Distribution segment expenses were lower due primarily to lower repair and maintenance of distribution lines ($15 million), including lower storm-related expenses, lower equipment maintenance expenses ($4 million), and lower PSNH generation expenses ($3 million), partially offset by higher vegetation management expenses ($5 million).
Depreciation
Depreciation increased in 2009, as compared to 2008, due primarily to higher transmission segment ($23 million) and distribution segment ($11 million) plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net
Amortization of Regulatory Assets, Net decreased $173 million in 2009, as compared to 2008, for the distribution segment due primarily to lower amortization at CL&P resulting from a lower recovery of stranded costs ($131 million) as a result of lower retail CTA revenues and higher transition costs, partially offset by higher amortization of the SBC balance ($15 million). The decreases for PSNH and WMECO are $39 million and $15 million, respectively.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes increased in 2009, as compared to 2008, due primarily to higher property taxes ($18 million) as a result of higher plant balances and increased municipal tax rates and higher payroll related taxes, partially offset by the resolution of various routine tax issues primarily surrounding sales and use tax amounts ($8 million).
Interest Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Interest on Long-Term Debt | $ | 224.7 |
| $ | 193.9 |
| $ | 30.8 |
| 15.9 | % |
Interest on RRBs |
| 36.5 |
|
| 50.2 |
|
| (13.7) |
| (27.3) |
|
Other Interest |
| 12.4 |
|
| 25.0 |
|
| (12.6) |
| (50.4) |
|
| $ | 273.6 |
| $ | 269.1 |
| $ | 4.5 |
| 1.7 | % |
Interest Expense increased in 2009, as compared to 2008, due primarily to higher Interest on Long-Term Debt resulting from the issuance of new long-term debt in 2008 and 2009, partially offset by lower Interest on RRBs resulting from lower principal balances outstanding, and lower Other Interest mostly related to the resolution of various routine tax issues.
Other Income, Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Other Income, Net | $ | 37.8 |
| $ | 50.4 |
| $ | (12.6) |
| (25.0) | % |
Other Income, Net decreased in 2009, as compared to 2008, due primarily to lower AFUDC equity income ($20 million) as a result of lower eligible CWIP balances, the absence of interest income related to the federal tax settlement in 2008 ($10 million), and lower CL&P EIA incentives ($6 million), partially offset by higher investment income due primarily to improved results from NU's supplemental benefit trust and the absence of other-than-temporary impairments recorded in 2008 ($24 million).
51
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 179.9 |
| $ | 105.7 |
| $ | 74.2 |
| 70.2 | % |
Income Tax Expense increased in 2009, as compared to 2008, due primarily to higher pre-tax earnings ($50 million), lower tax benefits associated with less capital expenditures ($10 million), lower federal and state tax credits ($4 million), and increases in allowance for uncollectible accounts reserves ($3 million).
52
Selected Consolidated Sales Statistics |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 | ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Regulated Companies: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 2,336,078 |
| $ | 2,569,278 |
| $ | 2,525,635 |
| $ | 2,558,547 |
| $ | 2,409,414 | |
Commercial |
|
| 1,303,841 |
|
| 1,462,786 |
|
| 1,607,224 |
|
| 1,735,923 |
|
| 1,977,444 | |
Industrial |
|
| 268,598 |
|
| 297,854 |
|
| 399,753 |
|
| 412,381 |
|
| 589,742 | |
Wholesale |
|
| 506,475 |
|
| 445,261 |
|
| 545,127 |
|
| 392,675 |
|
| 388,635 | |
Streetlighting and Railroads |
|
| 42,387 |
|
| 33,035 |
|
| 38,522 |
|
| 45,880 |
|
| 52,853 | |
Miscellaneous and Eliminations |
|
| (29,878) |
|
| 128,118 |
|
| 24,673 |
|
| 84,043 |
|
| 133,925 | |
Total Electric |
|
| 4,427,501 |
|
| 4,936,332 |
|
| 5,140,934 |
|
| 5,229,449 |
|
| 5,552,013 | |
Natural Gas |
|
| 434,277 |
|
| 449,571 |
|
| 577,390 |
|
| 514,185 |
|
| 453,894 | |
Total - Regulated Companies |
| $ | 4,861,778 |
| $ | 5,385,903 |
| $ | 5,718,324 |
| $ | 5,743,634 |
| $ | 6,005,907 | |
NU Enterprises: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Retail |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 583,829 | |
Wholesale |
|
| 24,633 |
|
| 30,009 |
|
| 31,882 |
|
| 25,992 |
|
| 20,163 | |
Generation |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 258,178 | |
Services |
|
| 51,998 |
|
| 48,195 |
|
| 78,625 |
|
| 68,324 |
|
| 39,887 | |
Miscellaneous and Eliminations |
|
| 3,716 |
|
| 3,145 |
|
| 3,574 |
|
| 3,354 |
|
| (243) | |
Total - NU Enterprises |
| $ | 80,347 |
| $ | 81,349 |
| $ | 114,081 |
| $ | 97,670 |
| $ | 901,814 | |
Other Miscellaneous and Eliminations |
|
| (43,958) |
|
| (27,822) |
|
| (32,310) |
|
| (19,078) |
|
| (30,034) | |
Total |
| $ | 4,898,167 |
| $ | 5,439,430 |
| $ | 5,800,095 |
| $ | 5,822,226 |
| $ | 6,877,687 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Regulated Companies - Sales: (GWh) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 14,913 |
|
| 14,412 |
|
| 14,509 |
|
| 15,051 |
|
| 14,652 | |
Commercial |
|
| 14,506 |
|
| 14,474 |
|
| 14,885 |
|
| 15,103 |
|
| 14,886 | |
Industrial |
|
| 4,481 |
|
| 4,423 |
|
| 5,149 |
|
| 5,635 |
|
| 5,750 | |
Wholesale |
|
| 3,423 |
|
| 4,183 |
|
| 3,576 |
|
| 3,855 |
|
| 8,777 | |
Streetlighting and Railroads |
|
| 330 |
|
| 336 |
|
| 340 |
|
| 353 |
|
| 332 | |
Total |
|
| 37,653 |
|
| 37,828 |
|
| 38,459 |
|
| 39,997 |
|
| 44,397 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Regulated Companies - Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 1,704,197 |
|
| 1,696,756 |
|
| 1,700,207 |
|
| 1,697,073 |
|
| 1,686,169 | |
Commercial |
|
| 192,266 |
|
| 189,265 |
|
| 190,067 |
|
| 189,727 |
|
| 188,281 | |
Industrial |
|
| 7,150 |
|
| 7,207 |
|
| 7,342 |
|
| 7,291 |
|
| 7,406 | |
Streetlighting and Railroads* |
|
| 6,292 |
|
| 7,548 |
|
| 4,605 |
|
| 3,855 |
|
| 3,873 | |
Total Electric |
|
| 1,909,905 |
|
| 1,900,776 |
|
| 1,902,221 |
|
| 1,897,946 |
|
| 1,885,729 | |
Natural Gas |
|
| 205,885 |
|
| 206,438 |
|
| 204,834 |
|
| 202,743 |
|
| 199,377 | |
Total |
|
| 2,115,790 |
|
| 2,107,214 |
|
| 2,107,055 |
|
| 2,100,689 |
|
| 2,085,106 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Customer counts were redefined with the implementation of a new customer service system (C2) completed in October 2008.
53
RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for CL&P included in this Annual Report on Form 10-K for the years ended December 31, 2010, 2009 and 2008:
Comparison of 2010 to 2009:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 2,999.1 |
| $ | 3,424.5 |
| $ | (425.4) |
| (12.4) | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 1,253.3 |
|
| 1,690.7 |
|
| (437.4) |
| (25.9) |
|
Other Operating Expenses |
|
| 524.3 |
|
| 571.0 |
|
| (46.7) |
| (8.2) |
|
Maintenance |
|
| 96.5 |
|
| 117.8 |
|
| (21.3) |
| (18.1) |
|
Depreciation |
|
| 172.2 |
|
| 186.9 |
|
| (14.7) |
| (7.9) |
|
Amortization of Regulatory Assets, Net |
|
| 83.9 |
|
| 45.8 |
|
| 38.1 |
| 83.2 |
|
Amortization of Rate Reduction Bonds |
|
| 167.0 |
|
| 156.0 |
|
| 11.0 |
| 7.1 |
|
Taxes Other Than Income Taxes |
|
| 214.2 |
|
| 191.2 |
|
| 23.0 |
| 12.0 |
|
Total Operating Expenses |
|
| 2,511.4 |
|
| 2,959.4 |
|
| (448.0) |
| (15.1) |
|
Operating Income |
| $ | 487.7 |
| $ | 465.1 |
| $ | 22.6 |
| 4.9 | % |
Operating Revenues
CL&P's retail electric sales were as follows:
| For the Years Ended December 31, |
| ||||||
| 2010 |
| 2009 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 22,666 |
| 22,266 |
| 400 |
| 1.8 | % |
CL&P's Operating Revenues decreased in 2010, as compared to 2009, due primarily to:
·
Lower electric distribution revenues related to the portions that are included in DPUC approved tracking mechanisms that track and recover certain incurred costs that do not impact earnings. The tracked electric distribution revenues decreased due primarily to lower GSC and supply-related FMCC revenues ($421 million) and lower delivery-related FMCC revenues ($39 million). The lower GSC and supply-related FMCC revenues were due primarily to lower customer rates resulting from lower average supply prices and additional customer migration to third party electric suppliers in 2010, as compared to 2009. The lower delivery-related FMCC revenues were due primarily to changes in projections for certain delivery-related FMCC costs for 2010 that lowered the average rate charged to customers. These lower revenues were partially offset by higher retail transmission revenues ($37 million), higher transitio n cost recoveries ($1527 million) and WMECO’s pension and default servicehigher wholesale revenues ($84 million). The tracking mechanisms allow for rates to be changed periodically with over-co llectionsovercollections refunded to customers or under-collections collectedundercollections recovered from customers in future periods. In addition, transmission segment intracompany billings to the distribution segment that are eliminated in consolidation decreased by $66 million.
·
The distribution componentportion of electric distribution segment revenues that flows throughimpacts earnings decreased $3 million due primarily to earnings increased $42 million primarily due to an unfavorable variance in demand and customer service charge components offset by a 1.8 percent increase in retail rates ($31 million) and retail sales ($11 million). Retail KWH electric sales increased by 1.5 percent in 20072010, as compared to 2009.
·
Improved transmission segment revenues ($29 million) resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with 2006 (a 0.4 percent increase on a weather normalized basis). Firm gas sales increased 10.3 percent in 2007 compared with 2006 (a 3.1 percent increase on a weather normalized basis).higher property taxes, depreciation and operation and maintenance expenses.
Fuel, Purchased and Net Interchange Power
Fuel, purchasedPurchased and net interchange power expensesNet Interchange Power decreased $1.28 billion in 20072010, as compared to 2009, due primarily to the following:
(Millions of Dollars) | 2010 | |
GSC Supply Costs | $ (385.7) | |
Deferred Fuel Costs | (26.0) | |
Other Purchased Power Costs | (25.7) | |
$ (437.4) |
The decrease in GSC supply costs was due primarily to lower expenses at NU Enterprises ($875 million)average supply prices and lower costs at the regulated companies ($405 million). NU Enterprises' fuel expenses decreased due to the exit from significant components of the competitive businesses. Fuel expense from the regulated companies decreased primarily due to lower fuel, purchased and net interchange power expenses at CL&P, PSNH and WMECO ($431 million), mainly due to a decrease in
63
standard offer supply costs as a result of a reduction in load caused byadditional customer migration to third party electric suppliers partially offset by higher Yankee Gasin 2010, as compared to 2009. These GSC supply costs are the contractual amounts CL&P must pay to various
54
suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. The decrease in deferred fuel expense ($26 million).costs was due primarily to a smaller net overrecovery in 2010, as compared to 2009. These costs are included in DPUC approved tracking mechanisms and do not impact earnings.
Other OperationOperating Expenses
Other operation expensesOperating Expenses decreased $160 million in 2007 primarily due2010, as compared to 2009, as a result of lower NU Enterprises expensescosts that are recovered through distribution tracking mechanisms and have no earnings impact ($11569 million) including RMR ($32 million) and lower regulated companies distribution andretail transmission segment expenses ($49 million).
NU Enterprises' expenses decreased $115 million primarily due to the exit from components of the competitive businesses during the latter part of 2006 and the $25 million donation to the NU Foundation in 2006.
Lower regulated company distribution and transmission segment expenses of $49 million are primarily due to lower reliability must run (RMR) expenses at CL&P ($13331 million), partially offset by higher Energy Independence Act (EIA)distribution segment expenses that are tracked and recovered through the regulatory tracking mechanisms ($29 million), higher administration and general expenses at CL&P, WMECO and PSNH ($22 million), higher retail transmission expenses at PSNH and WMECO ($2120 million) and Summer Savings Rewards Program that was implemented in 2007 at CL&Pmainly as a result of a legislative acthigher administrative and general expenses, including higher pension costs, and higher transmission segment expenses ($143 million).
Maintenance
Maintenance expenses increased $18decreased in 2010, as compared to 2009, primarily related to the allowed regulatory deferral of approximately $32 million as a result of the June 30, 2010 rate case decision, of which $29.5 million was recognized as a deferral in 2007 primarily due tomaintenance expense. Partially offsetting this decrease was higher transmission segmentdistribution overhead line expenses ($73 million) and regulated companyhigher distribution ($6 million).
Higher transmission segment expenses of $7 million in 2007 are primarily due to higher levels of employee support, compliance inspections, deferred maintenance, training, and unplanned repairs to transmission cables at CL&P.
Higher regulated company distribution expenses of $6 million in 2007 are primarily due to higher tree trimmingvegetation management costs ($3 million), equipment maintenance ($2 million) and underground line network inspection activities ($2 million).
Depreciation
Depreciation increased $25 milliondecreased in 20072010, as compared to 2009, due primarily due to higher distribution and transmissiona lower depreciation expenserate being used as a result of higher plant balances from the ongoing construction program.
Amortization
Amortization increased $24 million in 2007 for the distribution segment primarily due to higher recovery of transition costs for CL&P ($32 million) and WMECO ($20 million) and the 2006 $18 million credit associated with the deferral of retail transmission costs for WMECO, partially offset by PSNH ($46 million). The PSNH decrease is primarily due to lower ES over recoveries, lower amortization levels of stranded costs, and the deferral of retail transmission costs.rate case decision that was effective July 1, 2010.
Amortization of Rate Reduction BondsRegulatory Assets, Net
Amortization of RRBsRegulatory Assets, Net, increased $13 million in 2007. 2010, as compared to 2009, due primarily to higher retail CTA revenue ($22 million) and lower CTA transition costs ($17 million). Partially offsetting these increases was a deferral of lost tax benefits related to the 2010 Healthcare Act that we believe are probable of recovery in future electric distribution rates ($15 million).
Taxes Other Than Income Taxes
(Millions of Dollars) | 2010 | |
Connecticut Gross Earnings Tax | $ | 9.8 |
Property Taxes |
| 7.0 |
Use Taxes |
| 5.9 |
Other |
| 0.3 |
| $ | 23.0 |
The higher portion of principal within the RRB payment resultsincrease in a correspondingTaxes Other Than Income Taxes was due primarily to an increase in the amortizationConnecticut Gross Earnings Tax due primarily to the increase in the transmission segment revenues and an increase in distribution segment revenues primarily related to retail transmission and higher transition cost recoveries in 2010, as compared to 2009. The increase in property taxes was a result of RRBs.an increase in Property, Plant and Equipment related to CL&P's capital programs. The increase in use taxes was due to the absence in 2010 of a Connecticut state use tax refund.
Interest Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Interest on Long-Term Debt | $ | 134.6 |
| $ | 133.4 |
| $ | 1.2 |
| 0.9 | % |
Interest on RRBs |
| 7.5 |
|
| 19.1 |
|
| (11.6) |
| (60.7) |
|
Other Interest |
| (4.4) |
|
| 3.3 |
|
| (7.7) |
| (a) |
|
| $ | 137.7 |
| $ | 155.8 |
| $ | (18.1) |
| (11.6) | % |
(a)
Percent greater than 100 percent not shown as it is not meaningful.
Interest Expense decreased in 2010, as compared to 2009, due primarily to lower Interest on RRBs resulting from lower principal balances outstanding and the settlement of various state tax matters in the fourth quarter of 2010, which resulted in a reduction in Other Interest.
Other Income, Net
Interest expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Other Income, Net | $ | 26.7 |
| $ | 25.9 |
| $ | 0.8 |
| 3.1 | % |
Other Income, Net increased $2 million in 20072010, as compared to 2009, due primarily due to higher interest forC&LM and EIA incentives ($3 million and $3 million, respectively), offset by lower investment income ($3 million) and lower AFUDC related to equity funds ($1 million).
55
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 132.4 |
| $ | 118.8 |
| $ | 13.6 |
| 11.4 | % |
Income Tax Expense increased in 2010, as compared to 2009, due primarily to the regulated company distributionimpacts of the 2010 Healthcare Act ($15 million) and transmission segmentshigher pre-tax earnings ($225 million), partially offset by lower interest at NU Enterprisesimpacts related to flow-through items ($194 million). The higher regulated company distribution and transmission segment interest is primarily dueadjustments to long-term debt issuances for all four of the regulated companies. In 2007, $655 million of long-term debt was issued by the regulated companies consisting of $500 million for CL&P, $70 million for PSNH, $40 million for WMECO and $45 million for Yankee Gas. reconcile estimated taxes accrued to actual amounts reflected in our filed tax returns ($2 million).
Other Income, Net
Other income, net decreased $3 million, primarily due to a lower CL&P Traditional Standard Offer procurement fee ($11 million) and the absence of the gain on sale of investment in Globix Corporation (Globix) in 2006 ($3 million), partially offset by higher EIA incentives ($4 million), higher equity in earnings of regional nuclear generating and transmission companies ($4 million), and higher AFUDC equity ($4 million) mainly as a result of higher eligible construction work in progress.
Income Tax (Benefit)/Expense
Income tax expense increased $186 million primarily due to an increase in pre-tax earnings and lower favorable tax adjustments; partially offset by a decrease in flow through regulatory amortizations. In 2006, a significant portion of the tax adjustments included a $74 million tax benefit to remove deferred tax balances associated with the IRS PLR. Prior year flow through regulatory amortizations were higher as a result of the regulatory recovery of tax expense associated with nondeductible acquisition costs.
Income/(Loss) from Discontinued Operations
See Note 15, "Restructuring and Impairment Charges and Discontinued Operations," to the consolidated financial statements for a description and explanation of the discontinued operations.
64
RESULTS OF OPERATIONS - THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
The components of significant income statement variances for the past two years are provided in the table below.
Income Statement Variances | 2008 over/(under) 2007 |
|
| 2007 over/(under) 2006 |
| ||||||
(Millions of Dollars) | Amount |
| Percent |
|
| Amount |
| Percent |
| ||
Operating Revenues | $ | (123) |
| (3) | % |
| $ | (298) |
| (7) | % |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
Operation - |
|
|
|
|
|
|
|
|
|
|
|
Fuel, purchased and net interchange power |
| (432) |
| (19) |
|
|
| (327) |
| (13) |
|
Other operation |
| 22 |
| 4 |
|
|
| (79) |
| (13) |
|
Maintenance |
| 22 |
| 21 |
|
|
| 7 |
| 6 |
|
Depreciation |
| 11 |
| 7 |
|
|
| 4 |
| 3 |
|
Amortization of regulatory assets/(liabilities), net |
| 144 |
| (a) |
|
|
| 32 |
| (a) |
|
Amortization of rate reduction bonds |
| 10 |
| 7 |
|
|
| 9 |
| 7 |
|
Taxes other than income taxes |
| 11 |
| 7 |
|
|
| 7 |
| 4 |
|
Total operating expenses |
| (212) |
| (6) |
|
|
| (347) |
| (9) |
|
Operating Income |
| 89 |
| 31 |
|
|
| 49 |
| 21 |
|
Interest expense, net |
| 8 |
| 6 |
|
|
| 21 |
| 17 |
|
Other income, net |
| 2 |
| 5 |
|
|
| 2 |
| 5 |
|
Income before income tax expense |
| 83 |
| 45 |
|
|
| 30 |
| 19 |
|
Income tax expense |
| 25 |
| 49 |
|
|
| 96 |
| (a) |
|
Net income | $ | 58 |
| 43 | % |
| $ | (66) |
| (33) | % |
(a) Percent greater than 100.
Comparison of the Year2009 to 2008 to the Year 2007:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 3,424.5 |
| $ | 3,558.4 |
| $ | (133.9) |
| (3.8) | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 1,690.7 |
|
| 1,845.4 |
|
| (154.7) |
| (8.4) |
|
Other Operating Expenses |
|
| 571.0 |
|
| 557.6 |
|
| 13.4 |
| 2.4 |
|
Maintenance |
|
| 117.8 |
|
| 130.4 |
|
| (12.6) |
| (9.7) |
|
Depreciation |
|
| 186.9 |
|
| 162.6 |
|
| 24.3 |
| 14.9 |
|
Amortization of Regulatory Assets, Net |
|
| 45.8 |
|
| 164.2 |
|
| (118.4) |
| (72.1) |
|
Amortization of Rate Reduction Bonds |
|
| 156.0 |
|
| 145.6 |
|
| 10.4 |
| 7.1 |
|
Taxes Other Than Income Taxes |
|
| 191.2 |
|
| 179.2 |
|
| 12.0 |
| 6.7 |
|
Total Operating Expenses |
|
| 2,959.4 |
|
| 3,185.0 |
|
| (225.6) |
| (7.1) |
|
Operating Income |
| $ | 465.1 |
| $ | 373.4 |
| $ | 91.7 |
| 24.6 | % |
Operating Revenues
CL&P's retail electric sales were as follows:
| For the Years Ended December 31, |
| ||||||
| 2009 |
| 2008 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 22,266 |
| 23,145 |
| (879) |
| (3.8) | % |
Operating revenuesRevenues decreased $123 millionin 2009, as compared to 2008, due to lower distribution segment revenues ($233264 million), partially offset by higher transmission segment revenues ($110130 million).
The distribution segment revenues decreased $233$264 million due primarily due to a decrease in the componentportion of distribution revenues that does not impact earnings ($296289 million). These revenues do not impact earnings, primarily as a result of the inclusion of these distribution revenue being includedrevenues in regulatory tracking mechanisms and consolidation eliminations, partially offset by the componentintracompany revenues that are eliminated in consolidation. The portion of revenues that flows through toimpacts earnings which increased $62$25 million.
The $296$289 million decrease in distribution segment revenue decreaserevenues that does not impact earnings iswas due primarily due to a decrease in the componentsportions of retail revenues that are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs through CL&P's tariffs ($217265 million) and consolidation eliminations of transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($7824 million). The distribution revenuesegment revenues included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs decreased $217$265 million due primarily due to a decrease in revenues associated with the recovery of GSC and relatedsupply-related FMCC ($314184 million) and deliverylower wholesale revenues as a result of decreased market revenue related FMCCto sales of CL&P's IPP purchased generation output to ISO-NE due to a decrease in the market price of energy ($75163 million), partially offset by higher retail transmission revenues ($65 million) mainly as a result of higher 2008 rates, higher wholesale revenues ($59 million), and higher SBC revenues ($3675 million). The lower GSC and relatedsupply-related FMCC revenue was due primarily due to a reduction in load, caused primarily bylower retail sales, lower customer rates resulting from lower average supply prices and additional customer migration to third partythird-party suppliers lower congestion costs and lower sales in 2008.The lower delivery-related FMCC revenue was primarily due to a decrease in this rate component in 2008 as a result of lower RMR, VAR support and southwest Connecticut energy resource costs in 2008, as well as a larger prior year overrecovery being refunded to customers in 20082009, as compared to 2007.2008. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
The portion of the distribution segment revenues that flows through toimpacts earnings increased $62$25 million primarily due to theas a result of rate increase effective February 1, 2008 ($75 million),changes, partially offset by lower retail sales. The 2009 retail sales, ($10 million). Retailas compared to the same period in 2008, decreased 17.6 percent for the industrial, 2.9 percent for the commercial, and 0.7 percent for the residential classes. Total retail sales decreased 3.7 percent in 2008 compared to 2007.overall by 3.8 percent.
Transmission segment revenues increased $110$130 million due primarily due to a higher transmission investment base the impactas a result of the March 24,completion of our southwest Connecticut projects in 2008 FERC ROE decision and higher operating expenses that are passed through to customers under FERC-approved transmission tariffs.overall expenses.
56
Fuel, Purchased and Net Interchange Power
Fuel, purchasedPurchased and net interchange power expenseNet Interchange Power decreased $432 millionin 2009, as compared to 2008, due primarily due to a decrease inlower GSC supply costs ($231280 million) and other purchased power costs ($41 million), a decreasepartially offset by an increase in deferred fuel costs ($174 million) and lower other purchased power costs ($27165 million), all of which are included in DPUC approved tracking mechanisms. The $231$280 million decrease in GSC supply costs was due primarily due to a reduction in load caused primarily bylower retail sales, lower average supply prices and additional customer migration to third party suppliers and lower retail sales.third-party suppliers. These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have earnedbeen awarded the right to supply SS and LRS load through a competitive solicitation process. The $174$165 million decreaseincrease in deferred fuel costs was due primarily due to the combined effect of CL&P having a supplythe twelve months of 2008 net underrecovery of GSC and delivery-relatedFMCC expenses, as compared to the twelve months of 2009 net FMCC overrecovery in 2007 and a supply and delivery-related net FMCC underrecovery in 2008.of these expenses.
65
Other OperationOperating Expenses
Other operationOperating Expenses increased in 2009, as compared to 2008, as a result of higher distribution segment expenses increased $22 million($36 million) due primarily due to pension and expenses related to uncollectible receivable balances, and higher transmission segment expenses, which are tracked and recorded through FERC rate tariffs ($14 million), partially offset by lower costs that are tracked and recovered through distribution tracking mechanisms ($104 million) such as retail transmission ($59 million), RMR ($17 million), higher uncollectibles ($12 million), higher tracked administrative and general expenseshave no earnings impact ($930 million), and higher EIA expenses ($6 million). In addition, there were higher transmission segment expenses ($5 million), partially offset by consolidation eliminations oflower transmission segment intracompany billing to the distribution segment ($80 million) and lower distribution segment expenses ($8 million) primarily due to lower pension, regulatory assessments and workers compensation expenses, partially offset by a charge to refund the 2004 procurement incentive fee that was recognizedare eliminated in 2005 earnings.consolidation ($6 million).
Maintenance
Maintenance expenses increased $22 milliondecreased in 2008 primarily due to higher distribution overhead lines ($10 million), primarily due to more storms in 20082009, as compared to 2007, higher tree trimming expenses2008, due primarily to lower repair and maintenance of distribution lines ($6 million), higherincluding lower storm expenses, lower distribution substation equipment expenses ($2 million), lower transmission segment expenses ($41 million), and higher distribution substation equipmentlower transformer maintenance expenses ($21 million).
Depreciation
Depreciation expense increased $11 millionin 2009, as compared to 2008, due primarily due to higher utility plant balances resulting from completed construction programs putprojects placed into service.service in the transmission segment ($19 million) and the distribution segment ($5 million).
Amortization of Regulatory Assets/(Liabilities),Assets, Net
Amortization of regulatory assets/(liabilities), net increased $144 millionRegulatory Assets, Net decreased in 2009, as compared to 2008, due primarily due to higherlower amortization related to the recovery of transitionstranded charges ($62131 million), as a result of lower retail CTA revenue and higher recovery and lower expenses for SBC ($50 million) and a credit in 2007 pertaining to the refundtransition costs, partially offset by higher amortization of the GSC overrecoverySBC balance ($2915 million).
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $10 million. The higher portion of principal within the RRB payment results in a corresponding increase in the amortization of RRBs.
Taxes Other Than Income Taxes
Taxes other than income taxesOther Than Income Taxes increased $11 millionin 2009, as compared to 2008, due primarily due to higher gross earnings taxes as a result of higher distribution revenues that are subject to gross earnings tax ($13 million) and higher property taxes as a result of higher plant balances and higherincreased municipal tax rates ($10 million), higher gross earnings taxes ($4 million) recoverable in rates mainly as a result of higher transmission segment revenues that are subject to gross earnings tax, and higher payroll taxes ($2 million), partially offset by lower payroll taxes charged to expensethe resolution of various routine tax issues primarily surrounding sales and use tax amounts ($34 million).
Interest Expense Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Interest on Long-Term Debt | $ | 133.4 |
| $ | 105.0 |
| $ | 28.4 |
| 27.0 | % |
Interest on RRBs |
| 19.1 |
|
| 29.1 |
|
| (10.0) |
| (34.4) |
|
Other Interest |
| 3.3 |
|
| 12.1 |
|
| (8.8) |
| (72.7) |
|
| $ | 155.8 |
| $ | 146.2 |
| $ | 9.6 |
| 6.6 | % |
Interest expense, netExpense increased $8 millionin 2009, as compared to 2008, due primarily due to higher long-term debt interest ($21 million)Interest on Long-Term Debt resulting from the $200 million debt issuance in September 2007, the $300 million debt issuance in March 2007 and the $300 million debt issuance in May 2008 and the $250 million debt issuance in February 2009, partially offset by lower RRB interestOther Interest mostly related to the resolution of various routine tax issues, and lower Interest on RRBs resulting from lower principal balances outstanding ($9 million) and lower other interest ($3 million) mostly related to short-term debt.outstanding.
Other Income, Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Other Income, Net | $ | 25.9 |
| $ | 41.9 |
| $ | (16.0) |
| (38.2) | % |
Other income, net increased $2 millionIncome, Net decreased in 2009, as compared to 2008, due primarily due to a higherlower AFUDC equity income ($918 million) as a result of higherlower eligible CWIP due to large transmission projects being completed and placed in-service in 2008 and lower capital expenditures in 2009, the transmission construction program, higherabsence in 2009 of interest income related to the 2008a federal tax settlement in 2008 ($6 million), and higherlower EIA incentives ($26 million), partially offset by higher investment losses ($10 million)income due primarily due to theimproved results from NU's supplemental benefit trust a decreaseand the absence of other-than-temporary impairments recorded in conservation and load management incentive income2008 ($316 million) and a decrease in investment income ($2 million).
57
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 118.8 |
| $ | 77.9 |
| $ | 40.9 |
| 52.5 | % |
Income tax expenseTax Expense increased $25 milliondue primarily due to higher pre-tax earnings being subject to($23 million), less tax at marginal rates, partially offset by flow through impacts associated with plant differencesbenefits as a result of lower capital expenditures ($9 million), lower state tax credits ($3 million), and bad debts, thereby reducing the effective tax rate.
Comparison of the Year 2007 to the Year 2006
Operating Revenues
Operating revenues decreased $298 million due to lower distribution segment revenuesincreases in allowance for doubtful accounts reserves ($373 million), partially offset by higher transmission segment revenues ($754 million).
The distribution segment revenue decrease of $373 million is primarily due to the components of revenues, which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($388 million). The distribution segment revenue tracking components decreased $388 million primarily due to a decrease in revenues associated with the recovery of generation service and related congestion charges ($265 million) and lower delivery-related FMCC revenue ($104 million). The lower generation service and related congestion charge revenue was primarily due to a reduction in load caused primarily by customer migration to third party suppliers, partially offset by an increase in these rate components to recover higher 2007 supply prices. The lower delivery-related FMCC revenue was primarily due to a decrease in this rate component in 2007 as a result of the use of prior year overrecov eries to recover current year costs, as well as lower anticipated RMR costs in 2007. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.
The distribution component of revenues that impacts earnings increased $14 million as a result of the rate increase effective January 1, 2007 and higher retail sales. Retail sales increased 1.7 percent in 2007 compared to the same period in 2006.
66
Transmission segment revenues increased $75 million primarily due to a higher rate base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $327 million primarily due to a decrease in generation service supply costs ($286 million) and lower other purchased power costs ($73 million), partially offset by an increase in deferred fuel costs of $32 million, all of which are included in regulatory commission-approved tracking mechanisms. The $286 million decrease in supply costs was primarily due to a reduction in load caused primarily by customer migration to third party suppliers, partially offset by higher 2007 supply prices. These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply Standard Service and Last Resort Service load through a competitive solicitation process. The $32 million increase in deferred fuel costs was largely the result of the deferral of significant refunds received from the ISO-NE associated w ith previously remitted RMR payments that must be returned to customers.
Other Operation
Other operation expenses decreased $79 million primarily due to lower RMR costs ($133 million) that are tracked and recovered through the FMCC, partially offset by higher Energy Independence Act (EIA) expenses that will also be recovered through the FMCC deferral mechanism ($29 million), Summer Saver Rewards Program that was implemented in 2007 as a result of a legislative act ($14 million) and higher administrative expense ($8 million).
Maintenance
Maintenance expenses increased $7 million primarily due to higher transmission segment expenses ($5 million) and higher distribution segment expenses ($2 million).
Higher transmission segment expenses of $5 million in 2007 are primarily due to higher levels of employee support, compliance inspections, deferred maintenance, training, and unplanned repairs to transmission cables at CL&P.
Higher distribution segment expenses of $2 million in 2007 are primarily due to higher expenses related to substation maintenance, underground network inspection activities, line transformer maintenance, partially offset by lower expenses related to overhead lines maintenance primarily due to less storm-related expense.
Depreciation
Depreciation expense increased $4 million primarily due to higher utility plant balances resulting from the ongoing construction program.
Amortization of Regulatory Assets/(Liabilities), Net
Amortization of regulatory assets/(liabilities), net increased $32 million primarily due to higher amortization related to the recovery of transition charges ($32 million), higher SFAS No. 109 amortization ($7 million), partially offset by a lower system benefit charge deferral ($8 million).
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $9 million. The higher portion of principal within the RRB payment results in a corresponding increase in the amortization of RRBs.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $7 million primarily due to higher property taxes primarily related to new transmission projects such as the Bethel-Norwalk project that were completed in 2006, but not reflected in our tax assessment until 2007.
Interest Expense, Net
Interest expense, net increased $21 million primarily due to higher interest on long-term debt ($19 million) mainly as a result of $250 million of new debt issued in June of 2006, $300 million of new debt issued in March of 2007 and $200 million of new debt issued in September of 2007, higher FMCC deferral interest ($6 million) and higher interest on short-term debt ($2 million), partially offset by lower RRB interest resulting from lower principal balances outstanding ($9 million).
Other Income, Net
Other income, net increased $2 million primarily due to a higher equity AFUDC income ($7 million) as a result of higher eligible CWIP due to the transmission construction program, higher EIA incentives ($4 million) and higher equity of earnings of regional nuclear generating companies ($3 million), partially offset by the elimination of the Transitional Standard Offer (TSO) procurement fee approved by the DPUC associated with the TSO supply procurement that expired at the end of 2006 ($11 million).
Income Tax Expense
Income tax expense increased $96 million primarily due to the nonrecurring tax items in 2006 that included a $74 million tax benefit from the removal of deferred tax balances associated with a PLR received from the IRS, a decrease in favorable tax adjustments, lower state tax credits and higher pre-tax earnings.
67
LIQUIDITY
While the impact of continued market volatility and the extent and impacts of any economic downturn cannot be predicted, we currently believe that CL&P has sufficient operating flexibility and access to funding sources to maintain adequate amounts of liquidity (as evidenced by CL&P's issuance of $250 million of 10-year bonds in February 2009 at 5.5 percent). The credit outlooks for CL&P are all stable, with all its ratings and outlooks affirmed by S&P in late October 2008. CL&P has modest risk of calls for collateral due to its business model, as described under "Liquidity-Impact of Financial Market Conditions" in this "Management’s Discussion and Analysis of Financial Condition and Results of Operations." Capital contributions from NU parent and other internal sources of funding are provided to CL&P as necessary. CL&P does not have any long-term debt maturing in 2009, and projected capital expenditures for 2009 are significantly less than 2008.
CL&P had consolidated operating cash flows from operating activities in 2010 of $267.3$501.7 million, in 2008, after RRB payments included in financing activities, compared with operating cash flows of $4.5$482.2 million in 20072009 and $138.8$267.3 million in 2006, both after2008 (all amounts are net of RRB payments. Operatingpayments, which are included in financing activities). Improved cash flows in 2007 include2010 were attributed to a decrease in payments made related to CL&P's accounts payable in support of its operating activities. Improved cash flows were further due to increases in amortization on regulatory deferrals primarily attributable to 2009 activity within CL&P’s CTA tracking mechanism where such costs exceeded revenues resulting in an unfavorable cash flow impact in 2009. Offsetting the improved cash flows was an increase in income tax payments of approximately $177.2$29.1 million, related towhich was the 2006 saleresult of NU's competitive generation business. Other drivers resulting in increased operating cash flows in 2008 were higher operating results after adjustmentsbonus depreciation tax deduction benefits received throughout 2009 not being extended for reconciling items to net income primarily related to the significant increase in transmission segment earnings and a $77.8 million annualized increase in distribution rates, effective February 1, 2008. The increase in operating cash flows was also due to an income tax net settlementfull year of approximately $33 million in2010 until the fourth quarter of 20082010, as f urther described below.
On September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010, which extended bonus depreciation tax deduction through 2010. On December 17, 2010, President Obama signed into law the 2010 Tax Act, which, among other things, provides 100 percent bonus depreciation for tangible personal property placed in service after September 8, 2010, and through December 31, 2011. For tangible personal property placed in service after December 31, 2011, and through December 31, 2012, the 2010 Tax Act provides for 50 percent bonus depreciation. We project cash flows provided by operating activities at CL&P of between $600 million and $650 million in 2011, net of RRB payments, the increase over 2010 is due primarily to the cash flow benefit of our accounts payable balances having increased by $25 million. These factors were partially offset by a net reduction in other working capital items resulting primarilybenefits from a net $141 million increase in the cash flow benefit of our accounts receivable and unbilled revenue balances, which also included investments in securitizable assets.
CL&P projects consolidated operating cash flows of approximately $365 million in 2009, after approximately $183 million of RRB payments. This projection represents an increase of approximately $100 million from 2008 operating cash flows, after RRB payments, which is primarily due to the reflection in 2009 rates of CL&P’s major southwest Connecticut transmission projects completed in 2008; a $20.1 million annualized increase in distribution rates, effective February 1, 2009; and the recovery in 2009 of certain regulatory underrecoveries as of December 31, 2008, including $31.9 million from its semi-annual FMCC filing in February 2009 as compared to a $105 million overrecovery at December 31, 2007.2010 Tax Act.
On February 13, 2009,April 1, 2010, CL&P issued $250remarketed $62 million of first and refunding mortgage bonds due Februarytax-exempt PCRBs that were subject to a mandatory tender for purchase on April 1, 2019 and carrying2010. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 5.5 percent. Proceeds from this issuance will be used1.4 percent for a one-year period and are subject to repay short-term debt and funda mandatory tender on April 1, 2011, at which time CL&P's capital investment program, which is projected to be approximately $400 million in 2009. In mid-2009 or earlier depending on market opportunities, NU&P expects to issue between $250 million and $300 million of equity, a portion of which will be used to fund CL&P’s 2009 capital investment program. This program will also be funded by available short-term borrowings andremarket the projected growth in 2009 operating cash flows described above. bonds.
On September 24, 2010, CL&P, together with PSNH, WMECO, and Yankee Gas, entered into a three-year $400 million unsecured revolving credit facility, which expires on September 24, 2013. This facility replaced a five-year $400 million credit facility on similar terms and conditions that was scheduled to expire on November 6, 2010. CL&P is able to draw up to $300 million under this facility, subject to the $400 million maximum aggregate borrowing limit, either on a short-term or a long-term basis subject to regulatory approval. As of December 31, 2008 and February 25, 2009,2010, CL&P had no borrowings of $188 million under the $400 million credit facility it shares with other NU subsidiaries, of which it can borrow up to $200 million.this facility. Other financing activities for 2008the year ended December 31, 2010 included a $300 million issuance of 10-year bonds in May 2008 and capital contributions from NU parent of $210 million, offset by $106.5$217.7 million in common dividends paid to NU parent. parent, a $6.2 million increase in NU Money Pool borrowings, and $2.5 million in capital contributions from NU Parent. In 2011, CL&P has the mandatory tender of $62 million, which it pla ns to remarket, but does not have any long-term debt maturities until 2014, and there are no CL&P debt issuances planned for 2011.
On JuneNovember 1, 2010, the DPUC approved CL&P's application requesting authority to issue up to $900 million in long-term debt through 2014. Proceeds will be used to refinance CL&P's short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.
On December 30, 2008,2010, CL&P made its final interest and principal payment on approximately $1.4 billion of rate reduction bonds that were issued in 2001. As a result, CL&P will no longer recover any payments from customers associated with these RRBs. A total of $203.2 million of principal and interest payments were made on these RRBs in 2010. The full amortization of these RRBs in 2010 will reduce CL&P’s cash flows provided by operating activities in 2011, compared with previous years, but will have no material impact on CL&P’s operating cash flows net of RRB payments.
On October 18, 2010, following the announcement of the proposed merger of NU and NSTAR, Moody's announced that it had reaffirmed the ratings and "stable" outlooks of CL&P and S&P announced that it had placed CL&P's ratings outlooks on credit watch with "positive" implications. On October 19, 2010, also due to the availabilityannouncement of the proposed merger, Fitch announced that it had reaffirmed the ratings and lower relative cost"stable" outlooks of other liquidity sources, CL&P chose&P. On January 22, 2010, Fitch downgraded CL&P’s preferred stock rating from BBB to terminate the arrangement under which CL&P could sell toBBB- as a financial institution up to $100 millionresult of accounts receivablerevised guidelines for rating preferred stock and unbilled revenues. hybrid securities in general.
Cash capital expenditures included on the accompanying consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. CL&P’s&P's cash capital expenditures totaled $849.5$380.3 million in 2008,2010, compared with $826.2$435.7 million in 2007.2009. This increasedecrease was primarily the result of higher distributionlower transmission segment capital expenditures in 2008.2010.Other investing activities in 2010 included a decrease in lendings to the NU Money Pool of $97.8 million.
6858
Selected Consolidated Sales Statistics |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 | ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 1,597,754 |
| $ | 1,840,750 |
| $ | 1,811,845 |
| $ | 1,854,404 |
| $ | 1,709,700 | |
Commercial |
|
| 821,872 |
|
| 935,586 |
|
| 1,042,077 |
|
| 1,182,196 |
|
| 1,405,281 | |
Industrial |
|
| 144,463 |
|
| 151,839 |
|
| 190,723 |
|
| 208,087 |
|
| 380,479 | |
Wholesale |
|
| 441,660 |
|
| 386,034 |
|
| 484,843 |
|
| 347,514 |
|
| 318,958 | |
Streetlighting and Railroads |
|
| 32,084 |
|
| 22,638 |
|
| 28,710 |
|
| 35,370 |
|
| 42,099 | |
Miscellaneous |
|
| (38,731) |
|
| 87,691 |
|
| 163 |
|
| 54,246 |
|
| 123,294 | |
Total |
| $ | 2,999,102 |
| $ | 3,424,538 |
| $ | 3,558,361 |
| $ | 3,681,817 |
| $ | 3,979,811 | |
Sales: (GWh) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 10,196 |
|
| 9,848 |
|
| 9,913 |
|
| 10,336 |
|
| 10,053 | |
Commercial |
|
| 9,716 |
|
| 9,705 |
|
| 9,993 |
|
| 10,128 |
|
| 9,995 | |
Industrial |
|
| 2,467 |
|
| 2,427 |
|
| 2,945 |
|
| 3,264 |
|
| 3,306 | |
Wholesale |
|
| 3,040 |
|
| 3,434 |
|
| 3,637 |
|
| 3,563 |
|
| 3,749 | |
Streetlighting and Railroads |
|
| 286 |
|
| 286 |
|
| 294 |
|
| 304 |
|
| 284 | |
Total |
|
| 25,705 |
|
| 25,700 |
|
| 26,782 |
|
| 27,595 |
|
| 27,387 | |
Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 1,096,576 |
|
| 1,093,229 |
|
| 1,094,991 |
|
| 1,091,799 |
|
| 1,084,937 | |
Commercial |
|
| 103,166 |
|
| 101,814 |
|
| 102,464 |
|
| 102,411 |
|
| 101,563 | |
Industrial |
|
| 3,359 |
|
| 3,381 |
|
| 3,613 |
|
| 3,743 |
|
| 3,848 | |
Streetlighting and Railroads* |
|
| 4,366 |
|
| 5,307 |
|
| 2,883 |
|
| 2,583 |
|
| 2,592 | |
Total |
|
| 1,207,467 |
|
| 1,203,731 |
|
| 1,203,951 |
|
| 1,200,536 |
|
| 1,192,940 |
*Customer counts were redefined with the implementation of a new customer service system (C2) completed in October 2008.
59
RESULTS OF OPERATIONS -PUBLIC– PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
The components of significant income statementfollowing table provides the amounts and variances in operating revenues and expense line items for the past twoconsolidated statements of income for PSNH included in this Annual Report on Form 10-K for the years are provided in the table below. ended December 31, 2010, 2009 and 2008:
Income Statement Variances | 2008 over/(under) 2007 |
|
| 2007 over/(under) 2006 |
| ||||||
(Millions of Dollars) | Amount |
| Percent |
|
| Amount |
| Percent |
| ||
Operating Revenues | $ | 58 |
| 5 | % |
| $ | (58) |
| (5) | % |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
Operation - |
|
|
|
|
|
|
|
|
|
|
|
Fuel, purchased and net interchange power |
| 28 |
| 5 |
|
|
| (58) |
| (10) |
|
Other operation |
| 7 |
| 3 |
|
|
| 30 |
| 17 |
|
Maintenance |
| 17 |
| 23 |
|
|
| 3 |
| 4 |
|
Depreciation |
| 3 |
| 6 |
|
|
| 4 |
| 7 |
|
Amortization of regulatory assets, net |
| 2 |
| 24 |
|
|
| (46) |
| (86) |
|
Amortization of rate reduction bonds |
| (7) |
| (13) |
|
|
| 3 |
| 6 |
|
Taxes other than income taxes |
| 2 |
| 7 |
|
|
| 2 |
| 5 |
|
Total operating expenses |
| 52 |
| 5 |
|
|
| (62) |
| (6) |
|
Operating Income |
| 6 |
| 5 |
|
|
| 4 |
| 3 |
|
Interest expense, net |
| 4 |
| 8 |
|
|
| - |
| - |
|
Other income, net |
| 1 |
| 9 |
|
|
| (1) |
| (9) |
|
Income before income tax expense |
| 3 |
| 4 |
|
|
| 3 |
| 4 |
|
Income tax expense |
| (1) |
| (4) |
|
|
| (16) |
| (42) |
|
Net income | $ | 4 |
| 7 | % |
| $ | 19 |
| 54 | % |
Comparison of the Year 20082010 to the Year 20072009:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 1,033.4 |
| $ | 1,109.6 |
| $ | (76.2) |
| (6.9) | % |
Operating Expenses: |
|
|
|
|
|
|
|
| & nbsp; |
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 363.1 |
|
| 520.5 |
|
| (157.4) |
| (30.2) |
|
Other Operating Expenses |
|
| 230.2 |
|
| 239.7 |
|
| (9.5) |
| (4.0) |
|
Maintenance |
|
| 82.4 |
|
| 87.0 |
|
| (4.6) |
| (5.3) |
|
Depreciation |
|
| 67.2 |
|
| 62.0 |
|
| 5.2 |
| 8.4 |
|
Amortization of Regulatory Assets/(Liabilities), Net |
|
| 11.2 |
|
| (29.6) |
|
| 40.8 |
| (a) |
|
Amortization of Rate Reduction Bonds |
|
| 50.4 |
|
| 47.5 |
|
| 2.9 |
| 6.1 |
|
Taxes Other Than Income Taxes |
|
| 52.7 |
|
| 47.9 |
|
| 4.8 |
| 10.0 |
|
Total Operating Expenses |
|
| 857.2 |
|
| 975.0 |
|
| (117.8) |
| (12.1) |
|
Operating Income |
| $ | 176.2 |
| $ | 134.6 |
| $ | 41.6 |
| 30.9 | % |
(a)
Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
PSNH's retail electric sales were as follows:
| For the Years Ended December 31, |
| ||||||
| 2010 |
| 2009 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 7,847 |
| 7,750 |
| 97 |
| 1.3 | % |
PSNH's Operating Revenues decreased in 2010, as compared to 2009, due primarily to:
·
A $125 million decrease in distribution revenues increased $58that did not impact earnings. Of this decrease, $121 million related to lower recovery of purchased fuel and power costs mostly related to ES customer migration to third party electric suppliers, $19 million in lower transmission segment intracompany billings to the distribution segment that are eliminated in consolidation and $11 million related to lower wholesale revenues, offset by higher retail transmission revenues ($25 million) and an increase in the SCRC ($12 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers and undercollections to be recovered from customers in future periods.
·
A $40 million increase in distribution segment revenues that impacts earnings primarily as a result of the retail rate increase effective July 1, 2010 and higher sales volume. Retail electric sales increased 1.3 percent in 2010 compared to 2009.
·
A $9 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
Fuel, Purchased and Net Interchange Power
Fuel, Purchased and Net Interchange Power decreased in 2010, as compared to 2009, due primarily to an increased level of ES customer migration to third party electric suppliers, partially offset by higher retail sales.
Other Operating Expenses
Other Operating Expenses decreased in 2010, as compared to 2009, due primarily to lower distribution segment expenses ($7 million), mainly as a result of the rate case decision changing the collection of certain expenses to be tracked through the TCAM included in Amortization of Regulatory Assets/(Liabilities), Net in 2010.
Maintenance
Maintenance decreased in 2010, as compared to 2009, due primarily to lower boiler equipment and maintenance costs at the generation business ($12 million) as a result of insurance proceeds received in 2010 related to turbine damage, offset by higher distribution overhead line expenses related to storms in 2010 ($8 million).
Depreciation
Depreciation increased in 2010, as compared to 2009, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to PSNH's capital programs.
60
Amortization of Regulatory Assets/(Liabilities), Net
Amortization of Regulatory Assets/(Liabilities), Net increased in 2010, as compared to 2009, due primarily to increases in ES deferral ($42 million) and TCAM ($11 million) offset by decreases in the impact of the 2010 Healthcare Act related to the deferral of lost tax benefits that we believe are probable of recovery in future electric distribution rates ($7 million) and the NWPP accrual ($5 million).
Taxes Other Than Income Taxes
(Millions of Dollars) | 2010 | |
Property Taxes | $ | 3.1 |
Use Taxes |
| 1.5 |
Other |
| 0.2 |
| $ | 4.8 |
The increase in Taxes Other Than Income Taxes was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to PSNH's capital programs.
Interest Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Interest on Long-Term Debt | $ | 36.2 |
| $ | 33.0 |
| $ | 3.2 |
| 9.7 | % |
Interest on RRBs |
| 9.7 |
|
| 13.1 |
|
| (3.4) |
| (26.0) |
|
Other Interest |
| 1.2 |
|
| 0.4 |
|
| 0.8 |
| (a) |
|
| $ | 47.1 |
| $ | 46.5 |
| $ | 0.6 |
| 1.3 | % |
(a)
Percent greater than 100 percent not shown as it is not meaningful.
Interest Expense increased in 2010, as compared to 2009, due primarily to higher Interest on Long-Term Debt resulting from the $150 million debt issuance in December 2009, offset by lower Interest on RRBs resulting from lower principal balances outstanding.
Other Income, Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Other Income, Net | $ | 11.7 |
| $ | 9.5 |
| $ | 2.2 |
| 23.2 | % |
Other Income, Net increased in 2010, as compared to 2009, due primarily to higher AFUDC related to equity funds ($7 million), offset by higher rental expenses ($3 million) and lower interest income ($1 million).
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 50.8 |
| $ | 32.0 |
| $ | 18.8 |
| 58.8 | % |
Income Tax Expense increased in 2010, as compared to 2009, due primarily to higher pre-tax earnings ($13 million) and the impacts of the 2010 Healthcare Act ($7 million), partially offset by lower impacts related to flow-through items ($2 million).
61
Comparison of 2009 to 2008:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 1,109.6 |
| $ | 1,141.2 |
| $ | (31.6) |
| (2.8) | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 520.5 |
|
| 558.3 |
|
| (37.8) |
| (6.8) |
|
Other Operating Expenses |
|
| 239.7 |
|
| 215.5 |
|
| 24.2 |
| 11.2 |
|
Maintenance |
|
| 87.0 |
|
| 90.9 |
|
| (3.9) |
| (4.3) |
|
Depreciation |
|
| 62.0 |
|
| 56.3 |
|
| 5.7 |
| 10.1 |
|
Amortization of Regulatory Assets/(Liabilities), Net |
|
| (29.6) |
|
| 9.3 |
|
| (38.9) |
| (a) |
|
Amortization of Rate Reduction Bonds |
|
| 47.5 |
|
| 45.6 |
|
| 1.9 |
| 4.2 |
|
Taxes Other Than Income Taxes |
|
| 47.9 |
|
| 42.4 |
|
| 5.5 |
| 13.0 |
|
Total Operating Expenses |
|
| 975.0 |
|
| 1,018.3 |
|
| (43.3) |
| (4.3) |
|
Operating Income |
| $ | 134.6 |
| $ | 122.9 |
| $ | 11.7 |
| 9.5 | % |
(a)
Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
PSNH's retail electric sales were as follows:
| For the Years Ended December 31, |
| ||||||
| 2009 |
| 2008 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 7,750 |
| 7,926 |
| (176) |
| (2.2) | % |
Operating Revenues decreased in 2009, as compared to 2008, due to higherlower distribution segment revenues ($46 million) and, partially offset by higher transmission segment revenues ($1215 million).
The distribution segment revenues increaseddecreased $46 million due primarily due to a decrease in the portion of distribution revenues that does not impact earnings ($3757 million). These revenues do not impact earnings, primarily as a result of the inclusion of these distribution revenue being includedrevenues in regulatory tracking mechanisms and consolidation eliminations of transmission segment intracompany billings to the distribution segment, and the componentrevenues that are eliminated in consolidation. The portion of revenues that flows throughimpacts earnings increased $11 million primarily as a result of higher retail rates, partially offset by lower retail sales volumes. The 2009 retail sales, as compared to earnings ($8 million). the same period in 2008, decreased 8.2 percent for the industrial, 1.5 percent for the commercial, and 0.2 percent for the residential classes. Total retail sales decreased overall by 2.2 percent.
The $57 million decrease in the portion of distribution segment revenues that flows through to earnings increased $8 million primarily as a result of rate changes ($13 million) from increases effective July 1, 2007 and January 1, 2008, partially offset by a rate decrease effective July 1, 2008. The combined increase in rates is partially offset by lower retail sales ($4 million). Retail sales decreased 2.5 percent in 2008 compared to the same period in 2007.
The $37 million distribution from revenue increase that does not impact earnings iswas due primarily to a decrease in the componentsportions of retail revenues that are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs through PSNH's tariffs ($55 million), partially offset by revenues that are eliminated in consolidation ($18 million). The distribution revenue included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs increased $55 million primarily due to the pass-through of higher energy supply costs ($78 million), higher retail transmission revenues ($17 million), higher wholesale revenues ($8 million), and higher Northern Wood Power Plant renewable energy certificate revenues ($3 million), partially offset by a decrease in the SCRC ($5547 million) primarily due to a decrease in the SCRC rate effective July 1, 2008. The tracking mechanisms allow for rates to be changed periodically with overcolle ctions refunded to customers or undercollections recovered from customers in future periods.
Transmission segment revenues increased $12 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses that are passed through to customers under FERC-approved transmission tariffs.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power costs increased $28 million primarily due to higher forward energy market prices, partially offset by a decrease in payments to higher priced IPPs in 2008 as contracts expired.
Other Operation
Other operation expenses increased $7 million primarily due to higher costs that are tracked and recovered through distribution tracking mechanisms ($13 million) primarily due to retail transmission. In addition, there were higher distribution segment expenses ($10 million) primarily due to higher customer account and storm restoration expenses, and higher transmission segment expenses ($2 million), partially offset by consolidation eliminations of transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($189 million).
Maintenance
Maintenance expenses increased $17 million primarily due to higher generationThe distribution segment expenses that are tracked and recovered through anrevenues included in NHPUC approved tracking mechanism ($15 million)mechanisms decreased $47 million due primarily as a result of the Merrimack Station maintenance outages
69
with the remainder of the increase primarily due to higher distribution segment expenses related to storms and the Reliability Enhancement Program (REP) that began on July 1, 2007.
Depreciation
Depreciation expense increased $3 million primarily due to higher utility plant balances resulting from completed construction programs put into service.
Amortization of Regulatory Assets/(Liabilities), Net
Amortization of regulatory assets/(liabilities), net increased $2 million primarily as a result of increased recoveries of previously deferred storm costs.
Amortization of Rate Reduction Bonds
Amortization of RRBs decreased $7 million primarily due to the retirement of $50 million of RRBs in the first quarter of 2008.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $2 million primarily due to higher property taxes ($3 million) as a result of higher net plant balances and higher local municipal tax rates, partially offset by lower payroll taxes ($1 million).
Interest Expense, Net
Interest expense, net increased $4 million primarily due to higher long-term debt interest ($7 million) resulting primarily from the $70 million debt issuance in September 2007 and the $110 million debt issuance in May 2008, partially offset by lower RRB interest resulting from lower principal balances outstanding ($2 million).
Other Income, Net
Other income, net increased $1 million primarily due to higher AFUDC equity income as a result of a higher eligible CWIP and lower short-term debt resulting in an increase in CWIP financed by equity ($2 million) and higher interest income related to the 2008 federal tax settlement ($2 million), partially offset by higher investment losses ($2 million) primarily due to the supplement benefit trust and lower investment income ($1 million).
Income Tax Expense
Income tax expense decreased $1 million primarily due to lower plant related flow through impacts, partially offset by higher pre-tax earnings.
Comparison of the Year 2007 to the Year 2006
Operating Revenues
Operating revenues decreased by $58 million due to lower distribution revenues ($64 million), partially offset by higher transmission segment revenues ($6 million).
The distribution segment revenue decrease of $64 million was due to the decrease of the components of revenues that are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurredpurchased fuel and power costs ($8799 million), partially offset by an increase of the distribution component of PSNH's retail revenues that impacts earnings ($24 million). The distribution revenue tracking components decrease of $87 million was primarily due to a decrease in the SCRC revenue ($76 million) mainly as a result of rate decreases effective July 1, 2006 and July 1, 2007, lower wholesale revenues ($27 million) and the pass through of lower energy supply costs ($15 million), partially offset by higher retail transmission revenues ($1714 million), higher RECwholesale revenue from the Northern Wood Power Plant ($8 million), and higher SBC revenueNWPP renewable energy certificate revenues ($4 million). The tracking mechanisms allow for rates to be changed periodically with over collectionsovercollections refunded to customers or under collections collectedo r undercollections recovered from customers in future periods.
The distribution component of PSNH’s retail revenues that impacts earnings increased $24 million, as a result of the rate increases effective July 1, 2006 and July 1, 2007, and higher sales. Retail sales increased 1.2 percent in 2007 compared to 2006.
Transmission segment revenues increased $6$15 million due primarily due to a higher transmission investment base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.expenses.
Fuel, Purchased and Net Interchange Power
Fuel, purchasedPurchased and net interchange power costsNet Interchange Power decreased $58 millionin 2009, as compared to 2008, due primarily due to a decrease in the purchasean increased level of migration of ES customers to competitive supply and lower retail sales, partially offset by higher priced Independent Power Producers’ power as contracts expired. forward energy market prices.
Other OperationOperating Expenses
Other operationOperating Expenses increased in 2009, as compared to 2008, as a result of higher distribution segment expenses increased $30 million primarily due to higher retail transmission expenses ($1315 million), mainly as a result of higher administrative and general expenses, ($8 million),including higher pension and medical costs, and higher customer assistance costsexpenses related to uncollectible receivable balances, and higher retail transmission expenses that are recovered through distribution tracking mechanisms and have no earnings impact ($410 million), primarily due to the Electric Assistance Program (EAP).
Maintenance
Maintenance decreased in 2009, as compared to 2008, due primarily to lower repair and maintenance of distribution lines ($7 million), including lower storm costs, lower generation expenses increased $3 million primarily due toas a result of lower maintenance outage expenses at Merrimack Station ($2 million) and hydro expenses incurred in 2008 primarily as a result of two major dam resurfacing projects ($1 million), partially offset by higher overhead line maintenance expenses.vegetation management expenses ($5 million).
7062
Depreciation
Depreciation expense increased $4 millionin 2009, as compared to 2008, due primarily due to higher utility plant balances.balances resulting from completed construction projects placed into service in the distribution segment ($3 million) and the transmission segment ($2 million).
Amortization of Regulatory Assets,Assets/(Liabilities), Net
Amortization of regulatory assetsRegulatory Assets/(Liabilities), Net decreased $46 millionin 2009, as compared to 2008, due primarily due to lowera decrease in net deferrals associated with the ES over recoveries ($27 million), lower stranded cost amortization levels, primarily as a result of PSNH’s full recovery of non-securitized stranded costs in June 2006 ($13 million) and the deferral of retail transmission costs through the TCAM which was implemented in 2007 ($5 million).
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $3 million. The higher portion of principal within the RRB payment results in a correspondingtracking mechanisms, partially offset by an increase in net deferrals associated with the amortization of RRBs.SCRC tracking mechanism.
Taxes Other Than Income Taxes
Taxes other than income taxesOther Than Income Taxes increased $2 millionin 2009, as compared to 2008, due primarily due to higher property taxes ($1 million)as a result of higher net plant balances and higher payroll-relatedincreased local municipal tax rates ($7 million), partially offset by lower sales taxes as a result of the resolution of various routine tax issues ($1 million).
Interest Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Interest on Long-Term Debt | $ | 33.0 |
| $ | 32.7 |
| $ | 0.3 |
| 0.9 | % |
Interest on RRBs |
| 13.1 |
|
| 16.0 |
|
| (2.9) |
| (18.1) |
|
Other Interest |
| 0.4 |
|
| 1.5 |
|
| (1.1) |
| (73.3) |
|
| $ | 46.5 |
| $ | 50.2 |
| $ | (3.7) |
| (7.4) | % |
Interest Expense decreased in 2009, as compared to 2008, due primarily to lower Interest on RRBs resulting from lower principal balances outstanding and lower Other Interest mostly related to the resolution of various routine tax issues.
Other Income, Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Other Income, Net | $ | 9.5 |
| $ | 7.3 |
| $ | 2.2 |
| 30.1 | % |
Other Income, Net increased in 2009, as compared to 2008, due primarily to higher investment income net decreased $1 million primarilyrelated to improved results from the NU supplemental benefit trust and the absence of other-than-temporary impairments recorded in 2008, and higher interest income related to the return on the December 2008 ice storm, partially offset by the absence in 2009 of interest income related to a federal tax settlement in 2008 and lower AFUDC equity income due to lower AFUDC, as a result of decreased eligible construction work in progress (CWIP) for generation, higher short-term debt, andwhich resulted in a lower portion of CWIP being subject to the equity rate.rate based on borrowing costs.
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 32.0 |
| $ | 22.0 |
| $ | 10.0 |
| 45.5 | % |
Income tax expense decreased $16 millionincreased in 2009, as compared to 2008, due primarily to a decrease in the effective tax rate to 29.5 percent. The decrease in the effective tax rate was due to an increase in tax credits, decrease in state tax expensehigher pre-tax earnings ($6 million) and lower flow through regulatory amortizations. The increase in tax credits were the result of a full year of production tax credits at the Northern Wood Power Plant. In 2006, flow through regulatory amortizations were higher as a result of the regulatory recovery in revenue of income tax expense associated with non-deductible acquisition costs.less favorable depreciation deduction adjustments ($2 million).
LIQUIDITY
PSNH had consolidatedcash flows provided by operating activities in 2010 of $145.4 million, compared with operating cash flows of $58.2 million in 2009 and $116.4 million in 2008, afterall amounts are net of RRB payments included in financing activities compared with operatingon the accompanying consolidated statements of cash flows. The improved cash flows were due primarily to the absence in 2010 of $95.5 millioncosts related to the major storm in 2007December 2008 that were paid in the first quarter of 2009, a decrease in Fuel, Materials and $125 million in 2006, both after RRB payments. The increase in 2008 operating cash flows was primarily dueSupplies attributable to a $25$31.8 million reduction in coal inventory levels in 2010 at the generation business as ordered by the NHPUC, and increases in amortization on regulatory deferrals primarily attributable to 2009 activity within PSNH’s ES tracking mechanism where such costs exceeded revenues resulting in an unfavorable cash flow impact in 2009. Offsetting these favorable cash flow impacts was a $45 million contribution made in t he third quarter of 2010 into the NU Pension Plan and payments made relating to the February 2010 severe storm for which the costs were deferred. PSNH expects to develop a recovery plan for these 2010 storm costs, net of any insurance payments PSNH would receive, through a previously agreed upon cooperative effort between PSNH, the NHPUC Staff, and the Office of Consumer Advocate as outlined in the joint settlement agreement of PSNH's distribution rate case that was effective July 1, 2010.
63
Selected Consolidated Sales Statistics |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 | ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 529,992 |
| $ | 506,725 |
| $ | 472,486 |
| $ | 457,616 |
| $ | 467,517 | |
Commercial |
|
| 360,373 |
|
| 407,743 |
|
| 431,461 |
|
| 413,196 |
|
| 439,828 | |
Industrial |
|
| 90,243 |
|
| 112,460 |
|
| 169,785 |
|
| 156,258 |
|
| 166,132 | |
Wholesale |
|
| 33,003 |
|
| 41,193 |
|
| 35,935 |
|
| 25,030 |
|
| 52,255 | |
Streetlighting and Railroads |
|
| 6,669 |
|
| 6,331 |
|
| 6,515 |
|
| 6,018 |
|
| 5,729 | |
Miscellaneous |
|
| 13,159 |
|
| 35,139 |
|
| 25,020 |
|
| 24,954 |
|
| 9,439 | |
Total |
| $ | 1,033,439 |
| $ | 1,109,591 |
| $ | 1,141,202 |
| $ | 1,083,072 |
| $ | 1,140,900 | |
Sales: (GWh) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 3,175 |
|
| 3,097 |
|
| 3,105 |
|
| 3,176 |
|
| 3,087 | |
Commercial |
|
| 3,309 |
|
| 3,311 |
|
| 3,361 |
|
| 3,403 |
|
| 3,342 | |
Industrial |
|
| 1,339 |
|
| 1,318 |
|
| 1,435 |
|
| 1,528 |
|
| 1,582 | |
Wholesale |
|
| 206 |
|
| 562 |
|
| (243) |
|
| 105 |
|
| 985 | |
Streetlighting and Railroads |
|
| 24 |
|
| 24 |
|
| 25 |
|
| 24 |
|
| 23 | |
Total |
|
| 8,053 |
|
| 8,312 |
|
| 7,683 |
|
| 8,236 |
|
| 9,019 | |
Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 420,481 |
|
| 417,670 |
|
| 418,107 |
|
| 417,420 |
|
| 413,980 | |
Commercial |
|
| 71,746 |
|
| 70,984 |
|
| 70,807 |
|
| 70,341 |
|
| 69,528 | |
Industrial |
|
| 3,088 |
|
| 3,134 |
|
| 2,978 |
|
| 2,770 |
|
| 2,761 | |
Streetlighting and Railroads |
|
| 1,442 |
|
| 1,438 |
|
| 970 |
|
| 602 |
|
| 592 | |
Total |
|
| 496,757 |
|
| 493,226 |
|
| 492,862 |
|
| 491,133 |
|
| 486,861 |
64
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for WMECO included in this Annual Report on Form 10-K for the years ended December 31, 2010, 2009 and 2008:
Comparison of 2010 to 2009:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 395.2 |
| $ | 402.4 |
| $ | (7.2) |
| (1.8) | % |
Operating Expenses: |
|
|
|
|
|
|
|
| & nbsp; |
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 157.3 |
|
| 192.2 |
|
| (34.9) |
| (18.2) |
|
Other Operating Expenses |
|
| 102.1 |
|
| 85.6 |
|
| 16.5 |
| 19.3 |
|
Maintenance |
|
| 19.2 |
|
| 17.9 |
|
| 1.3 |
| 7.3 |
|
Depreciation |
|
| 23.6 |
|
| 22.5 |
|
| 1.1 |
| 4.9 |
|
Amortization of Regulatory Assets/(Liabilities), Net |
|
| 2.3 |
|
| (3.0) |
|
| 5.3 |
| (a) |
|
Amortization of Rate Reduction Bonds |
|
| 15.5 |
|
| 14.5 |
|
| 1.0 |
| 6.9 |
|
Taxes Other Than Income Taxes |
|
| 16.5 |
|
| 14.1 |
|
| 2.4 |
| 17.0 |
|
Total Operating Expenses |
|
| 336.5 |
|
| 343.8 |
|
| (7.3) |
| (2.1) |
|
Operating Income |
| $ | 58.7 |
| $ | 58.6 |
| $ | 0.1 |
| 0.2 | % |
(a)
Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
WMECO's retail electric sales were as follows:
| For the Years Ended December 31, |
| ||||||
| 2010 |
| 2009 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 3,732 |
| 3,644 |
| 88 |
| 2.4 | % |
WMECO's Operating Revenues decreased in 2010, as compared to 2009, due primarily to:
·
A $20 million decrease related to distribution revenues that did not impact earnings and was included in net income tax payments,DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs. Included in these costs are a decrease of $31 million related to a lower recovery of energy supply costs and an increase in cash flow benefitsa decrease of our accounts payable balances of $50.1$7 million excluding approximately $50 million in unpaid major storm costsrelated to transmission segment intracompany billings to the distribution segment that are deferredeliminated in consolidation. Offsetting these decreases were increases in transition cost recoveries, C&LM collections and expectedretail transmission revenues ($8 million, $5 million and $4 million, respectively). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers or insurance proceeds, offset byin future periods.
·
The portion of electric distribution revenues that impacts earnings increased $2 million due primarily to a $42.1 million2.4 percent increase in generation fuelretail electric sales in 2010, as compared to 2009.
·
A $10 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and suppliesoperation and maintenance expenses.
Fuel, Purchased and Net Interchange Power
Fuel, Purchased and Net Interchange Power decreased in 2010, as compared to 2009, due primarily to lower Basic/Default service supply costs. The basic/default service supply costs are the contractual amounts WMECO must pay to various suppliers that serve this load after winning a competitive solicitation process. These costs decreased due primarily to lower supplier contract rates.
Other Operating Expenses
Other Operating Expenses increased in 2010, as compared to 2009, as a result of higher distribution segment expenses ($9 million) resulting from higher administrative and general expenses, including pension costs, higher costs that are recovered through distribution tracking mechanisms and have no earnings impact primarily related to an increase in C&LM expenses attributable to the Massachusetts Green Communities Act ($6 million), and higher prices and other miscellaneous negative cash flow impacts. transmission segment expenses ($1 million).
We expect theMaintenance
Maintenance increased in 2010, as compared to 2009, consolidated operating cash flows of PSNH after RRB paymentsdue primarily to be negatively impacted in the first half of the year by the payment of major storm costs incurred in December 2008. However, operating cash flows in the second half of the year should strengthen as these costs begin to be recovered from customers.higher distribution overhead line expenses.
7165
Depreciation
Depreciation increased in 2010, as compared to 2009, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.
Amortization of Regulatory Assets/(Liabilities), Net
Amortization of Regulatory Assets/(Liabilities), Net, increased in 2010, as compared to 2009, due primarily to the recovery of the previously deferred unrecovered stranded generation costs ($11 million), offset by a deferral of lost tax benefits related to the 2010 Healthcare Act that we believe are probable of recovery in future electric distribution rates ($4 million). RESULTS OF OPERATIONS -WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
The components of significant income statement variances for the past two years are provided in the table below. Taxes Other Than Income Taxes
Income Statement Variances | 2008 over/(under) 2007 |
|
| 2007 over/(under) 2006 |
| ||||||
(Millions of Dollars) | Amount |
| Percent |
|
| Amount |
| Percent |
| ||
Operating Revenues | $ | (23) |
| (5) | % |
| $ | 33 |
| 8 | % |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
Operation - |
|
|
|
|
|
|
|
|
|
|
|
Fuel, purchased and net interchange power |
| 1 |
| - |
|
|
| (44) |
| (16) |
|
Other operation |
| (22) |
| (22) |
|
|
| 17 |
| 21 |
|
Maintenance |
| 2 |
| 11 |
|
|
| 3 |
| 18 |
|
Depreciation |
| - |
| - |
|
|
| 4 |
| 21 |
|
Amortization of regulatory assets/(liabilities), net |
| 2 |
| 17 |
|
|
| 38 |
| (a) |
|
Amortization of rate reduction bonds |
| 1 |
| 7 |
|
|
| 1 |
| 7 |
|
Taxes other than income taxes |
| - |
| - |
|
|
| - |
| - |
|
Total operating expenses |
| (16) |
| (4) |
|
|
| 19 |
| 5 |
|
Operating Income |
| (7) |
| (14) |
|
|
| 14 |
| 35 |
|
Interest expense, net |
| - |
| - |
|
|
| 1 |
| 5 |
|
Other income, net |
| (2) |
| (50) |
|
|
| 2 |
| 66 |
|
Income before income tax expense |
| (9) |
| (24) |
|
|
| 15 |
| 63 |
|
Income tax expense |
| (4) |
| (28) |
|
|
| 7 |
| 88 |
|
Net income | $ | (5) |
| (22) | % |
| $ | 8 |
| 51 | % |
(Millions of Dollars) | 2010 | |
Property Taxes | $ | 1.5 |
Sales Taxes |
| 0.6 |
Other |
| 0.3 |
| $ | 2.4 |
The increase in Taxes Other Than Income Taxes was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO's capital programs.
Interest Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Interest on Long-Term Debt | $ | 18.0 |
| $ | 14.1 |
| $ | 3.9 |
| 27.7 | % |
Interest on RRBs |
| 3.4 |
|
| 4.3 |
|
| (0.9) |
| (20.9) |
|
Other Interest |
| 0.4 |
|
| 0.9 |
|
| (0.5) |
| (55.6) |
|
| $ | 21.8 |
| $ | 19.3 |
| $ | 2.5 |
| 13.0 | % |
Interest Expense increased in 2010, as compared to 2009, due primarily to higher Interest on Long-Term Debt resulting from the $95 million debt issuance in March 2010, offset by lower Interest on RRBs resulting from lower principal balances outstanding.
Other Income, Net
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Other Income, Net | $ | 2.6 |
| $ | 1.8 |
| $ | 0.8 |
| 44.4 | % |
Other Income, Net increased in 2010, as compared to 2009, due primarily to higher AFUDC related to equity funds ($1 million) and higher interest income ($1 million), offset by lower investment income ($1 million).
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 16.3 |
| $ | 14.9 |
| $ | 1.4 |
| 9.4 | % |
Income Tax Expense increased in 2010, as compared to 2009, due primarily to the impacts of the 2010 Healthcare Act ($3 million), partially offset by lower pre-tax earnings and other impacts ($2 million).
66
Comparison of 2009 to 2008:
|
| Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 402.4 |
| $ | 441.5 |
| $ | (39.1) |
| (8.9) | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
|
| 192.2 |
|
| 237.4 |
|
| (45.2) |
| (19.0) |
|
Other Operating Expenses |
|
| 85.6 |
|
| 77.0 |
|
| 8.6 |
| 11.2 |
|
Maintenance |
|
| 17.9 |
|
| 20.7 |
|
| (2.8) |
| (13.5) |
|
Depreciation |
|
| 22.5 |
|
| 21.0 |
|
| 1.5 |
| 7.1 |
|
Amortization of Regulatory Assets/(Liabilities), Net |
|
| (3.0) |
|
| 12.4 |
|
| (15.4) |
| (a) |
|
Amortization of Rate Reduction Bonds |
|
| 14.5 |
|
| 13.6 |
|
| 0.9 |
| 6.6 |
|
Taxes Other Than Income Taxes |
|
| 14.1 |
|
| 12.9 |
|
| 1.2 |
| 9.3 |
|
Total Operating Expenses |
|
| 343.8 |
|
| 395.0 |
|
| (51.2) |
| (13.0) |
|
Operating Income |
| $ | 58.6 |
| $ | 46.5 |
| $ | 12.1 |
| 26.0 | % |
(a)
Percent greater than 100.
Comparison of the Year 2008 to the Year 2007100 percent not shown as it is not meaningful.
Operating Revenues
WMECO's retail electric sales were as follows:
| For the Years Ended December 31, |
| ||||||
| 2009 |
| 2008 |
| Increase/ |
| Percent |
|
Retail Electric Sales in GWh | 3,644 |
| 3,829 |
| (185) |
| (4.8) | % |
Operating revenuesRevenues decreased $23 million in 2009, as compared to 2008, due to lower distribution segment revenues ($2647 million), partially offset by higher transmission segment revenues ($38 million).
The distribution segment revenues decreased $26$47 million due primarily due to a decrease in the portion of distribution revenues that does not impact earnings ($2449 million). These revenues do not impact earnings, primarily as a result of the inclusion of these distribution revenue being includedrevenues in regulatory tracking mechanisms and consolidation eliminations of transmission segment intracompany billings to the distribution segment, and the componentrevenues that are eliminated in consolidation. The portion of revenues that flows through toimpacts earnings ($2 million). increased $1 million.
The $24$49 million distribution segment revenuerevenues decrease that does not impact earnings iswas due primarily to a decrease in the componentsportions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs ($1844 million) and revenuestransmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($65 million). The distribution revenuerevenues included in DPU approved tracking mechanisms that track the recovery of certain incurreddecreased $44 million due primarily to lower energy supply costs decreased $18 million primarily due to($48 million), lower transition cost recoveries ($10 million), and lower wholesale revenues ($5 million), partially offset by higher retail transmission revenues ($12 million) and lower pension tracke r and default service true-up revenues ($815 million). TrackingThe tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
The portion of the distribution segment revenues that flows through to earnings decreased $2 million primarily due to lower2009 retail sales, ($2 million) and a service quality performance assessment charge ($1 million), partially offset by the rate increase effective January 1, 2008 ($2 million). Retail sales decreased 4.2 percent in 2008as compared to the same period in 2007.2008, decreased 11.7 percent for the industrial, 4.8 percent for the commercial, and 1.6 percent for the residential classes. Total retail sales decreased overall by 4.8 percent.
Transmission segment revenues increased $3$8 million due primarily due to a higher transmission investment base the impact of the March 24, 2008 FERC ROE decision and higher operating expenses that are passed through to customers under FERC-approved transmission tariffs.expenses.
Fuel, Purchased and Net Interchange Power
Fuel, purchasedPurchased and net interchange power expense increased $1 millionNet Interchange Power decreased in 2009, as compared to 2008, due primarily due to higher basic servicelower Basic/Default Service supply costs ($47 million) and lower other purchased power costs ($2 million), partially offset by an increasedhigher deferral of excess basic serviceBasic/Default Service revenue over Basic/Default Service expense over basic service revenue and lower amortization of the CT Yankee regulatory asset.($4 million). The basic serviceBasic/Default Service supply costs are the contractual amounts weWMECO must pay to various suppliers that serve basic servicethis load after winning a competitive solicitation process. These costs decreased as a result of lower supplier contract rates and reduced load volumes. To the extent that these costs do not match the revenues collected from customers, the DPU allows the difference to be deferred for future collection or refund. Lower other purchased power costs are due primarily to a decrease in costs associated with customer generation and IPPs.
Other OperationOperating Expenses
Other operation expenses decreased $22 million primarily dueOperating Expenses increased in 2009, as compared to lower2008, as a result of higher retail transmission and other costs that are tracked and recovered through distribution tracking mechanisms ($20 million) such as retail transmissionand have no earnings impact ($11 million) and lower tracked administrative and general expenses mainly due to pension expense ($9 million). In addition, consolidation eliminations of transmission segment intracompany billings to the distribution segment reduced expenses ($6 million), partially offset by higherlower distribution segment expenses ($2 million) primarily due to higher uncollectible expenses and higher transmission segment expenses ($1 million).
72
Maintenance
Maintenance expenses increased $2 million primarily due to higher tree trimming expensesmainly as a result of storms.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $2 million primarily due to the deferral of transition revenues collected in excess of allowed transition costs resulting mainly from higher power contract market values.
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $1 million. The higher portion of principal within the RRB payment results in a corresponding increase in the amortization of RRBs.
Other Income, Net
Other income, net decreased $2 million in 2008 primarily due to higher investment losses ($2 million) primarily due to the supplemental benefit trustlower administrative and lower investment income ($2 million), partially offset by higher interest income related to the 2008 federal tax settlement ($1 million) and higher AFUDC equity income as a result of a higher eligible CWIP and lower short-term debt resulting in an increase in CWIP financed by equity ($1 million).
Income Tax Expense/(Benefit)
Income tax expense decreased $4 million primarily due to lower pre-tax earnings.
Comparison of the Year 2007 to the Year 2006
Operating Revenues
Operating revenues increased $33 million compared to the same period in 2006 due to higher distribution segment revenue ($31 million) and higher transmission segment revenue ($3 million).
The distribution segment revenue increase of $31 million is primarily due to the components of revenues that are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($27 million). See also amortization of regulatory assets/(liabilities), net below. The distribution revenue tracking components increase of $27 million is primarily due to higher retail transmission revenues ($25 million) and higher transition cost recoveries ($15 million), higher pension tracker and default service true-up revenues ($8 million) resulting from the distribution rate settlement that took effect January 1, 2007 and higher wholesale revenues ($3 million), partially offset by the pass through of lower energy supply costs ($25 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected fro m customers in future periods.
The distribution component of revenues that impacts earnings increased $4 million primarily due to the distribution rate increase effective January 1, 2007 and higher retail sales. Retail sales increased 0.6 percent compared to the same period of 2006.
Transmission segment revenues increased $3 million primarily due to a higher transmission investment base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $44 million primarily due to lower default service supply costs ($33 million) and lower purchased power costs ($10 million), which are included in a regulatory commission approved tracking mechanism. The default service supply costs are the contractual amounts we must pay to various suppliers that supply default service load after winning a competitive solicitation process. The decrease in these costs is primarily the result of decreased load levels resulting from customers migrating from default service to a third party energy supplier during 2007 as compared to 2006. Lower purchased power costs of $10 million are the result of lower capacity costs for the Yankee companies' contractual obligations as some of these companies complete decommissioning.
Other Operation
Other operation expenses increased $17 million primarily due to an increase in retail transmission expenses ($8 million), higher administrative expenses ($6 million) and higher uncollectible account expenses ($2 million). The increase in retail transmission expenses is mainly due to the deferral, resulting from the regulatory tracking mechanism as a result of the increase in retail transmission revenue rates.general expenses.
Maintenance
Maintenance expense increased $3 milliondecreased in 2009, as compared to 2008, due primarily due to higher tree trimminglower repair and maintenance of station equipmentdistribution lines including lower storm expenses and structures expenses.
Depreciation
Depreciation expense increased $4 million primarily due to revised depreciation rates effective January 1, 2007 from the distribution rate settlement and higher utility plant balances.lower vegetation management expense.
7367
Amortization of Regulatory Assets/(Liabilities), Net
Amortization of regulatory assets/(liabilities)Regulatory Assets/(Liabilities), net increased $38 millionNet decreased in 2009, as compared to 2008, due primarily due to the deferral of allowed transition costs that are in excess of transition revenues, resulting from a decrease in the transition cost portion of the rate and lower IPP revenue than previous years.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes increased in 2009, as compared to 2008, due primarily to higher property taxes as a result of a higher transition charge rateplant balances and lower power contract net costs and the 2006 $18 million credit associated with the deferral of retail transmission costs.
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $1 million. The higher portion of principal within the RRB payment results in a corresponding increase in the amortization of RRBs.
Interest Expense, Net
Interest expense, net increased $1 million primarily due to higher interest on long-term debt as a result of the issuance of the sale of $40 million of unsecured notes in August 2007, partially offset by lower RRB interest resulting from lower principal balances outstanding.
Other Income, Net
Other income, net increased $2 million primarily due to higher investment income and higher equity of earnings as a result of regional nuclear generating companies. municipal tax rates.
Income Tax Expense
| For the Years Ended December 31, |
| |||||||||
(Millions of Dollars) | 2009 |
| 2008 |
| Increase/ |
| Percent |
| |||
Income Tax Expense | $ | 14.9 |
| $ | 10.5 |
| $ | 4.4 |
| 41.9 | % |
Income tax expense increased $7 million due primarily to higher pre-tax earnings and a decrease in favorable tax adjustments. earnings.
LIQUIDITY
WMECO had consolidatedcash flows provided by operating activities in 2010 of $50.5 million, compared with operating cash flows of $47.7 million in 2009 and $53.9 million in 2008, afterall amounts are net of RRB payments included in financing activities compared with operatingon the accompanying consolidated statements of cash flows of $24.9 millionflows. The increase in 2007 and $4.4 million in 2006, both after RRB payments. The improvement in 2008 operating cash flows was primarily due to a $71.5 million decreasethe absence in net income tax payments2010 of costs related to the major storm in December 2008 that were absent the payment of $47.9 million in federal and state income taxespaid in the first quarter of 20072009. These costs, as a result of the 2006 sale of NU’s competitive generation business. This factor was partially offset by a decrease in regulatory overrecoveries of approximately $49 million.
We expect the 2009 consolidated operating cash flows of WMECO after RRB payments to be negatively impacted by the payment of majorwell as storm costs incurred in December 2008. We do not expect these costs to2010, were deferred and in accordance with WMECO’s February 1, 2011 distribution rate case decision will be recovered from customers over five years as part of WMECO's storm reserve. The deferral of the 2010 significant storms cost created an unfavorable cash flow impact to WMECO's regulatory underrecoveries of approximately $6.1 million.
Offsetting the improved cash flows was an increase in 2009.income tax payments of $14.1 million, which was the result of bonus depreciation tax deduction benefits received throughout 2009 not being extended for the full year of 2010 until the fourth quarter of 2010.
68
Selected Consolidated Sales Statistics |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 | ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 208,332 |
| $ | 221,803 |
| $ | 241,303 |
| $ | 246,526 |
| $ | 232,197 | |
Commercial |
|
| 121,597 |
|
| 119,457 |
|
| 133,686 |
|
| 140,531 |
|
| 132,336 | |
Industrial |
|
| 33,892 |
|
| 33,555 |
|
| 39,245 |
|
| 48,036 |
|
| 43,131 | |
Other Utilities |
|
| 31,812 |
|
| 18,034 |
|
| 24,349 |
|
| 20,131 |
|
| 17,421 | |
Streetlighting and Railroads |
|
| 3,633 |
|
| 4,066 |
|
| 3,297 |
|
| 4,492 |
|
| 5,025 | |
Miscellaneous |
|
| (4,105) |
|
| 5,498 |
|
| (353) |
|
| 5,029 |
|
| 1,399 | |
Total |
| $ | 395,161 |
| $ | 402,413 |
| $ | 441,527 |
| $ | 464,745 |
| $ | 431,509 | |
Sales: (GWh) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 1,542 |
|
| 1,467 |
|
| 1,491 |
|
| 1,539 |
|
| 1,511 | |
Commercial |
|
| 1,496 |
|
| 1,474 |
|
| 1,547 |
|
| 1,589 |
|
| 1,574 | |
Industrial |
|
| 675 |
|
| 679 |
|
| 769 |
|
| 842 |
|
| 862 | |
Other Utilities |
|
| 177 |
|
| 187 |
|
| 179 |
|
| 178 |
|
| 189 | |
Streetlighting and Railroads |
|
| 20 |
|
| 24 |
|
| 22 |
|
| 25 |
|
| 25 | |
Total |
|
| 3,910 |
|
| 3,831 |
|
| 4,008 |
|
| 4,173 |
|
| 4,161 | |
Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 187,140 |
|
| 185,856 |
|
| 187,109 |
|
| 187,854 |
|
| 187,252 | |
Commercial |
|
| 17,475 |
|
| 16,587 |
|
| 16,916 |
|
| 17,096 |
|
| 17,310 | |
Industrial |
|
| 703 |
|
| 692 |
|
| 751 |
|
| 777 |
|
| 798 | |
Streetlighting and Railroads |
|
| 516 |
|
| 835 |
|
| 785 |
|
| 703 |
|
| 705 | |
Total |
|
| 205,834 |
|
| 203,970 |
|
| 205,561 |
|
| 206,430 |
|
| 206,065 |
69
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Market Risk Information
Commodity Price Risk Management: We have no contracts entered into for trading purposes. Our regulatedRegulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the regulatedRegulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments, and the sensitivity analyses below do not include these contracts.instruments.
Select Energy's Wholesale Portfolio: The remaining wholesale portfolio held by Select Energy includes contracts that are market-risk sensitive, including a wholesale energy sales contract with NYMPA through 2013 with an agency comprised of municipalities with approximately 2.70.3 million remaining MWHMWh of supply contract volumes, net of related sales volume, offset by related supply contracts.volumes. Select Energy also has a non-derivative energy contract that expires in 2012mid-2012 to purchase output from a generation facility. facility, which is also exposed to market price volatility.
As Select Energy's contract volumes are winding down, and areas the wholesale energy sales contract is substantially hedged against price risks, we have somewhat limited exposure to commodity price risks.
We have not entered into any energy contracts for trading purposes. For Select Energy’sEnergy's wholesale energy portfolio derivatives, we utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks (including where applicable capacity and ancillary components).risks. Sensitivity analysis provides a presentation of the potential loss of future pre-tax earnings and fair values or cash flows from our market risk-sensitive contracts over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes. Under sensitivity analysis, the fair valueAs of the portfolio is a function of the underlying commodity components, contract pricesDecember 31, 2010, assuming hypothetical 30 percent increases and decreases in forward energy, capacity and ancillary market prices, represented by each derivative contract. For swaps, forward contracts and options, fair value reflects our best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recor ded at fair value basednominal adjusted impact on closing exchange prices. A portion of the fair value of the NYMPA contract is based on a model. The fair value of the generation purchase contract is based on a model using available market information.
Select Energy’s Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of the wholesale portfolio, which includes several derivative contracts and a non-derivative power purchase contract, whichpre-tax earnings would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.
A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices. At December 31, 2008, we calculated the market price resulting from a 10 percent change in forward market prices. A 10 percent increase in prices for all products would have resulted in a pre-tax increase in fair value of $5.6be $0.1 million and a 10 percent decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $6.1 million. A 10 percent increase in energy prices would have resulted in a $1$(0.8) million, pre-tax decrease in fair value, and a 10 percent decrease in energy prices would
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have resulted in a $0.5 million pre-tax increase in fair value. A 10 percent increase/(decrease) in capacity prices would have resulted in a $1.2 million pre-tax increase/(decrease) in fair value. A 10 percent increase/(decrease) in ancillary prices would have resulted in a $5.4 million pre-tax increase/(decrease) in fair value. At December 31, 2007, a 10 percent increase in prices for all products would have resulted in a pre-tax increase in fair value of $0.9 million, and a 10 percent decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $1.3 million. A 10 percent increase in energy prices would have resulted in a $6.8 million pre-tax decrease, and a 10 percent decrease in energy prices would have resulted in a $6.4 million pre-tax increase. A 10 percent increase/(decrease) in capacity prices would have resulted in a $2.2 million pre - -tax increase/(decrease). A 10 percent increase/(decrease) in ancillary prices would have resulted in a $5.5 million pre-tax increase/(decrease).respect ively.
The impact of a change in electricity prices on wholesale derivative transactions atas of December 31, 20082010 are not necessarily representative of the results that will be realized if such a change were to occur. Energy, capacity and ancillaries have different market volatilities. The method we use to determine the fair value of these contracts includes discounting expected future cash flows using a LIBOR swap curve. As such, the wholesale portfolio is also exposed to interest rate volatility. This exposure is not modeled in sensitivity analyses, and we do not believe that such exposure is material. The derivative contracts in the wholesale portfolio are accounted for at fair value, and changes in market prices impact earnings.
Other Risk Management Activities
We have implemented an Enterprise Risk Management methodology for identifying the principal risks of the Company. Enterprise Risk Management involves the application of a well-defined, enterprise-wide methodology that enables our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the Enterprise Risk Management process will identify or manage every risk or event that could impact our financial condition, results of operations or cash flows. The findings of this process are periodically discussed with our Board of Trustees.
Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. AtAs of December 31, 2008,2010, approximately 9293 percent (86(87 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable rate long-term debt) of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by a pre-tax amount of $3.3 million. AtAs of December 31, 2008,2010, we maintained a fixed-to-floating interest rate swap at NU parent to manage the interest rate risk associated with $263 million of its fixed-ratefixed-rat e long-term debt.
Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
Credit risks and market risks at NU EnterprisesOur Regulated companies are monitored regularly by a Risk Oversight Council. The Risk Oversight Council is comprised of individualssubject to credit risk from outside ofcertain long-term or high-volume supply contracts with energy marketing companies. Our Regulated companies manage the management ofcredit risk with these activities that create these risk exposures and functions to ensure compliance with our stated risk management policies.
We track and re-balance the risk in our portfoliocounterparties in accordance with fair valueestablished credit risk practices and other risk management methodologiesmaintain an oversight group that utilize forward price curves inmonitors contracting risks, including credit risk. As of December 31, 2010, our Regulated companies neither held cash collateral nor deposited cash collateral with counterparties. NU parent provides standby LOCs for the energy marketsbenefit of its subsidiaries under its revolving credit agreement. PSNH posts such LOCs as collateral with counterparties and ISO-NE. For further information, see Note 12E, "Commitments and Contingencies - Guarantees and Indemnifications," to estimate the size and probability of future potential exposure.consolidated financial statements.
The NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy. Select Energy has also established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty in the extentevent of default. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's o veralloverall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by
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changes to economic, regulatory or other conditions.
At December 31, 2008 For further information, see Note 1H, " Summary of Significant Accounting Policies - Special Deposits and 2007, Select Energy had cash collateral balances deposited with its NYMEX broker of $26.3 million and $18.9 million, respectively, which is included in current assets - prepayments and other onCounterparty Deposits," to the accompanying consolidated balance sheets. Select Energy held no collateral balances from counterparties at either period end. In addition, Select Energy has a $2 million letter of credit outstanding.
Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintain an oversight group that monitors contracting risks, including credit risk. At December 31, 2008 and 2007, our regulated companies neither held cash collateral nor deposited collateral with counterparties. PSNH has letters of credit posted as collateral with counterparties and ISO-NE. At December 31, 2008, PSNH had $85 million in letters of credit outstanding. financial statements.
Additional quantitative and qualitative disclosures about market risk are set forth in Part II, Item 7, "Management'sManagement's Discussion and Analysis of Financial Condition and Results of Operations" contained within the, included in this Annual Report on Form 10-K.
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Item 8.
Financial Statements and Supplementary Data
NU, CL&P, PSNH and WMECO. The consolidated Financial Statements of each of NU, CL&P, PSNH and WMECO, the accompanying combined Notes to the Financial Statements, the Report of Independent Registered Public Accounting Firm for each of NU, CL&P, PSNH and WMECO, and the respective Financial Statement Schedules filed as part of this Annual Report on Form 10-K are listed under "Item 15. Exhibits and Financial Statement Schedules" and begin on page FS-1 immediately following the signature pages of this Annual Report on Form 10-K.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
No events that would be described in response to this item have ocurred with respect to NU, CL&P, PSNH or WMECO.
Item 9A.
Controls and Procedures
Management, on behalf of NU, CL&P, PSNH and WMECO, is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements and other sections of this combined Annual Report on Form 10-K. NU’s internal controls over financial reporting were audited by Deloitte & Touche LLP. This combined annual report on Form 10-K does not include an attestation report from Deloitte & Touche LLP regarding the internal controls over financial reporting for CL&P, PSNH and WMECO. Management’s report on behalf of CL&P, PSNH and WMECO was not subject to attestation pursuant to temporary rules of the SEC that permit these companies to provide only management’s report in this combined annual report.
Management, on behalf of NU, CL&P, PSNH and WMECO, is responsible for establishing and maintaining adequate internal controls over financial reporting. The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officers and principal financial o fficer, an evaluation of the effectiveness of internal controls over financial reporting was conducted based on criteria established inInternal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at NU, CL&P, PSNH and WMECO were effective as of December 31, 2008.
Management, on behalf of NU, CL&P, PSNH and WMECO, undertook a separate evaluation of the design and operation of disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and forms of the SEC. This evaluation was made under management’s supervision and with management’s participation, including the principal executive officers and principal financial officer, as of the end of the period covered by this report on Form 10-K. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Exchange Act i) is recorded, processed, summarized, and reported within th e time periods specified in SEC rules and forms and ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH and WMECO during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
Item 9B.
Other Information
No information is required to be disclosed under this item at December 31, 2008, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2008.
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Part III
Item 10.
Directors, Executive Officers and Corporate Governance
The information in Item 10 is provided as of February 25, 2009 except where otherwise indicated.
Certain information required by this Item 10 is omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.
NU
In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information to be contained in the sections captioned "Election of Trustees," "Governance of Northeast Utilities" and the related subsections, "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of NU's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on April 1, 2009.
NU and CL&P
The following table sets forth certain information as of February 25, 2009 concerning NU’s and CL&P’s executive officers. All of the Company’s officers serve terms of one year and until their successors are elected and qualified
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*
Mr. Necci is an executive officer of CL&P only.
**
On February 17, 2009, Ms. Payne resigned her position and was appointed Vice President - Shared Services of NUSCO, in each case, effective April 1, 2009.
Gregory B. Butler. Mr. Butler became Senior Vice President and General Counsel of NU effective December 1, 2005, and of CL&P, PSNH and WMECO, subsidiaries of NU, effective March 9, 2006, and was elected a Director of Northeast Utilities Foundation, Inc. effective December 1, 2002. Previously Mr. Butler served as Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005 and Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.
Peter J. Clarke. Mr. Clarke was elected President and Chief Operating Officer and a Director of WMECO and a Director of Northeast Utilities Foundation, Inc., effective January 1, 2009. Previously Mr. Clarke served as Vice President of Shared Services of NUSCO, CL&P, PSNH and WMECO, from January 1, 2008 to December 31, 2008; Vice President - Customer Operations of CL&P from July 1, 2006 to December 31, 2007; Vice President - Customer Operations and Relations of CL&P from January 17, 2005 to June 30, 2006; and Director - System Projects of CL&P from March 11, 2002 to January 16, 2005.
Jean M. LaVecchia. Ms. LaVecchia was elected Vice President - Human Resources of NUSCO, effective January 1, 2005 and was elected a Director of Northeast Utilities Foundation, Inc. effective January 30, 2007. Previously Ms. LaVecchia served as Vice President - Human Resources and Environmental Services from May 1, 2001 to December 31, 2004.
David R. McHale. Mr. McHale was elected Executive Vice President and Chief Financial Officer of NU, CL&P, WMECO and PSNH, effective January 1, 2009, elected a Director of PSNH and WMECO, effective January 1, 2005, of CL&P effective January 15, 2007 and of Northeast Utilities Foundation, Inc. effective January 1, 2005. Previously, Mr. McHale served as Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO from January 1, 2005 to December 31, 2008 and Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.
Raymond P. Necci. Mr. Necci was elected President and Chief Operating Officer and a Director of CL&P January 17, 2005 and a Director of Northeast Utilities Foundation effective April 1, 2006. Previously Mr. Necci served as Vice President - Utility Group Services of NUSCO from January 1, 2002 to January 16, 2005.
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Leon J. Olivier. Mr. Olivier was elected Executive Vice President and Chief Operating Officer of NU effective May 13, 2008; He also has served as Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; a Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001. Previously, Mr. Olivier served as Executive Vice President - Operations of NU from February 13, 2007 to May 12, 2008; Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; and President and Chief Operating Officer of CL&P from September 2001 to January 2005.
Shirley M. Payne. Ms. Payne was elected Vice President - Accounting and Controller of NU effective February 13, 2007, and Vice President - Accounting and Controller of CL&P, PSNH and WMECO effective January 29, 2007. Previously Ms. Payne served as Vice President, Corporate Accounting and Tax of TECO Energy, Inc., from July 2000 to January 26, 2007, and Tax Officer of TECO Energy, Inc., from April 1999 to January 26, 2007.
James B. Robb. Mr. Robb was elected Senior Vice President, Enterprise Planning and Development of NUSCO on September 4, 2007. Previously, Mr. Robb served as Managing Director, Russell Reynolds Associates from December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; and Senior Vice President, Performance Management, Reliant Resources, Inc. from November 2002 to December 2003.
Charles W. Shivery. Mr. Shivery was elected Chairman of the Board, President and Chief Executive Officer of NU effective March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO effective January 19, 2007 and a Director of Northeast Utilities Foundation effective March 3, 2004. Previously, Mr. Shivery served as President (interim) of NU from January 1, 2004 to March 29, 2004; and President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.
None of the above executive officers serves as an executive officer pursuant to any agreement or understanding with any other person.
There are no family relationships between any director or executive officer and any other trustee, director or executive officer of NU or CL&P and none of the above executive officers or directors serves as an executive officer or director pursuant to any agreement or understanding with any other person. Our executive officers hold the offices set forth opposite their names until the next annual meeting of the Board of Trustees, in the case of NU, and the Board of Directors, in the case of CL&P, and until their successors have been elected and qualified.
CL&P obtains audit services from the independent registered public accounting firm engaged by the Audit Committee of NU's Board of Trustees. CL&P does not have its own audit committee or, accordingly, an audit committee financial expert. CL&P relies on NU, which has an audit committee and an audit committee expert.
CODE OF ETHICS AND STANDARDS OF BUSINESS CONDUCT
Each of NU, CL&P, PSNH and WMECO has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and a Standards of Business Conduct which is applicable to all Trustees, directors, officers, employees, contractors and agents of NU, CL&P, PSNH and WMECO. The Code of Ethics and the Standards of Business Conduct have both been posted on the NU web site and are available at www.nu.com/investors/corporate_gov/default.asp on the Internet. Any amendments to or waivers from the Code of Ethics and Standards of Business Conduct will be posted on the website. Any such amendment or waiver would require the prior consent of the Board of Directors or an applicable committee thereof.
Printed copies of the Code of Ethics and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:
Ms. O. Kay Comendul
Assistant Secretary
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141
Item 11.
Executive Compensation
NU
The information required by this Item 11 for NU is incorporated herein by reference to certain information contained in NU’s definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about April 1, 2009, under the sections captioned "Compensation Discussion and Analysis" plus the related subsections, and "Compensation Committee Report" plus the related subsections following such Report.
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PSNH and WMECO
Certain information required by this Item 11 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
CL&P
The information in this Item 11 relates solely to CL&P. CL&P is a wholly-owned subsidiary of NU with a board of directors made up entirely of executive officers of NU system companies. CL&P does not have a compensation committee, and the Compensation Committee of NU’s Board of Trustees determines compensation for the executive officers of CL&P, including their salaries, annual incentive awards and long-term incentive awards. All of CL&P’s "Named Executive Officers," as defined below, with the exception of Mr. Necci, also serve as officers of other subsidiaries of NU. Compensation set by the Compensation Committee of NU and set forth herein is for services rendered to NU and its subsidiaries by such officers in all capacities.
COMPENSATION DISCUSSION AND ANALYSIS
OVERALL OBJECTIVES OF EXECUTIVE COMPENSATION PROGRAM
The fundamental objective of the Executive Compensation Program for NU system companies is to motivate executives and key employees to support the strategy of investing in and operating businesses that benefit customers, employees, and shareholders. As a holding company for several regulated utilities, NU is also responsible to its franchise customers to provide energy services reliably, safely, with respect for its employees and the environment, and at a reasonable cost. The Executive Compensation Program supports its fundamental objective through the following design principles:
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Attract and retain key executives by providing total compensation competitive with that of other executives employed by companies of similar size and complexity. The program relies on compensation data obtained from consultants’ surveys of companies and from a customized peer group to ensure that compensation opportunities are competitive and capable of attracting and retaining executives with the experience and talent required to achieve NU’s strategic objectives. As NU continues to grow and improve its transmission, distribution, and regulated generation systems, having the right talent will be critical.
·
Establish performance-based compensation that balances rewards for short-term and long-term business results. The program motivates executives to run the business well in the short term, while executing the long-term business plan to benefit both NU’s customers and shareholders. The program aims to strike a balance between the short- and long-term programs so that they work in tandem. It also ensures that long-term objectives are not sacrificed to achieve short-term goals or vice versa.
Incentive plan performance criteria are based on a combination of financial, operational, stewardship, and strategic goals that are essential to the achievement of NU’s business strategies. This linkage to critical goals helps to align executives with NU’s key stakeholders, customers, employees, and shareholders. The long-term program also compares performance relative to a group of comparable utility companies.
·
Reward corporate and individual performance. Overall compensation has many metrics based on corporate performance but is also highly differentiated based on individual performance. The annual incentive program rewards both corporate performance (measured by adjusted net income) and individual performance (including individualized financial, operational, stewardship and strategic metrics). Long-term incentives are composed of a performance cash program and restricted share units (RSUs). The performance cash program pays out based on the achievement of NU corporate goals (cumulative net income, average return on equity, average credit rating and relative total shareholder return). The size of RSU grants reflects NU corporate performance during the preceding fiscal year as well as individual performance and contribution, but the ultimate value of the RSUs is based on NU corporate tot al shareholder return.
·
Encourage long-term commitment to the Company. Utility companies provide a public service and have a long-term commitment to ensure that customers receive reliable service day after day. Meeting this commitment requires specialized skills and institutional knowledge that are learned over time through local industry experience. These skills include familiarity with the regions and communities that NU serves, government regulations, and long-term energy policies. In addition, utility companies rely on long-term capital investments to serve their customers.
As a result, public utilities benefit from long-service employees. NU has structured its executive compensation programs to build long-term commitment as well as shareholder alignment. Providing competitive compensation opportunities and offering programs such as RSUs and supplemental retirement benefits that vest and have the ability to increase in value over time encourage long-term employment. Executive share ownership guidelines are another program component intended to build long-term shareholder alignment and commitment.
The executive officers of CL&P listed in the Summary Compensation Table in this Annual Report on Form 10-K and whose compensation is discussed in this CD&A are referred to as the "Named Executive Officers" or "NEOs." For 2008, CL&P’s Named Executive Officers are:
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·
Charles W. Shivery, Chairman of the Board, President and Chief Executive Officer of NU; Chairman of CL&P
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David R. McHale, Executive Vice President and Chief Financial Officer of NU and CL&P
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Leon J. Olivier, Executive Vice President and Chief Operating Officer of NU; Chief Executive Officer and Director of CL&P
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Gregory B. Butler, Senior Vice President and General Counsel of NU and CL&P
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Raymond P. Necci, President and Chief Operating Officer of CL&P
ELEMENTS OF 2008 COMPENSATION
Set forth below is a brief description and the objective of each material element of NU’s executive compensation program:
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MIX OF COMPENSATION ELEMENTS
NU strives to provide executive officers with base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with the market. The Compensation Committee determines the Total Direct Compensation for the Named Executive Officers as described under the caption "Market Analysis", below. As a result, the annual and long-term incentive target percentages for the NEOs are approximately equal to competitive median incentives.
With respect to incentive compensation, the Compensation Committee believes it is important to balance short-term goals, such as generating earnings per share, with longer term goals, such as long-term value creation and maintaining a strong balance sheet. As the executive officers are promoted to more senior positions, they assume increased responsibility for implementing NU’s long-term business plans and strategies, and a greater proportion of their total compensation is based on performance with a long-term focus. This survey data is discussed in greater detail below under the caption "Market Analysis."
The Compensation Committee determines total compensation for each executive officer based on the relative authority, duties and responsibilities of each office. Mr. Shivery’s responsibilities, as Chairman, President and Chief Executive Officer of NU, for the daily operations and management of the NU System companies, are significantly greater than the duties and responsibilities of the other executive officers. As a result, Mr. Shivery’s compensation is significantly higher than the compensation of the other executive officers. The Compensation Committee regularly reviews market compensation data for executive officer positions similar to those held by the executive officers, including Mr. Shivery, and this market data continues to indicate that chief executive officers are typically paid significantly more than other executive officers. For 2008, target annual incentive and long-term incentive compensation opportunities for Mr. Shivery were 100% and 300% of base salary, respectively. For the remaining NEOs, target annual incentive compensation opportunities ranged from 50% to 65% of base salary and target long-term incentive compensation opportunities ranged from 85% to 150% of base salary. Mr. Olivier’s long-term incentive compensation target was fixed at 125% of his base salary, which is below a target of 150% of base salary typically provided to executive officers at his level, because his total compensation includes a special retirement benefit.
The following table sets forth the contribution to 2008 Total Direct Compensation (TDC) of each element of compensation, at target, reflected as a percentage of TDC, for each Named Executive Officer. Annual incentive awards and performance cash awards under the long-term incentive program were performance based and, accordingly, were at risk.
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Named Executive Officer | Base | Annual | Performance |
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Charles W. Shivery | 20% | 20% | 30% | 30% | 100% |
David R. McHale | 32% | 20% | 24% | 24% | 100% |
Leon J. Olivier | 34% | 22% | 22% | 22% | 100% |
Gregory B. Butler | 32% | 20% | 24% | 24% | 100% |
Raymond P. Necci | 43% | 21% | 18% | 18% | 100% |
NEO Average, |
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(1)
The annual incentive compensation element and performance cash awards under the long-term incentive compensation element are performance-based.
(2)
Long-term incentive compensation at target consists of equal proportions of performance cash awards and RSUs.
(3)
The percentages reflect the guideline values of RSUs at target. Actual RSUs are granted based on annual corporate and individual performance and may vary above or below target. RSUs vest over three years contingent upon continued employment.
MARKET ANALYSIS
The Compensation Committee strives to provide the executive officers with compensation opportunities over time at or above the median compensation levels for executive officers of companies comparable to NU. The Committee determined executive officer TDC levels in two steps. First, the Committee determined the "market" values of executive officer compensation elements (base salaries, annual incentives and long-term incentives) as well as total compensation using compensation data obtained from other companies. The Committee reviewed compensation data obtained from two sources: (i) utility and general industry survey data and (ii) customized peer group data. The Committee then reviewed the compensation elements for each executive officer with respect to the median of these market values, and considered individual performance, experience and internal pay equity to determin e the amount, if any, by which the various compensation elements should differ from median market values. Significantly, the Committee has not made an explicit commitment to compensate the executive officers through a firm and direct connection between the compensation paid by NU and the compensation paid by any of the companies from which the utility and general industry survey data and the customized peer group data was obtained.
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Set forth below is a description of the sources of the compensation data used by the Compensation Committee when reviewing 2008 compensation:
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Utility and general industry survey data. The Committee analyzed compensation information obtained from surveys of diverse groups of utility and general industry companies that represent NU’s market for executive officer talent. The Committee used the utility and general industry survey data to determine base salaries and incentive opportunities. The compensation consultant reviewed subsets of survey data applicable to utility companies correlated to reflect entities similar in size to NU. Then the Committee compared utility-specific executive officer positions, including Mr. Olivier, who serves as NU’s Executive Vice President and Chief Operating Officer as well as CL&P’s Chief Executive Officer, to utility-specific market values. For executive officer positions that have counterparts in general industry, including NU’s CEO, Executive Vice President and Chief Financia l Officer, and Senior Vice President and General Counsel, the Committee averaged general industry comparisons with utility industry comparisons weighted equally.
·
Customized peer group data. The Committee also evaluated compensation data obtained from reviews of proxy statements from the customized group of peer utility companies. Periodically, the Committee assesses the composition of the customized peer group to ensure that the number of companies is sufficient and the companies have reasonably similar revenues. The Committee also strives to maintain year over year consistency within the group. In support of executive pay decisions during 2008, the customized peer group consisted of: (i) utilities that are substantially regulated with annual revenues that ranged from $2.7 billion to $13 billion, with median annual revenues of $4.9 billion; and (ii) utilities that are less regulated and closer in size to NU, with annual revenues that ranged from $3.1 billion to $6.9 billion. Although the Committee does not con sider utilities that are less regulated to be direct performance peers, these companies represent potential sources of talent. The Committee considered data only for those executive officer positions where there is a title match, e.g., the CEO, Chief Financial Officer, and General Counsel. For 2008, this group consisted of the following 22 companies:
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The Committee used compensation data obtained from these companies for insights into incentive compensation design practices and compensation levels, although no specific actions were taken in 2008 directly as a result of this data. In 2008, the Committee also used a subset of this group for performance comparisons under the performance cash program as described below under the caption "2008 - 2010 Long-Term Incentive Program." The Committee periodically adjusts the target percentages of annual and long-term incentives based on the survey data to ensure that they continue to represent market median levels. Adjustments are made gradually over time to avoid radical changes.
The Compensation Committee also sets supplemental benefits at levels that provide market-based compensation opportunities to the executive officers. Compensation includes perquisites to the extent they serve business purposes. The Committee periodically reviews the general market for supplemental benefits and perquisites using utility and general industry survey data, sometimes including data obtained from companies in the customized peer group. Benefits are adjusted occasionally to help maintain market parity. When the market trend for supplemental benefits reflects a general reduction, (e.g., the elimination of defined benefit pension plans), the Committee has reduced these benefits only for newly hired officers. The Committee reviewed NU’s supplemental retirement practices most recently in 2005 and 2006, as described in more detail below under the caption "Supplemental Benefits."
BASE SALARY
The Compensation Committee reviews executive officers’ base salaries annually. The Committee considers the following specific factors when setting or adjusting base salaries:
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Annual individual performance appraisals
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Market pay movement across industries (determined through market analysis)
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Targeted market pay positioning for each executive officer
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Individual experience and years of service
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Changes in corporate focus with respect to strategic importance of a position
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Internal equity
Individuals who are performing well in strategic positions are likely to have their base salaries increased more significantly than other individuals. From time-to-time, economic conditions and corporate performance have caused salary increases to be postponed. The Committee prefers to reflect subpar corporate performance through the variable pay components.
Based on these considerations, the Compensation Committee, acting jointly with the Corporate Governance Committee, recommended to the Board of Trustees a 2008 salary increase for Mr. Shivery of 3.5%, which was approved by the Board. Mr. Shivery’s base salary was increased to recognize his level of contribution to the daily operations and management of the Northeast
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Utilities System companies as Chief Executive Officer of NU. The Compensation Committee also approved base salary increases for the other NEOs in 2008 as follows: Mr. McHale: 11.1%; Mr. Olivier: 15.8%; Mr. Butler: 5.0%; and Mr. Necci: 3.5%. Mr. Olivier’s salary increase was primarily related to his new responsibilities as Executive Vice President and Chief Operating Officer of NU effective in May 2008. Mr. McHale’s salary increase was based primarily on his increased experience and individual performance during 2008. Mr. Butler’s increase recognized increasing competitive pay levels for top legal professionals and his responsibilities in addition to oversight of the legal function. Mr. Necci’s increase recognized his continuing significant contributions to the company.
INCENTIVE COMPENSATION
The annual incentive program and the long-term incentive program are provided under the Northeast Utilities Incentive Plan, which was approved by NU’s shareholders at the 2007 Annual Meeting of Shareholders. The annual incentive program provides cash compensation intended to reward performance under NU’s annual operating plans. The long-term incentive program is designed to reward demonstrated performance and leadership, motivate future superior performance, align the interests of the executive officers with those of NU’s shareholders and retain the executive officers during the term of awards. Awards under the long-term incentive program consist of two elements of compensation, RSUs and performance cash. The Compensation Committee selected RSUs as the equity component of long-term awards because utility companies create value for shareholders through the payment of periodic dividends as well as t hrough share price appreciation. The annual and long-term programs are intended to work in tandem so that achievement of NU’s annual goals leads NU towards attainment of its long-term financial goals.
Incentive awards are based on objective financial performance goals established by the Compensation Committee with the advice of the Finance Committee. The Compensation Committee sets the performance goals annually for new annual incentive and long-term incentive program performance periods, depending on NU’s business focus for the then-current year and the long-term strategic plan.
2008 ANNUAL INCENTIVE PROGRAM
The 2008 Annual Incentive Program consisted of a corporate goal plus individual goals for each NEO. The Compensation Committee set the annual incentive compensation targets for 2008 at 100% of base salary for Mr. Shivery and at 50% to 65% of base salary for the other NEOs. The annual incentive compensation targets are used as guidelines for the determination of annual incentive payments, but actual annual incentive payments may vary significantly from these targets, depending on individual and corporate performance. Actual annual incentive payments may equal up to two times target if NU achieves superior financial and operational results. The opportunity to earn up to two times the incentive target reflects the Compensation Committee’s belief that executive officers have significant ability to affect performance outcomes. However, we do not pay annual incentive awards if minimum levels of financial pe rformance are not met.
If CL&P’s earnings were to be restated as a result of noncompliance with accounting rules caused by fraud or misconduct, the Sarbanes-Oxley Act of 2002 would require Mr. Olivier, as Chief Executive Officer, and Mr. McHale, CL&P’s Chief Financial Officer, to reimburse CL&P for certain incentive compensation received by each of them. To the extent that reimbursement were not required under Sarbanes-Oxley, the Incentive Plan would require any employee whose misconduct or fraud caused such restatement, as determined by the Board of Trustees, to reimburse CL&P for any incentive compensation received by him or her. To date, there have been no restatements to which either the Sarbanes-Oxley reimbursement provisions or the Incentive Plan reimbursement provisions would apply.
2008 Corporate Goal
The objective of the 2008 Annual Incentive Program corporate goal for the NEOs was for NU to achieve an adjusted net income (ANI) target established by the Compensation Committee. ANI is defined as consolidated NU net income adjusted to exclude the effect of certain nonrecurring income and expense items or events. The Committee uses ANI because it believes that ANI serves as an indicator of ongoing operating performance. The minimum payout under the corporate goal was set at 50% of target and would have occurred if actual ANI had been at least 90% of the ANI target. The maximum payout under the corporate goal was set at 200% of target and would have occurred if actual ANI had been at least 10% above the ANI target. The payment of any amount of annual incentive compensation related to individual goals required actual ANI to be at least 80% of the ANI target.
For 2008, the Compensation Committee established the ANI target at $278.8 million. The ANI target reflects the midpoint of the range of internal ANI estimates calculated at the beginning of the year. The ANI thresholds for the individual and corporate goals appear below (dollars in millions):
Threshold For | Minimum | 2008 ANI Target | Maximum Corporate | Actual |
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$223.0 | $250.9 | $278.8 | $306.7 | $291.5 |
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The Compensation Committee set the ANI threshold for achieving individual goals and the minimum and maximum corporate goals in its discretion based on the following factors:
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An assessment of the potential volatility in results through an evaluation of critical elements of the strategic business plan, both individually and in combination with each other;
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The degree of difficulty in achieving the ANI target; and
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The minimum acceptable ANI.
At the time that the Compensation Committee established the performance goals for 2008, the Committee also considered and agreed upon exclusions from ANI consisting of certain nonrecurring income and expense items or events that were either beyond the control of management generally or related to a decision by the Committee not to penalize executive officers for making correct strategic business decisions. The Compensation Committee approved all final exclusions from ANI. The income and expense items set forth below were excluded from ANI in 2008.
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2008 Individual Goals
The 2008 Annual Incentive Program individual goals included various financial, operational, stewardship, and strategic metrics that are drivers of overall corporate performance. The achievement of individual goals would result in an annual incentive payment only if actual ANI is at least 80% of the ANI target. This ANI threshold satisfies the requirements of Section 162(m) of the Internal Revenue Code. Upon achieving this ANI threshold, the maximum payout is possible for individual goals for every participant.
The Committee acts in its discretion under Section 162(m) and related Internal Revenue Service rules and regulations to ensure that incentive compensation payments are "qualified performance based compensation" not subject to the $1 million limitation on deductibility. The Compensation Committee acting jointly with the Corporate Governance Committee determines Mr. Shivery’s proposed annual incentive program payment based on the extent to which individual and corporate goals have been achieved. The Compensation Committee recommends to the Board of Trustees for approval the proposed award for Mr. Shivery. For the remaining NEOs, Mr. Shivery recommends annual incentive awards to the Compensation Committee for its approval. NEOs are eligible to receive up to two times the annual incentive compensation target for the individual portion of the award.
Goal Weightings for 2008
The following table sets forth the weighting of the annual incentive program corporate goal and individual goals of each NEO’s compensation for 2008. These weightings reflect the Compensation Committee’s desire to balance individual accountability with teamwork across the NU organization. Individual goals range from 40% to 70% of the total annual incentive program target. Certain of the NEO’s individual performance goals are subjective in nature and cannot be measured either by reference to existing financial metrics or by using pre-determined mathematical formulas. The Committee believes that it is important to exercise judgment and discretion when determining the extent to which each NEO satisfies subjective individual performance goals. The Committee considers these goals along with several factors, including overall individual performance, corporate performance, prior year compensation and the other facto rs discussed below.
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Charles W. Shivery Chairman of CL&P; Chairman of the Board, President, and Chief Executive Officer of NU |
| 60% |
| 40% |
| Ensure effective execution of NU’s strategic plan and the 2008 operating and capital plans with special emphasis on meeting operational objectives (25% of individual goals). Develop a strategy and position NU to take advantage of opportunities beyond 2008 through the appropriate alignment of strategy, organizational structure, resources and culture. Define the company’s vision with respect to climate change and implement strategies consistent with that vision. Achieve improvements in the company’s reputation among its stakeholders (20% of individual goals). Continue progress in continued development and implementation of energy policy in New England consistent with the company’s strategic plan to benefit customers. Achieve successful outcomes in federal and state regulatory and legislative proceedings to support that strategy (20% of individual goals). Create a strategy that brings a customer focus to the forefront of the organization; communicate expectations and standards around the customer’s experience (20% of individual goals). Continue to implement cultural changes required for the company to succeed in an evolving environment. Define and promote a culture of safety. Lead through tone and actions NU’s efforts to realize NU’s vision and create an inclusive environment and a diverse workforce (15% of individual goals). |
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David R. McHale Executive Vice President and Chief Financial Officer |
| 60% |
| 40% |
| Achieve strategic initiatives: Operational planning, risk management, common equity requirements, and capital allocation (30% of individual goals). Achieve successful business execution: Lead efforts in rate cases, regulatory strategy, energy policy, and corporate cost analysis and management (25% of individual goals). Manage competitive businesses and divestiture (20% of individual goals). Provide internal customer service to operating companies and other corporate center groups (10% of individual goals). Achieve organization development goals: complete new financial planning organization; launch the Finance Academy; implement succession development plans; meet goals for safety and diversity and act on employee survey results (15% of individual goals). |
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Raymond P. President & Chief Operating Officer |
| 30% |
| 70% |
| Maximize CL&P and Yankee Gas net income performance (20% of individual goals). Achieve a successful outcome in an external agency audit of CL&P’s electric distribution system (10% of individual goals). Successfully implement a series of customer experience initiatives and complete CL&P’s new customer service system (20% of individual goals). Pursue strategic goals, including energy conservation and load management initiatives (10% of individual goals). Implement strategies designed to increase engagement of employees and labor unions, and to improve safety performance (20% of individual goals). Execute operational goals, including completion of scheduled maintenance, energy efficiency, and reliability projects, and managing operation and maintenance expenditures (20% of individual goals). |
2008 Results
The 2008 actual ANI was $291.5 million, which exceeded the target ANI amount for the annual program corporate goal, but was less than the maximum ANI amount. As a result, a portion of the total annual incentive payment to each NEO was attributable to achieving NU’s corporate goal at 146% of target. In addition, the 2008 actual ANI exceeded the individual goal threshold. Accordingly, the balance of the annual incentive payment to each NEO was based on the extent to which each NEO achieved his or her individual goals.
Mr. Shivery’s Annual Incentive Payment
The Compensation Committee and the Corporate Governance Committee of NU’s Board of Trustees assessed Mr. Shivery’s performance on his individual goals described in the table above. Set forth below is a description of the Committees’ assessment of Mr. Shivery’s performance against these goals:
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Mr. Shivery’s execution of NU’s long-term strategic plan as well as NU’s 2008 operating and capital plans was well above expectations. CL&P completed all of its remaining southwest Connecticut transmission projects. The major project, the 69-mile transmission line between Middletown and Norwalk Connecticut, was completed one year ahead of schedule and below budget. NU achieved successful outcomes in various legislative and regulatory proceedings, including obtaining an order from the Federal Energy Regulatory Commission providing a favorable base return on equity and incentives, including one for the use of advanced technologies. Implementation of the $6 billion capital investment program is on track and has yielded increased earnings and improved reliability. Distribution, generation and the new liquefied natural gas facilities operated reliably.
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Mr. Shivery’s work toward developing NU’s strategy and positioning NU for the future was well above expectations. NU proposed jointly with NSTAR the Hydro-Québec project, a visionary long-term project to deliver low-carbon power to New England over a new transmission line between northern New England and Hydro-Québec in eastern Canada. NU continues to remain financially strong in the face of extreme disruptions in the financial markets. Significant positive steps were taken to improve the company’s culture of performance and accountability and expand leadership visibility. Key members of management were assigned to positions with new or expanded responsibilities in order to increase their overall experience and better position NU for continued success. NU continued to improve in enterprise risk management and communications strategy and execution.
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Mr. Shivery’s role in energy policy initiatives in New England met expectations at both the federal and state levels. Of particular note were various programs to reduce the environmental impact of electricity generation, including the Hydro-Québec project with NSTAR, which is expected to provide a competitive source of clean power that is favorable in comparison to current alternatives; preliminary work to obtain approval for solar generation as permitted by the Massachusetts Green Communities Act; initiation of an advanced metering infrastructure pilot program in Connecticut; and continued progress on the Northern Loop project in New Hampshire, all of which are expected to provide long-term benefits to NU’s customers and communities and competitive returns to NU’s investors. NU continued to help shape legislative policy related to climate change. Mr. Shivery also co-chairs the E dison Electricity Institute (EEI) Energy
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Delivery Committee, which has helped frame EEI positions around critical energy policy issues on a national and regional level.
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On balance, Mr. Shivery’s performance regarding customer focus goals met expectations. NU recruited a new customer experience officer who oversaw the strengthening of NU’s customer service organization, including developing a customer experience vision, establishing standards of service excellence, and implementing NU’s customer service integration system. In addition, NU undertook extensive regulatory and stakeholder outreach.
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Mr. Shivery’s efforts to align the company’s culture with NU’s business strategies, improve safety performance and increase diversity met expectations. Increased focus was placed on development of leaders at all levels, and on development of critical engineering and financial talent to ensure the continuity of institutional knowledge critical to NU’s success. NU’s safety performance improved measurably in 2008. An increase in diversity at multiple leadership levels and throughout the organization was achieved.
The Compensation Committee and the Corporate Governance Committee jointly considered Mr. Shivery’s performance on all of the individual performance goals set forth above. Coupled with NU’s overall corporate performance measured by ANI, the committee members applied judgment to determine their recommendation for Mr. Shivery’s annual incentive payment. Following a detailed review of these factors without Mr. Shivery present, the Board of Trustees awarded Mr. Shivery an annual incentive payment of $1,519,129 for 2008, consisting of $935,046 attributable to the achievement of 146% of the corporate goal and an additional $584,083 attributable to Mr. Shivery’s performance of his individual goals. The Board of Trustees determined that this annual incentive payment was consistent with Mr. Shivery’s above-expectations performance based on corporate, financial and individua l criteria established for 2008. Mr. Shivery’s annual incentive payment exceeds that of the other NEOs because of his significantly greater duties and responsibilities as CEO of NU.
NEO Annual Incentive Payments
In addition to our corporate ANI goal described above, the Compensation Committee considered individual performance goals and other factors in determining the annual incentive payments for each of the other NEOs. These factors included the annual incentive payment recommendations made by Mr. Shivery with respect to each of the NEOs and the scope of each NEO's responsibilities, performance, and impact on or contribution to NU's corporate success and growth. The annual incentives paid to each NEO as described below include the corporate ANI goal component for 2008.
The Compensation Committee determined that Mr. McHale and his organization provided critical guidance and support for NU's strategies involving the Northern Solutions and Hydro-Québec major transmission projects, the Massachusetts Green Communities Act, and Connecticut peaking generation. Mr. McHale and his team took significant positive steps to ensure that NU remained financially strong despite extreme disruptions in the financial markets. Current credit ratings and rating agency outlooks on NU and NU's four regulated utilities were maintained despite significant capital expenditure projections and volatile market conditions. In addition, Mr. McHale’s organization implemented the NU Finance Academy, which is designed to strengthen employees’ business knowledge in support of NU's organization development efforts. Finally, Mr. McHale and his team successfully managed the market risk of NU's competitive businesses while achieving above-budget net income. Based on his demonstrated leadership and this assessment of his successes, the Compensation Committee awarded Mr. McHale an annual incentive payment of $465,520 for 2008.
The Compensation Committee determined that Mr. Olivier and his team effectively executed NU's operating plan and the 2008 components of NU's five-year strategic plan, including the early and below-budget completion of the Middletown-Norwalk transmission line, significant safety improvements, and effective completion of the year’s capital program. In addition, through their actions, Mr. Olivier and his team were successful in increasing NU's external stakeholders’ understanding of the benefits of NU's strategies around meeting the resource, environmental and energy supply needs of NU's region. Mr. Olivier and his team also made significant progress in improving customer experience, including the completion and launch of NU's integrated customer service system and an extensive reorganization of the customer experience organization. Based on his demonstrated leadership and the Committee’s assessment o f his successes, the Committee awarded Mr. Olivier an annual incentive payment of $494,571 for 2008.
The Compensation Committee determined that Mr. Butler’s team advanced NU's position on regional energy policy considerably in Connecticut, Massachusetts and New Hampshire, which will ultimately provide benefits to customers and shareholders. In addition, Mr. Butler’s team provided extensive support for various strategic initiatives, including the Northern Solutions and Hydro-Québec major transmission projects and the Massachusetts Green Communities Act. Mr. Butler and his team contributed significantly to NU's regulatory and financial strategies by achieving favorable outcomes in various federal and state regulatory proceedings. His team also supported NU's operating subsidiaries as each of them executed their operating plans. Based upon these successes, the Compensation Committee awarded Mr. Butler an annual incentive payment of $361,286 for 2008.
The Compensation Committee determined that, on balance, Mr. Necci and his team executed the operating plan successfully, with highly reliable operations of the electric distribution system and the new liquefied natural gas facility. Mr. Necci and his team also completed a high volume of important maintenance and capital projects. Mr. Necci and his team partnered with bargaining unit employees and generally increased employee participation in creative efforts to improve service, safety, and reliability. These results yielded significant benefits to both customers and shareholders. Based on his demonstrated leadership and the Committee’s assessment of his successes, the Committee awarded Mr. Necci an annual incentive payment of $173,807 for 2008.
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LONG-TERM INCENTIVE PROGRAM
General
Under NU’s Long-Term Incentive Programs, the Compensation Committee acting jointly with the Corporate Governance Committee recommends to the Board of Trustees a long-term incentive target grant value for Mr. Shivery as a percentage of base salary on the date of grant. This recommendation is forwarded to the Board for approval. The Compensation Committee also approves long-term incentive target grant values for each of the other NEOs as a percentage of base salary on the date of grant. At target, each grant typically consists of one-half RSUs and one-half performance cash, subject to adjustment by the Compensation Committee (except the Compensation Committee acts jointly with the Corporate Governance Committee in recommending to the Board of Trustees adjustments to Mr. Shivery’s targets), reflecting the Committee’s desire to balance total shareholder return with NU’s corporate financial performance.
In 2008, the Compensation Committee acting jointly with the Corporate Governance Committee recommended to the Board of Trustees a long-term incentive compensation target for Mr. Shivery at 300% of base salary, which the Board approved. The Compensation Committee established long-term incentive compensation targets at 85% to 150% of base salary for the remaining NEOs. Mr. Olivier’s long-term incentive compensation target was fixed at 125% of his base salary, which is below a target of 150% of base salary typically provided to executive officers at his level, because his compensation includes a special retirement benefit.
Restricted Share Units (RSUs)
Each RSU granted under the long-term incentive program entitles the holder to receive one NU common share at the time of vesting. All RSUs granted in 2008 will vest in equal annual installments over three years. RSU holders are eligible to receive dividend equivalents on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares. Dividend equivalents are accounted for as additional common shares that accrue and are distributed with the common shares issued upon vesting of the underlying RSUs.
General
Annually, the Compensation Committee determines RSU grants for each executive officer participating in the long-term incentive program. Initially, the target RSU grants are equal to one-half of the long-term incentive compensation target for each executive officer. RSU grants are based on a percentage of base salary and measured in dollars. The percentage used for each executive officer is based on the executive officer’s position in the company and ranges from 17.5% to 75% of salary, except for Mr. Shivery, whose percentage is set at 150%. The aggregate dollar amount of the RSU grants at target for each executive officer constitutes the target RSU Pool for that particular long-term incentive program. The Committee reserves the right to increase or decrease the target RSU Pool based on NU’s overall corporate performance during the preceding fiscal year. In its discretion, the Committee may also increase or decrease RSU grants for individual executive officers based on the contribution by the executive officer to NU’s long-term strategic direction and the Committee’s assessment of the need to motivate the executive officer’s future performance. The Compensation Committee acting jointly with the Corporate Governance Committee recommends to the Board of Trustees the final RSU grant for Mr. Shivery. Based on input from Mr. Shivery, the Compensation Committee determines the final RSU grants for each of the other executive officers, including the other NEOs. Increases or decreases to target RSU grants for the executive officers will increase or decrease their compensation as compared to the compensation of executive officers of utilities listed in the customized peer group. Increases or decreases to individual target RSU grants will also correspondingly increase or decrease the RSU Pool.
All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from dollars into NU common share equivalents by dividing the amount of each award by the average closing price for NU common shares during the last ten trading days in January in the year of the grant.
2008 RSU Grants
For 2008, the target RSU Pool totaled approximately $4.4 million, representing the sum of all RSU grants, at target, for all 27 executive officers participating in the long-term incentive program. The Committee decided to increase the target RSU Pool based on NU’s financial, operational and strategic performance during 2007. The Committee, using its judgment and experience, subjectively determined that NU’s performance in 2007 both improved NU’s strategic position and enhanced shareholder value. The Committee approved individual RSU grants for the executive officers, excluding Mr. Shivery, that totaled 113% of target. These grants were based on input from Mr. Shivery, the Committee’s subjective assessment of each executive officer’s individual performance and contribution to NU’s long-term strategic direction in 2007, and the desire to motivate each executive officer’s future p erformance. The Compensation Committee acting jointly with the Corporate Governance Committee recommended to the Board of Trustees an RSU grant for Mr. Shivery of 125% of target based on NU’s corporate performance in 2007 and the Committees’ subjective assessment of Mr. Shivery’s individual performance and contributions to NU’s long-term strategic direction in 2007. The final RSU Pool for executive officers, including Mr. Shivery, totaled approximately $5.2 million, or 117% of target. Dividing the final RSU Pool by $28.40, the average closing price for NU common shares during the last ten trading days in January 2008, resulted in an aggregate of 181,846 RSUs. The following RSU grants were approved, reflected as a percentage of target and in RSUs, based on individual performance and contributions: Mr. Shivery: 125% (68,332 RSUs); Mr. McHale: 125% (16,505 RSUs); Mr. Olivier: 125% (14,717 RSUs); Mr. Butler: 110% (11,823 RSUs); and Mr. Necci: 1 05% (4,860 RSUs).
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Share Ownership Guidelines
Effective in 2006, the Compensation Committee approved share ownership guidelines to emphasize the significance of increased share ownership by certain of NU’s executive officers. The Committee subsequently reviewed the guidelines for these executive officers and determined that they remain reasonable and require no modification.
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At the time the share ownership guidelines were implemented, the Committee required NU’s executive officers to attain these ownership levels within five years. The Committee requires all newly-elected executive officers to attain the ownership levels within seven years. All of the NEOs are currently at, or close to, these levels. Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs all satisfy the guidelines. Unexercised stock options do not count toward the ownership guidelines.
Performance Cash Program
General
The Performance Cash Program is a performance-based component of NU’s long-term incentive program. Performance cash awards are equal to one-half of total individual long-term incentive awards at target. A new three-year program commences every year. Payment under a program depends on the extent to which NU achieves goals in the four metrics described below during each year of the program, except as reduced in the discretion of the Compensation Committee. The Compensation Committee determines the actual amounts payable, if any, only after the end of the final year in the respective program.
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Cumulative Adjusted Net Income, which is consolidated NU net income adjusted by the Compensation Committee to exclude the effects of certain nonrecurring income and expense items or events (which was defined as ANI under the annual incentive program) over the three years in a program.
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Average adjusted ROE, which is the average of the annual return on equity for the three years in a program. The Committee adjusts average ROE on the same basis as cumulative adjusted net income.
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Average credit rating of NU (excluding the regulated utilities), which is the time-weighted average daily credit rating by the rating agencies Standard & Poor’s, Moody’s, and Fitch. The metric is calculated by assigning numerical values to credit ratings (A or A2: 5; A- or A3: 4; BBB+ or Baa1: 3; BBB or Baa2: 2; and BBB- or Baa3: 1) so that a high numerical value represents a high credit rating. In addition to average credit rating objectives, the ratings of NU by S&P and Moody’s must remain above investment grade.
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Relative total shareholder return of NU as compared to the return of the utility companies listed in the performance peer group identified for each Performance Cash Program.
The Committee weighs each of the four metrics equally, reflecting the Compensation Committee’s belief that these areas are critical measurements of corporate success. The Committee measures the cumulative adjusted net income, average adjusted ROE, and average credit rating, because these metrics are directly related to NU’s multi-year business plan in effect at the beginning of the three-year program. The Committee also measures relative total shareholder return to emphasize to the plan participants the importance of achieving total shareholder returns that are comparable to the returns for companies listed in the performance peer group. NU is required to achieve a minimum level of performance under each metric before any amount is payable with respect to that metric. If NU achieves the minimum level of performance, then the resulting payout will equal 50% of the target. If NU achieves the maximu m level of performance, then the resulting payout will equal 150% of target. The Committee fixed the minimum opportunity at 50% of target and the maximum opportunity at 150% of target because the Committee believes this range is consistent with the ranges used by companies listed in the performance peer group.
The performance peer groups used by the Committee for performance comparisons under each of the three Performance Cash Programs in effect during 2008 and described below consisted of a subset of the customized peer group described earlier under "Market Analysis". The performance peer group companies for each program are listed in footnote 1 accompanying each table. The performance peer groups represent companies with investment profiles, including growth potential, business models and areas of focus substantially similar to NU’s. The Committee compared NU’s total shareholder return to the total shareholder returns of the companies in the performance peer group. The customized peer group has historically been larger than the performance peer groups because NU competes for talent with more companies than those with which it competes for investment. However, beginning with the 2009 - 2011 Long-Term Incentive Program, to simplify the peer group structure, the Committee is using the full customized peer group to evaluate the total shareholder return metric. See "2009 Changes."
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2006 - 2008 Performance Cash Program
The Compensation Committee approved the 2006 - 2008 Performance Cash Program in early 2006. Upon completion of the fiscal year ended 2008, the Committee determined that NU achieved goals under each of the four metrics during the three-year program and, accordingly, that awards under the program were payable at an overall level of 138% of target.
The 2006 - 2008 program included goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2006 - 2008 program, cumulative adjusted net income and average adjusted ROE excluded the positive and negative effects of the following nonrecurring income and expense items or events: divestiture or discontinuance of a segment or component of NU’s business and net income associated with NU Enterprises.
The table set forth below describes the goals under the 2006 – 2008 program and NU’s actual results during that period:
2006 – 2008 Program Goals | ||||
Goal | Minimum | Target | Maximum | Actual Result |
Cumulative Adjusted Net Income ($ in millions) | $531.3 | $557.9 | $585.4 | $733.5 |
Average Adjusted ROE | 7.4% | 7.8% | 8.1% | 8.9% |
Average Credit Rating | 1.2 | 1.7 | 2.2 | 1.7 |
Relative Total Shareholder Return (percentile) (1) | 40th | 60th | 80th | 86th |
(1)
The performance peer group for the 2006 – 2008 program included NU and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., Consolidated Edison Inc., Energy East Corporation, KeySpan Corporation, NiSource Inc., NSTAR, NV Energy, Inc., Pinnacle West Capital Corporation, Pepco Holdings Inc., Puget Energy, Inc., SCANA Corporation, Wisconsin Energy Corporation, and Xcel Energy Inc.
Based on NU’s financial performance during the three-year performance period of the 2006 – 2008 Performance Cash Program, the Committee approved the following payments: Mr. Shivery: $1,738,800; Mr. McHale: $284,694; Mr. Olivier: $345,000; Mr. Butler: $362,388; and Mr. Necci: $161,322. The payments were determined pursuant to formulas set forth in the 2006 - 2008 Performance Cash Program and were not subject to the discretion of the Compensation Committee.
2007 - 2009 Performance Cash Program
The Committee approved the 2007 - 2009 Performance Cash Program goals in early 2007. The Committee will determine whether any amounts are payable after the end of the 2009 fiscal year, which is the final year in the three-year program.
The 2007 - 2009 program also includes goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2007 2009 program, cumulative adjusted net income and average adjusted ROE exclude the positive and negative effects of the following nonrecurring income and expense items or events: accounting or tax law changes; unusual Internal Revenue Service or regulatory issues; unexpected changes in costs related to nuclear decommissioning; unexpected changes in costs related to environmental remediation of the HWP; divestiture or discontinuance of a segment or component of NU’s business; mark-to-market impacts of agreements to which NU or any of its competitive subsidiaries are parties; unbudgeted charitable contributions; impairments on goodwill acquired before 2002 (more than five years prior to the beginning of t his program cycle); and the impact of NU’s litigation settlement with Consolidated Edison, Inc.
The table set forth below describes the goals under the 2007 - 2009 program:
2007 - 2009 Program Goals | |||
Goal | Minimum | Target | Maximum |
Cumulative Adjusted Net Income ($ in millions) | $753.2 | $836.9 | $920.6 |
Average Adjusted ROE | 8.4% | 9.2% | 10.0% |
Average Credit Rating | 1.2 | 1.7 | 2.2 |
Relative Total Shareholder Return (percentile) (1) | 40th | 60th | 80th |
(1)
The performance peer group for the 2007 - 2009 program includes NU and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., Consolidated Edison, Inc., Energy East Corporation, NiSource, Inc., NSTAR, NV Energy, Inc., Pepco Holdings, Inc., Pinnacle West Capital Corporation, Puget Energy, Inc., SCANA Corporation, Wisconsin Energy Corporation and Xcel Energy Inc.
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2008 – 2010 Performance Cash Program
The Committee approved the 2008 – 2010 Performance Cash Program goals in early 2008. The Committee will determine whether any amounts are payable after the end of the 2010 fiscal year, which is the final year in the three-year program.
The 2008 - 2010 program also includes goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2008 - 2010 program, cumulative adjusted net income and average adjusted ROE exclude the positive and negative effects of the following nonrecurring income and expense items or events: accounting or tax law changes; unusual Internal Revenue Service or regulatory issues; unexpected changes in costs related to nuclear decommissioning; unexpected changes in costs related to environmental remediation of the HWP; divestiture or discontinuance of a segment or component of NU’s business; the acquisition of shares or assets of another entity comprising an additional segment or component of NU’s business; impairments on goodwill acquired before 2003 (more than five years prior to the beginning of this program cycle); and the im pact of NU’s litigation settlement with Consolidated Edison, Inc.
The table set forth below describes the goals under the 2008 - 2010 program:
2008 – 2010 Program Goals | |||
Goal | Minimum | Target | Maximum |
Cumulative Adjusted Net Income ($ in millions) | $845.7 | $939.7 | $1,033.7 |
Average Adjusted ROE | 8.6% | 9.5% | 10.5% |
Average Credit Rating | 1.2 | 1.7 | 2.2 |
Relative Total Shareholder Return (percentile) (1) | 40th | 60th | 80th |
(1)
The performance peer group for the 2008 - 2010 program includes NU and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, Consolidated Edison, Inc., NiSource, Inc., NSTAR, NV Energy, Inc., Pepco Holdings, Inc., Pinnacle West Capital Corporation, SCANA Corporation, TECO Energy, Inc., Wisconsin Energy Corporation and Xcel Energy Inc.
2009 CHANGES
Customized Peer Group
As discussed previously under the caption "Market Analysis," to the extent practicable, year over year peer group consistency is important, because a large shift in peer company demographics can materially affect competitive compensation findings. While the Compensation Committee strives to maintain a consistent set of peer companies from year to year to avoid volatility in competitive compensation findings used for comparison across companies, the Committee modified the peer group for 2009. The modifications were necessary because the Committee changed its selection criteria. In the past, as described previously, the Committee had differentiated among utilities that were "substantially regulated" and "less regulated." This distinction proved to be unnecessary and complex because NU competes for executive talent with peer utility companies having different levels of regulated utilit y business. Therefore, the Compensation Committee decided to stop considering this criterion for the peer group beginning in 2009. However, the Committee continued to apply the size criterion (revenue between $3 billion and $13 billion). As a result, the new peer group includes the addition of two new peer utility companies, Integrys Energy Group Inc. and DTE Energy Company, and the removal of two companies, PPL Corporation and PG&E Corporation. The Committee also removed two additional companies, Puget Energy, Inc. and Energy East Corporation, due to pending or finalized acquisitions.
Furthermore, in an effort to simplify the peer group structure, beginning in 2009, the Committee is using the same customized peer group for both market analysis and performance comparisons.
The Committee’s review of these minor changes to the customized peer group indicates that it would not have materially affected the historical results of the market analyses or the results of the Performance Cash component of the long-term incentive programs.
2009 - 2011 Long-Term Incentive Program
In 2009, the Compensation Committee changed the components of the long-term incentive program to strengthen the connection between compensation and performance. For the 2009 - 2011 Long-Term Incentive Program, the grant value at target consisted of 25% RSUs, 25% performance shares, and 50% performance cash. Performance shares are performance units denominated in NU common shares that replace half of the targeted RSU grant from previous programs. Like performance cash, performance shares will be distributed only at the end of the three-year performance period, and the actual number of shares will vary from target based on performance against the same four equally-weighted corporate goals. No shares will be distributed if none of the goals is met.
Prior to 2009, in the event of a change of control, NU’s long-term incentive programs provided for the vesting, pro rata based on the number of days of employment during the performance period, and payment of performance cash at target, whether or not the executive’s employment terminated, unless the Committee determined otherwise. Commencing with the 2009 - 2011 Long-Term
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Incentive Program, in the event of a change of control after which an executive’s employment does not terminate, actual performance share awards and performance cash awards will be determined based on the measurement of the four metrics up to the effective date of the change of control. In such event, actual awards will be reduced pro rata based on the number of days from program commencement until the effective date of the change of control. Awards will continue to be distributed only at the end of the three-year program period. However, if the executive’s employment terminates within 24 months following the change of control, but before the end of the three-year performance period, then the executive will receive the full award, payable immediately, as if performance had been at target.
SUPPLEMENTAL BENEFITS
NU provides a variety of basic and supplemental benefits designed to assist it in attracting and retaining executive officers critical to NU’s success by reflecting competitive practices. The Compensation Committee endeavors to adhere to a high level of propriety in managing executive benefits and perquisites. NU does not provide permanent lodging or personal entertainment for any executive officer or employee, and the executive officers are eligible to participate in substantially the same health care and benefit programs available to all employees.
RETIREMENT BENEFITS
NU provides retirement income benefits for employees, including executive officers, who commenced employment before 2006 under the Northeast Utilities Service Company Retirement Plan (Retirement Plan) and, for officers, under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (Supplemental Plan). Each plan is a defined benefit pension plan, which determines retirement benefits based on years of service, age at retirement, and "plan compensation." Plan compensation for the Retirement Plan, which is a qualified plan under the Internal Revenue Code, includes primarily base pay and nonofficer annual incentives up to the Internal Revenue Code limits for qualified plans. Beginning in 2006, newly-hired nonunion employees, including executive officers, participate in an enhanced defined contribution retirement program in the Northeast Utilities Service Company 401k Plan (401k P lan), called the K-Vantage benefit, instead of participating in the Retirement Plan. Employees hired before 2006 continue to participate in the Retirement Plan, except for those who elected to participate in the K-Vantage benefit.
The Supplemental Plan adds to plan compensation: base pay over the Internal Revenue Code limits; deferred base salary; annual executive incentive program awards; and, for certain participants, long-term incentive program awards, as explained in the narrative accompanying the Pension Benefits Table.
The Supplemental Plan consists of two parts. The first part, called the make-whole benefit, compensates for benefits lost due to Internal Revenue Code limitations on benefits provided under the Retirement Plan. The second part, called the target benefit, is available to all NEOs except Mr. Olivier and Mr. Necci. The target benefit supplements the Retirement Plan and make-whole benefit under the Supplemental Plan so that, upon attaining at least 25 years of service, total retirement benefits from these plans will equal a target percentage of the final average compensation. To receive the target benefit, a participant must remain employed by NU or its subsidiaries at least for five years and until age 60, unless the Board of Trustees establishes a lower age.
The value of the target benefit was reduced in 2005 to reflect changes in competitive practices, which indicated general reductions in the prevalence of defined benefit plans and the value of special retirement benefits to senior executives. Individuals who began serving as officers before February 2005 are eligible to receive a target benefit with the target percentage fixed at 60%. Individuals who began serving as officers from and after February 2005 are eligible to receive a target benefit with the target percentage fixed at 50%. As a result, Messrs. Shivery and Butler have target benefits at 60% while Mr. McHale has a target benefit at 50%.
Mr. Shivery’s employment agreement provides for a special total retirement benefit determined using the Supplemental Plan target benefit formula plus three additional years of company service. This benefit will be reduced by two percent per year for each year Mr. Shivery retires before age 65. Upon retirement, Mr. Shivery will be eligible to receive retirement health benefits. In addition, the Named Executive Officers are eligible to receive certain health and welfare benefits upon termination of employment following a change of control or, for Messrs. Shivery, Olivier, McHale and Butler, an involuntary termination of employment. To the extent such benefits may not be provided through NU’s tax qualified plans, the executive is entitled to participate in a non-qualified health plan that will be treated as taxable compensation to the executive officer to the extent of company contributions and will be provided with a tax gross-up so that the value to the executive is equivalent to a tax qualified plan benefit. See the Pension Benefits Table and the accompanying narrative for more details of these arrangements.
NU entered into an employment agreement with Mr. Olivier that includes retirement benefits similar to the benefits provided by his previous employer. Accordingly, Mr. Olivier is entitled to receive separate retirement benefits in lieu of the Supplemental Plan benefits described above. Pursuant to his agreement, Mr. Olivier will receive a targeted pension value if he meets certain eligibility requirements. See the Pension Benefits Table and the accompanying narrative for more details of this arrangement. As discussed under the caption "Mix of Compensation Elements" above, Mr. Olivier’s long-term incentive plan targets and termination benefits are less than those provided to other similarly situated officers because of these separate retirement benefits. Mr. Necci’s offer of employment provided for an extra nine months of service in calculating his pension benefits.
401K PLAN
NU provides an opportunity for employees to save money for retirement on a tax-favored basis through the 401k Plan. The 401k Plan is a defined contribution qualified plan under the Internal Revenue Code and contains a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code. Participants with at least six months of service receive employer matching contributions, not to
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exceed 3% of base compensation, one-third of which are in cash available for investment in various mutual fund alternatives and two-thirds of which are in the form of NU common shares (ESOP shares).
The K-Vantage benefit provides for employer contributions to the 401k Plan in amounts between 2.5% and 6.5% of plan compensation based on an eligible employee’s age and years of service. These contributions are in addition to employer matching contributions. Executive officers hired beginning in 2006 also participate in a companion nonqualified K-Vantage benefit in the Nonqualified Deferred Compensation Plan (Deferral Plan) that provides defined contribution benefits above Internal Revenue Code limits on qualified plans.
NONQUALIFIED DEFERRED COMPENSATION PLAN
NU’s executive officers participate in the Deferral Plan to provide additional retirement benefits not available in the 401k Plan because of Internal Revenue Code limits on qualified plans. Under the Deferral Plan, executive officers are entitled to defer up to 100% of base salary and annual incentive awards. NU matches officer deferrals in an amount equal to 3% of the amount of base salary above Internal Revenue Code limits on qualified plans. The matching contribution is deemed to be invested in common shares and vests at the end of the third year after the calendar year in which the matching contribution was earned, or at retirement, whichever occurs first. Participants are entitled to select deemed investments for all deferred amounts from the same investments available in the 401k Plan, except for investments in NU common shares. NU also credits the Deferral Plan in amounts equal to the K-Vantage benef it that would have been provided under the 401k Plan but for Internal Revenue Code limits on qualified plans. This nonqualified plan is unfunded. Please see the Nonqualified Deferred Compensation Table and the accompanying notes for additional plan details.
PERQUISITES
It is NU’s philosophy that perquisites should be provided to executive officers only as needed for business reasons, and not simply in reaction to prevalent market practices.
The NEOs (except for Mr. Necci), are eligible to receive reimbursement for financial planning and tax preparation services. This benefit is intended to help ensure that executive officers seek competent tax advice, properly prepare complex tax returns, and leverage the value of NU’s compensation programs. Reimbursement is limited to $4,000 every two years for financial planning services and $1,500 per year for tax preparation services.
All executive officers receive a special annual physical examination benefit to help ensure serious health issues are detected early. The benefit is limited to the reimbursement of up to $800 for fees incurred beyond those covered by NU’s medical plan.
When hiring a new executive officer, NU sometimes reimburses executive officers for certain temporary living and relocation expenses, or provides a lump sum payment in lieu of specific reimbursement. These expenses are grossed-up for income taxes attributable to such reimbursements so that relocation is cost neutral to the executive officer.
When required for a valid business purpose, an executive officer may be accompanied by his or her spouse, in which case NU will reimburse the executive officer for all spousal travel expenses In 2008, tax gross-ups were provided for spousal travel expense reimbursement because of the corporate benefit to NU when executive officers incurred such expenses. The aggregate amount of the tax gross-ups was well below prevalent market practices and the impact of them was not material to NU. Commencing in 2009, NU will no longer pay gross-ups for taxes on any perquisites other than for taxes on reimbursement of relocation expenses for newly-hired or transferred executives.
CONTRACTUAL AGREEMENTS
NU has entered into employment agreements with certain executive officers, including Messrs. Shivery, McHale, Olivier and Butler. The agreements specify compensation and benefits during the employment term and include benefits payable upon involuntary termination of employment and termination of employment following a change of control. These termination and change of control benefits were in prevalent practice at the time the agreements were signed and were necessary to attract and retain competent and capable executive talent. NU continues to believe that these benefits help to ensure the executive officers’ dedication and objectivity at a time when they might otherwise be concerned about their future employment.
In the event of a change of control, the agreements with Messrs. Shivery, McHale and Butler provide for enhanced cash severance benefits following termination of employment without "cause" (as defined in the employment agreement, generally involving a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to NU’s property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement) or upon termination of employment by the executive for "good reason" (as defined in the employment agreement, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control). Th e Compensation Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. Mr. Olivier’s employment agreement does not provide for severance payments in the event that his employment terminates following a change of control. Mr. Olivier and Mr. Necci participate instead in the Special Severance Program.
As defined in the employment agreements with Messrs. Shivery, McHale and Butler, a "change of control" means a change in ownership or control of NU effected through (i) the acquisition of 20% or more of the combined voting power of NU common shares or other voting securities, (ii) a change in the majority of NU’s Board of Trustees over a 24-month period, unless approved by a majority
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of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50% of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than to an entity with respect to which following completion of the transaction more than 50% of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.
Pursuant to the change of control provisions in the employment agreements, each NEO except for Mr. Olivier and Mr. Necci will be reimbursed for the full amount of any excise taxes imposed on severance payments and any other payments under Section 4999 of the Internal Revenue Code. This "gross-up" is intended to preserve the aggregate amount of the severance payments by compensating the executive officers for any adverse tax consequences to which they may become subject under the Internal Revenue Code. Mr. Olivier’s and Mr. Necci’s severance payments may be reduced to avoid excise taxes.
We describe and explain how the appropriate payment and benefit levels are determined under the various circumstances that trigger payments or provision of benefits in the tables and accompanying footnotes appearing in the section captioned "Potential Payments Upon Termination or Change of Control," below.
To help protect NU after the termination of an executive officer’s employment, the employment agreements include non-competition and non-solicitation covenants pursuant to which the executive officers have agreed not to compete with NU or solicit NU’s employees for a period of two years (one year for Mr. Olivier and Mr. Necci) after termination of employment.
In the event of termination of employment without "cause" or upon termination of employment by an NEO for good reason, in each case following a change of control, the expiration date of all vested unexercised stock options held by the NEOs will be extended automatically for up to an additional 36 months, but not beyond the original expiration date, to provide these holders with an opportunity to benefit from increased shareholder value created by the change of control. Also, in the event of a change of control, the long-term incentive programs provide for the vesting, pro rata based on the number of days of employment during the performance period, and payment at target of performance cash, whether or not the executive’s employment terminates, unless the Committee determines otherwise.
Finally, in the event of a change of control, the Deferral Plan provides for the immediate vesting of any employer matches, although these matches will be paid according to the schedule defined by the executive’s original election.
As discussed under the caption "Supplemental Benefits" above, NU’s employment agreements with Messrs. Shivery and Olivier also include additional retirement benefits payable upon voluntary termination of employment.
TAX AND ACCOUNTING CONSIDERATIONS
Tax Considerations. All executive compensation for 2008 was fully deductible by NU for federal income tax purposes, except for approximately $330,000 paid to Mr. Shivery, consisting of restricted share and RSU distributions of approximately $280,000 and salary and reimbursements of approximately $50,000.
Section 162(m) of the Internal Revenue Code limits the tax deduction for compensation paid to a company’s CEO and certain other executives. NU is entitled to deduct compensation payments above $1 million as compensation expense only to the extent that these payments are "performance based" in accordance with Section 162(m) of the Internal Revenue Code. NU’s annual incentive program and performance cash program qualify as performance-based compensation under the Internal Revenue Code. As required by Section 162(m), the Compensation Committee reports to the Board of Trustees annually the extent to which various performance goals have been achieved. RSUs do not qualify as performance-based compensation.
Currently, Mr. Shivery is the only NEO to exceed the Section 162(m) limit. To preserve an employee compensation tax deduction for NU, Mr. Shivery agreed, for as long as it is beneficial to NU, to defer the distribution to him of common shares in respect of all vested RSUs, until the calendar year after he leaves the Company, at which time Section 162(m) will no longer apply to him. The non-deductible restricted share and RSU distributions for Mr. Shivery in 2008 described above relate to restricted share and RSU awards granted before Mr. Shivery was elected as NU’s Chief Executive Officer.
Section 409A of the Internal Revenue Code provides that amounts deferred under nonqualified deferred compensation plans are includable in an employee’s income when vested unless certain requirements are met. If these requirements are not met, employees are also subject to additional income tax and interest penalties. All of NU’s supplemental retirement plans, executive employment agreements, severance arrangements, and other nonqualified deferred compensation plans were amended in 2008 to satisfy the requirements of Section 409A.
Section 280G of the Internal Revenue Code disallows a tax deduction for "excess parachute payments" in connection with the termination of employment related to a change of control (as defined in the Internal Revenue Code), and Section 4999 of the Internal Revenue Code imposes a 20% excise tax on any person who receives excess parachute payments. As discussed above, the NEOs are entitled to receive certain payments upon termination of their employment, including termination following a change of control. Under the terms of the agreements, all NEOs except Mr. Olivier and Mr. Necci are entitled to receive tax gross-ups for any payments that constitute an excess parachute payment. Accordingly, NU’s tax deduction would be disallowed under Section 280G for all excess parachute payments as well as tax gross-ups. Not all of the payments to which NEOs are entitled are excess parachute payments.
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The amounts of the payments that constitute excess parachute payments are set forth in the tables found under the caption "Potential Payments upon Termination or Change of Control", below.
In the event of a change of control in which NU is not the surviving entity, RSU awards granted to executive officers provide that the acquirer will assume or replace the awards, even if the executive remains employed after the change of control.
Accounting Considerations. RSUs disclosed in the Grants of Plan-Based Awards Table are accounted for based on their grant date fair value, as determined under Statement of Financial Accounting Standards No. 123(R), which is recognized over the service period, or the three-year vesting period applicable to the RSUs. Assumptions used in the calculation of this amount appear in "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K. Forfeitures are estimated, and the compensation cost of the awards will be reversed if the employee does not remain employed by NU throughout the three-year vesting period. Performance cash program payments are accounted for on a variable basis based on the most likely payment outcome.
SUMMARY COMPENSATION TABLE
The table below summarizes the total compensation paid or earned by Mr. Olivier, CL&P’s Chief Executive Officer (CEO), Mr. McHale, CL&P’s Executive Vice President and Chief Financial Officer (CFO), and the three other most highly compensated executive officers, other than the CEO and CFO, who were serving as executive officers at the end of 2008, including Mr. Shivery, NU’s Chairman, President and Chief Executive Officer (collectively, the Named Executive Officers or NEOs). As explained in the footnotes below, the amounts reflect the economic benefit to each Named Executive Officer of the compensation item paid or accrued on his or her behalf for the fiscal year ended December 31, 2008. The compensation shown for each Named Executive Officer was for all services in all capacities to NU and its subsidiaries. All salaries, annual incentive amounts and long-term incentive amounts shown for each Named Exec utive Officer were paid for all services rendered to NU and its subsidiaries in all capacities.
Name and | Year | Salary | Bonus | Stock |
| Non-Equity Incentive Plan Compensation | Change in | All Other | Total ($) | |
Charles W. Shivery | 2008 | 1,067,404 | ― | 2,106,065 | ― | 3,257,929 | 1,627,493 | 35,397 | 8,094,288 | |
Chairman of CL&P; Chairman of the Board, President and Chief Executive Officer of NU | 2007 | 987,308 | ― | 1,779,313 | ― | 3,048,360 | 1,326,931 | 49,026 | 7,190,938 | |
2006 | 918,846 | ― | 1,061,205 | ― | 1,698,395 | 1,274,011 | 40,691 |
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David R. McHale | 2008 | 508,654 | ― | 406,677 | ― | 750,214 | 514,753 | 9,907 | 2,190,205 | |
Executive Vice President and Chief Financial Officer (8) | 2007 | 434,135 | ― | 296,891 | ― | 755,810 | 614,481 | 7,603 |
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2006 | 353,847 | ― | 148,512 | ― | 395,693 | 413,275 | 6,600 |
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Leon J. Olivier | 2008 | 550,962 | ― | 399,123 | ― | 839,571 | 324,854 | 18,997 | 2,133,507 | |
Chief Executive Officer of CL&P; Executive Vice President and Chief Operating Officer | 2007 | 462,096 | ― | 306,115 | ― | 777,226 | 251,556 | 15,042 |
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2006 | 411,039 | ― | 178,951 | ― | 451,419 | 275,264 | 13,692 |
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Gregory B. Butler | 2008 | 418,542 | ― | 354,393 | ― | 723,674 | 206,850 | 8,207 | 1,711,666 | |
Senior Vice President and General Counsel | 2007 | 382,244 | ― | 319,716 | ― | 731,950 | 195,321 | 12,941 |
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2006 | 359,659 | ― | 218,078 | ― | 383,279 | 215,642 | 7,077 |
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Raymond P. Necci | 2008 | 319,000 | ― | 149,395 | ― | 335,129 | 224,438 | 9,922 | 1,037,884 | |
President and Chief Operating Officer | 2007 | 295,846 | ― | 129,195 | ― | 346,850 | 309,856 | 9,299 | 1,091,046 | |
2006 | 282,589 | ― | 103,307 | ― | 200,229 | 191,963 | 8,898 | 786,986 |
(1)
Includes amounts deferred in 2008 by the Named Executive Officers under the Deferral Plan, as follows: Mr. Shivery: $32,022; Mr. Olivier: $137,741; and Mr. Necci: $63,800. For more information, see the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.
We pay each of our salaried employees, including each of the Named Executive Officers, 1/26th of their annual base salary every two weeks. This bi-weekly pay schedule typically results in one extra pay date per year approximately once every twelve years. Accordingly, the amounts reported for Salary for each Named Executive Officer in 2008 reflect 27 pay dates, as compared to 26 pay dates in each of 2007 and 2006.
(2)
No discretionary bonus awards were made to any of the Named Executive Officers in the fiscal years ended 2006, 2007 and 2008.
(3)
Reflects the dollar amounts recognized for financial statement reporting purposes for the fiscal year ended December 31, 2008, in accordance with the treatment of time-based RSU and restricted share grants under generally accepted accounting
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principles. The amounts reflect the accounting expense of shares granted in and prior to 2008. Assumptions used in the calculation of this amount appear in the "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K.
In 2005, 2006, 2007 and 2008, the Named Executive Officers were granted RSUs that vest in equal annual installments over three years as long-term incentive compensation. NU defers the distribution of common shares upon vesting of RSUs granted to Mr. Shivery, until the calendar year after he leaves the Company. RSU holders are eligible to receive dividend equivalents on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU’s common shares. Dividend equivalents are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.
In 2004, the Named Executive Officers were granted RSUs that vest in equal annual installments over four years as long-term incentive compensation. Pursuant to the long-term incentive programs approved in 2007, subject to the officer’s election in December 2007 to continue the automatic four-year deferral of one-half of RSUs as they vest under the 2004 program, NU distributes common shares with respect to RSUs upon vesting. In addition, upon his appointment as NU’s Chairman, President and CEO in 2004, Mr. Shivery was granted 25,000 restricted shares that vested in equal annual installments over four years. NU paid dividends on these restricted shares during the vesting period to the same extent that dividends are declared and paid on NU’s common shares.
(4)
NU has not granted any stock options since 2002. Accordingly, NU did not grant stock options to any of the Named Executive Officers in 2008.
(5)
Includes payments to the Named Executive Officers under the 2008 Annual Incentive Program (Mr. Shivery: $1,519,129; Mr. McHale: $465,520; Mr. Olivier: $494,571; Mr. Butler: $361,286; and Mr. Necci: $173,807). Also includes payments under the 2006 - 2008 Long-Term Incentive Program (Mr. Shivery: $1,738,800; Mr. McHale: $284,694; Mr. Olivier: $345,000; Mr. Butler: $362,388; and Mr. Necci: $161,322). Performance goals under the 2008 Annual Incentive Program were communicated to each officer by Mr. Shivery or, in the case of Mr. Shivery, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2008. The Compensation Committee acting jointly with the Corporate Governance Committee determined the extent to which these goals were satisfied (based on input from Mr. Shivery, in the case of the other Named Executive Off icers) in February 2009. Performance goals under the 2006 - 2008 Long-Term Incentive Program were communicated to each officer by Mr. Shivery or, in the case of Mr. Shivery, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2006. The Compensation Committee determined the extent to which the long-term goals were satisfied in February 2009.
(6)
Includes the actuarial increase in the present value from December 31, 2007 to December 31, 2008 of the Named Executive Officer’s accumulated benefits under all of NU’s defined benefit pension plans determined using interest rate and mortality rate assumptions consistent with those appearing in the "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K. The Named Executive Officer may not be fully vested in such amounts. More information on this topic is set forth in the notes to the Pension Benefits table, appearing further below. There were no above-market earnings on deferrals in 2008.
(7)
Includes matching contributions of $6,900 allocated by NU to the account of each of the Named Executive Officers under the 401k Plan and employer matching contributions under the Deferral Plan for the Named Executive Officers who deferred part of their salary in the fiscal year ended December 31, 2008 (Mr. Shivery: $25,122; Mr. Olivier: $9,629; and Mr. Necci: $2,670), plus tax gross-ups for wireless handheld and cell phone fees (Mr. Shivery: $707; Mr. McHale: $717; Mr. Olivier: $977; Mr. Butler: $977 and Mr. Necci: $352); and tax gross-ups for spousal travel expenses (Mr. Shivery: $2,669; Mr. McHale: $2,290; Mr. Olivier: $1,491; and Mr. Butler: $329). Mr. McHale and Mr. Butler did not participate in the Deferred Compensation Plan.
(8)
Mr. McHale was elected Executive Vice President and Chief Financial Officer of CL&P and NU effective January 1, 2009. He served as Senior Vice President and Chief Financial Officer of CL&P and NU from January 1, 2005 until January 1, 2009.
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GRANTS OF PLAN-BASED AWARDS DURING 2008
The Grants of Plan-Based Awards Table provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, 2008. The table also discloses the underlying stock awards and the grant date for equity-based awards. NU has not granted any stock options since 2002. Accordingly, NU did not grant stock options to any of the Named Executive Officers in 2008.
Name | Grant | Estimated Future Payouts Under | All Other | Grant Date | |||
Threshold ($) | Target ($) | Maximum ($) | |||||
Charles W. Shivery |
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Annual Incentive (1) | 533,702 | 1,067,404 | 2,134,808 | ― | ― | ||
Long-Term Incentive (2) | 2/12/2008 | 776,250 | 1,552,500 | 2,328,750 | 68,332 | 1,891,430 | |
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David R. McHale |
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Annual Incentive (1) | 2/12/2008 | 165,313 | 330,625 | 661,250 | ― | ― | |
Long-Term Incentive (2) | 2/12/2008 | 187,500 | 375,000 | 562,500 | 16,505 | 456,858 | |
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Leon J. Olivier |
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Annual Incentive (1) | 2/12/2008 | 179,063 | 358,125 | 716,250 | ― | ― | |
Long-Term Incentive (2) | 2/12/2008 | 167,187 | 334,375 | 501,562 | 14,717 | 407,367 | |
|
|
|
|
|
|
| |
Gregory B. Butler |
|
|
|
|
|
| |
Annual Incentive (1) | 2/12/2008 | 136,026 | 272,052 | 544,104 | ― | ― | |
Long-Term Incentive (2) | 2/12/2008 | 152,621 | 305,241 | 457,862 | 11,823 | 327,261 | |
|
|
|
|
|
|
| |
Raymond P. Necci |
|
|
|
|
|
| |
Annual Incentive (1) | 2/12/2008 | 79,750 | 159,500 | 319,000 | ― | ― | |
Long-Term Incentive (2) | 2/12/2008 | 65,730 | 131,459 | 197,189 | 4,860 | 134,525 |
(1)
Amounts reflect the range of potential payouts, if any, under the 2008 Annual Incentive Program for each Named Executive Officer, as described in the Compensation Discussion and Analysis. The payment in 2009 for performance in 2008 is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. The threshold payment under the Annual Incentive Program is 50% of target. However, based on Adjusted Net Income and individual performance, the actual payment under the Annual Incentive Program could be zero.
(2)
Reflects the range of potential payouts, if any, pursuant to performance cash awards under the 2008 - 2010 Long-Term Incentive Program, as described in the Compensation Discussion and Analysis. Grants of three-year performance cash awards were made to officers during 2008 under the 2008 - 2010 Long-Term Incentive Program. Performance cash will be fully vested at the end of the performance period and paid to the officer in cash during the first fiscal quarter after the end of the performance period.
(3)
Reflects the number of RSUs granted to each of the Named Executive Officers on February 12, 2008 under the 2008 - 2010 Long-Term Incentive Program. The RSUs will vest in equal installments on February 25, 2010, 2011 and 2012. Except for Mr. Shivery, NU will distribute common shares in respect to vested RSUs on a one-for-one basis immediately upon vesting, after reduction for applicable withholding taxes. For Mr. Shivery, NU will distribute common shares, after reduction for applicable withholding taxes, in respect to vested RSUs in three approximately equal annual installments beginning the later of (i) six months after he leaves the company and (ii) January of the calendar year after he leaves the company. RSU holders are eligible to receive dividend equivalents on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU 46;s common shares. Dividend equivalents are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs. The Annual Incentive Program does not include an equity component.
(4)
Reflects the grant-date fair value of RSUs granted to the Named Executive Officers on February 12, 2008, under the 2008 – 2010 Long-Term Incentive Program determined pursuant to generally accepted accounting principles. The Annual Incentive Program does not include an equity component.
99
EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2008
The following table sets forth option and RSU grants outstanding at the end of our fiscal year ended December 31, 2008 for each of the Named Executive Officers. All outstanding options were fully vested as of December 31, 2008.
| Option Awards (1) | Stock Awards (2) | |||
Name | Number of | Option | Option | Number of | Market Value of |
Charles W. Shivery | 29,024 | 18.90 | 6/11/2012 | 166,827 | 4,013,868 |
David R. McHale | ― | ― | ― | 34,771 | 836,587 |
Leon J. Olivier | ― | ― | ― | 31,217 | 751,071 |
Gregory B. Butler | ― | ― | ― | 26,724 | 642,985 |
Raymond P. Necci | ― | ― | ― | 10,748 | 258,596 |
(1)
NU has not granted stock options since 2002.
(2)
Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.
(3)
An aggregate of 137,653 unvested RSUs vested on February 25, 2009 (Mr. Shivery: 86,056; Mr. McHale: 16,902; Mr. Olivier: 15,361; Mr. Butler: 13,728; and Mr. Necci: 5,606). An additional 92,590 unvested RSUs will vest on February 25, 2010 (Mr. Shivery: 57,230; Mr. McHale: 12,183; Mr. Olivier: 10,785; Mr. Butler: 8,923; and Mr. Necci: 3,467). An additional 40,044 unvested RSUs will vest on February 25, 2011 (Mr. Shivery: 23,541; Mr. McHale: 5,686; Mr. Olivier: 5,070; Mr. Butler: 4,073 and Mr. Necci: 1,674).
(4)
The market value of RSUs is determined by multiplying the number of share units by $24.06, the closing price per share of NU common shares on December 31, 2008, the last trading day of the fiscal year.
OPTIONS EXERCISED AND STOCK VESTED IN 2008
The following table reports amounts realized on equity compensation during the fiscal year ended December 31, 2008. None of the Named Executive Officers exercised options in 2008. The Stock Awards columns report the vesting of restricted share grants and RSU grants to the Named Executive Officers in February 2008.
| Option Awards | Stock Awards | ||
Name | Number of | Value | Number of | Value |
Charles W. Shivery | ― | ― | 87,901 | 2,383,885 |
David R. McHale | ― | ― | 14,483 | 392,774 |
Leon J. Olivier | ― | ― | 15,281 | 414,423 |
Gregory B. Butler | ― | ― | 16,334 | 442,970 |
Raymond P. Necci | ― | ― | 6,581 | 178,488 |
(1)
Represents the amounts realized upon option exercises, which is the difference between the option exercise price and the market price at the time of exercise.
(2)
Includes 6,250 restricted shares granted to Mr. Shivery upon his appointment as NU’s Chairman, President and CEO in 2004, for which restrictions lapsed in 2008.
Also includes awards granted to our Named Executive Officers under NU’s long-term incentive programs, including dividend reinvestments, as follows:
100
Name | 2004 | 2005 | 2006 | 2007 |
Charles W. Shivery | 5,896 | 15,266 | 27,892 | 32,597 |
David R. McHale | 1,032 | 2,599 | 4,565 | 6,286 |
Leon J. Olivier | 1,204 | 4,119 | 4,427 | 5,530 |
Gregory B. Butler | 3,689 | 3,304 | 4,648 | 4,693 |
Raymond P. Necci | 1,026 | 1,751 | 2,070 | 1,735 |
In all cases, NU reduces the distribution of common shares by that number of shares valued in an amount sufficient to satisfy tax withholding obligations, which amount NU distributes in cash. Included in the value realized are values associated with deferred RSUs, which are also reported in the Registrant Contributions in Last Fiscal Year column of the Non-Qualified Deferred Compensation Table.
(3)
Value realized is based on $27.12 per share, the closing price of NU common shares on February 22, 2008. This value includes the value of vested RSUs for which the distribution of common shares is currently deferred.
PENSION BENEFITS IN 2008
The Pension Benefits Table sets forth the estimated present value of accumulated retirement benefits that would be payable to each Named Executive Officer upon his or her retirement as of the first date upon which he or she is eligible to receive an unreduced pension benefit (see below). The table distinguishes the benefits among those available through the Retirement Plan, the Supplemental Plan and any additional benefits available under the respective officer’s employment agreement. The Supplemental Plan provides a make whole benefit that is based in part on compensation that is not permitted to be recognized under a tax-qualified plan and provides a target benefit if the eligible officer continues his or her employment until age 60. Benefits under the Supplemental Plan are also based on elements of compensation that are not included under the Retirement Plan. This includes compensation equal to: (i) deferred compensa tion; (ii) the value of awards under the Annual Incentive Program for officers; and (iii) long-term incentive awards only for Messrs. McHale, Butler, and Necci (as to each of their respective make whole benefits), the values of which are frozen at the 2001 target levels.
The present value of accumulated benefits shown in the Pension Benefits Table was calculated as of December 31, 2008 assuming benefits would be paid in the form of a 50 percent spousal contingent annuitant option (the typical form of payment for the target benefit). For Mr. Olivier, who has a special retirement arrangement, we assumed that his special retirement benefit would be paid as a lump sum, and his Retirement Plan benefit would be paid in the form of a life annuity with a one-third spousal contingent annuitant option (the typical form of payment under the Retirement Plan). For Mr. Necci, we assumed all benefits would be paid in the form of a life annuity with a one-third percent spousal contingent annuitant option (the typical form of payment under the Retirement Plan). None of Mr. Olivier’s benefits will be provided under the Supplemental Plan. In addition, the present value of accrued benefits f or any Named Executive Officer assumes that benefits commence at the earliest age at which the participant would be eligible to retire and receive unreduced benefits. Named Executive Officers are eligible to receive unreduced benefits upon the earlier of (a) attainment of age 65 or (b) attainment of at least age 55 when age plus service equals 85 or more years, except for Mr. Olivier. Mr. Olivier’s unreduced benefit is available at age 60 pursuant to his employment agreement. The target benefit is available for Messrs. Butler and McHale only after age 60. Accordingly, Mr. Shivery is eligible to receive unreduced benefits at age 65, Messrs. McHale and Olivier are eligible to receive unreduced benefits at age 60, Mr. Butler is eligible to receive unreduced benefits at age 62, and Mr. Necci is eligible to receive unreduced benefits immediately.
The limitations applicable to the Retirement Plan under the Internal Revenue Code as of December 31, 2008 were used to determine the benefits under each plan. The accrued benefits reflect actual compensation (both salary and incentives) earned during 2008. Under the terms of the Supplemental Plan, annual incentives earned for services provided in a plan year are deemed to have been paid ratably over that plan year. For example, the March 2009 payment pursuant to the 2008 annual incentive program was reflected in the 2008 plan compensation. NU determined the present value of the benefit at retirement age by using the discount rate of 6.89% under Statement of Financial Accounting Standards No. 87 for the 2008 fiscal year end measurement (as of December 31, 2008). This present value assumes no pre-retirement mortality, turnover or disability. However, for the postretirement period beginning at the r etirement age, NU used the RP2000 Combined Healthy mortality table as published by the Society of Actuaries projected to 2009 with projection scale AA (same table used for financial reporting under FAS 87). Additional assumptions appear in the "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K.
101
Pension Benefits
Name | Plan Name | Number of | Present Value | Payments |
Charles W. Shivery (1) | Qualified Plan | 6.6 | 198,961 | ― |
Supplemental Plan | 6.6 | 3,887,754 | ― | |
Other Special Benefit | 9.6 | 1,862,537 | ― | |
David R. McHale | Qualified Plan | 27.3 | 421,008 | ― |
Supplemental Plan | 27.3 | 1,879,764 | ― | |
Leon J. Olivier (2) | Qualified Plan | 9.8 | 312,554 | ― |
Supplemental Plan | 7.3 | ― | ― | |
Other Special Benefit | 7.3 | 1,737,456 | ― | |
Other Special Benefit | 31.3 | 1,205,507 | 105,966 | |
Gregory B. Butler | Qualified Plan | 12.0 | 199,430 | ― |
Supplemental Plan | 12.0 | 1,001,261 | ― | |
Raymond P. Necci (3) | Qualified Plan | 31.6 | 1,186,345 | ― |
Supplemental Plan | 31.6 | 1,478,386 | ― | |
| Other Special Benefit | 32.3 | 63,831 | ― |
(1)
Mr. Shivery’s actual service with us totaled 6.6 years at December 31, 2008. However, Mr. Shivery’s employment agreement provides for a special retirement benefit consisting of an amount equal to the difference between: (i) the equivalent of fully-vested benefits under the Retirement Plan and the Supplemental Plan calculated by adding three years to his actual service and using an early retirement commencement reduction factor of two percent per year for each year Mr. Shivery’s age upon retirement is under age 65, if that factor yields a more favorable result to Mr. Shivery than the factors then in use under the Retirement Plan, and (ii) benefits otherwise payable from the Retirement Plan and the Supplemental Plan. The value of the additional three years of service on December 31, 2008 was approximately $1,862,537.
(2)
Mr. Olivier was employed with Northeast Nuclear Energy Company, one of NU’s subsidiaries, from October of 1998 through March of 2001. In connection with this employment, he received a special retirement benefit that provided credit for service with his previous employer, Boston Edison Company (BECO), when calculating the value of his defined benefit pension, offset by the pension benefit provided by BECO. The benefit, which commenced upon Mr. Olivier’s 55th birthday, provides an annuity of $105,966 per year in a form that provides no contingent annuitant benefit. The present value of future payments under this benefit was calculated using the actuarial assumptions currently used by the Retirement Plan. Mr. Olivier was rehired by NU from Entergy in September 2001. Mr. Olivier’s current employment agreement provides for certain supplemental pension benefi ts in lieu of benefits under the Supplemental Plan, in order to provide a benefit similar to that provided by Entergy. Under this arrangement, if Mr. Olivier remains continuously employed by us until September 10, 2011 (or terminates his employment earlier with our consent), he will be eligible to receive a special benefit, subject to reduction for termination prior to age 65, consisting of three percent of final average compensation for each of his first 15 years of service since September 10, 2001, plus one percent of final average compensation for each of the second 15 years of service. Alternatively, if Mr. Olivier voluntarily terminates his employment with NU after his 60th birthday, or NU terminates his employment earlier for any reason other than "cause" (as defined in his employment agreement, generally meaning willful and continued failure to perform his duties after written notice, a violation of our Standards of Business Conduct or conviction of a felony) he is eligible to receive upon retirement a lump sum payment of $2,050,000 in lieu of benefits under the Supplemental Plan and the benefit described in the preceding sentence. These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan. Because Mr. Olivier attained age 60 during 2008, amounts reported in the table assume the termination of his employment on December 31, 2008, and payment of the lump sum benefit of $2,050,000, offset by Retirement Plan benefits.
(3)
Mr. Necci’s offer of employment provides for a special retirement benefit that recognizes an additional nine months of service, the value of which on December 31, 2008 was approximately $63,831.
102
NONQUALIFIED DEFERRED COMPENSATION IN 2008
Name | Executive | Registrant | Aggregate | Aggregate | Aggregate |
Charles W. Shivery | 32,022 | 2,159,552 | (633,469) | ― | 3,957,405 |
David R. McHale | ― | 97,150 | (46,015) | (41,979) | 210,467 |
Leon J. Olivier | 137,741 | 141,854 | (181,878) | (16,772) | 1,301,131 |
Gregory B. Butler | ― | 157,831 | (87,703) | ― | 441,015 |
Raymond P. Necci | 126,398 | 68,389 | (113,179) | ― | 331,222 |
(1)
Reflects base salary deferrals by the Named Executive Officers under the Deferral Plan for 2008. Named Executive Officers who participate in the Deferral Plan are provided with a variety of investment opportunities, which the individual can modify and reallocate at any time. Fund gains and losses are updated daily by NU’s recordkeeper, Fidelity Investments. Contributions by the Named Executive Officer are vested at all times; however, the employer matching contribution vests after three years and will be forfeited if the executive’s employment terminates, other than for retirement, prior to vesting.
(2)
Includes employer matching contributions made to the Deferral Plan as of December 31, 2008 and posted on January 31, 2009, as reported in the All Other Compensation column of the Summary Compensation Table (Mr. Shivery: $25,122; Mr. Olivier: $9,629; and Mr. Necci: $2,670). The employer matching contribution is deemed to be invested in NU common shares but is paid in cash at the time of distribution. All other amounts relate to the value of NU common shares, the distribution of which was automatically deferred upon vesting of underlying RSUs pursuant to the terms of the respective Long-Term Incentive Programs, calculated using the closing price of the common shares on the vesting date (February 25, 2008). For more information, see the footnotes to the Options Exercised and Stock Vested Table.
(3)
Includes the total market value of Deferral Plan balances at December 31, 2008 plus the value of vested RSUs for which the distribution of common shares is currently deferred, based on $24.06 per share, the closing price of NU common shares on December 31, 2008.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
In the event of a change of control, the NEO’s are each entitled to receive compensation and benefits following termination of employment without "cause" or upon termination of employment by the executive for "good reason," either within 24 months following the change of control. The Compensation Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. Termination for "cause" generally means termination due to a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to company property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement. Termination for "good reason" generally is deemed to occur following an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement, a reduction in the compensation or benefits of the executive officer (a material reduction in base compensation for Mr. Olivier and Mr. Necci under the SSP, as defined below), or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control.
Generally, a "change of control" means a change in ownership or control effected through (i) the acquisition of 20% or more of the combined voting power of NU common shares or other voting securities, (ii) a change in the majority of NU’s Board of Trustees over a 24-month period, unless approved by a majority of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding NU common shares immediately prior to such business combination do not beneficially own more than 50% of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than to an entity with respect to which following completion of the transaction more than 50% (75% for Mr. Olivier and Mr. Necci) of NU common share s or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.
The discussion and tables below reflect the amount of compensation that would be payable to each of the Named Executive Officers in the event of: (i) termination of employment for cause; (ii) voluntary termination; (iii) involuntary not-for-cause termination (or voluntary termination for good reason); (iv) termination in the event of disability; (v) death; and (vi) termination following a change of control. The amounts shown assume that each termination was effective as of December 31, 2008, the last business day of the fiscal year as required under SEC reporting requirements.
103
Payments Upon Termination
Regardless of the manner in which the employment of a Named Executive Officer terminates, he or she is entitled to receive certain amounts earned during his or her term of employment. Such amounts include:
·
Vested RSUs;
·
Amounts contributed under the Deferral Plan;
·
Vested matching contributions under the Deferral Plan;
·
Pay for unused vacation; and
·
Amounts accrued and vested through the Retirement Plan and the 401k Plan.
I.
Post-Employment Compensation: Termination for Cause
| Shivery | McHale | Olivier | Butler | Necci |
|
|
|
|
|
|
Incentive Programs |
|
|
|
|
|
Annual Incentives | ― | ― | ― | ― | ― |
Performance Cash | ― | ― | ― | ― | ― |
RSUs (1) | 3,629,786 | 210,467 | 323,639 | 422,254 | 166,821 |
Pension and Deferred Compensation |
|
|
|
|
|
Retirement Plan (2) | 180,964 | 224,712 | 200,398 | 124,624 | 1,186,345 |
Supplemental Plan | ― | ― | ― | ― | ― |
Special Retirement Benefit | ― | ― | 1,849,602 | ― | ― |
Deferral Plan (3) | 283,421 | ― | 977,492 | 14,763 | 164,401 |
Other Benefits |
|
|
|
|
|
Health and Welfare Cash Value | ― | ― | ― | ― | ― |
Perquisites | ― | ― | ― | ― | ― |
Separation Payments | ― | ― | ― | ― | ― |
Excise Tax & Gross-Up | ― | ― | ― | ― | ― |
Separation Payment for Non-Compete Agreement | ― | ― | ― | ― | ― |
Separation Payment for Liquidated Damages | ― | ― | ― | ― | ― |
Total | 4,094,171 | 435,179 | 3,351,131 | 561,641 | 1,517,567 |
(1)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs that, as of the end of 2008, had been deferred upon vesting and remained deferred.
(2)
Represents the actuarial present values at the end of 2008 of benefits payable from the Retirement Plan to each Named Executive Officer at the earliest time that the payment of pension benefits can commence. The earliest benefit commencement times are different for each NEO based on plan provisions and age, as follows: Messrs. Shivery, Olivier, and Necci: immediately; Messrs. Butler and McHale: age 55. The benefits are payable as annuities, and the present values are calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008", above.
(3)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2008.
104
II.
Post-Employment Compensation: Voluntary Termination
| Shivery | McHale | Olivier | Butler | Necci |
|
|
|
|
|
|
Incentive Programs |
|
|
|
|
|
Annual Incentives (1) | 1,519,129 | 465,520 | 494,571 | 361,286 | 173,807 |
Performance Cash (2) | 3,256,300 | 284,694 | 654,375 | 362,388 | 289,818 |
RSUs (3) | 5,383,516 | 210,467 | 636,680 | 422,254 | 281,072 |
Pension and Deferred Compensation |
|
|
|
|
|
Retirement Plan (4) | 180,964 | 224,712 | 200,398 | 124,624 | 1,186,345 |
Supplemental Plan (5) | 4,426,647 | ― | ― | ― | 1,478,386 |
Special Retirement Benefit (6) | 2,099,936 |
| 1,849,602 | ― | 63,832 |
Deferral Plan (7) | 327,618 | ― | 977,492 | 14,763 | 164,401 |
Other Benefits |
|
|
|
|
|
Health and Welfare Benefits (8) | 105,879 | ― | ― | ― | ― |
Perquisites | ― | ― | ― | ― | ― |
Separation Payments |
|
|
|
|
|
Excise Tax & Gross-Up | ― | ― | ― | ― | ― |
Separation Payment for |
|
|
|
|
|
Separation Payment for |
|
|
|
|
|
Total | 17,299,989 | 1,185,393 | 4,813,118 | 1,285,315 | 3,637,661 |
(1)
Represents the actual 2008 annual incentive award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on Form 10-K.
(2)
Represents the actual 2006 - 2008 Performance Cash Program award for each Named Executive Officer. Also includes, for Messrs. Shivery, Olivier and Necci, prorated awards under the 2007 - 2009 and 2008 - 2010 Performance Cash Programs, because each of them would be considered to be a "retiree" under those programs. Amounts are prorated for time worked in each three-year performance period, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on Form 10-K.
(3)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs that, as of the end of 2008, had been deferred upon vesting and remained deferred, or that would vest upon voluntary termination of employment according to their program grant rules. Under the terms of each RSU grant, unvested RSUs that would have vested on February 25, 2009, would vest for Messrs. Shivery, Olivier, and Necci based on time worked since February 25, 2008, because each of them would be considered to be a "retiree" under those programs. The values were calculated by multiplying the number of RSUs by $24.06, the closing price of NU common shares on December 31, 2008.
(4)
Represents the actuarial present values at the end of 2008 of benefits payable from the Retirement Plan to each Named Executive Officer at the earliest time pension benefits can begin. The earliest benefit commencement times are different for each NEO based on plan provisions and age, as follows: Messrs. Shivery, Olivier, and Necci: immediately; Messrs. Butler and McHale: age 55. The benefits are payable as annuities, and the present values are calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(5)
Represents the actuarial present value at the end of 2008 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(6)
Represents the actuarial present values at the end of 2008 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon voluntary termination were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon voluntary termination. Pursuant to Mr. Necci’s offer of employment, pension benefits available upon voluntary termination were calculated with the addition of nine months of service.Pension amounts reflected in the table are present values at the end of 2008 of benefits payable to each Named Executive Officer upon termination. Mr. Shivery’s benefit would be paid as an annuity calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(7)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2008.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2008 of providing post-employment welfare benefits to Mr. Shivery beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. To the
105
extent these benefits are provided in excess of those provided to employees in general, Mr. Shivery would receive payments to offset the taxes incurred on such benefits.
III.
Post-Employment Compensation: Involuntary Termination, Not for Cause
| Shivery | McHale | Olivier | Butler | Necci |
|
|
|
|
|
|
Incentive Programs |
|
|
|
|
|
Annual Incentives (1) | 1,519,129 | 465,520 | 494,571 | 361,286 | 173,807 |
Performance Cash (2) | 3,256,300 | 284,694 | 654,375 | 362,388 | 289,818 |
RSUs (3) | 7,643,654 | 554,902 | 636,680 | 702,008 | 281,072 |
Pension and Deferred Compensation |
|
|
|
|
|
Retirement Plan (4) | 180,964 | 224,712 | 200,398 | 124,624 | 1,186,345 |
Supplemental Plan (5) | 4,426,647 | — | — | — | 1,478,386 |
Special Retirement Benefit (6) | 3,499,893 | 2,547,081 | 1,849,602 | 1,867,500 | 63,832 |
Deferral Plan (7) | 327,618 | — | 977,492 | 14,763 | 164,401 |
Other Benefits |
|
|
|
|
|
Health and Welfare Benefits (8) | 117,291 | 42,325 | 94,333 | 42,849 | — |
Perquisites (9) | 7,000 | 7,000 | — | 7,000 | —- |
Separation Payments |
|
|
|
|
|
Excise Tax & Gross-Up | — | — | — | — | — |
Separation Payment for Non-Compete |
|
|
|
|
|
Separation Payment for Liquidated |
|
|
|
|
|
Total | 25,248,112 | 5,804,792 | 4,907,451 | 4,863,606 | 3,637,661 |
(1)
Represents the actual 2008 annual incentive award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on Form 10-K
(2)
Represents the actual 2006 - 2008 Performance Cash Program award. Also includes, for Messrs. Shivery, Olivier, and Necci, prorated awards under the 2007 - 2009 and 2008 - 2010 Performance Cash Programs, because each of them would be considered to be a "retiree" under those programs. Amounts are prorated for time worked in each three-year performance period, because each of them would be considered to be a "retiree" under those programs, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on Form 10-K.
(3)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs that, as of the end of 2008, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of each RSU grant, for the Named Executive Officers other than Mr. Shivery, unvested RSUs that would have vested on February 25, 2009, vest based on time worked since February 25, 2008, because each of them would be considered to be a "retiree" under those programs. The values were calculated by multiplying the number of RSUs by $24.06, the closing price of NU common shares on December 31, 2008.
(4)
Represents the actuarial present values at the end of 2008 of benefits payable from the Retirement Plan to each Named Executive Officer at the earliest time pension benefits can begin. The earliest benefit commencement times are different for each NEO based on plan provisions and age, as follows: Messrs. Shivery, Olivier, and Necci: immediately; Messrs. Butler and McHale: age 55. The benefits are payable as annuities, and the present values are calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(5)
Represents the actuarial present value at the end of 2008 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(6)
Represents the actuarial present values at the end of 2008 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreements with Messrs. McHale and Butler, pension benefits available upon an involuntary termination for other than cause were calculated with the addition of two years of age and service. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon an involuntary termination for other than cause were calculated with the addition of two years of age and five years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon an involuntary terminatio n for other than cause. Pursuant to Mr. Necci’s offer of employment, pension benefits available upon voluntary termination were calculated with the addition of nine months of service. Pension amounts reflected in the table are present values at the end of 2008 of benefits payable to each Named Executive Officer upon termination. Except for the benefit payable to Mr. Olivier, all benefits are annuities calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(7)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2008.
106
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2008 of providing post-employment welfare benefits to the Named Executive Officers beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Each of Messrs. Shivery, McHale and Butler is entitled to receive active health benefits and the cash value of company-paid active long-term disability and life insurance benefits for two years under the terms of his respective employment agreement. Each of Messrs. Shivery and Olivier is entitled to receive retiree health benefits under his respective employment agreement. For all health and welfare benefits provided in excess of those provided to employees in general, executives receive payments to offset the taxes incurred on such benefits. Six months of company-paid COBRA benefits are generally made available to a ll employees whose employment terminates involuntarily without cause. As a result, the amount reported in the table for Mr. Shivery represents (a) the value of 18 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) the value of lifetime retiree health coverage, plus (c) tax gross-up payments thereon. The amounts reported in the table for Messrs. McHale and Butler represent (a) the value of 18 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) tax gross-up payments thereon. The amount reported in the table for Mr. Olivier represents (a) the value of lifetime retiree health coverage, plus (b) tax gross-up payments thereon.
(9)
Represents the cost to NU of reimbursing fees for financial planning and tax preparation services to Messrs. Shivery, McHale, and Butler for two years.
(10)
Represents payments made as consideration for agreements by each of Messrs. Shivery, McHale, and Butler not to compete with the company following termination. Employment agreements with these Named Executive Officers provide for a lump-sum payment in an amount equal to their annual salary plus their annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
(11)
Represents severance payments to Messrs. Shivery, McHale, and Butler paid in addition to the non-compete agreement payments described in note (10). This payment is an amount equal to their actual base salary paid in 2008 plus annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
IV.
Post-Employment Compensation: Termination Upon Disability
| Shivery | McHale | Olivier | Butler | Necci |
|
|
|
|
|
|
Incentive Programs |
|
|
|
|
|
Annual Incentives (1) | 1,519,129 | 465,520 | 494,571 | 361,286 | 173,807 |
Performance Cash (2) | 3,256,300 | 634,694 | 654,375 | 657,939 | 289,818 |
RSUs (3) | 5,383,516 | 554,902 | 636,680 | 702,008 | 281,072 |
Pension and Deferred Compensation |
|
|
|
|
|
Retirement Plan (4) | 199,044 | 629,437 | 200,398 | 197,098 | 1,186,345 |
Supplemental Plan (5) | 3,887,672 | 2,792,528 | — | 1,003,592 | 1,478,386 |
Special Retirement Benefit (6) | 1,862,536 | — | 1,849,602 | — | 63,832 |
Deferral Plan (7) | 327,618 | — | 977,492 | 18,762 | 164,401 |
Other Benefits |
|
|
|
|
|
Health and Welfare Benefits (8) | 105,879 | — | 94,333 | — | — |
Perquisites | — | — | — | — | — |
Separation Payments |
|
|
|
|
|
Excise Tax & Gross-Up | — | — | — | — | — |
Separation Payment for Non-Compete |
|
|
|
|
|
Separation Payment for Liquidated Damages | — | — | — | — | — |
Total | 16,541,694 | 5,077,081 | 4,907,451 | 2,940,685 | 3,637,661 |
(1)
Represents the actual 2008 annual incentive award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on From 10-K.
(2)
Represents the actual 2006 - 2008 Performance Cash Program award determined as described in the "Compensation Discussion and Analysis" in this Annual report on Form 10-K, plus awards at target under the 2007 - 2009 Performance Cash Program and 2008 - 2010 Performance Cash Program prorated for time worked in each three-year performance period.
(3)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs that, as of the end of 2008, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of each RSU grant, unvested RSUs that would have vested on February 25, 2009, vest based on time worked since February 25, 2008. The values were calculated by multiplying the number of RSUs by $24.06, the closing price of NU common shares on December 31, 2008.
(4)
Under NU’s Long-Term Disability (LTD) program, disabled participants in the Retirement Plan are allowed to continue to accrue service in the Retirement Plan during the period when they are receiving disability payments. Disability payments stop
107
when the LTD participant elects to commence pension payments, but not later than age 65. NU has assumed similar treatment in the development of the pension amounts reported in this table. For purposes of valuing the pension benefits, NU has assumed that each Named Executive Officer would remain on LTD until the executive’s first unreduced combined pension benefit age. All payments would consist of life annuities calculated using the same assumptions detailed in the notes to the Pension Benefits Table. Therefore, the numbers shown represent the actuarial present values at the end of 2008 of benefits payable from the Retirement Plan to each Named Executive Officer, assuming termination of employment at the earliest unreduced benefit age for the combined total of all pension benefits. The earliest unreduced benefit ages are different for each NEO based on employment agreement provisions and years of service, as follows: Mr. Shivery: age 65; Mr. McHale: age 55; Mr. Butler: age 62; and Mr. Olivier and Mr. Necci: immediately. The benefits are payable as annuities, and the present values are calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(5)
Represents the actuarial present value at the end of 2008 of the benefit payable from the Supplemental Plan to each NEO other than Mr. Olivier under the assumptions discussed in note (4). The benefit is payable as an annuity, and the present value was calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(6)
Represents the actuarial present values at the end of 2008 of the amounts payable to the Named Executive Officers under the assumptions discussed in note (4), solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon disability termination were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon disability termination. Pursuant to Mr. Necci’s employment offer, pension benefits available upon disability termination were calculated with the addition of nine months of service. Mr. Shivery’s benefit would be paid as an annuity calcu lated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(7)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2008.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2008 of providing post-employment welfare benefits to Messrs. Shivery and Olivier beyond those benefits that would be provided to a nonexecutive employee upon disability termination. Each of Messrs. Shivery and Olivier is entitled to receive retiree health benefits under his respective employment agreement. To the extent these benefits are provided in excess of those provided to employees in general, Messrs. Shivery and Olivier would receive payments to offset the taxes incurred on such benefits.
V.
Post-Employment Compensation: Death
| Shivery | McHale | Olivier | Butler | Necci |
|
|
|
|
|
|
Incentive Programs |
|
|
|
|
|
Annual Incentives (1) | 1,519,129 | 465,520 | 494,571 | 361,286 | 173,807 |
Performance Cash (2) | 3,256,300 | 634,694 | 654,375 | 657,939 | 289,818 |
RSUs (3) | 5,383,516 | 554,902 | 636,680 | 702,008 | 281,072 |
Pension and Deferred Compensation |
|
|
|
|
|
Retirement Plan (4) | 91,191 | 1,000,786 | 172,523 | 122,432 | 1,108,068 |
Supplemental Plan (4) | 2,230,676 | 2,584,178 | — | 759,256 | 1,380,840 |
Special Retirement Benefit (5) | 1,058,200 | — | 1,877,477 | — | 59,620 |
Deferral Plan (6) | 327,618 | — | 977,492 | 18,762 | 164,401 |
Other Benefits |
| — |
|
|
|
Health and Welfare Benefits (7) | 59,985 | — | 39,525 | — | — |
Perquisites | — | — | — | — | — |
Separation Payments |
|
|
|
|
|
Excise Tax & Gross-Up | — | — | — | — | — |
Separation Payment for Non-Compete |
|
|
|
|
|
Separation Payment for Liquidated |
|
|
|
|
|
Total | 13,926,615 | 5,240,080 | 4,852,643 | 2,621,683 | 3,457,626 |
(1)
Represents the actual 2008 annual incentive award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on Form 10-K.
(2)
Represents the actual 2006 - 2008 Performance Cash Program award determined as described in the "Compensation Discussion and Analysis" in this Annual report on Form 10-K, plus awards at target under the 2007 - 2009 Performance Cash Program and 2008 - 2010 Performance Cash Program prorated for time worked in each three-year performance period.
(3)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs that, as of the end of 2008, had been deferred upon vesting and remained deferred, or that had not yet vested according to their
108
program grant vesting schedules. Under the terms of each RSU grant, unvested RSUs that would have vested on February 25, 2009, vest based on time worked since February 25, 2008. The values were calculated by multiplying the number of RSUs by $24.06, the closing price of NU common shares on December 31, 2008.
(4)
Represents the lump sum present value of pension payments from the Retirement Plan and the Supplemental Plan to the surviving spouse of each Named Executive Officer. The benefits are payable as annuities, and the present values are calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(5)
Represents the actuarial present values at the end of 2008 of the amounts payable to the surviving spouses of the Named Executive Officers, solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon death were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier’s spouse upon death. Pursuant to Mr. Necci’s employment offer, pension benefits available upon death were calculated with the addition of nine months of service. Pension amounts reflected in the table are present values at the end of 2008 of benefits payable immediately t o each Named Executive Officer’s surviving spouse. Mr. Shivery’s benefit would be paid as an annuity calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(6)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2008.
(7)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2008 of providing post-employment welfare benefits to the surviving spouses of Messrs. Shivery and Olivier beyond those benefits that would be provided to a nonexecutive employee’s spouse upon the employee’s death. The surviving spouses of Messrs. Shivery and Olivier are entitled to receive retiree health benefits under the employment agreements. To the extent these benefits are taxable to the surviving spouses, they would receive payments to offset the taxes incurred on such benefits.
Payments Made Upon a Change of Control
The employment agreements with Messrs. Shivery, McHale, Olivier and Butler include change of control benefits. We have not entered into an employment agreement with Mr. Necci. Mr. Olivier and Mr. Necci participate in the Special Severance Program for Officers of Northeast Utilities System Companies (SSP), which provides benefits upon termination of employment in connection with a change of control. The employment agreements and the SSP are binding on NU. The terms of the various employment agreements are substantially similar, except for the agreement with Mr. Olivier, which refers instead to the change of control provisions of the SSP.
Pursuant to the employment agreements and under the terms of the SSP, if an executive officer’s employment terminates following a change of control, other than termination of employment for "cause" (as defined in the employment agreements, generally meaning willful and continued failure to perform his duties after written notice, a violation of our Standards of Business Conduct or conviction of a felony), or by reason of death or disability), or if the executive officer terminates his or her employment for "good reason" (as defined in the employment agreements, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control), then the executive officer will receive the benefits listed below, which receipt is conditioned upon delivery of a binding release of all legal claims against the company:
·
A lump sum severance payment of two-times (one-time for Mr. Olivier and Mr. Necci) the sum of the executive’s base salary plus all annual awards that would be payable for the relevant year determined at target (Base Compensation);
·
As consideration for a non-competition and non-solicitation covenant, a lump sum payment in an amount equal to the Base Compensation;
·
Active health benefits continuation, provided by NU for three years (two years for Mr. Olivier and Mr. Necci);
·
Retirement health coverage for Messrs. Shivery and Olivier, and for Messrs. McHale and Butler if the addition of three years of age and service would make the executive eligible under NU’s retirement health plan;
·
Benefits as if provided under the Supplemental Plan, notwithstanding eligibility requirements for the Target Benefit, including favorable actuarial reductions and the addition of three years to the executive’s age and years of service as compared to benefits available upon voluntary termination of employment (except for Mr. Olivier, whose benefits are described below, and Mr. Necci);
·
Automatic vesting and distribution of common shares in respect of all unvested RSUs; and
·
A lump sum payment in an amount equal to the excise tax charged to the executive under the Internal Revenue Code as a result of the receipt of any change of control payments, plus tax gross-up (except for Mr. Olivier and Mr. Necci).
The summaries of the employment agreements above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the employment agreements, copies of which have been filed as exhibits to this Annual Report on Form 10-K.
109
Pursuant to the terms of each of the 2007 – 2009 Performance Cash Program and 2008 – 2010 Performance Cash Program, following a change of control, performance cash awards would be vested, pro rata based on the number of days of employment during the performance period, and paid at target immediately, whether or not the executive’s employment terminated, unless the Compensation Committee determined otherwise. Including the payment for the actual performance of the 2006 - 2008 Performance Cash Program that would have been made upon a December 31, 2008 change of control, these payments would total $4,791,300 for Mr. Shivery, $997,194 for Mr. McHale, $976,250 for Mr. Olivier, $958,335 for Mr. Butler, and $419,795 for Mr. Necci.
VI.
Post-Employment Compensation: Termination Following a Change of Control
| Shivery | McHale | Olivier ($) | Butler | Necci |
Incentive Programs |
|
|
|
|
|
Annual Incentives (1) | 1,519,129 | 465,520 | 494,571 | 361,286 | 173,807 |
Performance Cash (2) | 4,791,300 | 997,194 | 976,250 | 958,335 | 419,795 |
RSUs (3) | 7,643,654 | 1,047,053 | 998,163 | 1,065,239 | 425,417 |
Pension and Deferred Compensation |
|
|
|
|
|
Retirement Plan (4) | 180,964 | 224,712 | 200,398 | 124,624 | 1,186,345 |
Supplemental Plan (5) | 4,426,647 | — | — | — | 1,478,386 |
Special Retirement Benefit (6) | 4,199,872 | 2,649,739 | 1,849,602 | 2,088,847 | 63,832 |
Deferral Plan (7) | 327,618 | — | 977,492 | 18,762 | 164,401 |
Other Benefits |
|
|
|
|
|
Health and Welfare Benefits (8) | 132,063 | 175,156 | 101,576 | 173,352 | 900 |
Perquisites (9) | 8,500 | 8,500 | — | 8,500 | — |
Separation Payments |
|
|
|
|
|
Excise Tax and Gross-Up (10) | 3,489,202 | 2,500,264 | — | 1,891,228 | — |
Separation Payment for Non-Compete |
|
|
|
|
|
Separation Payment for Liquidated Damages (12) | 4,269,616 | 1,678,558 | 909,087 | 1,381,188 | 478,500 |
Total | 33,123,373 | 10,585,975 | 7,416,226 | 8,761,955 | 4,869,883 |
(1)
Represents the actual 2008 annual incentive award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on Form 10-K.
(2)
Represents the actual 2006 - 2008 Performance Cash Program award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" in this Annual Report on Form 10-K, plus awards at target for each Named Executive Officer under the 2007 - 2009 Performance Cash Program and 2008 - 2010 Performance Cash Program.
(3)
Represents values of all RSUs granted to the Named Executive Officers under our long-term incentive programs that, as of the end of 2008, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. For Mr. Olivier, the value was reduced by $76,546 in accordance with provisions under the Special Severance Plan, which require a reduction in Change of Control payments if such reduction would eliminate the executive’s excise tax but increase his net benefit. The values were calculated by multiplying the number of RSUs by $24.06, the closing price of NU common shares on December 31, 2008.
(4)
Represents the actuarial present values at the end of 2008 of benefits payable from the Retirement Plan to each Named Executive Officer at the earliest time pension benefits can begin. The earliest benefit commencement times are different for each NEO based on plan provisions and age, as follows: Messrs. Shivery, Olivier, and Necci: immediately; Messrs. Butler and McHale: age 55. The benefits are payable as annuities, and the present values are calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(5)
Represents the actuarial present value at the end of 2008 of the benefit payable from the Supplemental Plan to Mr. Shivery and Mr. Necci upon termination. The benefit is payable as an annuity, and the present value was calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(6)
Represents the actuarial present values at the end of 2008 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreements with Messrs. McHale and Butler, pension benefits available upon termination following a Change of Control were calculated with the addition of three years of age and service. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon termination following a Change of Control were calculated with the addition of three years of age and six years of service. Pursuant to the employment agreement with Mr. Butler, the value of the Supplemental Plan and Special Retirement Benefits will be paid as a single lump sum rather than as an annuity if his termination date occurs within two years following a change in control that qualifies under Section 1.409A of the Treasury Regulations. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon termination following a Change in Control. Pursuant to Mr. Necci’s employment offer, pension benefits available upon termination following a Change of Control were calculated with the addition of nine months of age and six years of service. Pension amounts reflected in the
110
table are present values at the end of 2008 of benefits payable to each Named Executive Officer upon termination Except for the benefits payable to Messrs. Butler and Olivier, all benefits are annuities calculated as described in Notes 1 and 2 to the Pension Benefits Table under "Pension Benefits in 2008" above.
(7)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2008.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2008 of providing post-employment welfare benefits to the Named Executive Officers beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Each of Messrs. Shivery, McHale and Butler is entitled to receive active health benefits and the cash value of company-paid active long-term disability and life insurance benefits for three years under the terms of his respective employment agreement. Each of Messrs. Shivery and Olivier is entitled to receive retiree health benefits under his respective employment agreement. Under his respective employment agreement, each of Messrs. McHale and Butler is entitled to receive retiree health benefits if adding three years of age and service would have made the executive eligible under the Retirement Plan. Mr. Olivier and Mr. Necci participate in the SSP and are eligible for two years of active health benefits continuation. For all health and welfare benefits provided in excess of those provided to employees in general, executives receive payments to offset the taxes incurred on such benefits. Six months of company-paid COBRA benefits are generally made available to all employees whose employment terminates involuntarily without cause. As a result, the amounts reported in the table for Messrs. Shivery, McHale, and Butler represent (a) the value of 30 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) the value of lifetime retiree health coverage, plus (c) tax gross-up payments thereon. The amount reported in the table for Mr. Olivier represents (a) the value of 18 months of employer contributions toward active health benefits, plus (b) the value of lifetime retiree health coverage, plus (c) tax gross-up payments thereon. The amo unt reported in the table for Mr. Necci represents (a) the value of 18 months of employer contributions toward active health benefits, plus (b) tax gross-up payments thereon.
(9)
Represents the cost to NU of reimbursing fees for financial planning and tax preparation services to Messrs. Shivery, McHale, and Butler for three years.
(10)
Represents payments made to offset costs to Messrs. Shivery, McHale, and Butler associated with certain excise taxes under Section 280G of the Internal Revenue Code. Employees may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a termination following a Change of Control that exceed specified Internal Revenue Service limits. Employment agreements with each Named Executive Officer except Mr. Olivier and Mr. Necci provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on the Section 280G excise tax rate of 20%, the statutory federal income tax withholding rate of 35%, the Connecticut state income tax rate of 5%, and the Medicare tax rate of 1.45%.
(11)
Represents payments made as consideration for each Named Executive Officer’s agreement not to compete with the company following termination of employment. Agreements with each Named Executive Officer provide for a lump-sum payment in an amount equal to their annual salary plus their annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
(12)
Represents severance payments to each Named Executive Officer paid in addition to the non-compete agreement payments described in note (11). For Messrs. Shivery, McHale, and Butler, this payment is an amount equal to two-times actual base salary paid in 2008 plus annual incentive award at target. For Mr. Olivier and Mr. Necci, this payment is an amount equal to their actual base salary paid in 2008 plus their annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
NU
In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Common Share Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about April 1, 2009.
PSNH and WMECO
Certain information required by this Item 12 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
CL&P
NU owns 100% of the outstanding common stock of CL&P. The following table sets forth, as of February 17, 2009, the beneficial ownership of the equity securities of NU by (i) the Chief Executive Officer of CL&P and the executive officers of CL&P listed on the Summary Compensation Table in Item 11 and (ii) all of the current executive officers and directors of CL&P, as a group. No equity securities of CL&P are owned by any of the directors or executive officers of CL&P.
111
|
| Amount and Nature of Beneficial Ownership(1) | ||||||||
|
| NU |
|
|
|
|
|
|
| Restricted |
Leon J. Olivier, CEO of CL&P, Director(5) |
| 18,421 |
| - |
| 18,421 |
| * |
| 55,623 |
David R. McHale, CFO, Director(5)(6) |
| 13,495 |
| - |
| 13,495 |
| * |
| 51,812 |
Gregory B. Butler, Senior Vice President and |
| 27,902 |
| - |
| 27,902 |
| * |
| 51,049 |
Raymond P. Necci, President, Chief Operating |
| 19,503 |
| - |
| 19,503 |
| * |
| 20,719 |
Charles W. Shivery, Director(5)(7) |
| 48,264 |
| 29,024 |
| 77,288 |
| * |
| 356,645 |
|
|
|
|
|
|
|
| * |
|
|
All directors and Executive Officers |
| 140,781 |
| 51,924 |
| 192,705 |
| * |
| 584,524 |
*Less than 1% of common shares outstanding.
(1)
The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as noted below.
(2)
Reflects common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 17, 2009.
(3)
Includes unissued common shares consisting of restricted share units and deferred restricted share units as to which none of the Directors or Named Executive Officers has voting or investment power. Also includes "phantom" common shares representing employer matching contributions, distributable only in cash, held by individuals who participate in the NU Deferred Compensation Plan for Executives. Accordingly, these securities have been excluded from the "Total" column.
(4)
Includes 24,850 shares owned jointly by Mr. Butler and his spouse with whom he shares voting and investment power.
(5)
Includes common shares held in the 401k Plan in the employee stock ownership plan account over which the holder has sole voting and no investment power (Mr. Butler: 2,643 shares; Mr. McHale: 3,396 shares; Mr. Necci: 5,382 shares; Mr. Olivier: 1,366 shares; and Mr. Shivery: 1,509 shares).
(6)
Includes common shares held as units in the 401k Plan invested in the NU Common Shares Fund over which the holder has sole voting and investment power (Mr. Butler: 409 shares, Mr. McHale: 1,566 shares and Mr. Necci: 237 shares).
(7)
Includes 1,500 common shares owned jointly by Mr. Shivery and his spouse with whom he shares voting and investment power.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth the number of NU common shares issuable under NU equity compensation plans, as well as their weighted exercise price, in accordance with the rules of the SEC, at December 31, 2008:
|
|
|
| Weighted-average |
| Number of securities |
Equity compensation plans approved by security holders |
| 1,165,067(a) |
| $18.83(b) |
| 3,715,729(c) |
Equity compensation plans not approved by security holders (d) |
| - |
| - |
| - |
Total |
| 1,165,067 |
| $18.83 |
| 3,715,729 |
(a)
Includes 320,920 common shares to be issued upon exercise of options, and 844,147 common shares for distribution of restricted share units pursuant to the terms of our Incentive Plan.
(b)
The weighted-average exercise price in Column (b) does not take into account restricted share units, which have no exercise price.
(c)
Includes 1,010,114 common shares issuable under our Employee Share Purchase Plan II.
(d)
All of our current compensation plans under which equity securities of NU are authorized for issuance have been approved by NU’s shareholders.
112
Item 13.
Certain Relationships and Related Transactions, and Director Independence
NU
Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Certain Relationships and Related Transactions" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about April 1, 2009.
PSNH and WMECO
Certain information required by this Item 13 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
CL&P
NU’s Code of Ethics for Senior Financial Officers applies to the Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) of CL&P and certain other NU subsidiaries. Under the Code, one’s position as a Senior Financial Officer in the company may not be used to improperly benefit such officer or his or her family or friends. Under the Code, specific activities that may be considered conflicts of interest include, but are not limited to, directly or indirectly acquiring or retaining a significant financial interest in an organization that is a customer, vendor or competitor, or that seeks to do business with the company; serving, without proper safeguards, as an officer or director of, or working or rendering services for an organization that is a customer, vendor or competitor, or that seeks to do business with the company. Waivers of the provisions of the Code of Ethics must be appr oved by NU’s Board of Trustees. Any such Waivers will be disclosed pursuant to legal requirements.
NU’s Standards of Business Conduct (SBC), which applies to all Trustees, directors, officers and employees of NU and its subsidiaries, including CL&P, contains a Conflict of Interest Policy which requires all such individuals to disclose any potential conflicts of interest. Such individuals are expected to discuss their particular situations with management to ensure appropriate steps are in place to avoid a conflict of interest. All disclosures must be reviewed and approved by management to ensure a particular situation does not adversely impact the individual’s primary job and role.
In addition, NU’s Board of Trustees adopted a Related Party Transactions Policy on December 11, 2007. The Policy is administered by the Corporate Governance Committee of the Board. The Policy generally defines a "Related Party Transaction" as any transaction or series of transactions in which (i) Northeast Utilities or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any "Related Party" has a direct or indirect material interest. A "Related Party" is defined as any Trustee or nominee for Trustee, any executive officer, any shareholder owning more than 5% of our total outstanding shares, and any immediate family member of any such person. Management submits to the Corporate Governance Committee for consideration any Related Party Transaction into which NU proposes to enter. The Corporate Governance Committee recommends to the Boa rd of Trustees for approval only those transactions that are in NU’s best interests. If management causes the company to enter into a Related Party Transaction prior to approval by the Committee, the transaction will be subject to ratification by the Board of Trustees. If the Board determines not to ratify the transaction, then management will make all reasonable efforts to cancel or annul such transaction.
The Directors of CL&P are employees of CL&P and/or other subsidiaries of NU and thus are not considered independent.
Item 14.
Principal Accountant Fees and Services
NU
Incorporated herein by references is the information contained in the section "Relationship with Independent Auditors" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about April 1, 2009.
CL&P, PSNH and WMECO
Pre-Approval of Services Provided by Principal Auditors
None of CL&P, PSNH or WMECO is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit committee of NU’s Board of Trustees. NU’s Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the Audit Committee Chair and/or Vice Chair provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the Audit Committee at the next regularly scheduled meeting of the Committee.
The following relates to fees and services for the entire NU system, including NU, CL&P, PSNH and WMECO.
113
Fees Paid to Principal Auditor
NU and its subsidiaries paid Deloitte & Touche LLP fees aggregating $3,053,830 and $3,108,754 for the years ended December 31, 2008 and 2007, respectively, comprised of the following:
1.
Audit Fees
The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the Deloitte Entities), for audit services rendered for the years ended December 31, 2008 and 2007 totaled $2,914,830 and $2,789,900, respectively. The audit fees were incurred for audits of NU’s annual consolidated financial statements and those of its subsidiaries, reviews of financial statements included in NU’s Quarterly Reports on Form 10-Q and those of its subsidiaries, comfort letters, consents and other costs related to registration statements and financings. The fees also included audits of internal controls over financial reporting as of December 31, 2008 and 2007, as well as auditing the implementation of new accounting standards and the accounting for new contracts.
2.
Audit Related Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2008 and 2007 totaled $117,500 and $260,000, respectively, primarily related to the examination of management’s assertions about the securitization subsidiaries of CL&P, PSNH and WMECO. The 2007 fees also included the audits of NU’s various employee benefit plans.
3.
Tax Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2008 and 2007 totaled $20,000 and $57,354, respectively. These services related solely to reviews of tax returns. There were no services related to tax advice or tax planning.
4.
All Other Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for services other than the services described above totaled $1,500 for each of the years ended December 31, 2008 and 2007, consisting of a license fee for access to an accounting research database.
The Audit Committee of the NU Board of Trustees (Audit Committee) pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for NU and its subsidiaries by the independent auditors, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit. The Audit Committee may form, and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. During 2008, the only audit related services provided by the Deloitte Entities that were not pre-approved by the Audit Committe e were de minimis services for work paper review and other work related to transitioning the audit of our employee benefit plans to a different firm, for which the Deloitte Entities received a fee of $2,500. Also not pre-approved were services provided in rendering an agreed upon procedures certificate letter as required by a bond indenture, for which the Deloitte Entities received a fee of $5,000. The Audit Committee approved these de minimis services prior to the completion of the financial statement audit. The Deloitte Entities did not provide any other services that were not pre-approved by the Audit Committee.
The Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining auditor independence and has concluded that the Deloitte Entities were and are independent of NU and its subsidiaries in all respects.
114
Part IV
Item 15.
Exhibits and Financial Statement Schedules
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| Company Report on Internal Controls Over Financial Reporting | 82 | ||
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Consolidated Financial Statements | 84 | |||
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PSNH |
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Report of Independent Registered Public Accounting Firm | 91 | |||
Consolidated Financial Statements | 92 | |||
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WMECO |
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| Company Report on Internal Controls Over Financial Reporting |
| ||
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| |||
Consolidated Financial Statements | 99 | |||
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11572
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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116
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117
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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118
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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119
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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120
Company Report on Internal Controls Over Financial Reporting
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU or the Company) and of other sections of this annual report. NU’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2008.2010.
February 27, 200925, 2011
FS-1
73
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and Shareholders of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities and subsidiaries (the "Company") as of December 31, 20082010 and 2007,2009, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008.2010. Our audits also included the consolidated financial statement schedules listed in the Index at Item 15.15 of Part IV. We also have audited the Company's internal control over financial reporting as of December 31, 2008,2010, based on criteria established inInternal Control -— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control o ver financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial schedules and an opinion on the Company's internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of i nternal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principle s, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established inInternal Control — Integrated Framework issued by the Committee of Sponso ring Organizations of the Treadway Commission.
/s/ | Deloitte & Touche LLP |
Deloitte & Touche LLP |
Hartford, Connecticut
February 25, 2011
74
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
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CONSOLIDATED BALANCE SHEETS |
|
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| |||||
|
| As of December 31, | |||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
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|
ASSETS |
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Current Assets: |
|
|
|
|
|
Cash and Cash Equivalents | $ | 23,395 |
| $ | 26,952 |
Receivables, Net |
| 523,644 |
|
| 512,770 |
Unbilled Revenues |
| 208,834 |
|
| 229,326 |
Taxes Receivable |
| 89,638 |
|
| 27,600 |
Fuel, Materials and Supplies |
| 244,043 |
|
| 277,085 |
Marketable Securities |
| 78,306 |
|
| 66,236 |
Derivative Assets |
| 17,287 |
|
| 31,785 |
Prepayments and Other Current Assets |
| 132,595 |
|
| 96,100 |
Total Current Assets |
| 1,317,742 |
|
| 1,267,854 |
|
|
|
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|
|
Property, Plant and Equipment, Net |
| 9,567,726 |
|
| 8,839,965 |
|
|
|
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Deferred Debits and Other Assets: |
|
|
|
|
|
Regulatory Assets |
| 2,995,279 |
|
| 3,244,931 |
Goodwill |
| 287,591 |
|
| 287,591 |
Marketable Securities |
| 51,201 |
|
| 54,905 |
Derivative Assets |
| 123,242 |
|
| 189,751 |
Other Long-Term Assets |
| 179,261 |
|
| 172,682 |
Total Deferred Debits and Other Assets |
| 3,636,574 |
|
| 3,949,860 |
|
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Total Assets | $ | 14,522,042 |
| $ | 14,057,679 |
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The accompanying notes are an integral part of these consolidated financial statements. |
75
NORTHEAST UTILITIES AND SUBSIDIARIES |
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|
CONSOLIDATED BALANCE SHEETS |
|
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|
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| |||||
|
| As of December 31, | |||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
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|
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|
|
Current Liabilities: |
|
|
|
|
|
Notes Payable to Banks | $ | 267,000 |
| $ | 100,313 |
Long-Term Debt - Current Portion |
| 66,286 |
|
| 66,286 |
Accounts Payable |
| 417,285 |
|
| 457,582 |
Obligations to Third Party Suppliers |
| 74,659 |
|
| 44,978 |
Accrued Taxes |
| 107,067 |
|
| 50,246 |
Accrued Interest |
| 74,740 |
|
| 83,763 |
Derivative Liabilities |
| 71,501 |
|
| 37,617 |
Other Current Liabilities |
| 159,537 |
|
| 138,627 |
Total Current Liabilities |
| 1,238,075 |
|
| 979,412 |
|
|
|
|
|
|
Rate Reduction Bonds |
| 181,572 |
|
| 442,436 |
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
Accumulated Deferred Income Taxes |
| 1,693,860 |
|
| 1,380,143 |
Regulatory Liabilities |
| 439,058 |
|
| 485,706 |
Derivative Liabilities |
| 909,668 |
|
| 955,646 |
Accrued Pension |
| 802,195 |
|
| 781,431 |
Other Long-Term Liabilities |
| 695,915 |
|
| 845,868 |
Total Deferred Credits and Other Liabilities |
| 4,540,696 |
|
| 4,448,794 |
|
|
|
|
|
|
Capitalization: |
|
|
|
|
|
Long-Term Debt |
| 4,632,866 |
|
| 4,492,935 |
|
|
|
|
|
|
Noncontrolling Interest in Consolidated Subsidiary: |
|
|
|
|
|
Preferred Stock Not Subject to Mandatory Redemption |
| 116,200 |
|
| 116,200 |
|
|
|
|
|
|
Equity: |
|
|
|
|
|
Common Shareholders' Equity: |
|
|
|
|
|
Common Shares |
| 978,909 |
|
| 977,276 |
Capital Surplus, Paid In |
| 1,777,592 |
|
| 1,762,097 |
Deferred Contribution Plan |
| - |
|
| (2,944) |
Retained Earnings |
| 1,452,777 |
|
| 1,246,543 |
Accumulated Other Comprehensive Loss |
| (43,370) |
|
| (43,467) |
Treasury Stock |
| (354,732) |
|
| (361,603) |
Common Shareholders' Equity |
| 3,811,176 |
|
| 3,577,902 |
Noncontrolling Interests |
| 1,457 |
|
| - |
Total Equity |
| 3,812,633 |
|
| 3,577,902 |
Total Capitalization |
| 8,561,699 |
|
| 8,187,037 |
|
|
|
|
|
|
Commitments and Contingencies (Note 12) |
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 14,522,042 |
| $ | 14,057,679 |
|
|
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The accompanying notes are an integral part of these consolidated financial statements. | |||||
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76
NORTHEAST UTILITIES AND SUBSIDIARIES |
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|
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CONSOLIDATED STATEMENTS OF INCOME |
|
|
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|
|
|
|
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|
|
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|
|
|
|
|
|
| For the Years Ended December 31, | ||||||
(Thousands of Dollars, Except Share Information) |
| 2010 |
|
| 2009 |
|
| 2008 |
|
|
|
|
|
|
|
|
|
Operating Revenues | $ | 4,898,167 |
| $ | 5,439,430 |
| $ | 5,800,095 |
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
| 1,985,634 |
|
| 2,629,619 |
|
| 2,996,180 |
Other Operating Expenses |
| 958,417 |
|
| 1,001,190 |
|
| 1,021,704 |
Maintenance |
| 210,283 |
|
| 234,173 |
|
| 254,038 |
Depreciation |
| 300,737 |
|
| 309,618 |
|
| 278,588 |
Amortization of Regulatory Assets, Net |
| 95,593 |
|
| 13,315 |
|
| 186,396 |
Amortization of Rate Reduction Bonds |
| 232,871 |
|
| 217,941 |
|
| 204,859 |
Taxes Other Than Income Taxes |
| 314,741 |
|
| 282,199 |
|
| 267,565 |
Total Operating Expenses |
| 4,098,276 |
|
| 4,688,055 |
|
| 5,209,330 |
Operating Income |
| 799,891 |
|
| 751,375 |
|
| 590,765 |
|
|
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
|
|
Interest on Long-Term Debt |
| 231,089 |
|
| 224,712 |
|
| 193,883 |
Interest on Rate Reduction Bonds |
| 20,573 |
|
| 36,524 |
|
| 50,231 |
Other Interest (Note 11) |
| (14,371) |
|
| 12,401 |
|
| 25,031 |
Interest Expense |
| 237,291 |
|
| 273,637 |
|
| 269,145 |
Other Income, Net |
| 41,916 |
|
| 37,801 |
|
| 50,428 |
Income Before Income Tax Expense |
| 604,516 |
|
| 515,539 |
|
| 372,048 |
Income Tax Expense |
| 210,409 |
|
| 179,947 |
|
| 105,661 |
Net Income |
| 394,107 |
|
| 335,592 |
|
| 266,387 |
Net Income Attributable to Noncontrolling Interests |
| 6,158 |
|
| 5,559 |
|
| 5,559 |
Net Income Attributable to Controlling Interests | $ | 387,949 |
| $ | 330,033 |
| $ | 260,828 |
|
|
|
|
|
|
|
|
|
Basic Earnings Per Common Share | $ | 2.20 |
| $ | 1.91 |
| $ | 1.68 |
Diluted Earnings Per Common Share | $ | 2.19 |
| $ | 1.91 |
| $ | 1.67 |
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
Basic |
| 176,636,086 |
|
| 172,567,928 |
|
| 155,531,846 |
Diluted |
| 176,885,387 |
|
| 172,717,246 |
|
| 155,999,240 |
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
|
77
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
| ||
| For the Years Ended December 31, | |||||
(Thousands of Dollars) |
| 2010 |
| 2009 |
| 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
| $ 394,107 |
| $ 335,592 |
| $ 266,387 |
Other Comprehensive Income/(Loss), Net of Tax: |
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| 200 |
| 200 |
| (6,909) |
Changes in Unrealized Gains/(Losses) on Other Securities |
| 402 |
| (976) |
| (1,669) |
Change in Funded Status of Pension, SERP and Other |
|
|
|
|
|
|
Postretirement Benefit Plans |
| (505) |
| (5,426) |
| (38,046) |
Other Comprehensive Income/(Loss), Net of Tax |
| 97 |
| (6,202) |
| (46,624) |
Comprehensive Income Attributable to Noncontrolling Interests |
| (6,158) |
| (5,559) |
| (5,559) |
Comprehensive Income Attributable to Controlling Interests |
| $ 388,046 |
| $ 323,831 |
| $ 214,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
|
|
78
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
|
| |||||
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY |
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
| Accumulated |
| Total | |
|
|
|
| Capital | Deferred |
| Other |
| Common | |
|
| Common Shares | Surplus, | Contribution | Retained | Comprehensive | Treasury | Shareholders' | ||
(Thousands of Dollars, Except Share Information) | Shares | Amount | Paid In | Plan | Earnings | Income/(Loss) | Stock | Equity | ||
Balance as of January 1, 2008 |
| 155,079,770 | $ 879,623 | $ 1,465,946 | $ (26,352) | $ 946,792 | $ 9,359 | $ (361,533) | $ 2,913,835 | |
Net Income |
|
|
|
|
| 266,387 |
|
| 266,387 | |
Dividends on Common Shares - $0.825 Per Share |
|
|
|
|
| (129,026) |
|
| (129,026) | |
Issuance of Common Shares, $5 Par Value |
| 287,581 | 1,438 | 4,086 |
|
|
|
| 5,524 | |
Dividends on Preferred Stock |
|
|
|
|
| (5,559) |
|
| (5,559) | |
Allocation of Benefits – ESOP |
| 469,601 |
| 865 | 10,871 |
|
|
| 11,736 | |
Change in Restricted Shares, Net |
| (2,591) |
| 2,436 |
|
| �� | (70) | 2,366 | |
Tax Deduction for Stock Options Exercised and |
|
|
|
|
|
|
|
|
| |
Employee Stock Purchase Plan Disqualifying |
|
|
|
|
|
|
|
|
| |
Dispositions |
|
|
| 1,622 |
|
|
|
| 1,622 | |
Capital Stock Expenses, Net |
|
|
| 51 |
|
|
|
| 51 | |
Other Comprehensive Loss |
|
|
|
|
|
| (46,624) |
| (46,624) | |
Balance as of December 31, 2008 |
| 155,834,361 | 881,061 | 1,475,006 | (15,481) | 1,078,594 | (37,265) | (361,603) | 3,020,312 | |
Adoption of Accounting Guidance for Other-Than- |
|
|
|
|
|
|
|
|
| |
Temporary Impairments (Note 1K) |
|
|
|
|
| 728 | (728) |
| - | |
Net Income |
|
|
|
|
| 335,592 |
|
| 335,592 | |
Dividends on Common Shares - $0.95 Per Share |
|
|
|
|
| (162,812) |
|
| (162,812) | |
Issuance of Common Shares, $5 Par Value |
| 19,242,939 | 96,215 | 293,502 |
|
|
|
| 389,717 | |
Dividends on Preferred Stock |
|
|
|
|
| (5,559) |
|
| (5,559) | |
Allocation of Benefits – ESOP |
| 542,724 |
| (98) | 12,537 |
|
|
| 12,439 | |
Change in Restricted Shares, Net |
|
|
| 5,303 |
|
|
|
| 5,303 | |
Tax Deduction for Stock Options Exercised and |
|
|
|
|
|
|
|
|
| |
Employee Stock Purchase Plan Disqualifying |
|
|
|
|
|
|
|
|
| |
Dispositions |
|
|
| 913 |
|
|
|
| 913 | |
Capital Stock Expenses, Net |
|
|
| (12,529) |
|
|
|
| (12,529) | |
Other Comprehensive Loss |
|
|
|
|
|
| (5,474) |
| (5,474) | |
Balance as of December 31, 2009 |
| 175,620,024 | 977,276 | 1,762,097 | (2,944) | 1,246,543 | (43,467) | (361,603) | 3,577,902 | |
Net Income |
|
|
|
|
| 394,107 |
|
| 394,107 | |
Dividends on Common Shares - $1.025 Per Share |
|
|
|
|
| (181,715) |
|
| (181,715) | |
Issuance of Common Shares, $5 Par Value |
| 326,526 | 1,633 | 5,745 |
|
|
|
| 7,378 | |
Dividends on Preferred Stock |
|
|
|
|
| (6,101) |
|
| (6,101) | |
Net Income Attributable to Noncontrolling Interests |
|
|
|
|
| (57) |
|
| (57) | |
Allocation of Benefits – ESOP |
| 127,054 |
| 439 | 2,944 |
|
|
| 3,383 | |
ESOP Benefits from Treasury Shares |
|
|
| 3,856 |
|
|
| (3,856) | - | |
Change in Restricted Shares, Net |
|
|
| 4,868 |
|
|
|
| 4,868 | |
Change in Treasury Stock |
| 374,477 |
|
|
|
|
| 10,727 | 10,727 | |
Tax Deduction for Stock Options Exercised and |
|
|
|
|
|
|
|
|
| |
Employee Stock Purchase Plan Disqualifying |
|
|
|
|
|
|
|
|
| |
Dispositions |
|
|
| 866 |
|
|
|
| 866 | |
Capital Stock Expenses, Net |
|
|
| (279) |
|
|
|
| (279) | |
Other Comprehensive Income |
|
|
|
|
|
| 97 |
| 97 | |
Balance as of December 31, 2010 |
| 176,448,081 | $ 978,909 | $ 1,777,592 | $ - | $ 1,452,777 | $ (43,370) | $ (354,732) | $ 3,811,176 | |
|
|
|
|
|
|
|
|
|
|
80
NORTHEAST UTILITIES AND SUBSIDIARIES | |||
CONSOLIDATED STATEMENTS OF CAPITALIZATION | |||
| As of December 31, | ||
(Thousands of Dollars) | 2010 | 2009 | |
Common Shareholders’ Equity | $ 3,811,176 | $ 3,577,902 | |
Noncontrolling Interests | 1,457 | - | |
Preferred Stock: |
|
| |
CL&P Preferred Stock Not Subject to Mandatory Redemption - $50 par value - authorized 9,000,000 shares in 2010 and 2009; 2,324,000 shares outstanding in 2010 and 2009; Dividend rates of $1.90 to $3.24; Current redemption prices of $50.50 to $54.00 | 116,200 | 116,200 | |
Long-Term Debt: First Mortgage Bonds: |
|
| |
Final Maturity | Interest Rates |
|
|
2010-2012 | 7.19% | 8,571 | 12,857 |
2014-2018 | 4.80% to 6.90% | 1,205,000 | 1,205,000 |
2019-2024 | 4.50% to 8.48% | 659,845 | 609,845 |
2034-2037 | 5.35% to 6.375% | 830,000 | 830,000 |
Total First Mortgage Bonds |
| 2,703,416 | 2,657,702 |
Other Long-Term Debt: Pollution Control Notes: |
|
|
|
2016-2018 | 5.90% | 25,400 | 25,400 |
2021-2022 | Variable Rate and 4.75% to 6.00% | 428,285 | 428,285 |
2028 | 5.85% to 5.95% | 369,300 | 369,300 |
2031 (Note 9) | 1.40% | 62,000 | 62,000 |
Other: |
|
|
|
2012-2020 | 5.00% to 7.25% | 713,000 | 618,000 |
2034-2037 | 5.90% to 6.70% | 90,000 | 90,000 |
Total Pollution Control Notes and Other | 1,687,985 | 1,592,985 | |
Total First Mortgage Bonds, Pollution Control Notes and Other | 4,391,401 | 4,250,687 | |
Fees and Interest Due for Spent Nuclear Fuel Disposal Costs | 301,042 | 300,647 | |
Change in Fair Value Resulting from Interest Rate Hedge Instrument | 11,859 | 13,258 | |
Unamortized Premium and Discount, Net and Other | (5,150) | (5,371) | |
Total Long-Term Debt | 4,699,152 | 4,559,221 | |
Less: Amounts Due Within One Year | 66,286 | 66,286 | |
Long-Term Debt | 4,632,866 | 4,492,935 | |
Total Capitalization | $ 8,561,699 | $ 8,187,037 |
The accompanying notes are an integral part of these consolidated financial statements.
81
Company Report on Internal Controls Over Financial Reporting
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of The Connecticut Light and Power Company and subsidiaries (CL&P or the Company) and of other sections of this annual report. CL&P’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2010.
February 25, 2011
82
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2010 and 2009, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the consolidated financial statement schedules listed in the Index at Item 15 of Part IV. We also have audited the Company's internal control over financial reporting as of December 31, 2010, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedules, for mai ntaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company's internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effe ctivenesseffectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting p rinciples,pri nciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northeast UtilitiesThe Connecticut Light and Power Company and subsidiaries as of December 31, 20082010 and 2007,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008,2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008,2010, based on the criteria established inInternal Control -— Integrated Frameworkissued by the Committee of Spo nsoringSponsoring Organizations of the Treadway Commission.
As discussed in Note 4, the Company adopted Financial Accounting Standards Board Statement No. 157,CommissionFair Value Measurements., as of January 1, 2008.
/s/ | Deloitte & Touche LLP |
| Deloitte & Touche LLP |
Hartford, Connecticut
February 27, 200925, 2011
FS-283
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
|
CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
| At December 31, | ||
(Thousands of Dollars) |
| 2008 |
| 2007 |
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
Cash and cash equivalents |
| $ 89,816 |
| $ 15,104 |
Investments in securitizable assets (Note 1L) |
| - |
| 308,182 |
Receivables, less provision for uncollectible |
|
|
|
|
accounts of $43,275 in 2008 and $25,529 in 2007 |
| 698,755 |
| 401,283 |
Unbilled revenues |
| 218,440 |
| 101,860 |
Taxes receivable |
| - |
| 13,850 |
Fuel, materials and supplies |
| 300,049 |
| 210,850 |
Marketable securities - current |
| 78,452 |
| 70,816 |
Derivative assets - current |
| 31,373 |
| 105,517 |
Prepayments and other |
| 88,679 |
| 58,794 |
|
| 1,505,564 |
| 1,286,256 |
|
|
|
|
|
Property, Plant and Equipment: |
|
|
|
|
Electric utility |
| 9,219,351 |
| 7,594,606 |
Gas utility |
| 1,043,687 |
| 977,290 |
Other |
| 290,156 |
| 310,535 |
|
| 10,553,194 |
| 8,882,431 |
Less: Accumulated depreciation: $2,610,479 for electric |
|
|
|
|
and gas utility and $159,639 for other in 2008; |
|
|
|
|
$2,483,570 for electric and gas utility and |
|
|
|
|
$178,193 for other in 2007 |
| 2,770,118 |
| 2,661,763 |
|
| 7,783,076 |
| 6,220,668 |
Construction work in progress |
| 424,800 |
| 1,009,277 |
|
| 8,207,876 |
| 7,229,945 |
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
Regulatory assets |
| 3,502,606 |
| 2,057,083 |
Goodwill |
| 287,591 |
| 287,591 |
Prepaid pension |
| - |
| 202,512 |
Marketable securities - long-term |
| 30,757 |
| 53,281 |
Derivative assets - long-term |
| 241,814 |
| 298,001 |
Other |
| 212,272 |
| 167,153 |
|
| 4,275,040 |
| 3,065,621 |
Total Assets |
| $ 13,988,480 |
| $ 11,581,822 |
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
| ||
|
|
|
|
|
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES |
|
| |||
CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, | |||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
Cash | $ | 9,762 |
| $ | 45 |
Receivables, Net |
| 317,530 |
|
| 327,969 |
Accounts Receivable from Affiliated Companies |
| 822 |
|
| 2,362 |
Notes Receivable from Affiliated Companies |
| - |
|
| 97,775 |
Unbilled Revenues |
| 116,392 |
|
| 140,632 |
Taxes Receivable |
| 48,360 |
|
| 147 |
Materials and Supplies |
| 63,811 |
|
| 65,623 |
Derivative Assets |
| 7,870 |
|
| 24,593 |
Accumulated Deferred Income Taxes |
| 32,393 |
|
| - |
Prepayments and Other Current Assets |
| 19,596 |
|
| 18,238 |
Total Current Assets |
| 616,536 |
|
| 677,384 |
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| 5,586,504 |
|
| 5,340,561 |
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
|
Regulatory Assets |
| 1,878,945 |
|
| 2,068,778 |
Derivative Assets |
| 115,870 |
|
| 183,231 |
Other Long-Term Assets |
| 89,730 |
|
| 94,610 |
Total Deferred Debits and Other Assets |
| 2,084,545 |
|
| 2,346,619 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets | $ | 8,287,585 |
| $ | 8,364,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. | |||||
|
FS-384
NORTHEAST UTILITIES AND SUBSIDIARIES | . |
|
|
|
CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
| At December 31, | ||
(Thousands of Dollars) |
| 2008 |
| 2007 |
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
Notes payable to banks |
| $ 618,897 |
| $ 79,000 |
Long-term debt - current portion |
| 54,286 |
| 154,286 |
Accounts payable |
| 678,614 |
| 598,546 |
Accrued taxes |
| 12,527 |
| - |
Accrued interest |
| 69,818 |
| 56,592 |
Derivative liabilities - current |
| 100,919 |
| 71,601 |
Other |
| 168,401 |
| 246,125 |
|
| 1,703,462 |
| 1,206,150 |
|
|
|
|
|
Rate Reduction Bonds |
| 686,511 |
| 917,436 |
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
Accumulated deferred income taxes |
| 1,223,461 |
| 1,067,490 |
Accumulated deferred investment tax credits |
| 25,371 |
| 28,845 |
Deferred contractual obligations |
| 193,016 |
| 222,908 |
Regulatory liabilities |
| 592,540 |
| 851,780 |
Derivative liabilities - long-term |
| 912,426 |
| 208,461 |
Accrued pension |
| 740,930 |
| - |
Accrued postretirement benefits |
| 240,371 |
| 181,507 |
Other |
| 430,718 |
| 383,611 |
|
| 4,358,833 |
| 2,944,602 |
Capitalization: |
|
|
|
|
Long-Term Debt |
| 4,103,162 |
| 3,483,599 |
|
|
|
|
|
Preferred Stock of Subsidiary - Non-Redeemable |
| 116,200 |
| 116,200 |
|
|
|
|
|
Common Shareholders' Equity: |
|
|
|
|
Common shares, $5 par value - authorized |
|
|
|
|
225,000,000 shares; 176,212,275 shares issued |
|
|
|
|
and 155,834,361 shares outstanding in 2008 and |
|
|
|
|
175,924,694 shares issued and 155,079,770 shares |
|
|
|
|
outstanding in 2007 |
| 881,061 |
| 879,623 |
Capital surplus, paid in |
| 1,475,006 |
| 1,465,946 |
Deferred contribution plan - employee stock ownership plan |
| (15,481) |
| (26,352) |
Retained earnings |
| 1,078,594 |
| 946,792 |
Accumulated other comprehensive (loss)/income |
| (37,265) |
| 9,359 |
Treasury stock, 19,708,136 shares in 2008 and 19,705,545 shares in 2007 |
| (361,603) |
| (361,533) |
Common Shareholders' Equity |
| 3,020,312 |
| 2,913,835 |
Total Capitalization |
| 7,239,674 |
| 6,513,634 |
|
|
|
|
|
Commitments and Contingencies (Note 7) |
|
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization |
| $ 13,988,480 |
| $ 11,581,822 |
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES |
|
| |||
CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, | |||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
Notes Payable to Affiliated Companies | $ | 6,225 |
| $ | - |
Long-Term Debt - Current Portion |
| 62,000 |
|
| 62,000 |
Accounts Payable |
| 204,868 |
|
| 242,853 |
Accounts Payable to Affiliated Companies |
| 53,207 |
|
| 48,795 |
Obligations to Third Party Suppliers |
| 68,692 |
|
| 39,609 |
Accrued Taxes |
| 92,061 |
|
| 36,860 |
Accrued Interest |
| 42,548 |
|
| 49,867 |
Derivative Liabilities |
| 46,781 |
|
| 9,770 |
Other Current Liabilities |
| 45,835 |
|
| 61,237 |
Total Current Liabilities |
| 622,217 |
|
| 550,991 |
|
|
|
|
|
|
Rate Reduction Bonds |
| - |
|
| 195,587 |
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
Accumulated Deferred Income Taxes |
| 1,101,111 |
|
| 901,527 |
Regulatory Liabilities |
| 282,110 |
|
| 316,160 |
Derivative Liabilities |
| 883,091 |
|
| 913,349 |
Accrued Pension |
| 42,486 |
|
| 51,319 |
Other Long-Term Liabilities |
| 321,793 |
|
| 425,887 |
Total Deferred Credits and Other Liabilities |
| 2,630,591 |
|
| 2,608,242 |
|
|
|
|
|
|
Capitalization: |
|
|
|
|
|
Long-Term Debt |
| 2,521,102 |
|
| 2,520,361 |
|
|
|
|
|
|
Preferred Stock Not Subject to Mandatory Redemption |
| 116,200 |
|
| 116,200 |
|
|
|
|
|
|
Common Stockholder's Equity: |
|
|
|
|
|
Common Stock |
| 60,352 |
|
| 60,352 |
Capital Surplus, Paid In |
| 1,605,275 |
|
| 1,601,792 |
Retained Earnings |
| 734,561 |
|
| 714,210 |
Accumulated Other Comprehensive Loss |
| (2,713) |
|
| (3,171) |
Common Stockholder's Equity |
| 2,397,475 |
|
| 2,373,183 |
Total Capitalization |
| 5,034,777 |
|
| 5,009,744 |
|
|
|
|
|
|
Commitments and Contingencies (Note 12) |
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 8,287,585 |
| $ | 8,364,564 |
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
FS-485
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF INCOME |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||
(Thousands of Dollars, except share information) |
| 2008 |
| 2007 |
| 2006 |
|
|
|
|
|
|
|
Operating Revenues |
| $ 5,800,095 |
| $ 5,822,226 |
| $ 6,877,687 |
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
Operation - |
|
|
|
|
|
|
Fuel, purchased and net interchange power |
| 2,996,180 |
| 3,350,673 |
| 4,630,798 |
Other |
| 1,021,704 |
| 961,285 |
| 1,121,534 |
Maintenance |
| 254,038 |
| 211,589 |
| 193,706 |
Depreciation |
| 278,588 |
| 265,297 |
| 240,559 |
Amortization of regulatory assets, net |
| 186,396 |
| 40,674 |
| 16,292 |
Amortization of rate reduction bonds |
| 204,859 |
| 201,039 |
| 188,247 |
Taxes other than income taxes |
| 267,565 |
| 252,188 |
| 250,580 |
Total operating expenses |
| 5,209,330 |
| 5,282,745 |
| 6,641,716 |
Operating Income |
| 590,765 |
| 539,481 |
| 235,971 |
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
Interest on long-term debt |
| 193,883 |
| 162,841 |
| 141,579 |
Interest on rate reduction bonds |
| 50,231 |
| 61,580 |
| 74,242 |
Other interest |
| 25,031 |
| 15,824 |
| 22,375 |
Interest expense, net |
| 269,145 |
| 240,245 |
| 238,196 |
Other Income, Net |
| 50,428 |
| 61,639 |
| 64,394 |
Income from Continuing Operations Before |
|
|
|
|
|
|
Income Tax Expense/(Benefit) |
| 372,048 |
| 360,875 |
| 62,169 |
Income Tax Expense/(Benefit) |
| 105,661 |
| 109,420 |
| (76,326) |
Income from Continuing Operations Before |
|
|
|
|
|
|
Preferred Dividends of Subsidiary |
| 266,387 |
| 251,455 |
| 138,495 |
Preferred Dividends of Subsidiary |
| 5,559 |
| 5,559 |
| 5,559 |
Income from Continuing Operations |
| 260,828 |
| 245,896 |
| 132,936 |
Discontinued Operations (Note 14): |
|
|
|
|
|
|
Income from Discontinued Operations |
| - |
| 435 |
| 31,321 |
Gains from Sale/Disposition of Discontinued Operations |
| - |
| 2,054 |
| 504,314 |
Income Tax Expense |
| - |
| 1,902 |
| 197,993 |
Income from Discontinued Operations |
| - |
| 587 |
| 337,642 |
Net Income |
| $ 260,828 |
| $ 246,483 |
| $ 470,578 |
|
|
|
|
|
|
|
Basic Earnings Per Common Share: |
|
|
|
|
|
|
Income from Continuing Operations |
| $ 1.68 |
| $ 1.59 |
| $ 0.86 |
Income from Discontinued Operations |
| - |
| - |
| 2.20 |
Basic Earnings Per Common Share |
| $ 1.68 |
| $ 1.59 |
| $ 3.06 |
|
|
|
|
|
|
|
Fully Diluted Earnings Per Common Share: |
|
|
|
|
|
|
Income from Continuing Operations |
| $ 1.67 |
| $ 1.59 |
| $ 0.86 |
Income from Discontinued Operations |
| - |
| - |
| 2.19 |
Fully Diluted Earnings Per Common Share |
| $ 1.67 |
| $ 1.59 |
| $ 3.05 |
|
|
|
|
|
|
|
Basic Common Shares Outstanding (weighted average) |
| 155,531,846 |
| 154,759,727 |
| 153,767,527 |
Fully Diluted Common Shares Outstanding (weighted average) |
| 155,999,240 |
| 155,304,361 |
| 154,146,669 |
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES | ||||||||
CONSOLIDATED STATEMENTS OF INCOME |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
| 2008 |
|
|
|
|
|
|
|
|
|
Operating Revenues | $ | 2,999,102 |
| $ | 3,424,538 |
| $ | 3,558,361 |
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
| 1,253,329 |
|
| 1,690,671 |
|
| 1,845,367 |
Other Operating Expenses |
| 524,328 |
|
| 571,024 |
|
| 557,565 |
Maintenance |
| 96,522 |
|
| 117,822 |
|
| 130,365 |
Depreciation |
| 172,167 |
|
| 186,922 |
|
| 162,636 |
Amortization of Regulatory Assets, Net |
| 83,906 |
|
| 45,821 |
|
| 164,246 |
Amortization of Rate Reduction Bonds |
| 167,021 |
|
| 155,938 |
|
| 145,590 |
Taxes Other Than Income Taxes |
| 214,179 |
|
| 191,234 |
|
| 179,201 |
Total Operating Expenses |
| 2,511,452 |
|
| 2,959,432 |
|
| 3,184,970 |
Operating Income |
| 487,650 |
|
| 465,106 |
|
| 373,391 |
|
|
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
|
|
Interest on Long-Term Debt |
| 134,553 |
|
| 133,422 |
|
| 104,954 |
Interest on Rate Reduction Bonds |
| 7,542 |
|
| 19,061 |
|
| 29,129 |
Other Interest (Note 11) |
| (4,357) |
|
| 3,334 |
|
| 12,163 |
Interest Expense |
| 137,738 |
|
| 155,817 |
|
| 146,246 |
Other Income, Net |
| 26,669 |
|
| 25,874 |
|
| 41,865 |
Income Before Income Tax Expense |
| 376,581 |
|
| 335,163 |
|
| 269,010 |
Income Tax Expense |
| 132,438 |
|
| 118,847 |
|
| 77,852 |
Net Income | $ | 244,143 |
| $ | 216,316 |
| $ | 191,158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
|
|
|
|
|
Net Income | $ | 244,143 |
| $ | 216,316 |
| $ | 191,158 |
Other Comprehensive Income/(Loss), Net of Tax: |
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| 444 |
|
| 445 |
|
| (3,348) |
Changes in Unrealized Gains/(Losses) on Other Securities |
| 14 |
|
| (30) |
|
| (59) |
Other Comprehensive Income/(Loss), Net of Tax |
| 458 |
|
| 415 |
|
| (3,407) |
Comprehensive Income | $ | 244,601 |
| $ | 216,731 |
| $ | 187,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
FS-587
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
|
|
|
| For the Years Ended December 31, | |||||
(Thousands of Dollars) |
| 2008 |
| 2007 |
| 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
| $ 260,828 |
| $ 246,483 |
| $ 470,578 |
Other comprehensive (loss)/income, net of tax: |
|
|
|
|
|
|
Qualified cash flow hedging instruments |
| (6,909) |
| (3,591) |
| (12,340) |
Changes in unrealized gains on securities |
| (1,669) |
| (101) |
| 718 |
Change in funded status of pension, SERP and other post |
|
|
|
|
|
|
retirement plans |
| (38,046) |
| 8,553 |
| - |
Minimum SERP liability |
| - |
| - |
| 379 |
Other comprehensive (loss)/income, net of tax |
| (46,624) |
| 4,861 |
| (11,243) |
Comprehensive Income |
| $ 214,204 |
| $ 251,344 |
| $ 459,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
|
|
FS-6
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
|
|
| |||
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY |
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Deferred |
| Accumulated |
|
|
|
|
|
| Capital | Contribution |
| Other |
|
|
(Thousands of Dollars, except |
| Common Shares | Surplus, | Plan - | Retained | Comprehensive | Treasury |
| |
share information) |
| Shares | Amount | Paid In | ESOP | Earnings | Income/(Loss) | Stock | Total |
Balance as of |
|
|
|
|
|
|
|
|
|
January 1, 2006 |
| 153,225,892 | $ 874,489 | $1,437,561 | $(46,884) | $ 504,301 | $ 19,987 | $(360,210) | $2,429,244 |
Net income for 2006 |
|
|
|
|
| 470,578 |
|
| 470,578 |
Dividends on common shares - |
|
|
|
|
|
|
|
|
|
$0.725 per share |
|
|
|
|
| (112,219) |
|
| (112,219) |
Issuance of common shares, $5 par value |
| 522,535 | 2,612 | 6,882 |
|
|
|
| 9,494 |
Allocation of benefits - ESOP |
| 523,452 |
| (618) | 12,118 |
|
|
| 11,500 |
Change in restricted shares, net |
| (38,738) |
| 4,293 |
|
|
| (690) | 3,603 |
Tax deduction for stock options exercised |
|
|
|
|
|
|
|
|
|
and Employee Stock Purchase |
|
|
|
|
|
|
|
|
|
Plan disqualifying dispositions |
|
|
| 1,112 |
|
|
|
| 1,112 |
Capital stock expenses, net |
|
|
| 356 |
|
|
|
| 356 |
Adjustment to funded status of pension, |
|
|
|
|
|
|
|
| |
SERP and other post retirement |
|
|
|
|
|
|
|
| |
plans (SFAS No. 158) |
|
|
|
|
| (4,246) |
| (4,246) | |
Other comprehensive loss |
|
|
|
|
|
| (11,243) |
| (11,243) |
Balance as of |
|
|
|
|
|
|
|
|
|
December 31, 2006 |
| 154,233,141 | 877,101 | 1,449,586 | (34,766) | 862,660 | 4,498 | (360,900) | 2,798,179 |
Adoption of FIN48 - accounting for |
|
|
|
|
|
|
|
|
|
uncertainty of income taxes |
|
|
|
|
| (41,816) |
|
| (41,816) |
Net income for 2007 |
|
|
|
|
| 246,483 |
|
| 246,483 |
Dividends on common shares - |
|
|
|
|
|
|
|
|
|
$0.775 per share |
|
|
|
|
| (120,535) |
|
| (120,535) |
Issuance of common shares, $5 par value |
| 504,455 | 2,522 | 6,534 |
|
|
|
| 9,056 |
Allocation of benefits - ESOP |
| 363,470 |
| 2,129 | 8,414 |
|
|
| 10,543 |
Change in restricted shares, net |
| (21,104) |
| 4,368 |
|
|
| (627) | 3,741 |
Change in treasury stock |
| (192) |
| 6 |
|
|
| (6) | - |
Tax deduction for stock options exercised |
|
|
|
|
|
|
|
|
|
and Employee Stock Purchase |
|
|
|
|
|
|
|
|
|
Plan disqualifying dispositions |
|
|
| 3,183 |
|
|
|
| 3,183 |
Capital stock expenses, net |
|
|
| 140 |
|
|
|
| 140 |
Other comprehensive income |
|
|
|
|
|
| 4,861 |
| 4,861 |
Balance as of |
|
|
|
|
|
|
|
|
|
December 31, 2007 |
| 155,079,770 | 879,623 | 1,465,946 | (26,352) | 946,792 | 9,359 | (361,533) | 2,913,835 |
Net income for 2008 |
|
|
|
|
| 260,828 |
|
| 260,828 |
Dividends on common shares - |
|
|
|
|
|
|
|
|
|
$0.825 per share |
|
|
|
|
| (129,026) |
|
| (129,026) |
Issuance of common shares, $5 par value |
| 287,581 | 1,438 | 4,086 |
|
|
|
| 5,524 |
Allocation of benefits - ESOP |
| 469,601 |
| 865 | 10,871 |
|
|
| 11,736 |
Change in restricted shares, net |
| (2,591) |
| 2,436 |
|
|
| (70) | 2,366 |
Tax deduction for stock options exercised |
|
|
|
|
|
|
|
|
|
and Employee Stock Purchase |
|
|
|
|
|
|
|
|
|
Plan disqualifying dispositions |
|
|
| 1,622 |
|
|
|
| 1,622 |
Capital stock expenses, net |
|
|
| 51 |
|
|
|
| 51 |
Other comprehensive loss |
|
|
|
|
|
| (46,624) |
| (46,624) |
Balance as of |
|
|
|
|
|
|
|
|
|
December 31, 2008 |
| 155,834,361 | $ 881,061 | $1,475,006 | $(15,481) | $1,078,594 | $ (37,265) | $(361,603) | $3,020,312 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
FS-788
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||
(Thousands of Dollars) | 2008 |
| 2007 |
| 2006 |
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
|
Net income | $ 260,828 |
| $ 246,483 |
| $ 470,578 |
Adjustments to reconcile to net cash flows |
|
|
|
|
|
provided by operating activities: |
|
|
|
|
|
Pre-tax gains from sale/disposition of discontinued operations | - |
| (2,054) |
| (504,314) |
Bad debt expense | 28,573 |
| 29,140 |
| 29,366 |
Depreciation | 278,588 |
| 265,297 |
| 243,822 |
Deferred income taxes | 86,810 |
| 6,933 |
| (204,212) |
Amortization of investment tax credits | (3,474) |
| (3,583) |
| (3,673) |
Pension and PBOP expense and contributions, net of capitalized portion | (3,839) |
| 10,865 |
| 38,994 |
Stock-based compensation expense | 13,518 |
| 13,855 |
| 14,718 |
Allowance for equity funds used during construction | (29,028) |
| (17,417) |
| (13,573) |
Impairment of marketable securities | 17,399 |
| 2,539 |
| - |
(Deferral)/amortization of recoverable energy costs | (10,590) |
| 11,715 |
| 15,609 |
Amortization of rate reduction bonds | 204,859 |
| 201,039 |
| 188,247 |
Amortization of regulatory assets, net | 186,396 |
| 40,674 |
| 16,292 |
Regulatory (refunds and underrecoveries)/overrecoveries | (174,662) |
| 37,010 |
| (96,560) |
Derivative assets and liabilities | (37,052) |
| (43,808) |
| (90,867) |
Deferred contractual obligations | (32,326) |
| (41,950) |
| (90,671) |
(Increase)/decrease in other deferred debits | (16,873) |
| (5,026) |
| 2,837 |
Increase/(decrease) in other deferred credits | 4,735 |
| (8,784) |
| (10,451) |
Other adjustments | (5,738) |
| (4,464) |
| 22,921 |
Changes in current assets and liabilities: |
|
|
|
|
|
Receivables and unbilled revenues, net | (141,879) |
| (65,381) |
| 605,366 |
Fuel, materials and supplies | (74,531) |
| (33,727) |
| 16,718 |
Investments in securitizable assets | (25,787) |
| 33,531 |
| (158,651) |
Other current assets | (4,677) |
| 3,878 |
| 58,350 |
Accounts payable | 72,791 |
| (49,554) |
| (399,386) |
Counterparty deposits and margin special deposits | (7,474) |
| 29,505 |
| 26,469 |
Taxes receivable/accrued | 63,251 |
| (392,611) |
| 271,477 |
Other current liabilities | (400) |
| (15,670) |
| (42,332) |
Net cash flows provided by operating activities | 649,418 |
| 248,435 |
| 407,074 |
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
Investments in property and plant | (1,255,407) |
| (1,114,824) |
| (872,181) |
Net proceeds from sales of competitive businesses | - |
| - |
| 1,053,099 |
Cash payments related to the sale of competitive businesses | - |
| (16,648) |
| (32,359) |
Proceeds from sales of marketable securities | 259,361 |
| 254,832 |
| 193,459 |
Purchases of marketable securities | (262,357) |
| (261,777) |
| (193,917) |
Rate reduction bond escrow and other deposits | 1,686 |
| 63,722 |
| (50,686) |
Other investing activities | 3,360 |
| 7,229 |
| 19,649 |
Net cash flows (used in)/provided by investing activities | (1,253,357) |
| (1,067,466) |
| 117,064 |
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
Issuance of common shares related to share-based compensation | 5,524 |
| 9,056 |
| 9,494 |
Cash dividends on common shares | (129,077) |
| (120,988) |
| (112,745) |
Increase/(decrease) in short-term debt | 539,897 |
| 79,000 |
| (32,000) |
Issuance of long-term debt | 760,000 |
| 655,000 |
| 250,000 |
Reacquisition and retirements of long-term debt | (261,286) |
| (4,877) |
| (28,843) |
Retirements of rate reduction bonds | (230,925) |
| (259,722) |
| (173,344) |
Other financing activities | (5,482) |
| (5,245) |
| (571) |
Net cash flows provided by/(used in) financing activities | 678,651 |
| 352,224 |
| (88,009) |
Net increase/(decrease) in cash and cash equivalents | 74,712 |
| (466,807) |
| 436,129 |
Cash and cash equivalents - beginning of year | 15,104 |
| 481,911 |
| 45,782 |
Cash and cash equivalents - end of year | $ 89,816 |
| $ 15,104 |
| $ 481,911 |
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
FS-8
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES | ||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||
|
|
| ||||||
|
|
| ||||||
|
|
| ||||||
|
| For the Years Ended December 31, | ||||||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
| 2008 |
|
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
|
|
|
|
Net Income | $ | 244,143 |
| $ | 216,316 |
| $ | 191,158 |
Adjustments to Reconcile Net Income to Net Cash Flows |
|
|
|
|
|
|
|
|
Provided by Operating Activities: |
|
|
|
|
|
|
|
|
Bad Debt Expense |
| 7,484 |
|
| 15,276 |
|
| 5,951 |
Depreciation |
| 172,167 |
|
| 186,922 |
|
| 162,636 |
Deferred Income Taxes |
| 115,069 |
|
| 52,900 |
|
| 47,653 |
Pension and PBOP Expense, Net of PBOP Contributions |
| 1,595 |
|
| (10,709) |
|
| (19,257) |
Regulatory Overrecoveries/(Underrecoveries), Net |
| 32,492 |
|
| 51,292 |
|
| (153,843) |
Amortization of Regulatory Assets, Net |
| 83,906 |
|
| 45,821 |
|
| 164,246 |
Amortization of Rate Reduction Bonds |
| 167,021 |
|
| 155,938 |
|
| 145,590 |
Other |
| (55,515) |
|
| (38,731) |
|
| (50,670) |
Changes in Current Assets and Liabilities: |
|
|
|
|
|
|
|
|
Receivables and Unbilled Revenues, Net |
| 1,895 |
|
| 50,327 |
|
| (125,241) |
Investments in Securitizable Assets |
| - |
|
| - |
|
| (25,787) |
Materials and Supplies |
| 3,377 |
|
| (6,339) |
|
| (15,204) |
Taxes Receivable/Accrued |
| (56,002) |
|
| 25,823 |
|
| 60,864 |
Accounts Payable |
| (35,976) |
|
| (85,773) |
|
| 28,772 |
Other Current Assets and Liabilities |
| 15,649 |
|
| 5,718 |
|
| 20,885 |
Net Cash Flows Provided by Operating Activities |
| 697,305 |
|
| 664,781 |
|
| 437,753 |
|
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
|
|
|
Investments in Property, Plant and Equipment |
| (380,304) |
|
| (435,723) |
|
| (849,549) |
Decrease/(Increase) in NU Money Pool Lending |
| 97,775 |
|
| (97,775) |
|
| - |
Other Investing Activities |
| 5,385 |
|
| 4,888 |
|
| (2,443) |
Net Cash Flows Used in Investing Activities |
| (277,144) |
|
| (528,610) |
|
| (851,992) |
|
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
|
|
|
Cash Dividends on Common Stock |
| (217,691) |
|
| (113,848) |
|
| (106,461) |
Cash Dividends on Preferred Stock |
| (5,559) |
|
| (5,559) |
|
| (5,559) |
(Decrease)/Increase in Short-Term Debt |
| - |
|
| (187,973) |
|
| 187,973 |
Issuance of Long-Term Debt |
| - |
|
| 312,000 |
|
| 300,000 |
Increase/(Decrease) in NU Money Pool Borrowings |
| 6,225 |
|
| (102,725) |
|
| 63,900 |
Retirements of Rate Reduction Bonds |
| (195,587) |
|
| (182,608) |
|
| (170,491) |
Capital Contributions from NU Parent |
| 2,513 |
|
| 147,591 |
|
| 210,000 |
Reacquisition of Long-Term Debt |
| - |
|
| - |
|
| (62,000) |
Other Financing Activities |
| (345) |
|
| (3,004) |
|
| (3,661) |
Net Cash Flows (Used in)/Provided by Financing Activities |
| (410,444) |
|
| (136,126) |
|
| 413,701 |
Net Increase/(Decrease) in Cash |
| 9,717 |
|
| 45 |
|
| (538) |
Cash - Beginning of Year |
| 45 |
|
| - |
|
| 538 |
Cash - End of Year | $ | 9,762 |
| $ | 45 |
| $ | - |
|
|
|
|
|
|
|
|
|
NORTHEAST UTILITIES AND SUBSIDIARIES | |||
CONSOLIDATED STATEMENTS OF CAPITALIZATION | |||
| At December 31, | ||
(Thousands of Dollars) | 2008 | 2007 | |
Common Shareholders’ Equity | $ 3,020,312 | $ 2,913,835 | |
Preferred Stock: |
|
| |
CL&P Preferred Stock Not Subject to Mandatory Redemption - $50 par value - authorized 9,000,000 shares in 2008 and 2007; 2,324,000 shares outstanding in 2008 and 2007; Dividend rates of $1.90 to $3.28; Current redemption prices of $50.50 to $54.00 | 116,200 | 116,200 | |
Long-Term Debt: First Mortgage Bonds: |
|
| |
Final Maturity | Interest Rates |
|
|
2009-2012 | 6.20% to 7.19% | 67,143 | 71,429 |
2014-2018 | 4.80% to 6.90% | 1,205,000 | 695,000 |
2019-2024 | 5.26% to 8.48% | 209,845 | 209,845 |
2026-2037 | 5.35% to 6.375% | 830,000 | 830,000 |
Total First Mortgage Bonds |
| 2,311,988 | 1,806,274 |
Other Long-Term Debt: Pollution Control Notes: |
|
|
|
2016-2018 | 5.90% | 25,400 | 25,400 |
2021-2022 | Variable Rate and 4.75% to 6.00% | 428,285 | 428,285 |
2028 | 5.85% to 5.95% | 369,300 | 369,300 |
2031 | 3.35% and Variable Rate in 2008; 3.35% in 2007 | 62,000 | 62,000 |
Other: |
|
|
|
2008-2009 | Variable Rate and 3.30% | - | 195,000 |
2012-2015 | 5.00% to 7.25% | 618,000 | 368,000 |
2034-2037 | 5.90% to 6.70% | 90,000 | 90,000 |
Total Pollution Control Notes and Other | 1,592,985 | 1,537,985 | |
Total First Mortgage Bonds, Pollution Control Notes and Other | 3,904,973 | 3,344,259 | |
Fees and interest due for spent nuclear fuel disposal costs | 298,555 | 294,305 | |
Change in fair value resulting from interest rate hedge instrument | 20,828 | 4,172 | |
Unamortized premium and discount, net | (4,908) | (4,851) | |
Reacquisition of Pollution Control Notes | (62,000) | - | |
Total Long-Term Debt | 4,157,448 | 3,637,885 | |
Less: Amounts due within one year | 54,286 | 154,286 | |
Long-Term Debt | 4,103,162 | 3,483,599 | |
Total Capitalization | $ 7,239,674 | $ 6,513,634 |
The accompanying notes are an integral part of these consolidated financial statements.
FS-9
Company Report on Internal Controls Over Financial Reporting
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of The Connecticut Light and Power Company and subsidiaries (CL&P or the Company) and of other sections of this annual report. This combined annual report does not include an attestation report from Deloitte & Touche LLP regarding the internal controls over financial reporting for CL&P. Management’s report on behalf of CL&P was not subject to attestation pursuant to temporary rules of the Securities and Exchange Commission that permit this company to provide only management’s report in this combined annual report.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2008.
February 27, 2009
FS-10
Report of Independent Registered Public Accounting Firm
To the Board of Directors ofThe Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2008 and 2007, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the consolidated financial statement schedules listed in the Index at Item 15. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 4, the Company adopted Financial Accounting Standards Board Statement No. 157,Fair Value Measurement, as of January 1, 2008.
|
|
|
Hartford, Connecticut
February 27, 2009
FS-11
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES |
|
|
| ||
|
|
|
|
|
|
CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
|
|
|
|
|
|
|
| At December 31, | |||
(Thousands of Dollars) |
| 2008 |
|
| 2007 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
Cash |
| $ - |
|
| $ 538 |
Investments in securitizable assets (Note 1L) |
| - |
|
| 308,182 |
Receivables, less provision for uncollectible |
|
|
|
|
|
accounts of $23,956 in 2008 and $7,874 in 2007 |
| 416,304 |
|
| 118,342 |
Accounts receivable from affiliated companies |
| 11,215 |
|
| 3,339 |
Unbilled revenues |
| 127,844 |
|
| 8,225 |
Taxes receivable |
| - |
|
| 16,245 |
Materials and supplies |
| 70,676 |
|
| 55,477 |
Derivative assets - current |
| 30,478 |
|
| 57,003 |
Prepayments and other |
| 15,685 |
|
| 17,387 |
|
| 672,202 |
|
| 584,738 |
|
|
|
|
|
|
Property, Plant and Equipment: |
|
|
|
|
|
Electric utility |
| 6,244,705 |
|
| 4,899,075 |
Less: Accumulated depreciation |
| 1,346,062 |
|
| 1,279,697 |
|
| 4,898,643 |
|
| 3,619,378 |
Construction work in progress |
| 190,481 |
|
| 782,468 |
|
| 5,089,124 |
|
| 4,401,846 |
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
|
Regulatory assets |
| 2,274,088 |
|
| 1,329,963 |
Prepaid pension |
| - |
|
| 334,786 |
Derivative assets - long-term |
| 215,288 |
|
| 278,726 |
Other |
| 85,416 |
|
| 88,040 |
|
| 2,574,792 |
|
| 2,031,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
| $ 8,336,118 |
|
| $ 7,018,099 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
FS-12
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES | |||||
| |||||
CONSOLIDATED BALANCE SHEETS | |||||
| |||||
|
| At December 31, | |||
(Thousands of Dollars) |
| 2008 |
|
| 2007 |
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
Notes payable to banks |
| $ 187,973 |
|
| $ - |
Notes payable to affiliated companies |
| 102,725 |
|
| 38,825 |
Accounts payable |
| 353,584 |
|
| 368,356 |
Accounts payable to affiliated companies |
| 57,053 |
|
| 53,096 |
Accrued taxes |
| 24,839 |
|
| - |
Accrued interest |
| 37,567 |
|
| 29,532 |
Derivative liabilities - current |
| 8,873 |
|
| 4,234 |
Other |
| 92,444 |
|
| 107,940 |
|
| 865,058 |
|
| 601,983 |
|
|
|
|
|
|
Rate Reduction Bonds |
| 378,195 |
|
| 548,686 |
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
Accumulated deferred income taxes - long-term |
| 811,405 |
|
| 698,789 |
Accumulated deferred investment tax credits |
| 18,805 |
|
| 21,412 |
Deferred contractual obligations |
| 132,687 |
|
| 152,735 |
Regulatory liabilities |
| 363,547 |
|
| 601,455 |
Derivative liabilities - long-term |
| 848,106 |
|
| 135,991 |
Accrued pension |
| 89,254 |
|
| - |
Accrued postretirement benefits |
| 98,587 |
|
| 78,587 |
Other |
| 215,620 |
|
| 191,464 |
|
| 2,578,011 |
|
| 1,880,433 |
Capitalization: |
|
|
|
|
|
Long-Term Debt |
| 2,270,414 |
|
| 2,028,546 |
|
|
|
|
|
|
Preferred Stock - Non-Redeemable |
| 116,200 |
|
| 116,200 |
|
|
|
|
|
|
Common Stockholder's Equity: |
|
|
|
|
|
Common stock, $10 par value - authorized |
|
|
|
|
|
24,500,000 shares; 6,035,205 shares outstanding |
|
|
|
|
|
in 2008 and 2007 |
| 60,352 |
|
| 60,352 |
Capital surplus, paid in |
| 1,454,198 |
|
| 1,243,940 |
Retained earnings |
| 617,276 |
|
| 538,138 |
Accumulated other comprehensive loss |
| (3,586) |
|
| (179) |
Common Stockholder's Equity |
| 2,128,240 |
|
| 1,842,251 |
Total Capitalization |
| 4,514,854 |
|
| 3,986,997 |
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 7) |
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization |
| $ 8,336,118 |
|
| $ 7,018,099 |
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
FS-13
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES |
| |||||
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF INCOME |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||
(Thousands of Dollars) |
| 2008 |
| 2007 |
| 2006 |
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
| $ 3,558,361 |
| $ 3,681,817 |
| $ 3,979,811 |
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
Operation - |
|
|
|
|
|
|
Fuel, purchased and net interchange power |
| 1,845,367 |
| 2,277,054 |
| 2,603,882 |
Other |
| 557,565 |
| 535,750 |
| 614,372 |
Maintenance |
| 130,365 |
| 108,001 |
| 101,443 |
Depreciation |
| 162,636 |
| 152,005 |
| 147,460 |
Amortization of regulatory assets/(liabilities), net |
| 164,246 |
| 20,593 |
| (11,251) |
Amortization of rate reduction bonds |
| 145,590 |
| 135,929 |
| 126,909 |
Taxes other than income taxes |
| 179,201 |
| 167,943 |
| 160,926 |
Total operating expenses |
| 3,184,970 |
| 3,397,275 |
| 3,743,741 |
Operating Income |
| 373,391 |
| 284,542 |
| 236,070 |
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
Interest on long-term debt |
| 104,954 |
| 84,292 |
| 64,873 |
Interest on rate reduction bonds |
| 29,129 |
| 37,728 |
| 46,692 |
Other interest |
| 12,163 |
| 16,413 |
| 6,281 |
Interest expense, net |
| 146,246 |
| 138,433 |
| 117,846 |
Other Income, Net |
| 41,865 |
| 39,808 |
| 37,822 |
Income Before Income Tax Expense/(Benefit) |
| 269,010 |
| 185,917 |
| 156,046 |
Income Tax Expense/(Benefit) |
| 77,852 |
| 52,353 |
| (43,961) |
Net Income |
| $ 191,158 |
| $ 133,564 |
| $ 200,007 |
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
|
|
|
Net Income |
| $ 191,158 |
| $ 133,564 |
| $ 200,007 |
Other comprehensive (loss)/income, net of tax: |
|
|
|
|
|
|
Qualified cash flow hedging instruments |
| (3,348) |
| (4,814) |
| 4,537 |
Changes in unrealized gains on securities |
| (59) |
| (5) |
| 17 |
Minimum SERP liability |
| - |
| - |
| 364 |
Other comprehensive (loss)/income, net of tax |
| (3,407) |
| (4,819) |
| 4,918 |
Comprehensive Income |
| $ 187,751 |
| $ 128,745 |
| $ 204,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
FS-14
THE CONNECTICUT LIGHT AND POWER COMPANY |
|
|
|
| |||||||||||
| |||||||||||||||
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
|
|
|
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
| Accumulated |
|
| |||
|
|
|
|
|
| Capital |
|
|
| Other |
|
| |||
|
| Common Stock |
| Surplus, |
| Retained |
| Comprehensive |
|
| |||||
(Thousands of Dollars, except share information) | Shares |
| Amount |
| Paid In |
| Earnings |
| Income |
| Total | ||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Balance at January 1, 2006 |
| 6,035,205 |
| $ 60,352 |
| $ 612,815 |
| $ 382,628 |
| $ (278) |
| $ 1,055,517 | |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Net income for 2006 |
|
|
|
|
|
|
| 200,007 |
|
|
| 200,007 | |||
Dividends on preferred stock |
|
|
|
|
|
|
| (5,559) |
|
|
| (5,559) | |||
Dividends on common stock |
|
|
|
|
|
|
| (63,732) |
|
|
| (63,732) | |||
Allocation of benefits - ESOP |
|
|
|
|
| (157) |
|
|
|
|
| (157) | |||
Tax deduction for stock options |
|
|
|
|
|
|
|
|
|
| |||||
exercised and Employee Stock Purchase |
|
|
|
|
|
|
|
|
|
| |||||
Plan disqualifying dispositions |
|
|
| (995) |
|
|
|
|
| (995) | |||||
Capital stock expenses, net |
|
|
|
|
| 275 |
|
|
|
|
| 275 | |||
Capital contributions from NU parent |
|
|
|
|
| 60,755 |
|
|
|
|
| 60,755 | |||
Other comprehensive income |
|
|
|
|
|
|
|
|
| 4,918 |
| 4,918 | |||
Balance at December 31, 2006 |
| 6,035,205 |
| 60,352 |
| 672,693 |
| 513,344 |
| 4,640 |
| 1,251,029 | |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Adoption of FIN48 - accounting |
|
|
|
|
|
|
|
|
|
|
|
| |||
for uncertainty of income taxes |
|
|
|
|
|
|
| (24,030) |
|
|
| (24,030) | |||
Net income for 2007 |
|
|
|
|
|
|
| 133,564 |
|
|
| 133,564 | |||
Dividends on preferred stock |
|
|
|
|
|
|
| (5,559) |
|
|
| (5,559) | |||
Dividends on common stock |
|
|
|
|
|
|
| (79,181) |
|
|
| (79,181) | |||
Allocation of benefits - ESOP |
|
|
|
|
| 446 |
|
|
|
|
| 446 | |||
Capital stock expenses, net |
|
|
|
|
| 140 |
|
|
|
|
| 140 | |||
Capital contributions from NU parent |
|
|
|
|
| 570,661 |
|
|
|
|
| 570,661 | |||
Other comprehensive loss |
|
|
|
|
|
|
|
|
| (4,819) |
| (4,819) | |||
Balance at December 31, 2007 |
| 6,035,205 |
| 60,352 |
| 1,243,940 |
| 538,138 |
| (179) |
| 1,842,251 | |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Net income for 2008 |
|
|
|
|
|
|
| 191,158 |
|
|
| 191,158 | |||
Dividends on preferred stock |
|
|
|
|
|
|
| (5,559) |
|
|
| (5,559) | |||
Dividends on common stock |
|
|
|
|
|
|
| (106,461) |
|
|
| (106,461) | |||
Allocation of benefits - ESOP |
|
|
|
|
| 207 |
|
|
|
|
| 207 | |||
Capital stock expenses, net |
|
|
|
|
| 51 |
|
|
|
|
| 51 | |||
Capital contributions from NU parent |
|
|
|
|
| 210,000 |
|
|
|
|
| 210,000 | |||
Other comprehensive loss |
|
|
|
|
|
|
|
|
| (3,407) |
| (3,407) | |||
Balance at December 31, 2008 |
| 6,035,205 |
| $ 60,352 |
| $ 1,454,198 |
| $ 617,276 |
| $ (3,586) |
| $ 2,128,240 | |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
The accompanying notes are an integral part of these consolidated financial statements. |
FS-15
FS-16
89
Company Report on Internal Controls Over Financial Reporting
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiaries (PSNH or the Company) and of other sections of this annual report. This combined annual report does not include an attestation report from Deloitte & Touche LLP regarding thePSNH’s internal controls over financial reporting for PSNH. Management’s report on behalf of PSNH was not subject to attestation pursuant to temporary rules of the Securities and Exchange Commission that permit this company to provide only management’s report in this combined annual report.were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, PSNH conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2008.2010.
February 27, 200925, 2011
FS-1790
Report of Independent Registered Public Accounting FirmREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Public Service Company of New Hampshire:
We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiaries (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 20082010 and 2007,2009, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008.2010. Our audits also included the consolidated financial statement schedules listed in the Index at Item 15. These15 of Part IV. We also have audited the Company's internal control over financial reporting as of December 31, 2010, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements are the responsibilityand financial statement schedules, for m aintaining effective internal control over financial reporting, and for its assessment of the Company's management.effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company's internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration ofmisstatement and whether effective internal control over financial reporting as a basis for designing audit procedures that are appropriatewas maintained in the circumstances, but not for the purpose of expressing an opinion on the effectivenessall material respects. Our audits of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includesstatements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well asand evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting pri nciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, suchthe consolidated financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of New Hampshire and subsidiaries as of December 31, 20082010 and 2007,2009, and the results of their operations and their cash flows for each of the three years thenin the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established inInternal Control — Integrated Frameworkis sued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ | Deloitte & Touche LLP |
| Deloitte & Touche LLP |
Hartford, Connecticut
February 27, 200925, 2011
FS-1891
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES |
|
|
| ||
CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, | |||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
Cash | $ | 2,559 |
| $ | 1,974 |
Receivables, Net |
| 105,070 |
|
| 89,337 |
Accounts Receivable from Affiliated Companies |
| 858 |
|
| 286 |
Unbilled Revenues |
| 48,691 |
|
| 49,358 |
Taxes Receivable |
| 12,564 |
|
| 22,600 |
Fuel, Materials and Supplies |
| 116,074 |
|
| 127,447 |
Prepayments and Other Current Assets |
| 30,817 |
|
| 36,387 |
Total Current Assets |
| 316,633 |
|
| 327,389 |
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| 2,053,281 |
|
| 1,814,714 |
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
|
Regulatory Assets |
| 434,418 |
|
| 494,077 |
Other Long-Term Assets |
| 85,508 |
|
| 61,011 |
Total Deferred Debits and Other Assets |
| 519,926 |
|
| 555,088 |
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets | $ | 2,889,840 |
| $ | 2,697,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
| ||||
|
|
|
|
|
|
92
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES |
|
|
| ||
CONSOLIDATED BALANCE SHEETS |
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, | |||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
Notes Payable to Banks | $ | 30,000 |
| $ | - |
Notes Payable to Affiliated Companies |
| 47,900 |
|
| 26,700 |
Accounts Payable |
| 85,324 |
|
| 109,521 |
Accounts Payable to Affiliated Companies |
| 20,007 |
|
| 20,083 |
Accrued Interest |
| 10,231 |
|
| 10,255 |
Derivative Liabilities |
| 12,834 |
|
| 18,785 |
Other Current Liabilities |
| 35,144 |
|
| 27,983 |
Total Current Liabilities |
| 241,440 |
|
| 213,327 |
|
|
|
|
|
|
Rate Reduction Bonds |
| 138,247 |
|
| 188,113 |
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
Accumulated Deferred Income Taxes |
| 327,297 |
|
| 275,669 |
Regulatory Liabilities |
| 66,996 |
|
| 69,872 |
Derivative Liabilities |
| - |
|
| 7,635 |
Accrued Pension |
| 261,096 |
|
| 272,905 |
Other Long-Term Liabilities |
| 91,952 |
|
| 105,970 |
Total Deferred Credits and Other Liabilities |
| 747,341 |
|
| 732,051 |
|
|
|
|
|
|
Capitalization: |
|
|
|
|
|
Long-Term Debt |
| 836,365 |
|
| 836,255 |
|
|
|
|
|
|
Common Stockholder's Equity: |
|
|
|
|
|
Common Stock |
| - |
|
| - |
Capital Surplus, Paid In |
| 579,577 |
|
| 420,169 |
Retained Earnings |
| 347,471 |
|
| 307,988 |
Accumulated Other Comprehensive Loss |
| (601) |
|
| (712) |
Common Stockholder's Equity |
| 926,447 |
|
| 727,445 |
Total Capitalization |
| 1,762,812 |
|
| 1,563,700 |
|
|
|
|
|
|
Commitments and Contingencies (Note 12) |
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 2,889,840 |
| $ | 2,697,191 |
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
| ||
|
|
|
|
|
|
93
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES | ||||||||
CONSOLIDATED STATEMENTS OF INCOME |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
| 2008 |
|
|
|
|
|
|
|
|
|
Operating Revenues | $ | 1,033,439 |
| $ | 1,109,591 |
| $ | 1,141,202 |
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
| 363,147 |
|
| 520,529 |
|
| 558,313 |
Other Operating Expenses |
| 230,210 |
|
| 239,650 |
|
| 215,497 |
Maintenance |
| 82,384 |
|
| 87,026 |
|
| 90,933 |
Depreciation |
| 67,237 |
|
| 61,961 |
|
| 56,321 |
Amortization of Regulatory Assets/(Liabilities), Net |
| 11,232 |
|
| (29,619) |
|
| 9,254 |
Amortization of Rate Reduction Bonds |
| 50,357 |
|
| 47,482 |
|
| 45,644 |
Taxes Other Than Income Taxes |
| 52,686 |
|
| 47,975 |
|
| 42,291 |
Total Operating Expenses |
| 857,253 |
|
| 975,004 |
|
| 1,018,253 |
Operating Income |
| 176,186 |
|
| 134,587 |
|
| 122,949 |
|
|
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
|
|
Interest on Long-Term Debt |
| 36,220 |
|
| 33,045 |
|
| 32,655 |
Interest on Rate Reduction Bonds |
| 9,660 |
|
| 13,128 |
|
| 15,969 |
Other Interest |
| 1,187 |
|
| 316 |
|
| 1,539 |
Interest Expense |
| 47,067 |
|
| 46,489 |
|
| 50,163 |
Other Income, Net |
| 11,749 |
|
| 9,462 |
|
| 7,277 |
Income Before Income Tax Expense |
| 140,868 |
|
| 97,560 |
|
| 80,063 |
Income Tax Expense |
| 50,801 |
|
| 31,990 |
|
| 21,996 |
Net Income | $ | 90,067 |
| $ | 65,570 |
| $ | 58,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
|
|
|
|
|
Net Income | $ | 90,067 |
| $ | 65,570 |
| $ | 58,067 |
Other Comprehensive Income/(Loss), Net of Tax: |
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| 87 |
|
| 87 |
|
| (1,418) |
Changes in Unrealized Gains/(Losses) on Other Securities |
| 24 |
|
| (50) |
|
| (101) |
Other Comprehensive Income/(Loss), Net of Tax |
| 111 |
|
| 37 |
|
| (1,519) |
Comprehensive Income | $ | 90,178 |
| $ | 65,607 |
| $ | 56,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES | |||
| |||
CONSOLIDATED BALANCE SHEETS | |||
| |||
| At December 31, | ||
(Thousands of Dollars) | 2008 |
| 2007 |
|
| ||
ASSETS |
|
|
|
|
|
|
|
Current Assets: |
|
|
|
Cash | $ 195 |
| $ 450 |
Receivables, less provision for uncollectible |
|
|
|
accounts of $4,165 in 2008 and $2,675 in 2007 | 108,857 |
| 97,749 |
Notes receivable from affiliated companies | 53,800 |
| - |
Accounts receivable from affiliated companies | 264 |
| 817 |
Unbilled revenues | 41,449 |
| 45,607 |
Taxes receivable | 8,809 |
| 255 |
Fuel, materials and supplies | 113,121 |
| 72,215 |
Derivative assets - current | 843 |
| 6,146 |
Accumulated deferred income taxes - current | 27,345 |
| - |
Prepayments and other | 15,380 |
| 14,327 |
| 370,063 |
| 237,566 |
|
|
|
|
Property, Plant and Equipment: |
|
|
|
Electric utility | 2,238,515 |
| 2,010,220 |
Less: Accumulated depreciation | 771,282 |
| 737,917 |
| 1,467,233 |
| 1,272,303 |
Construction work in progress | 113,752 |
| 116,102 |
| 1,580,985 |
| 1,388,405 |
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
Regulatory assets | 549,934 |
| 401,374 |
Derivative assets - long-term | 3,826 |
| 12,075 |
Other | 124,025 |
| 67,549 |
| 677,785 |
| 480,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets | $ 2,628,833 |
| $ 2,106,969 |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
FS-1994
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES | |||||||
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
|
|
| ||||
|
|
|
| ||||
|
|
|
|
|
| Accumulated |
|
|
|
|
| Capital |
| Other |
|
|
| Common Stock | Surplus, | Retained | Comprehensive |
| |
(Thousands of Dollars, Except Share Information) | Shares | Amount | Paid In | Earnings | Income/(Loss) | Total | |
Balance as of January 1, 2008 |
| 301 | $ - | $ 275,569 | $ 261,528 | $ 770 | $ 537,867 |
Net Income |
|
|
|
| 58,067 |
| 58,067 |
Dividends on Common Stock |
|
|
|
| (36,376) |
| (36,376) |
Allocation of Benefits - ESOP |
|
|
| 93 |
|
| 93 |
Capital Contributions from NU Parent |
|
|
| 75,583 |
|
| 75,583 |
Other Comprehensive Loss |
|
|
|
|
| (1,519) | (1,519) |
Balance as of December 31, 2008 |
| 301 | - | 351,245 | 283,219 | (749) | 633,715 |
Adoption of Accounting Guidance for |
|
|
|
| 43 | (43) | - |
Net Income |
|
|
|
| 65,570 |
| 65,570 |
Dividends on Common Stock |
|
|
|
| (40,844) |
| (40,844) |
Allocation of Benefits - ESOP |
|
|
| (22) |
|
| (22) |
Capital Contributions from NU Parent |
|
|
| 68,946 |
|
| 68,946 |
Other Comprehensive Income |
|
|
|
|
| 80 | 80 |
Balance as of December 31, 2009 |
| 301 | - | 420,169 | 307,988 | (712) | 727,445 |
Net Income |
|
|
|
| 90,067 |
| 90,067 |
Dividends on Common Stock |
|
|
|
| (50,584) |
| (50,584) |
Allocation of Benefits - ESOP |
|
|
| 439 |
|
| 439 |
Capital Contributions from NU Parent |
|
|
| 158,969 |
|
| 158,969 |
Other Comprehensive Income |
|
|
|
|
| 111 | 111 |
Balance as of December 31, 2010 |
| 301 | $ - | $ 579,577 | $ 347,471 | $ (601) | $ 926,447 |
The accompanying notes are an integral part of these consolidated financial statements.
FS-2095
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES | ||||||
|
| |||||
CONSOLIDATED STATEMENTS OF INCOME | ||||||
|
| |||||
|
| For the Years Ended December 31, | ||||
(Thousands of Dollars) |
| 2008 |
| 2007 |
| 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
| $ 1,141,202 |
| $ 1,083,072 |
| $ 1,140,900 |
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
Operation - |
|
|
|
|
|
|
Fuel, purchased and net interchange power |
| 558,313 |
| 530,680 |
| 588,132 |
Other |
| 215,497 |
| 208,691 |
| 178,577 |
Maintenance |
| 90,933 |
| 74,070 |
| 71,400 |
Depreciation |
| 56,321 |
| 53,315 |
| 49,740 |
Amortization of regulatory assets, net |
| 9,254 |
| 7,470 |
| 53,156 |
Amortization of rate reduction bonds |
| 45,644 |
| 52,344 |
| 49,370 |
Taxes other than income taxes |
| 42,291 |
| 39,671 |
| 37,640 |
Total operating expenses |
| 1,018,253 |
| 966,241 |
| 1,028,015 |
Operating Income |
| 122,949 |
| 116,831 |
| 112,885 |
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
Interest on long-term debt |
| 32,655 |
| 26,029 |
| 24,100 |
Interest on rate reduction bonds |
| 15,969 |
| 18,013 |
| 20,828 |
Other interest |
| 1,539 |
| 2,243 |
| 829 |
Interest expense, net |
| 50,163 |
| 46,285 |
| 45,757 |
Other Income, Net |
| 7,277 |
| 6,682 |
| 7,378 |
Income Before Income Tax Expense |
| 80,063 |
| 77,228 |
| 74,506 |
Income Tax Expense |
| 21,996 |
| 22,794 |
| 39,183 |
Net Income |
| $ 58,067 |
| $ 54,434 |
| $ 35,323 |
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
|
|
|
Net Income |
| $ 58,067 |
| $ 54,434 |
| $ 35,323 |
Other comprehensive (loss)/income, net of tax: |
|
|
|
|
|
|
Qualified cash flow hedging instruments |
| (1,418) |
| 605 |
| - |
Changes in unrealized gains on securities |
| (101) |
| (11) |
| 32 |
Minimum SERP liability |
| - |
| - |
| 61 |
Other comprehensive (loss)/income, net of tax |
| (1,519) |
| 594 |
| 93 |
Comprehensive Income |
| $ 56,548 |
| $ 55,028 |
| $ 35,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
FS-21
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES |
|
|
| ||||||||
|
|
| |||||||||
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
|
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
| ||
|
|
| Capital |
|
|
| Other |
|
| ||
| Common Stock |
| Surplus, |
| Retained |
| Comprehensive |
|
| ||
(Thousands of Dollars, except share information) | Shares |
| Amounts |
| Paid In |
| Earnings |
| Income/(Loss) |
| Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2006 | 301 |
| $ - |
| $ 209,788 |
| $ 242,633 |
| $ 83 |
| $ 452,504 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income for 2006 |
|
|
|
|
|
| 35,323 |
|
|
| 35,323 |
Dividends on common stock |
|
|
|
|
|
| (41,741) |
|
|
| (41,741) |
Allocation of benefits - ESOP |
|
|
|
| (68) |
|
|
|
|
| (68) |
Tax deduction for stock options exercised and |
|
|
|
|
|
|
|
|
|
|
|
Employee Stock Purchase Plan |
|
|
|
|
|
|
|
|
|
|
|
disqualifying dispositions |
|
|
|
| (242) |
|
|
|
|
| (242) |
Capital contributions from NU parent |
|
|
|
| 21,693 |
|
|
|
|
| 21,693 |
Other comprehensive income |
|
|
|
|
|
|
|
| 93 |
| 93 |
Balance at December 31, 2006 | 301 |
| - |
| 231,171 |
| 236,215 |
| 176 |
| 467,562 |
|
|
|
|
|
|
|
|
|
|
|
|
Adoption of FIN48 - accounting |
|
|
|
|
|
|
|
|
|
|
|
for uncertainty of income taxes |
|
|
|
|
|
| 1,599 |
|
|
| 1,599 |
Net income for 2007 |
|
|
|
|
|
| 54,434 |
|
|
| 54,434 |
Dividends on common stock |
|
|
|
|
|
| (30,720) |
|
|
| (30,720) |
Allocation of benefits - ESOP |
|
|
|
| 204 |
|
|
|
|
| 204 |
Capital contributions from NU parent |
|
|
|
| 44,194 |
|
|
|
|
| 44,194 |
Other comprehensive income |
|
|
|
|
|
|
|
| 594 |
| 594 |
Balance at December 31, 2007 | 301 |
| - |
| 275,569 |
| 261,528 |
| 770 |
| 537,867 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income for 2008 |
|
|
|
|
|
| 58,067 |
|
|
| 58,067 |
Dividends on common stock |
|
|
|
|
|
| (36,376) |
|
|
| (36,376) |
Allocation of benefits - ESOP |
|
|
|
| 93 |
|
|
|
|
| 93 |
Capital contributions from NU parent |
|
|
|
| 75,583 |
|
|
|
|
| 75,583 |
Other comprehensive loss |
|
|
|
|
|
|
|
| (1,519) |
| (1,519) |
Balance at December 31, 2008 | 301 |
| $ - |
| $ 351,245 |
| $ 283,219 |
| $ (749) |
| $ 633,715 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
|
|
FS-22
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES | |||||
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
|
|
|
|
| For the Years Ended December 31, | ||||
(Thousands of Dollars) | 2008 |
| 2007 |
| 2006 |
|
|
|
|
|
|
Operating activities: |
|
|
|
|
|
Net income | $ 58,067 |
| $ 54,434 |
| $ 35,323 |
Adjustments to reconcile to net cash flows |
|
|
|
|
|
provided by operating activities: |
|
|
|
|
|
Depreciation | 56,321 |
| 53,315 |
| 49,740 |
Deferred income taxes | 25,001 |
| (4,726) |
| (21,929) |
Amortization of investment tax credits | (227) |
| (295) |
| (353) |
Bad debt expense | 5,661 |
| 3,433 |
| 4,208 |
Pension and PBOP expense and contributions, |
|
|
|
|
|
net of capitalized portion | 12,350 |
| 7,258 |
| 17,310 |
Allowance for equity funds used during construction | (4,374) |
| (1,958) |
| (4,367) |
Amortization of rate reduction bonds | 45,644 |
| 52,344 |
| 49,370 |
Amortization of regulatory assets, net | 9,254 |
| 7,470 |
| 53,156 |
Regulatory refunds and underrecoveries | (23,848) |
| (6,167) |
| (6,850) |
Net settlement of cash flow hedge instruments | (1,730) |
| - |
| - |
Deferred contractual obligations | (4,978) |
| (6,365) |
| (12,589) |
Increase in other deferred debits | (19,716) |
| (7,787) |
| (9,128) |
(Decrease)/increase in other deferred credits | (64) |
| 125 |
| (4,101) |
Other adjustments | (2,808) |
| (1,939) |
| (659) |
Changes in current assets and liabilities: |
|
|
|
|
|
Receivables and unbilled revenues, net | (12,058) |
| (15,799) |
| 27,637 |
Taxes receivable/accrued | (2,117) |
| 4,144 |
| (11,857) |
Fuel, materials and supplies | (26,209) |
| 15,882 |
| (12,036) |
Other current assets | (1,516) |
| (1,949) |
| 5,106 |
Accounts payable | 41,959 |
| (8,178) |
| 14,073 |
Other current liabilities | 8,664 |
| 4,051 |
| 1,764 |
Net cash flows provided by operating activities | 163,276 |
| 147,293 |
| 173,818 |
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
Investments in property and plant | (238,912) |
| (167,712) |
| (126,657) |
Increase in NU Money Pool lending | (53,800) |
| - |
| - |
Proceeds from sales of marketable securities | 5,380 |
| 3,454 |
| 3,788 |
Purchases of marketable securities | (5,508) |
| (3,692) |
| (4,059) |
Other investing activities | 4,735 |
| 5,921 |
| 2,564 |
Net cash flows used in investing activities | (288,105) |
| (162,029) |
| (124,364) |
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
Cash dividends on common stock | (36,376) |
| (30,720) |
| (41,741) |
Increase in short-term debt | 35,227 |
| 10,000 |
| - |
(Decrease)/increase in NU Money Pool borrowings | (11,300) |
| (25,200) |
| 20,600 |
Capital contributions from NU parent | 75,583 |
| 44,194 |
| 21,693 |
Issuance of long-term debt | 110,000 |
| 70,000 |
| - |
Retirements of rate reduction bonds | (46,879) |
| (51,813) |
| (48,861) |
Other financing activities | (1,681) |
| (1,306) |
| (1,141) |
Net cash flows provided by/(used in) financing activities | 124,574 |
| 15,155 |
| (49,450) |
Net (decrease)/increase in cash | (255) |
| 419 |
| 4 |
Cash - beginning of year | 450 |
| 31 |
| 27 |
Cash - end of year | $ 195 |
| $ 450 |
| $ 31 |
|
|
|
|
|
|
Supplemental Cash Flow Information: |
|
|
|
|
|
Cash paid during the year for: |
|
|
|
|
|
Interest, net of amounts capitalized | $ 49,990 |
| $ 50,237 |
| $ 49,305 |
Income taxes | $ 1,023 |
| $ 26,167 |
| $ 75,198 |
Non-cash investing activities: |
|
|
|
|
|
Capital expenditures incurred but not paid | $ 31,391 |
| $ 37,811 |
| $ 15,036 |
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
FS-23
96
Company Report on Internal Controls Over Financial Reporting
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Western Massachusetts Electric Company and subsidiary (WMECO or the Company) and of other sections of this annual report. This combined annual report does not include an attestation report from Deloitte & Touche LLP regarding theWMECO’s internal controls over financial reporting for WMECO. Management’s report on behalf of WMECO was not subject to attestation pursuant to temporary rules of the Securities and Exchange Commission that permit this company to provide only management’s report in this combined annual report.were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, WMECO conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2008.2010.
February 27, 200925, 2011
FS-2497
Report of Independent Registered Public Accounting FirmREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Western Massachusetts Electric Company:
We have audited the accompanying consolidated balance sheets of Western Massachusetts Electric Company and subsidiary (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 20082010 and 2007,2009, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008.2010. Our audits also included the consolidated financial statement schedules listed in the Index at Item 15. These15 of Part IV. We also have audited the Company's internal control over financial reporting as of December 31, 2010, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements are the responsibilityand financial statement schedules, for main taining effective internal control over financial reporting, and for its assessment of the Company's management.effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company's internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration ofmisstatement and whether effective internal control over financial reporting as a basis for designing audit procedures that are appropriatewas maintained in the circumstances, but not for the purpose of expressing an opinion on the effectivenessall material respects. Our audits of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includesstatements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and si gnificantsignificant estimates made by management, as well asand evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting pri nciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, suchthe consolidated financial statements referred to above present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 20082010 and 2007,2009, and the results of their operations and their cash flows for each of the three years thenin the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established inInternal Control — Integrated Frameworkissued by the Co mmittee of Sponsoring Organizations of the Treadway Commission.
/s/ | Deloitte & Touche LLP |
| Deloitte & Touche LLP |
Hartford, Connecticut
February 27, 200925, 2011
FS-2598
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY | |||||
CONSOLIDATED BALANCE SHEETS | |||||
| |||||
| |||||
|
| At December 31, | |||
(Thousand of Dollars) |
| 2010 |
|
| 2009 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
Cash | $ | 1 |
| $ | 1 |
Receivables, Net |
| 37,585 |
|
| 38,415 |
Accounts Receivable from Affiliated Companies |
| 505 |
|
| 191 |
Unbilled Revenues |
| 16,578 |
|
| 16,090 |
Taxes Receivable |
| 7,346 |
|
| 4,192 |
Materials and Supplies |
| 3,664 |
|
| 8,314 |
Marketable Securities |
| 33,194 |
|
| 28,261 |
Prepayments and Other Current Assets |
| 1,968 |
|
| 1,774 |
Total Current Assets |
| 100,841 |
|
| 97,238 |
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| 817,146 |
|
| 705,760 |
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
|
Regulatory Assets |
| 227,115 |
|
| 240,804 |
Marketable Securities |
| 23,860 |
|
| 28,500 |
Other Long-Term Assets |
| 30,597 |
|
| 29,498 |
Total Deferred Debits and Other Assets |
| 281,572 |
|
| 298,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets | $ | 1,199,559 |
| $ | 1,101,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
99
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY |
|
| |||
CONSOLIDATED BALANCE SHEETS |
|
| |||
|
|
| |||
|
|
| |||
|
| December 31, | |||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
Notes Payable to Affiliated Companies | $ | 20,400 |
| $ | 136,100 |
Accounts Payable |
| 48,344 |
|
| 36,680 |
Accounts Payable to Affiliated Companies |
| 7,848 |
|
| 7,924 |
Accrued Interest |
| 6,787 |
|
| 5,274 |
Other Current Liabilities |
| 11,474 |
|
| 8,873 |
Total Current Liabilities |
| 94,853 |
|
| 194,851 |
|
|
|
|
|
|
Rate Reduction Bonds |
| 43,325 |
|
| 58,735 |
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
Accumulated Deferred Income Taxes |
| 222,333 |
|
| 211,391 |
Regulatory Liabilities |
| 23,008 |
|
| 21,683 |
Other Long-Term Liabilities |
| 58,168 |
|
| 62,858 |
Total Deferred Credits and Other Liabilities |
| 303,509 |
|
| 295,932 |
|
|
|
|
|
|
Capitalization: |
|
|
|
|
|
Long-Term Debt |
| 400,288 |
|
| 305,475 |
|
|
|
|
|
|
Common Stockholder's Equity: |
|
|
|
|
|
Common Stock |
| 10,866 |
|
| 10,866 |
Capital Surplus, Paid In |
| 248,044 |
|
| 145,400 |
Retained Earnings |
| 98,757 |
|
| 90,549 |
Accumulated Other Comprehensive Loss |
| (83) |
|
| (8) |
Common Stockholder's Equity |
| 357,584 |
|
| 246,807 |
Total Capitalization |
| 757,872 |
|
| 552,282 |
|
|
|
|
|
|
Commitments and Contingencies (Note 12) |
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 1,199,559 |
| $ | 1,101,800 |
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
100
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY |
|
|
|
|
| |||
CONSOLIDATED STATEMENTS OF INCOME |
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||||
(Thousands of Dollars) | 2010 |
| 2009 |
| 2008 | |||
|
|
|
|
|
|
|
|
|
Operating Revenues | $ | 395,161 |
| $ | 402,413 |
| $ | 441,527 |
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
Fuel, Purchased and Net Interchange Power |
| 157,276 |
|
| 192,177 |
|
| 237,369 |
Other Operating Expenses |
| 102,053 |
|
| 85,591 |
|
| 76,929 |
Maintenance |
| 19,196 |
|
| 17,895 |
|
| 20,720 |
Depreciation |
| 23,561 |
|
| 22,454 |
|
| 21,025 |
Amortization of Regulatory Assets/(Liabilities), Net |
| 2,395 |
|
| (2,980) |
|
| 12,445 |
Amortization of Rate Reduction Bonds |
| 15,494 |
|
| 14,521 |
|
| 13,625 |
Taxes Other Than Income Taxes |
| 16,529 |
|
| 14,174 |
|
| 12,867 |
Total Operating Expenses |
| 336,504 |
|
| 343,832 |
|
| 394,980 |
Operating Income |
| 58,657 |
|
| 58,581 |
|
| 46,547 |
|
|
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
|
|
Interest on Long-Term Debt |
| 17,988 |
|
| 14,074 |
|
| 13,244 |
Interest on Rate Reduction Bonds |
| 3,372 |
|
| 4,335 |
|
| 5,133 |
Other Interest |
| 479 |
|
| 877 |
|
| 1,256 |
Interest Expense |
| 21,839 |
|
| 19,286 |
|
| 19,633 |
Other Income, Net |
| 2,597 |
|
| 1,824 |
|
| 1,961 |
Income Before Income Tax Expense |
| 39,415 |
|
| 41,119 |
|
| 28,875 |
Income Tax Expense |
| 16,325 |
|
| 14,923 |
|
| 10,545 |
Net Income | $ | 23,090 |
| $ | 26,196 |
| $ | 18,330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
|
|
|
|
|
Net Income | $ | 23,090 |
| $ | 26,196 |
| $ | 18,330 |
Other Comprehensive Loss, Net of Tax: |
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| (79) |
|
| (79) |
|
| (79) |
Changes in Unrealized Gains/(Losses) on Other Securities |
| 4 |
|
| (119) |
|
| 38 |
Other Comprehensive Loss, Net of Tax |
| (75) |
|
| (198) |
|
| (41) |
Comprehensive Income | $ | 23,015 |
| $ | 25,998 |
| $ | 18,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
101
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY |
| ||||||
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
|
| |||||
|
|
| |||||
|
|
|
|
|
| Accumulated |
|
|
|
|
| Capital |
| Other |
|
|
| Common Stock | Surplus, | Retained | Comprehensive |
| |
(Thousands of Dollars, Except Share Information) | Shares | Amount | Paid In | Earnings | Income/(Loss) | Total | |
Balance as of January 1, 2008 |
| 434,653 | $ 10,866 | $ 128,228 | $ 103,925 | $ 231 | $ 243,250 |
Net Income |
|
|
|
| 18,330 |
| 18,330 |
Dividends on Common Stock |
|
|
|
| (39,706) |
| (39,706) |
Allocation of Benefits - ESOP |
|
|
| 36 |
|
| 36 |
Capital Contributions from NU Parent |
|
|
| 16,281 |
|
| 16,281 |
Other Comprehensive Loss |
|
|
|
|
| (41) | (41) |
Balance as of December 31, 2008 |
| 434,653 | 10,866 | 144,545 | 82,549 | 190 | 238,150 |
Adoption of Accounting Guidance for |
|
|
|
| 7 | (7) | - |
Net Income |
|
|
|
| 26,196 |
| 26,196 |
Dividends on Common Stock |
|
|
|
| (18,203) |
| (18,203) |
Allocation of Benefits - ESOP |
|
|
| (8) |
|
| (8) |
Capital Contributions from NU Parent |
|
|
| 863 |
|
| 863 |
Other Comprehensive Loss |
|
|
|
|
| (191) | (191) |
Balance as of December 31, 2009 |
| 434,653 | 10,866 | 145,400 | 90,549 | (8) | 246,807 |
Net Income |
|
|
|
| 23,090 |
| 23,090 |
Dividends on Common Stock |
|
|
|
| (14,882) |
| (14,882) |
Allocation of Benefits - ESOP |
|
|
| 165 |
|
| 165 |
Capital Contributions from NU Parent |
|
|
| 102,479 |
|
| 102,479 |
Other Comprehensive Loss |
|
|
|
|
| (75) | (75) |
Balance as of December 31, 2010 |
| 434,653 | $ 10,866 | $ 248,044 | $ 98,757 | $ (83) | $ 357,584 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
FS-26102
FS-27
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY | ||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||||
(Thousands of Dollars) |
| 2010 |
|
| 2009 |
|
| 2008 |
|
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
|
|
|
|
Net Income | $ | 23,090 |
| $ | 26,196 |
| $ | 18,330 |
Adjustments to Reconcile Net Income to Net Cash Flows |
|
|
|
|
|
|
|
|
Provided by Operating Activities: |
|
|
|
|
|
|
|
|
Bad Debt Expense |
| 9,747 |
|
| 7,590 |
|
| 8,185 |
Depreciation |
| 23,561 |
|
| 22,454 |
|
| 21,025 |
Deferred Income Taxes |
| 10,963 |
|
| 22,908 |
|
| 12,222 |
Pension Income and PBOP Expense, Net of PBOP Contributions |
| (535) |
|
| (2,630) |
|
| (4,844) |
Regulatory (Underrecoveries)/Overrecoveries, Net |
| (11,551) |
|
| 589 |
|
| (17,093) |
Amortization of Regulatory Assets/(Liabilities), Net |
| 2,395 |
|
| (2,980) |
|
| 12,445 |
Amortization of Rate Reduction Bonds |
| 15,494 |
|
| 14,521 |
|
| 13,625 |
Other |
| (7,032) |
|
| (5,547) |
|
| (9,697) |
Changes in Current Assets and Liabilities: |
|
|
|
|
|
|
|
|
Receivables and Unbilled Revenues, Net |
| (6,838) |
|
| 3,757 |
|
| (14,210) |
Materials and Supplies |
| 4,650 |
|
| (4,489) |
|
| (1,490) |
Taxes Receivable/Accrued |
| (393) |
|
| 1,307 |
|
| 4,081 |
Accounts Payable |
| (92) |
|
| (19,397) |
|
| 22,186 |
Other Current Assets and Liabilities |
| 2,406 |
|
| (2,150) |
|
| 2,718 |
Net Cash Flows Provided by Operating Activities |
| 65,865 |
|
| 62,129 |
|
| 67,483 |
|
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
|
|
|
Investments in Property, Plant and Equipment |
| (115,178) |
|
| (105,440) |
|
| (78,253) |
Proceeds from Sales of Marketable Securities |
| 114,191 |
|
| 106,308 |
|
| 169,056 |
Purchases of Marketable Securities |
| (114,587) |
|
| (106,937) |
|
| (169,902) |
Other Investing Activities |
| (888) |
|
| 1,298 |
|
| 939 |
Net Cash Flows Used in Investing Activities |
| (116,462) |
|
| (104,771) |
|
| (78,160) |
|
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
|
|
|
Cash Dividends on Common Stock |
| (14,882) |
|
| (18,203) |
|
| (39,706) |
(Decrease)/Increase in Short-Term Debt |
| - |
|
| (29,850) |
|
| 29,850 |
Issuance of Long-Term Debt |
| 95,000 |
|
| - |
|
| - |
(Decrease)/Increase in NU Money Pool Borrowings |
| (115,700) |
|
| 104,500 |
|
| 16,700 |
Retirements of Rate Reduction Bonds |
| (15,410) |
|
| (14,441) |
|
| (13,555) |
Capital Contributions from NU Parent |
| 102,479 |
|
| 863 |
|
| 16,281 |
Other Financing Activities |
| (890) |
|
| (226) |
|
| (3) |
Net Cash Flows Provided by Financing Activities |
| 50,597 |
|
| 42,643 |
|
| 9,567 |
Net Increase/(Decrease) in Cash |
| - |
|
| 1 |
|
| (1,110) |
Cash - Beginning of Year |
| 1 |
|
| - |
|
| 1,110 |
Cash - End of Year | $ | 1 |
| $ | 1 |
| $ | - |
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
FS-28
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY |
|
|
|
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| |
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
|
|
|
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| Accumulated |
|
| |
|
|
|
|
|
| Capital |
|
|
| Other |
|
| |
|
| Common Stock |
| Surplus, |
| Retained |
| Comprehensive |
|
| |||
(Thousands of Dollars, except share information) | Shares |
| Amount |
| Paid In |
| Earnings |
| Income |
| Total | ||
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Balance at January 1, 2006 |
| 434,653 |
| $ 10,866 |
| $ 82,811 |
| $ 84,965 |
| $ 694 |
| $ 179,336 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income for 2006 |
|
|
|
|
|
|
| 15,644 |
|
|
| 15,644 | |
Dividends on common stock |
|
|
|
|
|
|
| (7,946) |
|
|
| (7,946) | |
Allocation of benefits - ESOP |
|
|
|
|
| (29) |
|
|
|
|
| (29) | |
Tax deduction for stock options exercised |
|
|
|
|
|
|
|
|
|
|
|
| |
and Employee Stock Purchase Plan |
|
|
|
|
|
|
|
|
|
|
|
| |
disqualifying dispositions |
|
|
| (183) |
|
|
|
|
| (183) | |||
Capital contributions from NU parent |
|
|
|
|
| 31,945 |
|
|
|
|
| 31,945 | |
Other comprehensive income |
|
|
|
|
|
|
|
|
| 199 |
| 199 | |
Balance at December 31, 2006 |
| 434,653 |
| 10,866 |
| 114,544 |
| 92,663 |
| 893 |
| 218,966 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Adoption of FIN48 - accounting |
|
|
|
|
|
|
|
|
|
|
|
| |
for uncertainty of income taxes |
|
|
|
|
|
|
| 437 |
|
|
| 437 | |
Net income for 2007 |
|
|
|
|
|
|
| 23,604 |
|
|
| 23,604 | |
Dividends on common stock |
|
|
|
|
|
|
| (12,779) |
|
|
| (12,779) | |
Allocation of benefits - ESOP |
|
|
|
|
| 77 |
|
|
|
|
| 77 | |
Capital contributions from NU parent |
|
|
|
|
| 13,607 |
|
|
|
|
| 13,607 | |
Other comprehensive loss |
|
|
|
|
|
|
|
|
| (662) |
| (662) | |
Balance at December 31, 2007 |
| 434,653 |
| 10,866 |
| 128,228 |
| 103,925 |
| 231 |
| 243,250 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income for 2008 |
|
|
|
|
|
|
| 18,330 |
|
|
| 18,330 | |
Dividends on common stock |
|
|
|
|
|
|
| (39,706) |
|
|
| (39,706) | |
Allocation of benefits - ESOP |
|
|
|
|
| 36 |
|
|
|
|
| 36 | |
Capital contributions from NU parent |
|
|
|
|
| 16,281 |
|
|
|
|
| 16,281 | |
Other comprehensive loss |
|
|
|
|
|
|
|
|
| (41) |
| (41) | |
Balance at December 31, 2008 |
| 434,653 |
| $ 10,866 |
| $ 144,545 |
| $ 82,549 |
| $ 190 |
| $ 238,150 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
FS-29
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY | |||||
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
|
|
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||
(Thousands of Dollars) | 2008 |
| 2007 |
| 2006 |
|
| ||||
Operating Activities: |
|
|
|
|
|
Net income | $ 18,330 |
| $ 23,604 |
| $ 15,644 |
Adjustments to reconcile to net cash flows |
|
|
|
|
|
provided by operating activities: |
|
|
|
|
|
Depreciation | 21,025 |
| 20,868 |
| 17,204 |
Deferred income taxes | 12,222 |
| (15,332) |
| (17,192) |
Amortization of investment tax credits | (263) |
| (304) |
| (336) |
Bad debt expense | 8,185 |
| 6,922 |
| 5,503 |
Pension and PBOP income and contributions, |
|
|
|
|
|
net of capitalized portion | (4,844) |
| (3,050) |
| (1,044) |
Allowance for equity funds used during construction | (1,183) |
| (156) |
| (184) |
Impairment of marketable securities | 2,248 |
| 636 |
| - |
Amortization of rate reduction bonds | 13,625 |
| 12,766 |
| 11,968 |
Amortization of regulatory assets/(liabilities), net | 12,445 |
| 10,601 |
| (27,516) |
Regulatory (underrecoveries)/overrecoveries | (17,093) |
| 32,129 |
| 10,327 |
Deferred contractual obligations | (5,822) |
| (7,568) |
| (16,807) |
(Increase)/decrease in other deferred debits | (1,270) |
| 836 |
| 3,364 |
Increase/(decrease) in other deferred credits | 922 |
| 652 |
| 119 |
Other adjustments | (4,329) |
| (1,469) |
| 1,904 |
Changes in current assets and liabilities: |
|
|
|
|
|
Receivables and unbilled revenues, net | (14,210) |
| (9,749) |
| (4,600) |
Materials and supplies | (1,490) |
| (478) |
| (461) |
Other current assets | 703 |
| (1,300) |
| (183) |
Accounts payable | 22,186 |
| 1,417 |
| (7,544) |
Taxes receivable/accrued | 4,081 |
| (35,014) |
| 25,995 |
Other current liabilities | 2,015 |
| 1,537 |
| 176 |
Net cash flows provided by operating activities | 67,483 |
| 37,548 |
| 16,337 |
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
Investments in property and plant | (78,253) |
| (47,315) |
| (42,818) |
Proceeds from sales of marketable securities | 169,056 |
| 196,865 |
| 123,148 |
Purchases of marketable securities | (169,902) |
| (199,803) |
| (125,782) |
Other investing activities | 939 |
| 929 |
| 2,637 |
Net cash flows used in investing activities | (78,160) |
| (49,324) |
| (42,815) |
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
Cash dividends on common stock | (39,706) |
| (12,779) |
| (7,946) |
Increase in short-term debt | 29,850 |
| - |
| - |
Issuance of long-term debt | - |
| 40,000 |
| - |
Retirements of rate reduction bonds | (13,555) |
| (12,697) |
| (11,903) |
Increase/(decrease) in NU Money Pool borrowings | 16,700 |
| (15,900) |
| 15,900 |
Capital contributions from NU parent | 16,281 |
| 13,607 |
| 31,945 |
Other financing activities | (3) |
| (681) |
| (183) |
Net cash flows provided by financing activities | 9,567 |
| 11,550 |
| 27,813 |
Net (decrease)/increase in cash | (1,110) |
| (226) |
| 1,335 |
Cash - beginning of year | 1,110 |
| 1,336 |
| 1 |
Cash - end of year | $ - |
| $ 1,110 |
| $ 1,336 |
|
|
|
|
|
|
Supplemental Cash Flow Information: |
|
|
|
|
|
Cash paid/(received) during the year for: |
|
|
|
|
|
Interest, net of amounts capitalized | $ 19,979 |
| $ 20,259 |
| $ 20,140 |
Income taxes | $ (5,872) |
| $ 65,595 |
| $ (677) |
Non-cash investing activities: |
|
|
|
|
|
Capital expenditures incurred but not paid | $ 11,465 |
| $ 6,593 |
| $ 2,019 |
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements. |
|
|
FS-30103
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the consolidated financial statements.
1.
Summary of Significant Accounting Policies (All Companies)SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A.
About Northeast Utilities, The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric CompanyProposed Merger with NSTAR
Consolidated:On October 18, 2010, Northeast Utilities (NU or the company)Company) and NSTAR announced that each company's Board of Trustees unanimously approved a Merger Agreement (the "agreement") to create a combined company that will be called Northeast Utilities. The transaction was structured as a merger of equals in a tax-free exchange. The post-transaction company will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.
Under the terms of the agreement, NSTAR shareholders would receive 1.312 NU common shares for each NSTAR common share that they own (the "exchange ratio"). The exchange ratio was structured to result in a no premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement. Based on the number of NU common shares and NSTAR common shares estimated to be outstanding immediately prior to the closing of the merger, upon such closing NU shareholders will own approximately 56 percent of the post-transaction company and former NSTAR shareholders will own approximately 44 percent of the post-transaction company. It is anticipated that NU would issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger. Subject to the conditions in the agreement, NU’s first quarterly dividend per share declared aft er the completion of the merger will be increased to an amount that is equivalent, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.
In accordance with accounting standards for business combinations, NU will account for the transaction as an acquisition of NSTAR by NU and, upon completion of the transaction, NSTAR will become a direct wholly owned subsidiary of NU.
Completion of the merger is subject to various customary conditions, including, among others, approval by holders of two-thirds of the outstanding common shares of each company, the continued effectiveness of the registration statement for the NU shares to be issued to NSTAR shareholders in the merger, and receipt of all required regulatory approvals. Special meetings of shareholders of both companies to approve the merger are scheduled for March 4, 2011.
B.
Presentation
The consolidated financial statements of NU, CL&P, PSNH and WMECO include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
In accordance with accounting guidance on the consolidation of VIEs, the Company evaluates its variable interests to determine if it has a controlling financial interest in a VIE that would require consolidation. The Company's variable interests outside of the consolidated group consist of contracts with developers of power plants that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. The Company would consolidate a VIE if it had both the power to direct the activities of a VIE that most significantly impact the entity's economic performance and the obligation to absorb losses of, or receive benefits from, the entity that could potentially be significant to the VIE.
For each variable interest in a power plant, NU evaluates the activities of that particular power plant that most significantly impact the VIE's economic performance to determine whether it has control over those activities. NU's assessment of control includes an analysis of who operates and maintains the power plant including dispatch rights and who controls the activities of the power plant after the expiration of its power purchase agreement with NU. NU also evaluates its exposure to potentially significant losses and benefits of the VIE. As of December 31, 2010, NU held variable interests in VIEs through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers. NU does not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. NU does not have fi nancial exposure because the costs and benefits of all of these arrangements are fully recoverable from, or refundable to, NU's customers. As of December 31, 2010, NU was not identified as the primary beneficiary of, and therefore does not consolidate, any power plant VIEs.
NUTV and a subsidiary of NSTAR have formed a 75 percent/25 percent owned limited liability company, NPT, to construct, own and operate the Northern Pass transmission project. NPT and Hydro Renewable Energy entered into a TSA whereby NPT will sell to Hydro Renewable Energy electric transmission rights over the Northern Pass for a 40-year term at cost of service rates. NPT will be required to maintain a 50/50 debt to equity ratio. NU determined that NUTV, through its controlling financial interest in NPT, must consolidate NPT, as NUTV has the power to direct the activities of NPT which most significantly impact its economic performance, including permitting and siting and operation and maintenance activities over the term of the TSA. As of December 31, 2010, NPT had property, plant and equipment of $9.7 million and current liabilities of $3.9 million. NPT’s assets are restricted to use by NPT and its cred itors do not have recourse to NU.
104
The Company does not have any variable interests in an unconsolidated VIE that are material to the accompanying consolidated financial statements.
In accordance with accounting guidance on noncontrolling interests in consolidated financial statements effective January 1, 2009, the Preferred Stock of CL&P, which is not owned by NU or its consolidated subsidiaries and is not subject to mandatory redemption, has been presented as a noncontrolling interest in CL&P in the accompanying consolidated financial statements of NU. The Preferred Stock of CL&P is considered to be temporary equity and has been classified between liabilities and permanent shareholders' equity on the accompanying consolidated balance sheets of NU and CL&P due to a provision in CL&P's certificate of incorporation that grants preferred stockholders the right to elect a majority of CL&P's board of directors should certain conditions exist, such as if preferred dividends are in arrears for one year. The Net Income reported in the accompanying consolidated statements of income a nd cash flows represents consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR's portion of the net income of NPT.
The included presentation and disclosure requirements effective January 1, 2009 have been applied retrospectively to the consolidated statements of income, comprehensive income, common shareholders' equity, and cash flows for the year ended December 31, 2008. For the years ended December 31, 2010, 2009 and 2008, there was no change in NU parent's 100 percent ownership of the common equity of CL&P.
Certain other reclassifications of prior period data were made in the accompanying consolidated balance sheets and statements of cash flows for all companies presented. These reclassifications were made to conform to the current year's presentation.
NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses but does not recognize in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued. See Note 22, "Subsequent Event," for further information.
C.
About NU, CL&P, PSNH and WMECO
Consolidated: NU is the parent company of the regulated companiesCL&P, PSNH, WMECO, Yankee Gas and NU Enterprises, Inc. (NU Enterprises), as described below. NU was formed on July 1, 1966 when The Connecticut Light and Power Company (CL&P), Western Massachusetts Electric Company (WMECO)CL&P, WMECO and The Hartford Electric Light Company affiliated under the common ownership of the NU system. In 1967, Holyoke Water Power Company (HWP) joined the affiliation.NU. In 1992, Public Service Company of New Hampshire (PSNH)PSNH became a subsidiary of NU parent.NU. On March 1, 2000, natural gas became an integral part of NU's Connecticut operations when NU's merger with Yankee Energy System, Inc. (Yankee) and its principal subsidiary, Yankee Gas, Services Company (Yankee Gas), was completed. CL&P, PSNH and WMECO are reporting companies under the Securities Exchange Act of 1934. Until February 8, 2006, NU w as registered with the Securities and Exchange Commission (SEC) asis a public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On February 8, 2006, PUHCA was repealed. NU is now registered with the Federal Energy Regulatory Commission (FERC) as a public utility holding company under the PUHCA of 2005. Arrangements among the regulated electric companies, NU Enterprises and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulationregul ation by the FERC. The regulatedRegulated companies are subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the Connecticut Department of Public Utility Control (DPUC)DPUC for CL&P and Yankee Gas, the New Hampshire Public Utilities Commission (NHPUC),NHPUC as well as certain regulatory oversight by the Vermont Department of Public Service and the Maine Public Utilities Comm issionCommission for PSNH, and the Massachusetts Department of Public Utilities (DPU)DPU for WMECO).
Regulated Companies: CL&P, PSNH and WMECO furnish franchised retail electric service in Connecticut, New Hampshire and Massachusetts, respectively. Yankee Gas owns and operates Connecticut’sConnecticut's largest natural gas distribution system. CL&P, PSNH and WMECO's results include the operations of itstheir respective distribution and transmission segments. PSNH's and WMECO's distribution results include the operations of itstheir respective generation business.businesses. Yankee Gas’Gas' results include the operations of its natural gas distribution segment. NPT was formed to construct, own and operate the Northern Pass line, a new HVDC transmission line from Québec to New Hampshire that will interconnect with a new HVDC transmission line being developed by a transmission subsidiary of HQ.
NU Enterprises: NU Enterprises is the parent company of Select Energy, Inc. (Select Energy), E. S. Boulos, Company (Boulos), Northeast Generation Services Company (NGS),NGS, NGS Mechanical Inc. and SECI. As of December 31, 2010, NU Enterprises’ primary business consisted of (i) Select Energy Contracting, Inc. (SECI), which are collectively referredEnergy’s remaining energy wholesale marketing contracts, and (ii) NGS’ operation and maintenance agreements as well as its subsidiary, Boulos, an electrical contractor based in Maine that NU Enterprises continues to as NU Enterprises. For information regarding NU's exit from certain of these businesses, see Note 15, "Restructuringown and Impairment Charges and Discontinued Operations," to the consolidated financial statements.manage.
B.D.
PresentationCash and Cash Equivalents
TheCash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from Cash and Cash Equivalents to Accounts Payable on the accompanying consolidated financial statementsbalance sheets.
E.
Restricted Cash
As of December 31, 2009, PSNH had $10 million of restricted cash held with a trustee related to insurance proceeds received on bondable property, which was included in Prepayments and Other Current Assets on the accompanying consolidated balance sheet. These funds were released from the trustee during the second quarter of 2010 and there was no restricted cash held as of December 31, 2010.
105
F.
Provision for Uncollectible Accounts
NU, including CL&P, PSNH and WMECO, includemaintains a provision for uncollectible accounts to record receivables at an estimated net realizable value. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written-off against the provision for uncollectible accounts when the accounts of all their respective subsidiaries. CL&P's subsidiaries are CL&P Receivables Corporation (CRC)terminated and CL&P Funding LLC. PSNH's subsidiariesthese balances are PSNH Funding LLC, PSNH Funding LLC2 and Properties, Inc. WMECO's subsidiary is WMECO Funding LLC. Intercompany transactions have been eliminated in consolidation.deemed to be uncollectible.
The preparation of consolidated financial statementsprovision for uncollectible accounts, which is included in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior period data included inReceivables, Net on the accompanying consolidated financial statements have been madebalance sheets, was as follows:
|
| As of December 31, | ||||
(Millions of Dollars) |
| 2010 |
| 2009 | ||
NU |
| $ | 39.8 |
| $ | 55.3 |
CL&P |
|
| 17.2 |
|
| 26.1 |
PSNH |
|
| 6.8 |
|
| 5.1 |
WMECO |
|
| 6.0 |
|
| 7.2 |
The DPUC allows CL&P and Yankee Gas to conformaccelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. As of December 31, 2010, CL&P and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $65 million and $7.5 million, respectively, with the current year's presentation. corresponding bad debt expense recorded as Regulatory Assets as these amounts are probable of recovery. As of December 31, 2009, these amounts totaled $54.5 million and $8.6 million, respectively.
NU'sAs of December 31, 2010 and 2009, WMECO had a reserve for uncollectible hardship accounts receivable of $6.9 million and $9.1 million, respectively. As a result of the January 2011 DPU decision, WMECO is allowed to collect these amounts in rates.
G.
Fuel, Materials and Supplies and Allowance Inventory
Fuel, Materials and Supplies include natural gas, coal, oil and materials purchased primarily for construction or operation and maintenance purposes. Natural gas inventory, coal and oil are valued at their respective weighted average cost. Materials and supplies are valued at the lower of average cost or market.
PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including SO2, CO2, and NOx related to its regulated generation units, and uses SO2, CO2, and NOx emissions allowances. At the end of each compliance period, PSNH is required to relinquish SO2, CO2, and NOx emissions allowances corresponding to the actual emissions emitted by its generating units over the compliance period. SO2 and NOx emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties. CO2 emissions allowances are acquired through auctions and through purchases from third parties.
SO2, CO2, and NOxemissions allowances are recorded within Fuel, Materials and Supplies and are classified on the balance sheet as short-term or long-term depending on the period they are expected to be utilized against actual emissions. As of December 31, 2010 and 2009, PSNH had $7.1 million and $7.8 million, respectively, of short-term SO2, CO2, and NOxemissions allowances classified as Fuel, Materials and Supplies on the accompanying consolidated statementsbalance sheets and $18.2 million and $20.7 million, respectively, of incomelong-term SO2 and CO2emissions allowances classified as Other Long-Term Assets on the accompanying consolidated balance sheets.
SO2, CO2, and NOx emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH's generating units. PSNH recorded expenses of $6.6 million, $7.6 million and $2.8 million for the years ended December 31, 20072010, 2009, and 2006 classify2008, respectively, which was included in Fuel, Purchased and Net Interchange Power on the following as discontinued operations:accompanying consolidated statements of income. These costs are recovered from customers through PSNH ES revenues. See Note 2, "Regulatory Accounting," for further information.
·H.
Northeast Generation Company (NGC), including certain components of NGS,Special Deposits and Counterparty Deposits
·
The Mt. Tom generating plant (Mt. Tom) previously owned by HWP,
·
To the extent NU Enterprises, through Select Energy, Services, Inc. (SESI)requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is held on deposit by Select Energy or with unaffiliated counterparties and its wholly-owned subsidiaries HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC,
·
Abrokerage firms as a part of the total collateral required based on Select Energy's position in transactions with the counterparty. Select Energy's right to use cash collateral is determined by the terms of the related agreements. Key factors affecting the unrestricted status of a portion of this cash collateral include the former Woods Electrical Co., Inc. (Woods Electrical),financial standing of Select Energy and
·
SECI (including Reeds Ferry Supply Co., Inc.). of NU as its credit supporter.
Special deposits paid by Select Energy to unaffiliated counterparties and brokerage firms not subject to master netting agreements totaled $22.6 million and $28.1 million as of December 31, 2010 and 2009, respectively. These amounts are included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets. There were no counterparty deposits for Select Energy as of December 31, 2010 and 2009.
NU, including CL&P, PSNH, and WMECO, records special deposits and counterparty deposits posted under master netting agreements as an offset to a derivative asset or liability if the related derivatives are recorded in a net position. For further information, regarding discontinued operations, see Note 15, "Restructuring and Impairment Charges and Discontinued Operations,"4, "Derivative Instruments" to the consolidated financial statements.
FS-31106
C.NU, CL&P, PSNH and WMECO have established credit policies regarding counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties, financial condition, collateral requirements and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. These evaluations result in established credit limits prior to entering into a contract. As of December 31, 2010 and 2009, there were no counterparty deposits for these companies.
Accounting Standards Issued But Not Yet Adopted
In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 160, "Noncontrolling Interests in Consolidated Financial Statements," which is effective January 1, 2009. SFAS No. 160 requires ownership interests in subsidiaries held by third parties (noncontrolling interests) to be presented within equityCL&P, PSNH and clearly identified and labeled. It sets forth requirements for income statement presentationWMECO had amounts on deposit related to subsidiaries used to facilitate the activitiesissuance of noncontrolling interests and for accounting for changes in ownership interests and provides guidance for deconsolidation. Implementation of SFAS No. 160 is not expected to have a material impact on the company's consolidated financial statements or the consolidated financial statements ofRRBs. In addition, CL&P, PSNH or WMECO. and WMECO had other cash deposits held with unaffiliated parties as of December 31, 2010 and 2009. These amounts were as follows:
|
| As of December 31, | ||||
|
| 2010 |
| 2009 | ||
(Millions of Dollars) |
| NU |
| NU | ||
Rate Reduction Bond Deposits |
| $ | 53.1 |
| $ | 40.2 |
Other Deposits |
|
| 7.3 |
|
| 8.1 |
In June 2008, the FASB issued FASB Staff Position (FSP) EITF 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities," which is effective January 1, 2009 and is required to be applied retrospectively. As a result of this FSP, NU's restricted stock awards that were not vested in 2007 and the first quarter of 2008 are considered participating securities in calculating earnings per share (EPS) for these periods using the two-class method. NU's restricted stock awards were completely vested during the first quarter of 2008 and are no longer awarded. FSP EITF 03-6-1 is not expected to impact NU's EPS for any period.
|
| As of December 31, | ||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Rate Reduction Bond Deposits |
| $ | 22.1 |
| $ | 26.9 |
| $ | 4.1 |
| $ | 16.8 |
| $ | 19.7 |
| $ | 3.7 |
Other Deposits |
|
| 2.1 |
|
| 2.8 |
|
| 1.2 |
|
| 5.0 |
|
| 2.2 |
|
| - |
SFAS No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value, was issued in 2006 and applied in 2008 to the fair value measurements of financial assets and liabilities of NU and its subsidiaries. The statement defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. SFAS No. 157 is required to be applied to nonrecurring fair value measurements of non-financial assets and liabilities beginning in 2009, including asset retirement obligations (ARO) and goodwill and other impairment analyses. Implementation of SFAS No. 157 to non-financial assets and liabilities is not expected to have a material impact on the company’s consolidated financial statements or the consolidated financial statements of CL&P, PSNH or WME CO.
D.
Revenues
Regulated Companies: The regulated companies' retail revenues are based on rates approved by the state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. The regulated companies utilize regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.
The regulated companies record monthly, day ahead and real time energy purchases and sales, net in accordance with The Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as defined in EITF Issue No. 02-3." Revenues associated with derivative instruments to purchase and sell in the day ahead and real time markets are recorded net in revenues and fuel, purchased and net interchange power.
Regulated Companies' Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas delivered to customers for which the customers have not yet been billed. Unbilled revenuesThese amounts are included in revenueOther Long-Term Assets on the statement of income and are assets on theaccompanying consolidated balance sheet that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.sheets.
The regulated companies estimate unbilled revenues monthly using the daily load cycle (DLC) method. The DLC method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total calendar month sales to estimate unbilled sales. Unbilled revenues are estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.I.
Fair Value Measurements
Regulated Companies' Transmission Revenues - Wholesale Rates: Wholesale transmission revenues are based on formula rates that are approved by the FERC. Most of NU’s wholesale transmission revenues,NU, including CL&P, PSNH, and WMECO, are collected under the New England Independent System Operator (ISO-NE) FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3). Tariff No. 3 includes Regional Network Service (RNS) and Schedule 21 - NU rate schedules to recover fees for transmission and other services. The RNS rate, administered by ISO-NE and billedapplies fair value measurement guidance to all New England transmission users, including CL&P, PSNH,derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust and WMECO's transmission businesses,spent nuclear fuel trust. Fair value measurement guidance is reset on June 1stalso applied to investment valuations used to calculate the funded status of each yearNU's Pension and recoversPBOP plans and non-recurring fair value measurements of NU's non-financial assets and liabilities, such as AROs and Yankee Gas' goodwill.
Upon adoption of fair value measurement guidance, the revenue requirements associated with transmission facilities that benefit the New England region. The Schedule 21 - NU rate, administered by NU, is reset onCompany recorded a pre-tax charge to Net Income of $6.1 million as of January 1,st 2008 related to derivative liabilities for its remaining unregulated wholesale marketing contracts. In 2010, 2009 and June 1st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate, including 100 percent of the construction work in progress (CWIP) that is included in rate base on the New England East-West Solutions (NEEWS) projects. The Schedule 21 - NU rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all regional and local revenue requirements as prescribed in Tariff No. 3. Both the RNS and Schedule 21 - NU rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to customers. At December 31, 2008, the Schedule 21 - NU rates wereCompany recorded benefits of $0.8 million, $0.7 million and $0.8 million, respectively, to partially reverse the exit price impact recorded as the Company served out rather than exited its one remaining fixed price forward sales contract. In 2008, the Company also recorded a benefit of $1.8 million related to a contract that expired in a total underrecovery position of $4.6 million ($3.8 million for CL&P, $0.6 million for P SNH and $0.2 million for WMECO) that will be collected from customers in mid-2009.May 2008.
Regulated Companies' Transmission Revenues - Retail Rates:Fair Value Hierarchy: A significant portionIn measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Unobservable inputs are needed to value certain derivative contracts due to complexities in the terms of the NU consolidated transmission segment revenue comes from ISO-NE chargescontracts. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the distribution segmentsfair value measurement. NU evaluates the classification of CL&P, PSNHassets and WMECO, each of which recovers these costs through rates charged to their retail customers. CL&P, PSNH and WMECO each have a retail transmission cost tracking mechanism as part of their rates, which allows the companies to charge their retail customers for transmission costsliabilities measured at fair value on a timelyquarterly basis, and NU's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:
Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.
Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products. Significant unobservable inputs are used in the valuations, including items such as energy and energy-related product prices in future years for which observable prices are not yet available, future contract quantities under full-requirements or supplemental sales contracts, and market volatilities. Items valued using these valuation techniques are classified according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, an item may be classified in Level 3 even though the re may be some significant inputs that are readily observable.
Determination of Fair Value: The valuation techniques and inputs used in NU's fair value measurements are described in Note 4, "Derivative Instruments," and Note 5, "Marketable Securities," to the consolidated financial statements. There were no changes to the valuation methodologies for derivative instruments or marketable securities as of December 31, 2010 and 2009.
FS-32107
NU Enterprises: NU Enterprises' revenues are recognized at different times for its different business lines. Service revenues are recognized as services are provided, often on a percentage of completion basis. Wholesale marketing revenues are recognized through mark-to-market accounting on underlying derivative contracts and recorded in fuel, purchased and net interchange power. This net presentation of the mark-to-market and settlement amounts is required because NU Enterprises cannot assert that physical delivery of contract quantities is deemed probable. J.
For further information regarding the recognition of revenue, see Note 1E, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.
E.
Derivative Accounting
Most of CL&P and PSNH's contracts for the purchase and sale of energy or energy related products are derivatives, along with all but one of Select Energy'sNU Enterprises' remaining wholesale marketing contracts. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. Non-derivative contracts are recorded at the time of delivery or settlement.
The application of derivative accounting under SFAS No. 133 is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the "normal purchases or normal purchases and salessales" (normal) exception, identifying, electing and designating hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on the consolidated financial statements.
The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the companyCompany determines whether it is a derivative by using amounts referenced in default provisions and other relevant sections of the contract. The estimated quantities to be served are updated during the term of the contract, and such updates can have a material impact on mark-to-market amounts. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as permitted under FASB Interpretation No. (FIN) 39, "Offsetting of Amounts Relateda net derivative asset or liability to Certain Contracts - an Interpretation of APB Opinion No. 10 and FASB Statement No. 105."the consolidated balance sheets.
The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business over a reasonable period in the normal course of business. CL&P and WMECO haveThe Company has elected normal on many derivative contracts, including all of WMECO's derivative contracts. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied prospectively.
Contracts that are hedging an underlying transaction and that qualify as derivatives that hedge exposure to the variable cash flows of a forecasted transaction (cash flow hedges) are recorded on the consolidated balance sheets at fair value with changes in fair value reflected in accumulated other comprehensive income. Cash flow hedges include forward interest rate swap agreements on proposed debt issuances. When a cash flow hedge is settled, the settlement amount is recorded in accumulated other comprehensive income and is amortized into earnings over the term of the debt. In addition, cash flow hedges impact earnings when hedge ineffectiveness is measured and recorded or when the forecasted transaction being hedged is no longer probable of occurring.
MostAll but one of the contracts that comprise Select Energy’sNU Enterprises' wholesale marketing activities are derivatives, and many of NU’sNU's regulated company contracts for the purchase or sale of energy or energy-related products are derivatives.
EITF 03-11 addresses income statement classification of derivatives that are not related to energy trading activities. In accordance with EITF 03-11, the remaining wholesaleWholesale marketing contracts, which are marked-to-market derivative contracts, are not considered to be held for trading purposes, and sales and purchase activity is reported on a net basis in fuel, purchasedFuel, Purchased and net interchange power.
EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," prohibited recording the initial gains and losses on derivative contracts if their estimated fair values are based on significant non-observable inputs. Based upon the significance of non-observable capacity prices to their valuation, the estimated initial fair values of CL&P’s contracts for differences (CfDs) were not recordedNet Interchange Power on the balance sheet asconsolidated statements of December 31, 2007. These initial losses were recorded upon adoption of SFAS No. 157 on January 1, 2008. For further information, see Note 1F, "Fair Value Measurements," to the consolidated financial statements.income.
For further information regarding derivative contracts of NU, CL&P, PSNH and WMECO and their accounting, see Note 3,4, "Derivative Instruments," to the consolidated financial statements.
F.K.
Fair Value MeasurementsMarketable Securities
On January 1, 2008, NU and its subsidiaries, including CL&P, PSNHSupplemental Benefit Trust and WMECO adopted SFAS No. 157, "Fair Value Measurements,"Spent Nuclear Fuel Trust: NU maintains a supplemental benefit trust to fund NU's SERP and non-SERP obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability, both of which establishes a framework for defining and measuring fair value and requires expanded disclosures about fair value measurements. SFAS No. 157:hold marketable securities.
·
Defines fair value asOther-than-temporary impairments on debt securities held in the priceNU supplemental benefit trust that wouldNU intends to sell or will be received forrequired to sell are recorded in Net Income. Credit losses identified on debt securities held in the sale of an asset or paid to transfer a liabilityNU supplemental benefit trust are also recorded in an orderly transaction between market participants at the measurement date (an exit price).
·
Establishes a three-level fair value hierarchy based upon the observability of inputs to the valuations of assetsNet Income. Unrealized gains and liabilities.
·
Requires consideration of the company's own creditworthiness and risk of nonperformance when valuing its liabilities.
FS-33
·
Required prospective implementation with adjustments to fair value reflected in earnings, similar to a change in estimate, with exceptions including recognition of previously deferred initial gains or losses described below.
·
Required recognition in retained earnings of previously deferred initial gains orunrealized losses on derivative contracts whose estimated fair valuesdebt securities held in the NU supplemental benefit trust that NU does not intend to sell or will not be required to sell are based on significant unobservable inputs. Recognition of the initial gains or losses was previously prohibited under EITF 02-3. CL&P’s initialrecorded in Accumulated Other Comprehensive Income/(Loss). Realized gains and losses on its CfDs that would have beendebt securities WMECO intends to sell or will be required to sell, credit losses and unrealized gains and losses associated with the WMECO spent nuclear fuel trust are recorded on the accompanying consolidated balance sheets due to the regulatory accounting treatment of this trust.
In the second quarter of 2009, NU adopted new accounting guidance related to the recognition and presentation of other- than-temporary impairments. NU recorded an after-tax cumulative effect of accounting change in accounting principle of $0.7 million as an increase to Retained Earnings with an offset to Accumulated Other Comprehensive Income relating to unrealized losses previously recorded in retained earnings upon adoption were recorded as regulatory assets and liabilities because their costs or benefits are expected to be fully recovered from or refunded to customers.
Upon adoption, the company applied SFAS No. 157 to the regulated and unregulated companies' derivative contracts that are recorded at fair value and to the marketableNet Income on debt securities held in the Trust Under Supplemental Executive Retirement Plan (SERP) ("NU supplemental benefit trust"),trust, which did not meet the criteria established for non-pension retirement benefits,in the new accounting guidance.
Prior to the adoption of accounting guidance in the second quarter of 2009, changes in the fair value of debt securities in the NU supplemental benefit trust and WMECO'sthe WMECO spent nuclear fuel trust. The company also applied SFAS No. 157trust relating to investment valuations usedunrealized losses were considered other-than-temporary because NU and WMECO did not have the ability to calculatehold the funded statusdebt securities to maturity. Losses on the NU supplemental benefit trust were recorded in Net Income and losses on the WMECO spent nuclear fuel trust were recorded on the balance sheet due to the regulatory nature of NU’s pensionthe trust.
In 2010 and postretirement benefit plans as of December 31, 2008. In 2009, the company will be required to apply SFAS No. 157 to nonrecurringunder applicable fair value measurements of non-financial assets and liabilities, such as goodwill and AROs.
As a result of adopting SFAS No. 157,accounting guidance, the company recorded a pre-tax chargeCompany elected to earnings of $6.1 million as of January 1, 2008 related to derivative liabilities for its remaining unregulated wholesale marketing contracts. In 2008, the company recorded a $0.8 million pre-tax benefit to partially reverse the exit price impact recorded under SFAS No. 157 as the company served out rather than exited the contracts.
The company also recordedrecord changes in fair value of certain derivative contractsnewly purchased equity securities in the NU supplemental benefit trust in Net Income. Realized and unrealized gains and losses related to these securities are included in Other Income, Net, on the accompanying consolidated statements of CL&P. Because CL&P is a cost-of-service, rate regulated entity,income for the cost or benefit of the contracts is expected to be fully recovered from or refunded to CL&P's customers,years ended December 31, 2010 and an offsetting regulatory asset or liability was recorded to reflect these changes. As of January 1, 2008, implementing SFAS No. 157 resulted in a total increase to CL&P's derivative liabilities, with an offset2009.
These trusts are not subject to regulatory assets, of approximately $590 million, and a total decrease to derivative assets, with an offset to regulatory liabilities, of approximately $30 million.
Fair Value Hierarchy: As requiredoversight by SFAS No. 157, in measuring fair value the company uses observable market data when available and minimizes the use of unobservable inputs. Unobservable inputs are needed to value certain derivative contracts due to complexities in contractual terms and the long duration of contracts. SFAS No. 157 requires inputs used in fair value measurements to be categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement.
The three levels of the fair value hierarchy are described below:
Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assetsstate or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.
Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products. Significant unobservable inputs are used in the valuations, including items such as energy and energy-related product prices in future years for which observable prices are not yet available, future contract quantities under full-requirements or supplemental sales contracts, and market volatilities. Items valued using these valuation techniques are classified according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, an item may be classified in Level 3 even though t here may be some significant inputs that are readily observable.
Determination of Fair Value: The following is a description of the valuation techniques utilized in NU, CL&P, PSNH, and WMECO's fair value measurements:
Derivative contracts:Many of the company's derivative positions that are recorded at fair value are classified as Level 3 within the fair value hierarchy and are valued using models that incorporate both observable and unobservable inputs. Fair value is modeled using techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price and the Black-Scholes option pricing model, incorporating the terms of the contracts. Significant unobservable inputs utilized in the valuations include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical mark et transaction information. Valuations of derivative contracts also reflect nonperformance risk, including credit. The derivative contracts classified as Level 3 include NU Enterprises’ remaining wholesale marketing contract and its related supply contracts, CL&P's CfDs, CL&P's contracts with certain independent power producers (IPPs), PSNH and Yankee Gas options and CL&P and PSNH financial transmission rights (FTRs).
Other derivative contracts recorded at fair value are classified as Level 2 within the fair value hierarchy. An active market for the same or similar contracts exists for these contracts, which include PSNH forward contracts to purchase energy and interest rate swap
FS-34
agreements for the regulated companies and NU parent. For these contracts, valuations are based on quoted prices in the market and include some modeling using market-based assumptions. federal agencies.
For further information on derivative contracts,regarding marketable securities, see Note 3, "Derivative Instruments," to the consolidated financial statements.
Marketable securities: NU and WMECO hold in trust marketable securities, which include equity securities, mutual funds and cash equivalents, and fixed maturity securities.
Equity securities, mutual funds and cash equivalents are classified as Level 1 in the fair value hierarchy. These investments are traded in active markets and quoted prices are available for identical investments.
Fixed maturity securities classified as Level 2 within the fair value hierarchy include U.S. Treasury securities, corporate bonds, collateralized mortgage obligations, U.S. pass-through bonds, asset-backed securities, commercial mortgage-backed securities, and commercial paper. The fair value of these instruments is estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures.
For further information see Note 4, "Fair Value Measurements," and Note 9,"Marketable5, "Marketable Securities," to the consolidated financial statements.
G.
Regulatory Accounting
The accounting policies of the regulated companies conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
The transmission and distribution segments of CL&P, PSNH and WMECO, along with Yankee Gas’ distribution segment, continue to be cost-of-service, rate regulated. Management believes that the application of SFAS No. 71 to those segments continues to be appropriate. Management also believes it is probable that NU’s regulated companies will recover their investments in long-lived assets, including regulatory assets. All material net regulatory assets are earning an equity return, except for securitized regulatory assets, the majority of deferred benefit costs and regulatory assets offsetting regulated company derivative liabilities, which are not supported by equity. Amortization and deferrals of regulatory assets/(liabilities) are included on a net basis in amortization expense on the accompanying consolidated statements of income.
Regulatory Assets: The components of regulatory assets are as follows:
|
| At December 31, | ||||
|
| 2008 |
| 2007 | ||
|
| NU |
| NU | ||
Securitized assets |
| $ | 677.4 |
| $ | 907.0 |
Income taxes, net |
|
| 355.4 |
|
| 335.5 |
Deferred benefit costs |
|
| 1,140.9 |
|
| 201.4 |
Unrecovered contractual obligations |
|
| 169.1 |
|
| 189.9 |
Regulatory assets offsetting regulated |
|
|
|
|
|
|
CL&P undercollections |
|
| 75.2 |
|
| 90.6 |
Other regulatory assets |
|
| 240.4 |
|
| 210.4 |
Totals |
| $ | 3,502.6 |
| $ | 2,057.1 |
|
| At December 31, | ||||||||||||||||
|
| 2008 |
| 2007 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Securitized assets |
| $ | 377.8 |
| $ | 227.6 |
| $ | 72.0 |
| $ | 548.2 |
| $ | 273.2 |
| $ | 85.6 |
Income taxes, net |
|
| 306.8 |
|
| 16.1 |
|
| 20.7 |
|
| 279.4 |
|
| 10.3 |
|
| 38.2 |
Deferred benefit costs |
|
| 537.7 |
|
| 142.9 |
|
| 113.5 |
|
| 72.2 |
|
| 50.4 |
|
| 8.2 |
Unrecovered contractual obligations |
|
| 132.6 |
|
| - |
|
| 36.5 |
|
| 148.0 |
|
| - |
|
| 42.0 |
Regulatory assets offsetting regulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P undercollections |
|
| 75.2 |
|
| - |
|
| - |
|
| 90.6 |
|
| - |
|
| - |
WMECO recoverable nuclear costs |
|
| - |
|
| - |
|
| 5.0 |
|
| - |
|
| - |
|
| 9.3 |
Other regulatory assets |
|
| 92.1 |
|
| 71.2 |
|
| 20.7 |
|
| 71.8 |
|
| 65.0 |
|
| 10.6 |
Totals |
| $ | 2,274.1 |
| $ | 549.9 |
| $ | 268.4 |
| $ | 1,330.0 |
| $ | 401.4 |
| $ | 193.9 |
Additionally, the regulated companies had $68.3 million ($62.7 million for PSNH and $5.6 million for CL&P) and $11.9 million (CL&P) of regulatory costs at December 31, 2008 and 2007, respectively, which were included in deferred debits and other assets - other on the accompanying consolidated balance sheets. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. The $62.7 million for PSNH relates to costs incurred relating to December 2008 storm restorations that met NHPUC specified criteria for deferral to a major storm cost reserve. Management believes these costs are recoverable in future cost-of-service regulated rates.
FS-35108
Securitized Assets: In March 2001, CL&P issued $1.4 billion in rate reduction bonds (RRBs). CL&P used $1.1 billion of the proceeds from that issuance to buyout or buydown certain contracts with IPPs. The unamortized CL&P securitized asset balance was $322.9 million and $468.6 million at December 31, 2008 and 2007, respectively, which includes $44.9 million and $65.1 million, respectively, related to unrecovered contractual obligations. CL&P also used the proceeds from the issuance of the RRBs to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset. The securitized SFAS No. 109 regulatory asset had an unamortized balance of $54.9 million and $79.6 million at December 31, 2008 and 2007, respectively.
In April 2001, PSNH issued RRBs in the amount of $525 million. PSNH used the majority of the proceeds from that issuance to buydown its affiliated power contracts with North Atlantic Energy Corporation. The unamortized PSNH securitized asset balance was $227.6 million and $272.4 million at December 31, 2008 and 2007, respectively. In January 2002, PSNH issued an additional $50 million in RRBs and used the proceeds from that issuance to repay short-term debt that was incurred to buyout a purchased-power contract in December 2001. The unamortized PSNH securitized asset balance for the January 2002 issuance was $0.8 million at December 31, 2007. The January 2002 RRBs were paid in full in the first quarter of 2008.
In May 2001, WMECO issued $155 million in RRBs and used the majority of the proceeds from that issuance to buyout an IPP contract. The unamortized WMECO securitized asset balance was $72 million and $85.6 million at December 31, 2008 and 2007, respectively.
Securitized regulatory assets, which are not earning an equity return, are being recovered over the amortization period of their associated RRBs. All outstanding CL&P RRBs are scheduled to fully amortize by December 30, 2010, while PSNH RRBs are scheduled to fully amortize by May 1, 2013, and WMECO RRBs are scheduled to fully amortize by June 1, 2013.
Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions, SFAS No. 109 and FIN 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." Differences in income taxes between SFAS No. 109, FIN 48 and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.
Deferred Benefit Costs: On December 31, 2006, the company implemented SFAS No. 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans." SFAS No. 158 applies to NU’s Pension Plan, SERP, and postretirement benefits other than pension (PBOP) Plan and requires an additional benefit liability to be recorded with an offset to accumulated other comprehensive income in shareholders’ equity, which is remeasured annually. However, because the regulated companies are cost-of-service rate regulated entities under SFAS No. 71, offsets were recorded as a regulatory asset at December 31, 2008 and 2007 as these amounts have been and continue to be recoverable in cost-of-service regulated rates. Regulatory accounting was also applied to the portions of the Northeast Utilities Service Company (NUSCO) costs that support the regula ted companies, as these amounts are also recoverable. The deferred benefit costs of CL&P and PSNH are not in rate base and are being recovered over a period of up to 12 years. WMECO’s deferred benefit costs are in rate base.
Unrecovered Contractual Obligations: Under the terms of contracts with the Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Electric Company (YAEC), and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), CL&P, PSNH, and WMECO are responsible for their proportionate share of the remaining costs of the units, including decommissioning. A portion of these amounts was recorded as unrecovered contractual obligations regulatory assets at December 31, 2008 and 2007. A portion of these obligations for CL&P was securitized in 2001 and was included in securitized regulatory assets. Amounts for CL&P are being recovered through the Competitive Transition Assessment (CTA). Amounts for WMECO are being recovered along with other stranded costs. Amounts for PSNH were fully recovered by December 31, 2006.
Regulatory Assets Offsetting Regulated Company Derivative Liabilities: The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future. Included in these amounts are $677.8 million and $86.7 million at December 31, 2008 and 2007, respectively, of derivative liabilities relating to CL&P’s capacity contracts, referred to as CfDs. See Note 3, "Derivative Instruments," to the consolidated financial statements for further information. This asset is excluded from rate base.
CL&P Undercollections: The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes and displaced workers protection costs. At December 31, 2008 and 2007, SBC undercollections totaled $43.3 million and $36.6 million, respectively.
The Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard service, which includes forward capacity market charges. The Federally Mandated Congestion Charges (FMCC) mechanism allows CL&P to recover the costs of power market rules by the FERC, including Reliability Must Run (RMR) costs. At December 31, 2008, CL&P’s GSC and FMCC was recorded as a $31.9 million regulatory asset as GSC and FMCC unrecovered costs were in excess of GSC and FMCC collections. At December 31, 2007, GSC and FMCC collections were in excess of GSC and FMCC costs, and a $119.2 million regulatory liability was recorded.
The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the RRBs, amortization of regulatory assets, and IPP over market costs. At December 31, 2007, CL&P's CTA was recorded as a $54 million regulatory asset as CTA unrecovered costs were in excess of CTA collections. At December 31, 2008, CTA collections were in excess of CTA costs, and a $69.5 million regulatory liability was recorded.
FS-36
WMECO Recoverable Nuclear Costs: Included in recoverable nuclear costs at December 31, 2008 and 2007 are costs primarily related to Millstone 1 recoverable nuclear costs for the undepreciated plant and related assets at the time Millstone 1 was shutdown.
Other Regulatory Assets: Other regulatory assets at December 31, 2008 and 2007 consisted of the following:
|
| At December 31, | ||||
|
| 2008 |
| 2007 | ||
|
| NU |
| NU | ||
Asset retirement obligations |
| $ | 42.3 |
| $ | 40.6 |
Losses on reacquired debt |
|
| 26.4 |
|
| 28.8 |
Environmental costs |
|
| 27.2 |
|
| 29.3 |
Storm reserves |
|
| 19.3 |
|
| 6.8 |
Buyout/buydown of other IPP contracts |
|
| 14.2 |
|
| 16.1 |
Write-off of uncollectible hardship receivables |
|
| 16.0 |
|
| 26.8 |
Conservation & load management deferral |
|
| 19.1 |
|
| 13.3 |
Recoverable nuclear costs |
|
| 5.0 |
|
| 9.3 |
Recoverable energy costs |
|
| 0.7 |
|
| 1.3 |
Other |
|
| 70.2 |
|
| 38.1 |
Total other regulatory assets |
| $ | 240.4 |
| $ | 210.4 |
|
| At December 31, | ||||||||||||||||
|
| 2008 |
| 2007 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Asset retirement obligations |
| $ | 23.1 |
| $ | 13.9 |
| $ | 2.8 |
| $ | 22.2 |
| $ | 13.3 |
| $ | 2.7 |
Losses on reacquired debt |
|
| 14.0 |
|
| 10.1 |
|
| 0.5 |
|
| 15.4 |
|
| 10.9 |
|
| 0.5 |
Environmental costs |
|
| - |
|
| 2.0 |
|
| - |
|
| - |
|
| 2.3 |
|
| - |
Storm reserves |
|
| - |
|
| 8.2 |
|
| 11.1 |
|
| - |
|
| 6.8 |
|
| - |
Buyout/buydown of other IPP contracts |
|
| 0.8 |
|
| 13.4 |
|
| - |
|
| 1.1 |
|
| 15.0 |
|
| - |
Write-off of uncollectible hardship receivables |
|
| - |
|
| - |
|
| - |
|
| 10.4 |
|
| - |
|
| - |
Conservation & load management deferral |
|
| 17.6 |
|
| - |
|
| 0.2 |
|
| 9.9 |
|
| - |
|
| 2.6 |
Recoverable energy costs |
|
| - |
|
| - |
|
| 0.7 |
|
| - |
|
| - |
|
| 1.3 |
Other |
|
| 36.6 |
|
| 23.6 |
|
| 5.4 |
|
| 12.8 |
|
| 16.7 |
|
| 3.5 |
Total other regulatory assets |
| $ | 92.1 |
| $ | 71.2 |
| $ | 20.7 |
| $ | 71.8 |
| $ | 65.0 |
| $ | 10.6 |
The regulatory assets above associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," included $12 million and $11.6 million at December 31, 2008 and 2007, respectively, related to PSNH that have been approved for future recovery. As part of WMECO's rate case settlement, the DPU approved accounting requirements setting forth the recognition of its AROs and a corresponding regulatory asset. Management believes that recovery of the remaining FIN 47 regulatory assets is probable.
Regulatory Liabilities: The components of regulatory liabilities are as follows:
|
| At December 31, | ||||
|
| 2008 |
| 2007 | ||
|
| NU |
| NU | ||
Cost of removal |
| $ | 226.0 |
| $ | 262.6 |
Regulatory liabilities offsetting |
|
|
|
|
|
|
CL&P overcollections |
|
| 69.5 |
|
| 119.2 |
CL&P AFUDC transmission incentive (Note 1K) |
|
| 47.6 |
|
| 21.4 |
PSNH deferred ES revenue, net |
|
| 33.0 |
|
| 17.6 |
Pension and PBOP liabilities - |
|
|
|
|
|
|
Overrecovered gas costs |
|
| 16.9 |
|
| 10.4 |
Other regulatory liabilities |
|
| 44.1 |
|
| 69.5 |
Totals |
| $ | 592.5 |
| $ | 851.8 |
FS-37
|
| At December 31, | ||||||||||||||||
|
| 2008 |
| 2007 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Cost of removal |
| $ | 91.2 |
| $ | 64.7 |
| $ | 19.2 |
| $ | 116.6 |
| $ | 72.8 |
| $ | 21.5 |
Regulatory liabilities offsetting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| - |
CL&P overcollections |
|
| 69.5 |
|
| - |
|
| - |
|
| 119.2 |
|
| - |
|
| - |
CL&P AFUDC transmission incentive (Note 1K) |
|
| 47.6 |
|
| - |
|
| - |
|
| 21.4 |
|
| - |
|
| - |
PSNH deferred ES revenue, net |
|
| - |
|
| 33.0 |
|
| - |
|
| - |
|
| 17.6 |
|
| - |
PSNH deferred environmental credit revenue |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 10.1 |
|
| - |
WMECO transition charge overcollections |
|
| - |
|
| - |
|
| 5.7 |
|
| - |
|
| - |
|
| 2.4 |
WMECO transmission refunds |
|
| - |
|
| - |
|
| 0.2 |
|
| - |
|
| - |
|
| 5.8 |
WMECO pension/PBOP tracker |
|
| - |
|
| - |
|
| 2.0 |
|
| - |
|
| - |
|
| 4.6 |
WMECO default service overcollections |
|
| - |
|
| - |
|
| 1.3 |
|
| - |
|
| - |
|
| 3.9 |
Other regulatory liabilities |
|
| 23.9 |
|
| 9.1 |
|
| 1.4 |
|
| 31.3 |
|
| 9.9 |
|
| 1.2 |
Totals |
| $ | 363.5 |
| $ | 111.4 |
| $ | 29.8 |
| $ | 601.5 |
| $ | 127.6 |
| $ | 39.4 |
Cost of Removal: NU’s regulated companies currently recover amounts in rates for future costs of removal of plant assets. These amounts are classified as regulatory liabilities on the accompanying consolidated balance sheets. This liability is included in rate base.
Regulatory Liabilities Offsetting Regulated Company Derivative Assets: The regulatory liabilities offsetting derivative assets relate to the fair value of contracts used to purchase power and other related contracts that will benefit ratepayers in the future. See Note 3, "Derivative Instruments," to the consolidated financial statements for further information. This liability is excluded from rate base.
CL&P Overcollections: As noted previously, the CTA allows CL&P to recover stranded costs, the GSC allows CL&P to recover the costs of the procurement of energy for standard service and the FMCC allows CL&P to recover the costs of power market rules by the FERC. At December 31, 2008, CTA overcollections totaled $69.5 million and were recorded as a regulatory liability while GSC and FMCC undercollections totaled $31.9 million and was recorded as a regulatory asset. At December 31, 2007, GSC and FMCC overcollections totaled $119.2 million and was recorded as a regulatory liability while CTA undercollections totaled $54 million and was recorded as a regulatory asset.
PSNH Deferred ES Revenue, Net: PSNH default energy service (ES) revenues and costs are fully tracked, and the difference between ES revenues and costs are deferred. ES deferrals are being collected from/refunded to customers through a charge/(credit) in the subsequent ES rate period.
PSNH Deferred Environmental Credit Revenue: PSNH recorded a regulatory obligation to credit ratepayers for accelerated recovery of certain Clean Air Act capital improvements allowed in prior years. This amount was refunded to customers in 2008.
WMECO Transition Charge Overcollections: WMECO recovers it stranded costs through a transition charge. This amount represents the cumulative excess of transition cost revenues over transition cost expenses.
WMECO Transmission Refunds: Transmission refunds relate to the retail transmission tracker costs that WMECO incurred on behalf of its customers in the delivery of customer energy services and collected these costs in rates.
WMECO Pension/PBOP Tracker: In 2006, the DPU approved a cost tracking mechanism for WMECO's pension and PBOP plan costs effective on January 1, 2007. The approved tracking mechanism also allows WMECO to earn a return on its pension and PBOP assets and liabilities at its weighted average cost of capital, including the future pension and PBOP benefit obligations deferred under SFAS No. 158.
WMECO Default Service Overcollections: The default service rate allows WMECO to recover the costs of the procurement of energy for basic service, which includes forward capacity market charges.
Pension and PBOP Liabilities - Yankee Gas Acquisition: When Yankee Gas was acquired by NU, the Pension and PBOP liabilities were adjusted to fair value with offsets to these adjustments recorded as regulatory liabilities, as approved by the DPUC.
Overrecovered Gas Costs:The Yankee Gas regulated rates include a Purchased Gas Adjustment (PGA) clause under which gas costs below base rate levels calculated annually on August 31st are returned to customers. Differences between the actual gas costs and the current base rate recovery amounts are deferred and returned in future periods.
FS-38
H.
Income Taxes
The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions, SFAS No. 109 and FIN 48. Details of income tax expense/(benefit) related to continuing operations are as follows:
|
| For the Years Ended December 31, | |||||||
|
| 2008 |
| 2007 |
| 2006 | |||
|
| NU |
| NU |
| NU | |||
(Millions of Dollars) |
|
| |||||||
The components of the federal and state |
|
|
|
|
|
|
|
|
|
Current income taxes: |
|
|
|
|
|
|
|
|
|
Federal |
| $ | 6.0 |
| $ | 89.3 |
| $ | 59.7 |
State |
|
| 16.3 |
|
| 18.9 |
|
| (19.1) |
Total current |
|
| 22.3 |
|
| 108.2 |
|
| 40.6 |
Deferred income taxes, net: |
|
|
|
|
|
|
|
|
|
Federal |
|
| 100.2 |
|
| 26.2 |
|
| (49.7) |
State |
|
| (13.4) |
|
| (21.4) |
|
| (4.2) |
Total deferred |
|
| 86.8 |
|
| 4.8 |
|
| (53.9) |
Investment tax credits, net |
|
| (3.4) |
|
| (3.6) |
|
| (63.0) |
Income tax expense/(benefit) |
| $ | 105.7 |
| $ | 109.4 |
| $ | (76.3) |
|
| At December 31, | |||||||||||||||||||||||||
|
| 2008 |
| 2007 |
| 2006 | |||||||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||||
(Millions of Dollars) |
|
| |||||||||||||||||||||||||
Current income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Federal |
| $ | 13.9 |
| $ | 0.8 |
| $ | (1.4) |
| $ | 36.3 |
| $ | 21.9 |
| $ | 26.4 |
| $ | 104.9 |
| $ | 50.5 |
| $ | 25.5 |
State |
|
| 19.0 |
|
| (3.6) |
|
| - |
|
| (10.0) |
|
| 5.9 |
|
| 3.8 |
|
| 3.8 |
|
| 11.0 |
|
| (0.2) |
Total current |
|
| 32.9 |
|
| (2.8) |
|
| (1.4) |
|
| 26.3 |
|
| 27.8 |
|
| 30.2 |
|
| 108.7 |
|
| 61.5 |
|
| 25.3 |
Deferred income taxes, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
| 68.0 |
|
| 17.4 |
|
| 10.4 |
|
| 23.5 |
|
| (1.7) |
|
| (12.9) |
|
| (69.2) |
|
| (17.1) |
|
| (21.2) |
State |
|
| (20.4) |
|
| 7.6 |
|
| 1.8 |
|
| 5.2 |
|
| (3.0) |
|
| (2.4) |
|
| (21.5) |
|
| (4.8) |
|
| 4.0 |
Total deferred |
|
| 47.6 |
|
| 25.0 |
|
| 12.2 |
|
| 28.7 |
|
| (4.7) |
|
| (15.3) |
|
| (90.7) |
|
| (21.9) |
|
| (17.2) |
Investment tax credits, net |
|
| (2.6) |
|
| (0.2) |
|
| (0.2) |
|
| (2.6) |
|
| (0.3) |
|
| (0.3) |
|
| (62.0) |
|
| (0.4) |
|
| (0.3) |
Income tax expense/(benefit) |
| $ | 77.9 |
| $ | 22.0 |
| $ | 10.6 |
| $ | 52.4 |
| $ | 22.8 |
| $ | 14.6 |
| $ | (44.0) |
| $ | 39.2 |
| $ | 7.8 |
A reconciliation between income tax expense/(benefit) and the expected tax expense/(benefit) at the statutory rate is as follows:
|
| For the Years Ended December 31, | ||||||||||
|
| NU |
| NU |
| NU | ||||||
|
| 2008 |
| 2007 |
| 2006 | ||||||
|
| (Millions of Dollars, except percentages) | ||||||||||
Income from continuing operations |
| $ |
|
|
| $ |
|
|
| $ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected federal income tax expense/(benefit) |
|
| 130.2 |
|
|
| 126.3 |
|
|
| 21.7 |
|
Tax effect of differences: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
| (12.9) |
|
|
| (6.6) |
|
|
| (4.0) |
|
Amortization of regulatory assets |
|
| 0.2 |
|
|
| 0.2 |
|
|
| 13.3 |
|
Investment tax credit amortization (including |
|
|
|
|
|
|
|
|
|
|
|
|
Other federal tax credits |
|
| (4.6) |
|
|
| (4.2) |
|
|
| (0.3) |
|
State income taxes, net of federal impact |
|
| (9.5) |
|
|
| (9.6) |
|
|
| (16.8) |
|
Excess deferred income taxes - CL&P PLR |
|
| - |
|
|
| - |
|
|
| (14.7) |
|
Deferred tax adjustment - sale to affiliate |
|
| - |
|
|
| - |
|
|
| (6.0) |
|
Medicare subsidy |
|
| (4.2) |
|
|
| (4.4) |
|
|
| (5.5) |
|
Tax asset valuation allowance/reserve adjustments |
|
| 12.5 |
|
|
| 10.5 |
|
|
| 1.4 |
|
Other, net |
|
| (2.6) |
|
|
| 0.8 |
|
|
| (2.4) |
|
Income tax expense/(benefit) |
| $ | 105.7 |
|
| $ | 109.4 |
|
| $ | (76.3) |
|
Effective tax rate |
|
| 28.4 | % |
|
| 30.3 | % |
|
| * | % |
*Not meaningful.
FS-39
|
| For the Years Ended December 31, | ||||||||||||||||||||||||||||||||||
|
| 2008 |
| 2007 |
| 2006 | ||||||||||||||||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||||||||||||||
|
| (Millions of Dollars, except percentages) | ||||||||||||||||||||||||||||||||||
Income from continuing operations |
| $ |
|
|
| $ |
|
|
| $ |
|
|
| $ |
|
|
| $ |
|
|
| $ |
|
|
| $ |
|
|
| $ |
|
|
| $ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected federal income tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax effect of differences: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
| (11.1) |
|
|
| (1.8) |
|
|
| 0.1 |
|
|
| (6.6) |
|
|
| - |
|
|
| 0.5 |
|
|
| (1.8) |
|
|
| - |
|
|
| (0.3) |
|
Amortization of regulatory assets |
|
| 0.1 |
|
|
| - |
|
|
| 0.1 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 13.2 |
|
|
| - |
|
Investment tax credit amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other federal tax credits |
|
| (1.2) |
|
|
| (3.4) |
|
|
| - |
|
|
| (1.1) |
|
|
| (3.1) |
|
|
| - |
|
|
| - |
|
|
| (0.6) |
|
|
| - |
|
State income taxes, net of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess deferred income taxes - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax adjustment - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Medicare subsidy |
|
| (1.5) |
|
|
| (0.8) |
|
|
| (0.4) |
|
|
| (1.8) |
|
|
| (0.9) |
|
|
| (0.4) |
|
|
| (2.2) |
|
|
| (1.0) |
|
|
| (0.5) |
|
Tax asset valuation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net |
|
| (1.3) |
|
|
| (2.4) |
|
|
| (0.3) |
|
|
| 0.4 |
|
|
| (1.8) |
|
|
| 0.5 |
|
|
| (2.3) |
|
|
| (2.5) |
|
|
| 0.2 |
|
Income tax expense/(benefit) |
| $ | 77.9 |
|
| $ | 22.0 |
|
| $ | 10.6 |
|
| $ | 52.4 |
|
| $ | 22.8 |
|
| $ | 14.6 |
|
| $ | (44.0) |
|
| $ | 39.2 |
|
| $ | 7.8 |
|
Effective tax rate |
|
| 28.9 | % |
|
| 27.5 | % |
|
| 36.7 | % |
|
| 28.2 | % |
|
| 29.5 | % |
|
| 38.2 | % |
|
| * | % |
|
| 52.6 | % |
|
| 33.3 | % |
*Not meaningful.
NU and its subsidiaries, including CL&P, PSNH and WMECO, file a consolidated federal income tax return and file state income tax returns, with some filing in more than one state. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.
In 2000, CL&P requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (UITC) and excess deferred income taxes (EDIT) related to generation assets that were sold. In 2006, the IRS issued a PLR in response to CL&P's request for a ruling, which held that it would be a violation of tax regulations if the EDIT or UITC are used to reduce customers' rates following the sale of the generation assets. CL&P's UITC and EDIT balances related to generation assets that had been sold totaled $59 million and $15 million, respectively, and $74 million combined. Later in 2006, the DPUC determined that the UITC and EDIT amounts were no longer required to be held in their existing accounts. As a result of this determination, the $74 million balance was reflected as a reduction to CL&P's 2006 income tax expense with an increase to CL&P's earnings by the same amount.
Included in 2006 amortization of regulatory assets above is $13 million associated with PSNH's restructuring settlement agreement, which was implemented in 2001. In accordance with the provisions of the restructuring settlement, pre-tax amortization of PSNH non-deductible acquisition costs was $38 million in 2006.
FS-40
The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:
|
| At December 31, | ||||
|
| 2008 |
| 2007 | ||
|
| NU |
| NU | ||
Deferred tax liabilities - current: |
|
|
|
|
|
|
Derivative asset and change in fair value of energy contracts |
| $ | 12.5 |
| $ | 21.9 |
Property tax accruals and other |
|
| 47.5 |
|
| 52.2 |
Total deferred tax liabilities - current |
|
| 60.0 |
|
| 74.1 |
Deferred tax assets - current: |
|
|
|
|
|
|
Derivative liability and change in fair value of energy contracts |
|
| 42.4 |
|
| 11.0 |
Allowance for uncollectible accounts and other |
|
| 35.3 |
|
| 22.7 |
Total deferred tax assets - current |
|
| 77.7 |
|
| 33.7 |
Net deferred tax (assets)/liabilities - current |
|
| (17.7) |
|
| 40.4 |
Deferred tax liabilities - long-term: |
|
|
|
|
|
|
Accelerated depreciation and other plant-related differences |
|
| 1,155.4 |
|
| 967.5 |
Employee benefits |
|
| 3.8 |
|
| 167.8 |
Regulatory amounts: |
|
|
|
|
|
|
Securitized contract termination costs |
|
| 135.3 |
|
| 167.0 |
Other regulatory deferrals |
|
| 875.8 |
|
| 93.9 |
Income tax gross-up |
|
| 192.6 |
|
| 194.7 |
Derivative assets |
|
| 88.1 |
|
| 111.1 |
Other |
|
| 10.7 |
|
| 66.5 |
Total deferred tax liabilities - long-term |
|
| 2,461.7 |
|
| 1,768.5 |
Deferred tax assets - long-term: |
|
|
|
|
|
|
Regulatory deferrals |
|
| 168.2 |
|
| 192.2 |
Employee benefits |
|
| 481.3 |
|
| 280.3 |
Income tax gross-up |
|
| 29.0 |
|
| 34.0 |
Derivative liability |
|
| 364.8 |
|
| 54.2 |
Other |
|
| 211.3 |
|
| 164.6 |
Total deferred tax assets - long-term |
|
| 1,254.6 |
|
| 725.3 |
Less: valuation allowance |
|
| 16.4 |
|
| 24.3 |
Net deferred tax assets - long-term |
|
| 1,238.2 |
|
| 701.0 |
Net deferred tax liabilities - long-term |
|
| 1,223.5 |
|
| 1,067.5 |
Net deferred tax liabilities |
| $ | 1,205.8 |
| $ | 1,107.9 |
FS-41
|
| At December 31, | ||||||||||||||||
|
| 2008 |
| 2007 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Deferred tax liabilities - current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative asset and change in fair value |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
Property tax accruals and other |
|
| 32.3 |
|
| 4.4 |
|
| 2.5 |
|
| 35.3 |
|
| 6.2 |
|
| 2.3 |
Total deferred tax liabilities - current |
|
| 44.5 |
|
| 4.7 |
|
| 2.5 |
|
| 57.1 |
|
| 6.2 |
|
| 2.3 |
Deferred tax assets - current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liability and change in fair value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for uncollectible accounts and other |
|
| 24.3 |
|
| 1.4 |
|
| 2.6 |
|
| 16.3 |
|
| 0.9 |
|
| 2.2 |
Total deferred tax assets - current |
|
| 27.8 |
|
| 32.0 |
|
| 2.6 |
|
| 16.3 |
|
| 1.9 |
|
| 2.2 |
Net deferred tax liabilities/(assets) - current |
|
| 16.7 |
|
| (27.3) |
|
| (0.1) |
|
| 40.8 |
|
| 4.3 |
|
| 0.1 |
Deferred tax liabilities - long-term: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accelerated depreciation and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee benefits |
|
| - |
|
| - |
|
| - |
|
| 133.2 |
|
| - |
|
| 33.5 |
Regulatory amounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securitized contract termination costs |
|
| 19.3 |
|
| 88.4 |
|
| 27.6 |
|
| 28.2 |
|
| 106.0 |
|
| 32.7 |
Other regulatory deferrals |
|
| 548.2 |
|
| 134.2 |
|
| 53.4 |
|
| 70.8 |
|
| 14.0 |
|
| - |
Income tax gross-up |
|
| 158.5 |
|
| 9.1 |
|
| 15.7 |
|
| 161.3 |
|
| - |
|
| 17.8 |
Derivative assets |
|
| 85.8 |
|
| 1.5 |
|
| - |
|
| 111.1 |
|
| - |
|
| - |
Other |
|
| 9.0 |
|
| 6.7 |
|
| 1.8 |
|
| 16.0 |
|
| 23.2 |
|
| 19.8 |
Total deferred tax liabilities - long-term |
|
| 1,458.8 |
|
| 456.2 |
|
| 233.7 |
|
| 1,067.4 |
|
| 305.8 |
|
| 217.2 |
Deferred tax assets - long-term: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory deferrals |
|
| 82.3 |
|
| 51.1 |
|
| 12.1 |
|
| 168.5 |
|
| 27.5 |
|
| 16.9 |
Employee benefits |
|
| 101.9 |
|
| 121.5 |
|
| 13.1 |
|
| 63.6 |
|
| 77.2 |
|
| 7.1 |
Income tax gross-up |
|
| 14.3 |
|
| 2.8 |
|
| 7.3 |
|
| 18.2 |
|
| - |
|
| 2.8 |
Derivative liability |
|
| 338.2 |
|
| 5.9 |
|
| - |
|
| 54.2 |
|
| - |
|
| - |
Other |
|
| 110.7 |
|
| 21.2 |
|
| 13.9 |
|
| 64.1 |
|
| 9.0 |
|
| 3.3 |
Net deferred tax assets - long-term |
|
| 647.4 |
|
| 202.5 |
|
| 46.4 |
|
| 368.6 |
|
| 113.7 |
|
| 30.1 |
Net deferred tax liabilities - long-term |
|
| 811.4 |
|
| 253.7 |
|
| 187.3 |
|
| 698.8 |
|
| 192.1 |
|
| 187.1 |
Net deferred tax liabilities |
| $ | 828.1 |
| $ | 226.4 |
| $ | 187.2 |
| $ | 739.6 |
| $ | 196.4 |
| $ | 187.2 |
Net deferred tax liabilities/(assets) - current are recorded as current liabilities or assets and are included in current liabilities - other or prepayments and other, respectively, on the accompanying consolidated balance sheets.
At December 31, 2008, NU had state net operating loss (NOL) carryforwards of $269.1 million that expire between December 31, 2010 and December 31, 2028 and state credit carryforwards of $90.8 million that expire by December 31, 2013. At December 31, 2007, NU had state NOL carryforwards of $434.1 million that expire between December 31, 2009 and December 31, 2027 and state credit carryforwards of $61.3 million that expire by December 31, 2012. The NOL carryforward deferred tax asset has been fully reserved by a valuation allowance. At December 31, 2008, CL&P had state tax credit carryforwards of $64.4 million that expire by 2013. At December 31, 2007, CL&P had state tax credit carry forwards of $38 million that expire by 2012.
On July 3, 2008, Massachusetts amended its corporate excise tax provisions, which are effective for tax years beginning on or after January 1, 2009. Companies must account for the impact of income tax law changes in the period that includes the enactment date of the law change. As a result, WMECO recorded an estimate of the impact of the new legislation as a $11.9 million decrease to deferred tax liabilities and a decrease to regulatory assets on its consolidated balance sheet as of December 31, 2008.
Effective on January 1, 2007, NU and its subsidiaries, including CL&P, PSNH and WMECO, implemented FIN 48. FIN 48 applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on the balance sheets. FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with income tax positions that are deemed to be uncertain, including related interest and penalties. Previously, NU consolidated, CL&P, PSNH and WMECO recorded estimates for uncertain tax positions in accordance with SFAS No. 5, "Accounting for Contingencies."
As a result of implementing FIN 48, NU consolidated recognized a cumulative effect of a change in accounting principle of $41.8 million as a reduction to the January 1, 2007 balance of retained earnings, including CL&P, PSNH and WMECO reductions/(increases) of $24 million, $(1.6) million and $(0.4) million, respectively.
Interest and Penalties: Effective on January 1, 2007, the accounting policy of NU consolidated, CL&P, PSNH and WMECO for the classification of interest and penalties related to FIN 48 is as follows:
FS-42
Interest on uncertain tax positions is recorded and generally classified as a component of other interest expense. However, when resolution of uncertainties results in the company receiving interest income, any related interest benefit is recorded in other income, net on the accompanying consolidated statements of income. No penalties have been recorded under FIN 48. If penalties are recorded in the future, then the estimated penalties would be classified as a component of other income, net on the accompanying consolidated statements of income. The components of interest on uncertain tax positions by company in 2008 and 2007 are as follows:
|
| For the Years Ended |
|
|
|
| At December 31, | ||||||||
Expense/(Income) |
| 2008 |
| 2007 |
|
| Expense/(Income) |
| 2008 |
| 2007 | ||||
(Millions of Dollars) |
|
|
|
|
|
|
|
| (Millions of Dollars) |
|
|
|
|
|
|
CL&P |
| $ | 4.8 |
| $ | 2.3 |
|
| CL&P |
| $ | 18.0 |
| $ | 11.0 |
PSNH |
|
| - |
|
| (1.1) | * |
| PSNH |
|
| 1.8 |
|
| (2.1) |
WMECO |
|
| 0.2 |
|
| (1.4) | * |
| WMECO |
|
| 0.4 |
|
| (2.3) |
NU parent and other |
|
| 3.2 |
|
| 2.6 |
|
| NU parent and other |
|
| 18.5 |
|
| 15.2 |
NU consolidated |
| $ | 8.2 |
| $ | 2.4 |
|
| NU consolidated |
| $ | 38.7 |
| $ | 21.8 |
*The PSNH and WMECO amounts were reflected in other income, net on the accompanying consolidated statements of income.
Unrecognized Tax Benefits:Upon adoption of FIN 48 on January 1, 2007, NU consolidated, CL&P and PSNH had unrecognized tax benefits totaling $86.1 million, $62.6 million and $0.8 million, respectively, of which $69.5 million, $39.7 million and none, respectively, would impact the effective tax rate, if recognized. WMECO did not have any unrecognized tax benefits upon the adoption of FIN 48 on January 1, 2007. As of December 31, 2008, the portion of unrecognized tax benefits of NU consolidated and CL&P that would impact the effective tax rate, if recognized, were $120 million and $87 million, respectively. As of December 31, 2007, the portion of NU consolidated and CL&P unrecognized tax benefits that would impact the effective tax rate, if recognized, were $93 million and $62.3 million, respectively. As of December 31, 2008 and 2007, there is no such impact for PSNH and WMECO.
A reconciliation of the activity in unrecognized tax benefits from January 1, 2007 to December 31, 2008 is as follows:
| |||
| |||
|
|
| |
|
| ||
|
| ||
|
| ||
|
| ||
|
| ||
|
| ||
|
| ||
|
|
|
|
|
|
|
|
|
| |||
(Millions of Dollars) |
|
|
|
|
|
|
|
|
|
Balance at January 1, 2007 |
| $ | 62.6 |
| $ | 0.8 |
| $ | - |
Gross increases - current year |
|
| 23.5 |
|
| - |
|
| - |
Gross (decreases)/increases - prior year |
|
| (10.2) |
|
| 9.8 |
|
| 2.9 |
Lapse of statute of limitations |
|
| - |
|
| - |
|
| - |
Balance at December 31, 2007 |
|
| 75.9 |
|
| 10.6 |
|
| 2.9 |
Gross increases - current year |
|
| 24.9 |
|
| - |
|
| - |
Gross increases - prior year |
|
| 5.6 |
|
| 1.8 |
|
| 0.9 |
Lapse of statute of limitations |
|
| - |
|
| - |
|
| - |
Balance at December 31, 2008 |
| $ | 106.4 |
| $ | 12.4 |
| $ | 3.8 |
Tax Positions: In September 2008, NU and the IRS reached a settlement agreement related to the timing for deducting certain costs. This agreement closed the federal tax years 2002 through 2004 and resulted in a refund of $123 million less a $35 million payment for 2005. The issues regarding the timing for deducting these costs are also subject to review during the 2005 through 2007 IRS federal audit cycle and therefore are not considered effectively settled for years after 2004. While this settlement resulted in $10.1 million of pre-tax interest income ($6.4 million for CL&P, $1.9 million for PSNH and $1.1 million for WMECO), it did not have a significant impact on income tax expense. NU is currently working to resolve certain tax matters regarding the timing for certain deductions in the open federal tax years. While discussions are currently ongoing with federal and state taxing authorit ies, it is reasonably possible that one or more of these open tax years could be resolved within the next twelve months. Management estimates that potential resolutions, which are primarily related to timing differences, could result in a $2 million to $42 million decrease in unrecognized tax benefits on an NU consolidated basis, $2 million to $24 million decrease in unrecognized tax benefits by CL&P, zero to $12 million decrease in unrecognized tax benefits by PSNH, and a zero to $4 million decrease in unrecognized tax benefits by WMECO. These estimated changes are related to timing, as well as state tax impacts, which could have an impact on NU consolidated earnings of $1 million to $4 million in 2009. The individual impact from these estimated changes to the 2009 earnings of CL&P, PSNH, and WMECO is not expected to be material.
FS-43
Tax Years: The following table summarizes NU consolidated, CL&P, PSNH and WMECO's tax years that remain subject to examination by major tax jurisdictions at December 31, 2008:
|
| |
|
| |
|
| |
|
| |
|
|
I.
Property, Plant and Equipment and Accumulated Depreciation
The following tables summarize the NU consolidated, CL&P, PSNH, and WMECO investments in utility plant at December 31, 2008 and 2007:
|
| At December 31, | ||||
|
| 2008 |
| 2007 | ||
|
| NU |
| NU | ||
Distribution |
| $ | 6,644.4 |
| $ | 6,230.3 |
Transmission |
|
| 2,981.2 |
|
| 1,751.1 |
Generation |
|
| 637.5 |
|
| 590.5 |
Competitive energy |
|
| 12.8 |
|
| 18.7 |
Other |
|
| 277.3 |
|
| 291.8 |
Total property, plant and equipment |
|
| 10,553.2 |
|
| 8,882.4 |
Less: Accumulated depreciation |
|
| 2,770.1 |
|
| 2,661.8 |
Net property, plant and equipment |
|
| 7,783.1 |
|
| 6,220.6 |
Construction work in progress |
|
| 424.8 |
|
| 1,009.3 |
Total property, plant and equipment, net |
| $ | 8,207.9 |
| $ | 7,229.9 |
|
| At December 31, | ||||||||||||||||
|
| 2008 |
| 2007 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Distribution |
| $ | 3,780.3 |
| $ | 1,228.6 |
| $ | 625.0 |
| $ | 3,559.3 |
| $ | 1,128.7 |
| $ | 596.3 |
Transmission |
|
| 2,464.4 |
|
| 372.4 |
|
| 156.5 |
|
| 1,339.8 |
|
| 291.0 |
|
| 132.4 |
Generation |
|
| - |
|
| 637.5 |
|
| - |
|
| - |
|
| 590.5 |
|
| - |
Total property, plant and equipment |
|
| 6,244.7 |
|
| 2,238.5 |
|
| 781.5 |
|
| 4,899.1 |
|
| 2,010.2 |
|
| 728.7 |
Less: Accumulated depreciation |
|
| 1,346.1 |
|
| 771.3 |
|
| 214.7 |
|
| 1,279.7 |
|
| 737.9 |
|
| 205.7 |
Net property, plant and equipment |
|
| 4,898.6 |
|
| 1,467.2 |
|
| 566.8 |
|
| 3,619.4 |
|
| 1,272.3 |
|
| 523.0 |
Construction work in progress |
|
| 190.5 |
|
| 113.8 |
|
| 57.4 |
|
| 782.4 |
|
| 116.1 |
|
| 36.4 |
Total property, plant and equipment, net |
| $ | 5,089.1 |
| $ | 1,581.0 |
| $ | 624.2 |
| $ | 4,401.8 |
| $ | 1,388.4 |
| $ | 559.4 |
PSNH uses the direct expense method to account for planned major maintenance expenses primarily related to generation. PSNH charges planned major maintenance activities to operating expense unless the cost represents the acquisition of additional components. PSNH capitalizes the cost of plant additions.
In 2008, CL&P, PSNH and WMECO entered into certain equipment purchase contracts that required the company to make advance payments during the design, manufacturing, shipment and installation of equipment. As of December 31, 2008, these advance payments totaled $13.8 million on an NU consolidated basis ($3.6 million for CL&P, $8.9 million for PSNH and $1.3 million for WMECO) and are included in construction work in progress on the accompanying consolidated balance sheets.
The following table summarizes average depreciable lives at December 31, 2008:
|
| Average Depreciable Life | ||||||||||
|
|
| NU |
|
|
|
|
|
|
|
|
|
Distribution |
|
| 33.7 |
|
| 30.3 |
|
| 42.3 |
|
| 33.7 |
Transmission |
|
| 59.6 |
|
| 61.4 |
|
| 50.0 |
|
| 58.3 |
Generation |
|
| 31.6 |
|
| - |
|
| 31.6 |
|
| - |
Competitive energy |
|
| 5.6 |
|
| - |
|
| - |
|
| - |
Other |
|
| 18.0 |
|
| - |
|
| - |
|
| - |
The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency, where applicable. Depreciation rates are applied to plant-in-service from the time it is placed in service. When a plant is retired from service, the original cost of the plant is charged to the accumulated provision for depreciation, which includes cost of removal less salvage. Cost of removal is classified as a regulatory liability. The depreciation rates for the several classes of utility plant-in-service are equivalent to composite rates as follows:
FS-44
(Percent) |
| 2008 |
| 2007 |
| 2006 | |||
NU Consolidated |
|
| 3.0 |
|
| 3.2 |
|
| 3.2 |
CL&P |
|
| 3.1 |
|
| 3.3 |
|
| 3.5 |
PSNH |
|
| 2.7 |
|
| 2.8 |
|
| 2.8 |
WMECO |
|
| 2.8 |
|
| 2.9 |
|
| 2.5 |
J.L.
Equity Method Investments
Regional Nuclear Companies: AtAs of December 31, 2008,2010, CL&P, PSNH and WMECO owned common stock in three regional nuclear generation companies (Yankee Companies). Each of the Yankee Companies owned a single nuclear generating plantfacility that has been decommissioned. Ownership interests in the Yankee Companies atas of December 31, 2008,2010, which are accounted for on the equity method, are as follows:
(Percent) |
| CYAPC |
| YAEC |
| MYAPC |
| CYAPC |
| YAEC |
| MYAPC | ||||||||
CL&P |
|
| 34.5 |
|
| 24.5 |
|
| 12.0 |
|
|
| 34.5 |
|
| 24.5 |
|
| 12.0 |
|
PSNH |
|
| 5.0 |
|
| 7.0 |
|
| 5.0 |
|
|
| 5.0 |
|
| 7.0 |
|
| 5.0 |
|
WMECO |
|
| 9.5 |
|
| 7.0 |
|
| 3.0 |
|
|
| 9.5 |
|
| 7.0 |
|
| 3.0 |
|
Total NU Consolidated |
|
| 49.0 | % |
| 38.5 | % |
| 20.0 | % | ||||||||||
Total NU |
|
| 49.0 | % |
| 38.5 | % |
| 20.0 | % |
The total carrying values of ownership interests in CYAPC, YAEC and MYAPC, which are included in deferred debits and other assets - otherOther Long-Term Assets on the accompanying consolidated balance sheets and in the regulatedRegulated companies - electricElectric distribution reportable segment, are as follows:
(Millions of Dollars) |
| 2008 |
| 2007 | ||
CL&P |
| $ | 5.0 |
| $ | 4.5 |
PSNH |
|
| 0.8 |
|
| 0.8 |
WMECO |
|
| 1.4 |
|
| 1.3 |
Total NU Consolidated |
| $ | 7.2 |
| $ | 6.6 |
Net earnings related to these equity investments are included in other income, net on the accompanying consolidated statements of income. For further information, see Note 1R, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.
For further information, see Note 7E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.
(Millions of Dollars) |
| 2010 |
| 2009 | ||
CL&P |
| $ | 1.3 |
| $ | 1.6 |
PSNH |
|
| 0.3 |
|
| 0.4 |
WMECO |
|
| 0.4 |
|
| 0.5 |
Total NU |
| $ | 2.0 |
| $ | 2.5 |
Hydro-Québec:Regional Transmission Companies: NU parent has a 22.7 percent equity ownership interest in two companies that transmit electricity imported from the Hydro-Québec system in Canada. NU parent’sparent's investment, which is included in deferred debits and other assets - otherOther-Long Term Assets on the accompanying consolidated balance sheets, totaled $7.2$5.6 million and $7.6$6.2 million atas of December 31, 20082010 and 2007,2009, respectively.
Dividends received from the Yankee Companies and the regional transmission companies investments were recorded as a reduction to NU's, including CL&P, PSNH and WMECO, investment and were as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2008 | |||
NU |
| $ | 1.5 |
| $ | 3.8 |
| $ | 1.0 |
CL&P |
|
| 0.4 |
|
| 1.5 |
|
| - |
PSNH |
|
| 0.1 |
|
| 0.2 |
|
| - |
WMECO |
|
| 0.1 |
|
| 0.4 |
|
| - |
Net earnings related to these equity investments are included in Other Income, Net on the accompanying consolidated statements of income. For further information, see Note 1P, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.
The application of the equity method is considered the appropriate method to account for the Yankee Companies and the Hydro-Québecregional transmission companies investments because NU's ownership interests are between 20 and 50 percent of the voting stock and NU has the ability to exercise significant influence over the investees’investees' operating and financial policies.
K.For further information on the Yankee Companies, see Note 12D, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.
M.
Revenues
Regulated Companies: The Regulated companies' retail revenues are based on rates approved by the state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs as incurred. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.
The Regulated companies record monthly, day ahead and real time energy purchases and sales net in accordance with applicable accounting guidance. Revenues and expenses associated with derivative instruments to purchase and sell energy in the day ahead and real time markets are recorded on a net basis in Operating Revenues or Fuel, Purchased and Net Interchange Power on the consolidated statements of income.
Regulated Companies' Unbilled Revenues: Unbilled revenues represent an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed. Unbilled revenues are included in Operating Revenues on the consolidated statements of income and are assets on the consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.
The Regulated companies estimate unbilled revenues monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from
109
total calendar month sales to estimate unbilled sales. Unbilled revenues are estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.
Regulated Companies' Transmission Revenues - Wholesale Rates: Wholesale transmission revenues are based on formula rates that are approved by the FERC. Wholesale transmission revenues for CL&P, PSNH, and WMECO are collected under the ISO-NE FERC, Transmission, Markets and Services Tariff (ISO-NE Tariff). The ISO-NE Tariff includes Regional Network Service (RNS) and Schedule 21 - NU rate schedules to recover fees for transmission and other services. The RNS rate, administered by ISO-NE and billed to all New England transmission users, including CL&P, PSNH, and WMECO's transmission businesses, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The Schedule 21 - NU rate, administered by NU, is reset on January 1st and June 1st of each year and recovers the reven ue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate, including 100 percent of the CWIP that is included in rate base on the NEEWS projects. The Schedule 21 - NU rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all of CL&P's, PSNH's and WMECO's regional and local revenue requirements as prescribed in the ISO-NE Tariff. Both the RNS and Schedule 21 - NU rates provide for the annual reconciliation and recovery/refund of estimated (or projected) costs to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from, or refunded to, customers. As of December 31, 2010, the Schedule 21 - NU rates were in a total overrecovery position of $40.9 million ($37.2 million for CL&P, $3 million for PSNH and $0.7 million for WMECO), which will be refunded to customers in June 2011.
Regulated Companies' Transmission Revenues - Retail Rates: A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution segments of CL&P, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers. CL&P, PSNH and WMECO each have a retail transmission cost tracking mechanism as part of their rates, which allows the companies to charge their retail customers for transmission costs on a timely basis.
NU Enterprises: Service revenues are recognized as services are provided, often on a percentage of completion basis. Wholesale marketing revenues are recognized through mark-to-market accounting on underlying derivative contracts and recorded in Fuel, Purchased and Net Interchange Power on the consolidated statements of income. This net presentation of the mark-to-market and settlement amounts is required as a result of NU Enterprises not being able to assert that physical delivery of contract quantities is probable.
N.
Operating Expenses
Fuel, Purchased and Net Interchange Power: For the years ended December 31, 2010, 2009 and 2008, Fuel, Purchased and Net Interchange Power included costs related to fuel (and natural gas costs as it related to Yankee Gas) as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2008 | |||
CL&P |
| $ | 0.3 |
| $ | 0.5 |
| $ | 4.1 |
PSNH |
|
| 184.3 |
|
| 174.1 |
|
| 177.4 |
WMECO |
|
| 0.1 |
|
| 0.8 |
|
| 0.8 |
Yankee Gas |
|
| 206.4 |
|
| 226.1 |
|
| 358.8 |
Other |
|
| 0.5 |
|
| 0.2 |
|
| 0.6 |
NU |
| $ | 391.6 |
| $ | 401.7 |
| $ | 541.7 |
O.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFUDC)AFUDC is included in the cost of the regulatedRegulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense,Other Interest Expense and the AFUDC related to equity funds is recorded as other income, netOther Income, Net on the accompanying consolidated statements of income.
|
| For the Years Ended December 31, | ||||||||||
|
| NU Consolidated | ||||||||||
(Millions of Dollars, except percentages) |
| 2008 |
| 2007 |
| 2006 | ||||||
AFUDC: |
|
|
|
|
|
|
|
|
|
|
| |
Borrowed funds |
| $ | 17.8 |
|
| $ | 17.5 |
|
| $ | 13.5 | |
Equity funds |
|
| 29.0 |
|
|
| 17.4 |
|
|
| 13.6 | |
Totals |
| $ | 46.8 |
|
| $ | 34.9 |
|
| $ | 27.1 | |
Average AFUDC rates |
|
| 8.1% |
|
|
| 7.6% |
|
|
| 7.5% |
|
| For the Years Ended December 31, | ||||||||||
|
| NU | ||||||||||
(Millions of Dollars, except percentages) |
| 2010 |
| 2009 |
| 2008 | ||||||
AFUDC: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowed Funds |
| $ | 10.2 |
|
| $ | 5.9 |
|
| $ | 17.8 |
|
Equity Funds |
|
| 16.7 |
|
|
| 9.4 |
|
|
| 29.0 |
|
Total |
| $ | 26.9 |
|
| $ | 15.3 |
|
| $ | 46.8 |
|
Average AFUDC Rates |
|
| 7.1 | % |
|
| 6.1 | % |
|
| 8.1 | % |
|
| For the Years Ended December 31, | |||||||||||||||||||||||||
|
| 2008 |
| 2007 |
| 2006 | |||||||||||||||||||||
(Millions of Dollars, except percentages) | CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||||||
AFUDC: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowed funds |
| $ | 13.0 |
| $ | 3.0 |
| $ | 1.0 |
| $ | 10.9 |
| $ | 3.0 |
| $ | 1.0 |
| $ | 6.6 |
| $ | 2.8 |
| $ | 0.9 |
Equity funds |
|
| 23.2 |
|
| 4.4 |
|
| 1.2 |
|
| 14.2 |
|
| 2.0 |
|
| 0.2 |
|
| 7.6 |
|
| 4.4 |
|
| 0.2 |
Totals |
| $ | 36.2 |
| $ | 7.4 |
| $ | 2.2 |
| $ | 25.1 |
| $ | 5.0 |
| $ | 1.2 |
| $ | 14.2 |
| $ | 7.2 |
| $ | 1.1 |
Average AFUDC rates |
|
| 8.4% |
|
| 7.9% |
|
| 7.6% |
|
| 8.0% |
|
| 7.0% |
|
| 6.1% |
|
| 7.9% |
|
| 7.3% |
|
| 6.8% |
FS-45
|
| For the Years Ended December 31, | ||||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | ||||||||||||||||||||||
(Millions of Dollars, except percentages) | CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||||||
AFUDC: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowed Funds |
| $ | 2.7 |
| $ | 6.6 |
| $ | 0.3 |
| $ | 2.2 |
| $ | 3.1 |
| $ | 0.2 |
| $ | 13.0 |
| $ | 3.0 |
| $ | 1.0 |
|
Equity Funds |
|
| 4.9 |
|
| 10.4 |
|
| 0.6 |
|
| 5.7 |
|
| 3.6 |
|
| - |
|
| 23.2 |
|
| 4.4 |
|
| 1.2 |
|
Total |
| $ | 7.6 |
| $ | 17.0 |
| $ | 0.9 |
| $ | 7.9 |
| $ | 6.7 |
| $ | 0.2 |
| $ | 36.2 |
| $ | 7.4 |
| $ | 2.2 |
|
Average AFUDC Rates |
|
| 8.3 | % |
| 6.8 | % |
| 6.4 | % |
| 7.2 | % |
| 6.2 | % |
| 1.7 | % |
| 8.4 | % |
| 7.9 | % |
| 7.6 | % |
The regulatedRegulated companies' average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity). The
110
average rate is applied to average eligible CWIP amounts to calculate AFUDC. Although AFUDC wasis recorded on 100 percent of CL&P's CWIP for its major transmission projects in southwest Connecticut, 50 percent of this AFUDC was being reserved as a regulatory liability to reflect current rate base recovery for 50 percent of the CWIP as a result of FERC approved transmission incentives. AFUDC is also recorded on 100 percent of CL&P’s and WMECO’sWMECO's CWIP for their NEEWS projects, all of which is being reserved as a regulatory liability to reflect current rate base recovery for 100 percent of the CWIP as a result of FERC approvedFERC-approved transmission incentives.
L.
Sale of Customer Receivables
Prior to June 30, 2008, under For the Receivables Purchase and Sale Agreement, CRC, a consolidated, wholly-owned subsidiary of CL&P, purchased an undivided interest in CL&P's accounts receivable and unbilled revenues and could sell up to $100 million thereof to a financial institution. At December 31, 2007, there were $20 million in such sales. On June 30, 2008, CL&P terminated the Receivables Purchase and Sale Agreement, and there are no receivables sold under that facility.
At December 31, 2007, amounts totaling $308.2 million sold to CRC by CL&P but not sold to the financial institution were included in investments in securitizable assets on the accompanying consolidated balance sheet. These amounts would have been excluded from CL&P's assets in the event of bankruptcy by CL&P. Since CL&P chose to terminate the Receivables Purchase and Sale Agreement on June 30, 2008, all such amounts are now included gross in accounts receivables and unbilled revenues on the accompanying consolidated balance sheet as ofyear ended December 31, 2008, with $17.5 million50 percent of bad debt expense recorded inAFUDC related to other major transmission projects at CL&P were being reserved as a regulatory liability to reflect current rate base recovery for 50 percent of the provision for uncollectible accounts, which previously offset the investments in securitizable assets balance.CWIP as a result of FERC-approved transmission incentives.
In 2007, the transferP.
Other Income, Net
The pre-tax components of receivablesother income/(loss) items are as follows:
NU |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2008 | |||
Other Income: |
|
|
|
|
|
|
|
|
|
Investment Income |
| $ | 6.4 |
| $ | 10.1 |
| $ | 6.6 |
Interest Income |
|
| 4.0 |
|
| 5.6 |
|
| 10.1 |
AFUDC - Equity Funds |
|
| 16.7 |
|
| 9.4 |
|
| 29.0 |
EIA Incentives |
|
| 8.7 |
|
| 6.1 |
|
| 12.1 |
C&LM Incentives |
|
| 7.2 |
|
| 4.3 |
|
| 4.8 |
Other |
|
| 2.2 |
|
| 2.7 |
|
| 2.7 |
Total Other Income |
|
| 45.2 |
|
| 38.2 |
|
| 65.3 |
Other Loss: |
|
|
|
|
|
|
|
|
|
Investment Loss |
|
| - |
|
| - |
|
| (14.6) |
Other |
|
| (3.3) |
|
| (0.4) |
|
| (0.3) |
Total Other Loss |
|
| (3.3) |
|
| (0.4) |
|
| (14.9) |
Total Other Income, Net |
| $ | 41.9 |
| $ | 37.8 |
| $ | 50.4 |
|
| For the Years Ended December 31, | |||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | |||||||||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||||
Other Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Investment Income |
| $ | 4.3 |
| $ | 1.0 |
| $ | 0.9 |
| $ | 6.8 |
| $ | 1.7 |
| $ | 1.5 |
| $ | 6.0 |
| $ | 1.9 |
| $ | 1.2 |
Interest Income |
|
| 3.4 |
|
| 1.0 |
|
| 0.6 |
|
| 3.5 |
|
| 2.2 |
|
| (0.3) |
|
| 6.4 |
|
| 1.9 |
|
| 1.1 |
AFUDC - Equity Funds |
|
| 4.9 |
|
| 10.4 |
|
| 0.6 |
|
| 5.7 |
|
| 3.6 |
|
| - |
|
| 23.2 |
|
| 4.4 |
|
| 1.2 |
EIA Incentives |
|
| 8.7 |
|
| - |
|
| - |
|
| 6.1 |
|
| - |
|
| - |
|
| 12.1 |
|
| - |
|
| - |
C&LM Incentives |
|
| 5.0 |
|
| 1.7 |
|
| 0.5 |
|
| 2.3 |
|
| 1.5 |
|
| 0.5 |
|
| 3.0 |
|
| 1.3 |
|
| 0.5 |
Other |
|
| 0.5 |
|
| 0.1 |
|
| - |
|
| 1.6 |
|
| 0.5 |
|
| 0.2 |
|
| 1.1 |
|
| 0.2 |
|
| 0.1 |
Total Other Income |
|
| 26.8 |
|
| 14.2 |
|
| 2.6 |
|
| 26.0 |
|
| 9.5 |
|
| 1.9 |
|
| 51.8 |
|
| 9.7 |
|
| 4.1 |
Other Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment Loss |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (9.8) |
|
| (2.4) |
|
| (2.1) |
Other |
|
| (0.1) |
|
| (2.5) |
|
| - |
|
| (0.1) |
|
| - |
|
| (0.1) |
|
| (0.1) |
|
| - |
|
| - |
Total Other Loss |
|
| (0.1) |
|
| (2.5) |
|
| - |
|
| (0.1) |
|
| - |
|
| (0.1) |
|
| (9.9) |
|
| (2.4) |
|
| (2.1) |
Total Other Income, Net |
| $ | 26.7 |
| $ | 11.7 |
| $ | 2.6 |
| $ | 25.9 |
| $ | 9.5 |
| $ | 1.8 |
| $ | 41.9 |
| $ | 7.3 |
| $ | 2.0 |
Other Income - Other includes equity in earnings, which relates to the financial institution under this arrangement qualified for sale treatment under SFAS No. 140, "Accounting for Transfers and ServicingCompany's investments, including investments of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."
M.
Asset Retirement Obligations
NU and its subsidiaries, including CL&P, PSNH and WMECO, implemented FIN 47 on December 31, 2005. FIN 47 requires an entity to recognize a liability forin the fair value of an ARO on the obligation date if the liability’s fair value can be reasonably estimatedYankee Companies and is conditional on a future event. FIN 47 provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available and provides guidance on the definition and timing of sufficient informationNU's investments in determining expected cash flows and fair values. Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination. A fair value calculation, reflecting expected probabilities for settlement scenarios, has been performed.
The fair value of the AROs is recorded as a liability in deferred credits and other liabilities - other with an offset included in property, plant and equipment on the accompanying consolidated balance sheets. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively. Both the depreciation and accretion were recorded as increases to regulatory assets on the accompanying consolidated balance sheets at December 31, 2008 and 2007.
As the regulated companies are cost-of-service, rate regulated entities, these companies apply regulatory accounting in accordance with SFAS No. 71, and the costs associated with the regulated companies' AROs were included in other regulatory assets at December 31, 2008 and 2007.
The following tables present the ARO asset, the related accumulated depreciation, the regulatory asset, and the ARO liabilities at December 31, 2008 and 2007:
NU Consolidated |
| At December 31, 2008 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 2.7 |
| $ | (1.6) |
| $ | 20.7 |
| $ | (22.6) |
Hazardous contamination |
|
| 5.1 |
|
| (1.4) |
|
| 15.2 |
|
| (19.4) |
Other AROs |
|
| 4.0 |
|
| (2.0) |
|
| 6.4 |
|
| (8.6) |
Total AROs |
| $ | 11.8 |
| $ | (5.0) |
| $ | 42.3 |
| $ | (50.6) |
NU Consolidated |
| At December 31, 2007 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 2.7 |
| $ | (1.6) |
| $ | 19.6 |
| $ | (21.3) |
Hazardous contamination |
|
| 4.5 |
|
| (1.2) |
|
| 13.7 |
|
| (17.3) |
Other AROs |
|
| 6.8 |
|
| (3.0) |
|
| 7.3 |
|
| (11.1) |
Total AROs |
| $ | 14.0 |
| $ | (5.8) |
| $ | 40.6 |
| $ | (49.7) |
FS-46
CL&P |
| At December 31, 2008 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 1.6 |
| $ | (1.0) |
| $ | 12.0 |
| $ | (12.6) |
Hazardous contamination |
|
| 4.1 |
|
| (1.0) |
|
| 8.7 |
|
| (11.8) |
Other AROs |
|
| 3.4 |
|
| (1.5) |
|
| 2.4 |
|
| (4.3) |
Total AROs |
| $ | 9.1 |
| $ | (3.5) |
| $ | 23.1 |
| $ | (28.7) |
CL&P |
| At December 31, 2007 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 1.6 |
| $ | (1.0) |
| $ | 11.2 |
| $ | (11.8) |
Hazardous contamination |
|
| 3.5 |
|
| (0.9) |
|
| 7.6 |
|
| (10.2) |
Other AROs |
|
| 5.7 |
|
| (2.5) |
|
| 3.4 |
|
| (6.6) |
Total AROs |
| $ | 10.8 |
| $ | (4.4) |
| $ | 22.2 |
| $ | (28.6) |
PSNH |
| At December 31, 2008 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 0.9 |
| $ | (0.5) |
| $ | 7.1 |
| $ | (8.3) |
Hazardous contamination |
|
| 0.5 |
|
| (0.3) |
|
| 5.6 |
|
| (6.3) |
Other AROs |
|
| - |
|
| - |
|
| 1.2 |
|
| (1.3) |
Total AROs |
| $ | 1.4 |
| $ | (0.8) |
| $ | 13.9 |
| $ | (15.9) |
PSNH |
| At December 31, 2007 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 0.9 |
| $ | (0.5) |
| $ | 6.9 |
| $ | (7.7) |
Hazardous contamination |
|
| 0.5 |
|
| (0.2) |
|
| 5.3 |
|
| (5.9) |
Other AROs |
|
| - |
|
| - |
|
| 1.1 |
|
| (1.3) |
Total AROs |
| $ | 1.4 |
| $ | (0.7) |
| $ | 13.3 |
| $ | (14.9) |
WMECO |
| At December 31, 2008 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 0.2 |
| $ | (0.1) |
| $ | 1.7 |
| $ | (1.8) |
Hazardous contamination |
|
| 0.5 |
|
| (0.1) |
|
| 0.9 |
|
| (1.3) |
Other AROs |
|
| 0.3 |
|
| (0.2) |
|
| 0.2 |
|
| (0.3) |
Total AROs |
| $ | 1.0 |
| $ | (0.4) |
| $ | 2.8 |
| $ | (3.4) |
WMECO |
| At December 31, 2007 | ||||||||||
|
|
|
| Accumulated |
|
|
|
| ||||
Asbestos |
| $ | 0.2 |
| $ | (0.1) |
| $ | 1.5 |
| $ | (1.6) |
Hazardous contamination |
|
| 0.5 |
|
| (0.1) |
|
| 0.8 |
|
| (1.2) |
Other AROs |
|
| 0.8 |
|
| (0.3) |
|
| 0.4 |
|
| (0.9) |
Total AROs |
| $ | 1.5 |
| $ | (0.5) |
| $ | 2.7 |
| $ | (3.7) |
FS-47
A reconciliation of the beginning and ending carrying amounts of regulated companies' AROs is as follows:
|
| At December 31, | ||||
|
| 2008 |
| 2007 | ||
|
| NU |
| NU | ||
Balance at beginning of year |
| $ | (49.7) |
| $ | (59.7) |
Liabilities incurred during the year |
|
| (1.8) |
|
| (2.8) |
Liabilities settled during the year |
|
| 3.6 |
|
| 7.3 |
Accretion |
|
| (3.2) |
|
| (1.3) |
Changes in estimates |
|
| - |
|
| 7.9 |
Revisions in estimated cash flows |
|
| 0.5 |
|
| (1.1) |
Balance at end of year |
| $ | (50.6) |
| $ | (49.7) |
|
| At December 31, | ||||||||||||||||
|
| 2008 |
| 2007 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Balance at beginning of year |
| $ | (28.6) |
| $ | (14.9) |
| $ | (3.7) |
| $ | (35.8) |
| $ | (17.3) |
| $ | (4.0) |
Liabilities incurred during the year |
|
| (1.8) |
|
| - |
|
| - |
|
| (2.8) |
|
| - |
|
| - |
Liabilities settled during the year |
|
| 3.0 |
|
| - |
|
| 0.5 |
|
| 7.1 |
|
| - |
|
| 0.2 |
Accretion |
|
| (1.8) |
|
| (1.0) |
|
| (0.2) |
|
| (0.8) |
|
| (0.3) |
|
| (0.1) |
Changes in estimates |
|
| - |
|
| - |
|
| - |
|
| 4.2 |
|
| 2.9 |
|
| 0.5 |
Revisions in estimated cash flows |
|
| 0.5 |
|
| - |
|
| - |
|
| (0.5) |
|
| (0.2) |
|
| (0.3) |
Balance at end of year |
| $ | (28.7) |
| $ | (15.9) |
| $ | (3.4) |
| $ | (28.6) |
| $ | (14.9) |
| $ | (3.7) |
Changes in estimates and revisions in estimated cash flows supporting the carrying amounts of AROs include changes in estimated quantities and removal costs, discount rates and inflation rates.
N.
Fuel, Materials and Supplies
Fuel, materials and supplies include natural gas storage, coal, oil and materials purchased primarily for construction or operation and maintenance (O&M) purposes. Natural gas inventory, coal and oil are valued at the weighted average cost of gas, coal and oil. Materials and supplies are valued at the lower of average cost or market.
PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including sulfur dioxide (SO2) and nitrogen oxide (NOx) related to its regulated generation units, and uses SO2 and NOx emissions allowances. At the end of each compliance period, PSNH is required to relinquish SO2 and NOx emissions allowances corresponding to the actual emissions emitted by its generating units over the compliance period. SO2 and NOx emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties.
SO2 and NOx emissions allowances are recorded as fuel, materials and supplies and are classified on the balance sheet as short-term or long-term depending on the period they are expected to be utilized against actual emissions. At December 31, 2008 and 2007, PSNH had $6.5 million and $3.4 million, respectively, of short-term SO2 and NOx emissions allowances classified as fuel, materials and supplies on the accompanying consolidated balance sheets and $23.5 million and $23.3 million, respectively, of long-term SO2 and NOx emissions allowances classified as deferred debits and other assets - other on the accompanying consolidated balance sheets.
SO2 and NOx emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH’s generating units. PSNH recorded expenses of $2.8 million, $5.9 million, and $7.9 million fortwo regional transmission companies. For the years ended December 31, 2010, 2009, and 2008, 2007,equity in earnings was $1.4 million, $1.8 million and 2006,$1.6 million, respectively, which was included in fuel, purchased and net interchange power onfor NU. For the accompanying consolidated income statements. These costs are recovered from ratepayers through PSNH ES revenues. See Note 1G, "Summary of Significant Accounting Policies - Regulatory Accounting" for further information.
O.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from cash and cash equivalents to accounts payable.
P.
Special Deposits and Counterparty Deposits
To the extent Select Energy requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is held on deposit by Select Energy or with unaffiliated counterparties and brokerage firms as a part of the total collateral required based on Select Energy’s position in transactions with the counterparty. Select Energy's right to use cash collateral is determined by the terms of the related agreements. Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.
NU and its subsidiaries record special deposits and counterparty deposits in accordance with FSP FIN 39-1, "Amendment of FASB Interpretation No. 39," which requires NU to net collateral amounts posted under a master netting agreement if the related derivatives are recorded in a net position. Atyear ended December 31, 2008, NU and its subsidiaries, including2010, CL&P, PSNH and WMECO had no special deposits or counterparty collateral posted under master netting agreements that would be required to be netted againstde minimis amounts for equity in earnings. Equity in earnings was $0.3 million for CL&P and $0.1 million for PSNH and WMECO for both the fair value of derivatives.
FS-48
Special deposits paid by Select Energy to unaffiliated counterpartiesyears ended December 31, 2009 and brokerage firms were not subject to master netting agreements2008. For the years ended December 31, 2010, 2009 and totaled $26.32008, income tax expense associated with the equity in earnings was $0.6 million, $0.7 million and $18.9$0.6 million, at December 31, 2008 and 2007, respectively. Theserespectively, for NU (de minimis amounts are recorded as current assets and are included in prepayments and other on the accompanying consolidated balance sheets. There were no counterparty deposits for Select Energy as of December 31, 2008 and 2007.
NU consolidated, CL&P, PSNH and WMECO have established credit policies regarding counterpartiesfor all periods presented).
The EIA incentives relate to minimize overall credit risk. These policies require an evaluationincentives earned by Connecticut regulated companies from the construction of potential counterparties financial condition, collateral requirementsdistributed generation, new large-scale generation and the useimplementation of standardized agreements that allowC&LM initiatives to reduce FMCC charges.
Included in Other Loss - Other for NU and PSNH for the netting of positive and negative exposures associated with a single counterparty. These evaluations result in established credit limits prior to entering into a contract. Atyear ended December 31, 2010 is a $2.5 million write-off of carrying charges related to storm costs incurred during the December 2008 and 2007, there were no counterparty deposits for these companies.ice storm. This write-off was part of PSNH's multi-year rate case settlement agreement that was effective July 1, 2010.
CL&P, PSNH and WMECO had amounts on depositFor further information regarding interest income related to four subsidiaries usedfederal tax settlements, see Note 11, "Income Taxes," to facilitate the issuance of RRBs. In addition, CL&P, PSNH and WMECO had other cash deposits held with unaffiliated parties at December 31, 2008 and 2007. These amounts were as follows:
|
| At December 31, 2008 | ||||||||||
|
| NU |
| CL&P |
| PSNH |
|
| ||||
Rate reduction bond deposits |
| $ | 41.3 |
| $ | 18.0 |
| $ | 19.3 |
| $ | 4.0 |
Other deposits |
|
| 7.0 |
|
| 5.2 |
|
| 0.9 |
|
| - |
|
| At December 31, 2007 | ||||||||||
|
| NU |
| CL&P |
| PSNH |
|
| ||||
Rate reduction bond deposits |
| $ | 43.5 |
| $ | 14.3 |
| $ | 24.4 |
| $ | 4.8 |
Other deposits |
|
| 6.4 |
|
| 5.8 |
|
| 0.5 |
|
| - |
These amounts are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.financial statements.
Q.
Other Taxes
Certain excise taxes levied by state or local governments are collected by CL&P and Yankee Gas from itstheir respective customers. These excise taxes are accounted forshown on a gross basis with collections in revenues and payments in expenses. Gross receipts taxes, franchise taxes and other excise taxes were included in operating revenuesOperating Revenues and taxes other than income taxesTaxes Other Than Income Taxes on the accompanying consolidated statements of income as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
NU Consolidated |
| $ | 126.6 |
| $ | 112.2 |
| $ | 114.1 |
CL&P |
|
| 107.2 |
|
| 95.0 |
|
| 92.7 |
111
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2008 | |||
NU |
| $ | 143.7 |
| $ | 135.6 |
| $ | 126.6 |
CL&P |
|
| 128.0 |
|
| 119.0 |
|
| 107.2 |
Certain sales taxes are also collected by CL&P, WMECO, and Yankee Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.
R.
Other Income, Net
The pre-tax components of other income/(loss) items are as follows:
NU Consolidated |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Other Income: |
|
|
|
|
|
|
|
|
|
Investment income |
| $ | 6.6 |
| $ | 22.3 |
| $ | 24.9 |
2008 federal tax settlement - interest |
|
| 10.1 |
|
| - |
|
| - |
AFUDC - equity funds |
|
| 29.0 |
|
| 17.4 |
|
| 13.6 |
Energy Independence Act incentives |
|
| 12.1 |
|
| 9.9 |
|
| 5.5 |
Conservation and load management incentives |
|
| 4.8 |
|
| 7.7 |
|
| 6.5 |
CL&P fixed procurement fee |
|
| - |
|
| - |
|
| 11.0 |
Equity in earnings of regional nuclear generating and |
|
|
|
|
|
|
|
|
|
Gain on sale of Globix investment |
|
| - |
|
| - |
|
| 3.1 |
Other |
|
| 1.1 |
|
| 1.0 |
|
| 0.8 |
Total Other Income |
|
| 65.3 |
|
| 62.3 |
|
| 65.7 |
Other Loss: |
|
|
|
|
|
|
|
|
|
Investment write-downs |
|
| (14.6) |
|
| (0.5) |
|
| - |
Loss on investment in receivables |
|
| - |
|
| - |
|
| (1.1) |
Other |
|
| (0.3) |
|
| (0.2) |
|
| (0.2) |
Total Other Loss |
|
| (14.9) |
|
| (0.7) |
|
| (1.3) |
Total Other Income, Net |
| $ | 50.4 |
| $ | 61.6 |
| $ | 64.4 |
FS-49
CL&P |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Other Income: |
|
|
|
|
|
|
|
|
|
Investment income |
| $ | 6.0 |
| $ | 7.7 |
| $ | 9.8 |
2008 federal tax settlement - interest |
|
| 6.4 |
|
| - |
|
| - |
AFUDC - equity funds |
|
| 23.2 |
|
| 14.2 |
|
| 7.6 |
Energy Independence Act incentives |
|
| 12.1 |
|
| 9.9 |
|
| 5.5 |
Conservation and load management incentives |
|
| 3.0 |
|
| 5.5 |
|
| 4.2 |
Fixed procurement fee |
|
| - |
|
| - |
|
| 11.0 |
Equity in earnings of regional nuclear generating companies |
|
| 0.3 |
|
| 1.9 |
|
| (0.9) |
Other |
|
| 0.8 |
|
| 0.7 |
|
| 0.7 |
Total Other Income |
|
| 51.8 |
|
| 39.9 |
|
| 37.9 |
Other Loss: |
|
|
|
|
|
|
|
|
|
Investment write-downs |
|
| (9.8) |
|
| - |
|
| - |
Rental investment expenses |
|
| (0.1) |
|
| (0.1) |
|
| (0.1) |
Total Other Loss |
|
| (9.9) |
|
| (0.1) |
|
| (0.1) |
Total Other Income, Net |
| $ | 41.9 |
| $ | 39.8 |
| $ | 37.8 |
PSNH |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Other Income: |
|
|
|
|
|
|
|
|
|
Investment income |
| $ | 1.9 |
| $ | 2.6 |
| $ | 1.7 |
2008 federal tax settlement - interest |
|
| 1.9 |
|
| - |
|
| - |
AFUDC - equity funds |
|
| 4.4 |
|
| 2.0 |
|
| 4.4 |
Conservation and load management incentives |
|
| 1.3 |
|
| 1.7 |
|
| 1.4 |
Equity in earnings of regional nuclear generating companies |
|
| 0.1 |
|
| 0.3 |
|
| (0.1) |
Other |
|
| 0.1 |
|
| 0.1 |
|
| - |
Total Other Income |
|
| 9.7 |
|
| 6.7 |
|
| 7.4 |
Other Loss: |
|
|
|
|
|
|
|
|
|
Investment write-downs |
|
| (2.4) |
|
| - |
|
| - |
Total Other Loss |
|
| (2.4) |
|
| - |
|
| - |
Total Other Income, Net |
| $ | 7.3 |
| $ | 6.7 |
| $ | 7.4 |
WMECO |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Other Income: |
|
|
|
|
|
|
|
|
|
Investment income |
| $ | 1.2 |
| $ | 2.7 |
| $ | 1.4 |
2008 federal tax settlement - interest |
|
| 1.1 |
|
| - |
|
| - |
AFUDC - equity funds |
|
| 1.2 |
|
| 0.2 |
|
| 0.2 |
Conservation and load management incentives |
|
| 0.5 |
|
| 0.5 |
|
| 0.9 |
Equity in earnings of regional nuclear generating companies |
|
| 0.1 |
|
| 0.5 |
|
| (0.2) |
Total Other Income |
|
| 4.1 |
|
| 3.9 |
|
| 2.3 |
Other Loss: |
|
|
|
|
|
|
|
|
|
Investment write-downs |
|
| (2.1) |
|
| - |
|
| - |
Total Other Loss |
|
| (2.1) |
|
| - |
|
| - |
Total Other Income, Net |
| $ | 2.0 |
| $ | 3.9 |
| $ | 2.3 |
Equity in earnings of regional nuclear generating and transmission companies relates to the NU consolidated investment, including CL&P, PSNH and WMECO's investment, in the Yankee Companies and NU’s investment in the two Hydro-Québec transmission companies.
The CL&P fixed procurement fee represents compensation approved by the DPUC associated with Transitional Standard Offer (TSO) supply procurement. The conservation and load management incentives relate to incentives earned if certain energy and demand savings goals are met.
The Energy Independence Act incentives relate to incentives earned under the Act to encourage regulated companies to construct distributed generation, new large-scale generation and implement conservation and load management initiatives to reduce FMCC charges.
For further information regarding interest from the 2008 federal tax settlement, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.
FS-50
S.
Supplemental Cash Flow Information (NU Consolidated)
|
| For the Years Ended December 31, | |||||||
|
| 2010 |
| 2009 |
| 2008 | |||
(Millions of Dollars) |
| NU |
| NU |
| NU | |||
Cash Paid/(Received) During the Year for: |
|
|
|
|
|
|
|
|
|
Interest, Net of Amounts Capitalized |
| $ | 258.3 |
| $ | 263.8 |
| $ | 261.4 |
Income Taxes |
|
| 84.5 |
|
| 35.1 |
|
| (36.1) |
Non-Cash Investing Activities: |
|
|
|
|
|
|
|
|
|
Capital Expenditures Incurred But Not Paid |
|
| 127.9 |
|
| 125.5 |
|
| 132.8 |
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Cash paid (received) during the year for: |
|
|
|
|
|
|
|
|
|
Interest, net of amounts capitalized |
| $ | 261.4 |
| $ | 261.6 |
| $ | 277.2 |
Income taxes |
|
| (36.1) |
|
| 496.2 |
|
| 51.3 |
Non-cash investing activities: |
|
|
|
|
|
|
|
|
|
Capital expenditures incurred but not paid |
|
| 132.8 |
|
| 184.4 |
|
| 105.2 |
Cash paid during the year for income taxes increased from 2006 to 2007 as a result of the payment of approximately $400 million in federal and state income taxes in 2007 related to the 2006 sale of the competitive generation business.
|
| For the Years Ended December 31, | |||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | |||||||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||||
(Millions of Dollars) |
|
| |||||||||||||||||||||||||
Cash Paid/(Received) During the Year for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Interest, Net of Amounts Capitalized |
| $ | 142.2 |
| $ | 51.4 |
| $ | 20.2 |
| $ | 146.7 |
| $ | 49.0 |
| $ | 19.4 |
| $ | 145.5 |
| $ | 50.0 |
| $ | 20.0 |
Income Taxes |
|
| 71.5 |
|
| 1.6 |
|
| 5.0 |
|
| 42.4 |
|
| 12.8 |
|
| (9.1) |
|
| (20.6) |
|
| 1.0 |
|
| (5.9) |
Non-Cash Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Capital Expenditures Incurred But Not Paid |
|
| 46.2 |
|
| 35.8 |
|
| 21.2 |
|
| 48.2 |
|
| 46.5 |
|
| 10.3 |
|
| 76.1 |
|
| 31.4 |
|
| 11.5 |
Regulatory (refundsOverrecoveries/(Refunds and underrecoveries)/overrecoveriesUnderrecoveries) on the accompanying consolidated statements of cash flows represents the year-over-year change in regulatory assets and regulatory liabilities, net of amortization charged during the year and other adjustments for non-cash items. These deferred amounts are expected to be recovered from or refunded to customers through the rate-making process.process and are generally short-term in nature.
T.
Operating Expenses
Fuel, purchased and net interchange power: For the years ended December 31, 2008, 2007, and 2006, fuel, purchased and net interchange power included costs related to fuel (and gas costs as it related to Yankee Gas) as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
CL&P |
| $ | 4.1 |
| $ | 14.2 |
| $ | 14.1 |
PSNH |
|
| 177.4 |
|
| 190.2 |
|
| 156.2 |
WMECO |
|
| 0.8 |
|
| 0.8 |
|
| 0.8 |
Yankee Gas |
|
| 358.8 |
|
| 317.7 |
|
| 291.3 |
Other |
|
| 0.6 |
|
| 1.2 |
|
| 29.8 |
NU Consolidated |
| $ | 541.7 |
| $ | 524.1 |
| $ | 492.2 |
Other operating expenses:For the years ended December 31, 2008, 2007 and 2006, theThe majority of the other operating expenses were for general and administrative employee salaries, NUSCO’s salary expenses, and conservation and load management customer assistance costs.
U.
Marketable Securities
Supplemental benefit trust and Spent Nuclear Fuel Trust:short-term borrowings of NU, maintains a supplemental benefit trust and WMECO maintains a spent nuclear fuel trust, both of which hold marketable securities. The trusts are used to fund NU’s SERP/non-SERP and WMECO’s prior period spent nuclear fuel liability. NU and WMECO’s marketable securities are classified as available-for-sale, as defined by SFAS No. 115, "Accounting for Certain Investments and Debt and Equity Securities." At December 31, 2008, changes in the fair value of securities in the supplemental benefit trust relating to unrealized losses are considered other than temporary because NU and WMECO do not have the ability to hold the securities to maturity and are recorded as a pre-tax loss. Changes related to unrealized gains are recorded in accumulated other comprehensive income. Realized gains and losses and unrealized lo sses related to the supplemental benefit trust are included in other income, net, on the consolidated statements of income. Realized gains, net of realized and unrealized losses associated with the WMECO spent nuclear fuel trust are recorded as an offset to the spent nuclear fuel trust obligation.
These trusts are not subject to regulatory oversight by state or federal agencies.
For information regarding marketable securities, see Note 9, "Marketable Securities," to the consolidated financial statements.
V.
Provision for Uncollectible Accounts
NU and its subsidiaries, including CL&P, PSNH and WMECO, maintain a provision for uncollectible accounts to record their receivables at an estimatedhave original maturities of three months or less. Accordingly, borrowings and repayments are shown net realizable value. This provision is determined based upon a varietyon the statement of factors, including applying an estimated uncollectible account percentage to each receivable aging category, historical collection and write-off experience and management’s assessmentcash flows. In December 2008, NU borrowed $127 million under its revolving credit agreement that had original maturities in excess of collectibility from individual customers. Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible.
In November 2006, the DPUC issued an order allowing CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. At December 31, 2008, CL&PThese amounts were repaid in March 2009 and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $41 million and $10 million, respectively, with the corresponding bad debt expense recorded as regulatory assets as these amounts are probable of recovery. These regulatory asset amounts are included in the net activity in the statement of cash flows. In 2010, 2009 and 2008, NU, CL&P, undercollectionsPSNH and write-off of uncollectible hardship receivables for CL&P and Yankee Gas, respectively. At December 31, 2007, these amounts totaled $24 million and $8 million, respectively, and were included in write-off of uncollectible hardship receivables. WMECO had no other such borrowings.
For the year ended December 31, 2008, the CL&P and Yankee Gas reserves offset receivables. For the year ended December 31, 2007, the reserve offset amounts sold to CRC by CL&P but not sold to the financial institution. These amounts were classified as
FS-51
investments in securitizable assets on the accompanying consolidated balance sheets. For the year ended December 31, 2007, Yankee Gas reserves offset receivables.
W.S.
Self-Insurance Accruals
NU, and its subsidiaries, including CL&P, PSNH and WMECO, are self-insured for employee medical coverage, long-term disability coverage and general liability coverage and up to certain limits for workers compensation coverage. Liabilities for insurance claims include accruals of estimated settlements for known claims, as well as accruals of estimates of incurred but not reported claims. These accruals are included in deferred credits and other liabilities - otherOther Long-Term Liabilities on the accompanying consolidated balance sheets. In estimating these costs, NU and its subsidiaries considerconsiders historical loss experience and makes judgments about the expected levels of costs per claim. These claims are accounted for based on estimates of the undiscounted claims, including those claims incurred but not reported.
X.T.
Related Parties
Several wholly-owned subsidiaries of NU provide support services for NU, and its subsidiaries, including CL&P, PSNH and WMECO. NUSCO provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies. ThreeRRR and Properties, Inc., two other NU subsidiaries, construct, acquire or lease some of the property and facilities used by NU's companies.
AtAs of both December 31, 20082010 and 2007,2009, CL&P, PSNH and WMECO had long-term receivables from NUSCO in the amount of $25 million, $3.8 million and $5.5 million, respectively, which are included in deferred debits and other assets - otherOther Long-Term Assets on the accompanying consolidated balance sheets related to the funding of investments held in trust by NUSCO in connection with certain postretirement benefits for CL&P, PSNH and WMECO employees. These amounts have been eliminated in consolidation on the NU consolidated financial statements.
Included in the CL&P, PSNH and WMECO consolidated balance sheets atas of December 31, 20082010 and 20072009 are accounts receivableAccounts Receivable from affiliated companiesAffiliated Companies and accounts payableAccounts Payable to affiliated companiesAffiliated Companies relating to transactions between CL&P, PSNH and WMECO and other subsidiaries that are wholly-owned by NU. As of December 31, 2007,2010 and 2009, CL&P, PSNH and WMECO had $0.3 million, $0.2 million and $0.1 million, respectively,a de minimis amount of tax payments accrued in accounts payableAccounts Payable to affiliated companiesAffiliated Companies related to the estimated quarterly income tax obligation paid in the following quarter. As of December 31, 2008, PSNH had $0.1 million related to this accrual. CL&P and WMECO had a de minimis balance as of December 31, 2008. These amounts have been eliminated in consolidation on the NU consolidated financial statements.
Total CL&P purchases from Select Energy were $6.1 million for the year ended December 31, 2006. Total WMECO purchases from Select Energy were $0.9 million for the year ended December 31, 2006. There were no such purchases in 2008 or 2007. These amounts have been eliminated in consolidation on the NU consolidated financial statements.
The Rocky River Realty Company (RRR), a subsidiary of NU, conveyed a Conservation Easement (CE) on a parcel of land to the Connecticut Forest and Park Association in 2007 as a mitigation requirement for CL&P’s Middletown to Norwalk, Connecticut transmission project. Pursuant to this transaction, CL&P paid $1.4 million for the fair value of the easement to RRR, and RRR maintains ownership of the land. This payment has been recorded as a permitting cost for the Middletown to Norwalk project and is included as property, plant and equipment on the accompanying consolidated balance sheet of CL&P as of December 31, 2008 and 2007.
On December 31, 2008, NU's wholly owned subsidiaries, HWP and Holyoke Power and Electric Company (HP&E) transferred $4 million in transmission related assets to WMECO, after certain routine regulatory filings, will cease being subject to FERC.
In 2007, NU and its subsidiaries made aggregate discretionary contributions of $3 million ($0.6 million for CL&P, $0.6 million for PSNH, and $0.1 million for WMECO) to the NU Foundation (Foundation),is an independent not-for-profit charitable entity designed to invest in projects that emphasize economic development, workforce training and education, and a clean and healthy environment. In 2008, NU and its subsidiaries did not make any contributions. The board of directors of the NU Foundation consists of certain NU officers. The NU Foundation is not included in the consolidated financial statements of NU because the Foundationas it is a not-for-profit
112
entity and because the companyCompany does not have title to the NU Foundation's assets and cannot receive contributions back from the NU Foundation. Any donationsNU made contributions to the NU Foundation negatively impactof $1 million in 2010. The operating companies (CL&P, PSNH, WMECO and Yankee) made contributions totaling $1 million in January 2011, which have been recorded as payables in December 2010 ($0.6 million for CL&P, $0.2 million for PSNH and $0.1 million for WMECO). NU did not make any contributions to the earningsNU Foundation in 2009 and 2008.
2.
REGULATORY ACCOUNTING
The Regulated companies continue to be rate-regulated on a cost-of-service basis, therefore, the accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process.
Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. All material net regulatory assets are earning a return, except for the majority of deferred benefit cost assets, regulatory assets offsetting derivative liabilities, securitized regulatory assets and income tax regulatory assets, all of which are not in rate base. Amortization and deferrals of regulatory assets/(liabilities) are primarily included on a net basis in Amortization of Regulatory Assets/(Liabilities), Net on the accompanying consolidated statements of income.
Regulatory Assets: The components of regulatory assets are as follows:
|
| As of December 31, | ||||
|
| 2010 |
| 2009 | ||
(Millions of Dollars) |
| NU |
| NU | ||
Deferred Benefit Costs |
| $ | 1,094.2 |
| $ | 1,132.1 |
Regulatory Assets Offsetting Derivative Liabilities |
|
| 859.7 |
|
| 855.6 |
Securitized Assets |
|
| 171.7 |
|
| 432.9 |
Income Taxes, Net |
|
| 401.5 |
|
| 363.2 |
Unrecovered Contractual Obligations |
|
| 123.2 |
|
| 149.5 |
Regulatory Tracker Deferrals |
|
| 70.3 |
|
| 104.1 |
Storm Cost Deferrals |
|
| 60.1 |
|
| 60.0 |
Asset Retirement Obligations |
|
| 45.3 |
|
| 42.9 |
Losses On Reacquired Debt |
|
| 21.5 |
|
| 24.0 |
Deferred Environmental Remediation Costs |
|
| 36.8 |
|
| 24.6 |
Deferred Operation and Maintenance Costs |
|
| 29.5 |
|
| - |
Other Regulatory Assets |
|
| 81.5 |
|
| 56.0 |
Totals |
| $ | 2,995.3 |
| $ | 3,244.9 |
|
| As of December 31, | ||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Deferred Benefit Costs |
| $ | 471.8 |
| $ | 152.6 |
| $ | 96.0 |
| $ | 502.4 |
| $ | 154.2 |
| $ | 104.9 |
Regulatory Assets Offsetting Derivative Liabilities |
|
| 846.2 |
|
| 12.8 |
|
| - |
|
| 828.6 |
|
| 26.4 |
|
| - |
Securitized Assets |
|
| - |
|
| 129.8 |
|
| 41.9 |
|
| 195.4 |
|
| 180.1 |
|
| 57.4 |
Income Taxes, Net |
|
| 328.9 |
|
| 31.4 |
|
| 16.8 |
|
| 304.1 |
|
| 21.9 |
|
| 16.9 |
Unrecovered Contractual Obligations |
|
| 97.9 |
|
| - |
|
| 25.3 |
|
| 118.0 |
|
| - |
|
| 31.5 |
Regulatory Tracker Deferrals |
|
| 35.5 |
|
| 14.7 |
|
| 15.2 |
|
| 70.3 |
|
| 19.0 |
|
| 11.3 |
Storm Cost Deferrals |
|
| 4.0 |
|
| 40.7 |
|
| 15.4 |
|
| - |
|
| 50.8 |
|
| 9.2 |
Asset Retirement Obligations |
|
| 24.9 |
|
| 14.7 |
|
| 3.0 |
|
| 23.8 |
|
| 14.0 |
|
| 2.8 |
Losses On Reacquired Debt |
|
| 11.2 |
|
| 8.4 |
|
| 0.4 |
|
| 12.7 |
|
| 9.2 |
|
| 0.4 |
Deferred Environmental Remediation Costs |
|
| - |
|
| 9.7 |
|
| - |
|
| - |
|
| 1.3 |
|
| - |
Deferred Operation and Maintenance Costs |
|
| 29.5 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Other Regulatory Assets |
|
| 29.0 |
|
| 19.6 |
|
| 13.1 |
|
| 13.5 |
|
| 17.2 |
|
| 6.4 |
Totals |
| $ | 1,878.9 |
| $ | 434.4 |
| $ | 227.1 |
| $ | 2,068.8 |
| $ | 494.1 |
| $ | 240.8 |
Additionally, the Regulated companies had $37.5 million ($0.6 million for CL&P, $26.5 for PSNH, and $1.9 million for WMECO) and $27.1 million ($9.9 million for CL&P and $9.1 million for WMECO) of regulatory costs as of December 31, 2010 and 2009, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes these costs are probable of recovery in future cost-of-service regulated rates.
Of the total December 31, 2010 amount, $6.6 million for PSNH relates to the probable recovery in future rates of previously recognized tax benefits lost as a result of a provision in the 2010 Healthcare Act that eliminated the tax deductibility of actuarially equivalent Medicare Part D benefits for retirees. On July 28, 2010, the DPUC allowed CL&P the creation of a regulatory asset for the recovery of future tax benefits lost as a result of the 2010 Healthcare Act, subject to review in its next rate case. On January 31, 2011, the DPU also allowed WMECO the creation of a regulatory asset as a result of the 2010 Healthcare Act. NU has concluded that these costs are probable of recovery and has recorded regulatory assets of $22 million ($15.5 million for CL&P, $3.9 million for WMECO and $2.6 million for Yankee Gas) as of December 31, 2010, which are reflected in Other Regulatory Assets in the table above. These assets are not earning a return. For further information regarding the 2010 Healthcare Act, see Note 11, "Income Taxes," to the consolidated financial statements. The December 31, 2010 balance at PSNH also includes $19.9 million of costs incurred for the February 2010
113
winter storm restorations that met the NHPUC specified criteria for deferral to a major storm cost reserve. PSNH expects to request recovery of both the Medicare asset and the 2010 winter storm costs in 2011.
Deferred Benefit Costs: NU's Pension, SERP, and PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other postretirement plans. Under this accounting guidance, the funded status of its pension and PBOP plans is recorded with an offset to Accumulated Other Comprehensive Income/(Loss) and is remeasured annually. However, because the Regulated companies are rate-regulated on a cost-of-service basis, offsets were recorded as regulatory assets as of December 31, 2010 and 2009 as these amounts have been and continue to be recoverable in cost-of-service regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support the Regulated companies, as these amounts are also recoverable. The deferred benefit costs of CL&P and PSNH are not in rate base and are expected to be amortized int o expense over a period of up to 12 years. WMECO's deferred benefit costs are earning an equity return at the same rate as the assets included in rate base.
Regulatory Assets Offsetting Derivative Liabilities: The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future. Included in these amounts are $779 million and $768.7 million as of December 31, 2010 and 2009, respectively, of derivative liabilities relating to CL&P's capacity contracts, referred to as CfDs. See Note 4, "Derivative Instruments," to the consolidated financial statements for further information. These assets are excluded from rate base and are being recovered as the actual settlement occurs over the duration of the contracts.
Securitized Assets: In March 2001, CL&P issued approximately $1.4 billion in RRBs. CL&P used $1.1 billion of the proceeds from that issuance to buyout or buydown certain contracts with IPPs. The CL&P securitized asset balance was fully amortized as of December 31, 2010. As of December 31, 2009, the unamortized CL&P securitized asset balance was $167 million, which included $23.2 million related to unrecovered contractual obligations. CL&P also used the proceeds from the issuance of the RRBs to securitize a portion of its regulatory assets associated with income taxes. The securitized income tax regulatory asset was fully amortized as of December 31, 2010 and had an unamortized balance of $28.4 million as of December 31, 2009.
In April 2001, PSNH issued RRBs in the amount of $525 million. PSNH used the majority of the proceeds from that issuance to buydown its power contracts with an affiliate, North Atlantic Energy Corporation. In May 2001, WMECO issued $155 million in RRBs and used the majority of the proceeds from that issuance to buyout an IPP contract.
Securitized regulatory assets are not earning an equity return and are being recovered over the amortization period of their associated RRBs. PSNH RRBs are scheduled to fully amortize by May 1, 2013 and WMECO RRBs are scheduled to fully amortize by June 1, 2013.
Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. For further information regarding income taxes, see Note 11, "Income Taxes," to the consolidated financial statements.
Unrecovered Contractual Obligations: Under the terms of contracts with CYAPC, YAEC, and MYAPC, CL&P, PSNH, and WMECO are responsible for their proportionate share of the remaining costs of the nuclear facilities, including decommissioning. A portion of these amounts was recorded as unrecovered contractual obligations regulatory assets as of December 31, 2010 and 2009. A portion of these obligations for CL&P was securitized in 2001 and was included in securitized regulatory assets. The securitized portion of these regulatory assets for CL&P was fully recovered as of December 31, 2010. Remaining amounts for CL&P are earning a return and are being recovered through the CTA. Amounts for WMECO are being recovered without a return along with other stranded costs and are anticipated to be recovered by 2013, the scheduled completion date of stranded cost recovery. Amounts for PSNH were fully recovered by 2006.
Regulatory Tracker Deferrals: Regulatory tracker deferrals are approved rate mechanisms that allow utilities to recover costs in specific business segments through reconcilable tracking mechanisms that are reviewed at least annually by the applicable regulatory commission. Regulatory tracker deferrals are recorded as regulatory assets if unrecovered costs are in excess of collections and are recorded as regulatory liabilities if collections are in excess of costs. The majority of regulatory tracker deferrals are earning a return. The following regulatory tracker deferrals were recorded as either regulatory assets or liabilities as of December 31, 2010 and 2009:
CL&P Tracker Deferrals: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the RRBs, amortization of regulatory assets, and IPP over market costs. As of December 31, 2010 and 2009, CL&P's CTA was a $35.5 million and $32.2 million regulatory asset, respectively, as CTA unrecovered costs were in excess of CTA collections. As part of the CTA reconciliation process, CL&P has also established an obligation to potentially refund the variable incentive portion of its transition service procurement fee, which totaled $24.7 million and $23.2 million as of December 31, 2010 and 2009, respectively, and was recorded as a regulatory liability.
The GSC allows CL&P to recover the costs of the procurement of energy for SS and LRS. The FMCC mechanism allows CL&P to recover the costs of congestion and other costs associated with power market rules approved by the FERC or as approved by the DPUC. CL&P's GSC and FMCC were recorded as a $0.3 million regulatory liability as of December 31, 2010 and a $2.4 million regulatory asset as of December 31, 2009. The SBC allows CL&P to recover certain regulatory and energy public policy costs, such as
114
hardship protection costs and transition period property taxes. As of December 31, 2010, SBC overrcollections totaled $4.8 million and was recorded as a regulatory liability whereas as of December 31, 2009, SBC undercollections totaled $18 million and was recorded as a regulatory asset. The C&LM charge allows CL&P to recover the costs of C&LM programs. C&LM overcollections totaled $36.4 million and $32.8 million and were recorded as regulatory liabilities as of December 31, 2010 and 2009, respectively. As of December 31, 2010, CL&P retail transmission collections were in excess of costs and $13.2 million was recorded as a regulatory liability whereas as of December 31, 2009, retail transmission costs were in excess of collections and $17.7 million was recorded as a regulatory asset.
PSNH Tracker Deferrals: The NHPUC permits PSNH to recover the actual and prudent costs of providing generation for ES, subject to annual review. Accordingly, ES revenues and costs are fully tracked, and the difference between ES revenues and costs are deferred. ES deferrals are being collected from/refunded to customers through a charge/(credit) in the subsequent ES rate period. As of December 31, 2010 and 2009, the ES deferral was in an underrecovery position of $14.7 million and $8.4 million, respectively and was recorded as a regulatory asset. The SCRC allows PSNH to recover restructuring costs as a result of deregulation and the TCAM covers retail transmission costs incurred by PSNH's distribution business. As of December 31, 2010, SCRC overcollections totaled $2.4 million and TCAM overcollections totaled $0.8 million whereas as of December 31, 2009, SCRC undercollections totaled $ 3.9 million and TCAM undercollections totaled $6.7 million. PSNH recovers the cost of C&LM programs and C&LM overcollections totaled $3.4 million and $4.4 million as of December 31, 2010 and 2009, respectively.
WMECO Tracker Deferrals: The basic service rate allows WMECO to recover the costs of the procurement of energy for basic service. Basic service undercollections totaled $0.1 million and overcollections totaled $2.1 million as of December 31, 2010 and 2009, respectively. WMECO recovers its stranded costs through a transition charge. This amount represents the cumulative excess of transition expenses over transition revenues. Transition charge undercollections totaled $0.6 million and $6.9 million, and were recorded as a regulatory asset as of December 31, 2010 and 2009, respectively. The C&LM charge allows WMECO to recover the costs of C&LM programs. C&LM undercollections totaled $4.5 million and $2.5 million and were recorded as a regulatory asset as of December 31, 2010 and 2009, respectively. As of December 31, 2010, WMECO retail transmission collect ions were in excess of costs and $4.8 million was recorded as a regulatory liability whereas, as of December 31, 2009, WMECO retail transmission costs were in excess of collections and $0.9 million was recorded as a regulatory asset.
WMECO's pension and PBOP plan costs are recovered through a tracking mechanism that allows WMECO to earn a return on its pension and PBOP assets and liabilities at its weighted average cost of capital, including the deferred future pension and PBOP benefit obligations. As of December 31, 2010 and 2009, pension/PBOP undercollections totaled $4.6 million and $1 million, respectively, and were recorded as a regulatory asset as the pension/PBOP expenses exceeded the revenue collected from customers.
Storm Cost Deferrals: The storm cost deferrals relate to costs incurred at CL&P, PSNH and WMECO for restorations that met regulatory agency specified criteria for deferral to a major storm cost reserve. The PSNH deferral as of December 31, 2010 relates to remaining costs incurred for a major storm in December 2008. As part of a multi-year rate case settlement agreement effective July 1, 2010, PSNH was allowed recovery of these storm costs. WMECO's 2008 and 2010 storm costs were deferred and in accordance with WMECO's January 31, 2011 distribution rate case decision will be recovered from customers over five years as part of WMECO's storm reserve. These assets are included in rate base.
The CL&P deferral as of December 31, 2010 relates to remaining costs incurred for the March 2010 winter storm restorations that met the DPUC criteria for a major storm. CL&P is allowed to collect from customers $3 million per year for major storm costs. Storm cost deferrals/reserves are included in rate base.
Asset Retirement Obligations: See Note 6, "Asset Retirement Obligations," to the consolidated financial statements for further information.
Losses on Reacquired Debt: The regulatory asset relates to the losses associated with the reacquisition or redemption of long-term debt. These deferred losses are amortized over the life of the respective long-term debt issuance.
Deferred Environmental Remediation Costs: This regulatory asset relates to environmental remediation costs at PSNH of $9.7 million and Yankee Gas of $27.1 million. Both PSNH and Yankee Gas have regulatory rate recovery mechanisms for environmental costs and accordingly, offsets to environmental reserves were recorded as regulatory assets. Management continues to believe these costs are probable of recovery in future cost-of-service regulated rates.
Deferred Operation and Maintenance Costs: This regulatory asset represents the deferral of maintenance expense in connection with the deferred recovery of revenue requirements for the period July 1, 2010 through December 31, 2010, as allowed by the DPUC. CL&P is allowed to recover these costs beginning January 1, 2011 through June 2012.
115
Regulatory Liabilities: The components of regulatory liabilities are as follows:
|
| As of December 31, | ||||
|
| 2010 |
| 2009 | ||
(Millions of Dollars) |
| NU |
| NU | ||
Cost of Removal |
| $ | 194.8 |
| $ | 209.2 |
Regulatory Liabilities Offsetting Derivative Assets |
|
| 38.1 |
|
| 109.4 |
Regulatory Tracker Deferrals |
|
| 95.1 |
|
| 69.5 |
AFUDC Transmission Incentive |
|
| 62.1 |
|
| 51.1 |
Pension Liability - Yankee Gas Acquisition |
|
| 12.5 |
|
| 15.0 |
Other Regulatory Liabilities |
|
| 36.5 |
|
| 31.5 |
Totals |
| $ | 439.1 |
| $ | 485.7 |
|
| As of December 31, | ||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Cost of Removal |
| $ | 78.6 |
| $ | 57.3 |
| $ | 9.5 |
| $ | 82.2 |
| $ | 60.5 |
| $ | 16.6 |
Regulatory Liabilities Offsetting Derivative Assets |
|
| 38.1 |
|
| - |
|
| - |
|
| 109.0 |
|
| 0.4 |
|
| - |
Regulatory Tracker Deferrals |
|
| 79.4 |
|
| 6.6 |
|
| 4.8 |
|
| 56.0 |
|
| 4.4 |
|
| 2.1 |
AFUDC Transmission Incentive |
|
| 56.5 |
|
| - |
|
| 5.6 |
|
| 50.4 |
|
| - |
|
| 0.7 |
WMECO Provision For Rate Refunds |
|
| - |
|
| - |
|
| 2.0 |
|
| - |
|
| - |
|
| 2.0 |
Other Regulatory Liabilities |
|
| 29.5 |
|
| 3.1 |
|
| 1.1 |
|
| 18.6 |
|
| 4.6 |
|
| 0.3 |
Totals |
| $ | 282.1 |
| $ | 67.0 |
| $ | 23.0 |
| $ | 316.2 |
| $ | 69.9 |
| $ | 21.7 |
Cost of Removal: NU's Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. These amounts are classified as Regulatory Liabilities on the accompanying consolidated balance sheets. This liability is included in rate base.
Regulatory Liabilities Offsetting Derivative Assets: The regulatory liabilities offsetting derivative assets relate to the fair value of contracts used to purchase power and other related contracts that will benefit customers in the future. See Note 4, "Derivative Instruments," to the consolidated financial statements for further information. This liability is excluded from rate base and is refunded as the actual settlement occurs over the duration of the contracts.
AFUDC Transmission Incentive: See Note 1O, "Summary of Significant Accounting Policies - Allowance for Funds Used During Construction," to the consolidated financial statements for further information.
Pension Liability - Yankee Gas Acquisition: When Yankee Gas was acquired by NU, the pension liability was adjusted to fair value with offsets to the adjustment recorded as a regulatory liability, as approved by the DPUC. The pension liability was approved for amortization over an approximate 13-year period beginning in 2002 without a return on the liability.
WMECO Provision for Rate Refunds: The provision for rate refunds was established to reserve a refund to customers as a result of DPU service quality penalty guidelines.
3.
PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
The following tables summarize the NU, CL&P, PSNH, and WMECO investments in utility plant:
|
| As of December 31, | ||||
|
| 2010 |
| 2009 | ||
(Millions of Dollars) |
| NU |
| NU | ||
Distribution - Electric |
| $ | 6,197.2 |
| $ | 5,893.9 |
Distribution - Natural Gas |
|
| 1,126.6 |
|
| 1,071.1 |
Transmission |
|
| 3,378.0 |
|
| 3,219.2 |
Generation |
|
| 697.1 |
|
| 660.1 |
Electric and Natural Gas Utility |
|
| 11,398.9 |
|
| 10,844.3 |
Other(1) |
|
| 305.5 |
|
| 265.6 |
Total Property, Plant and Equipment, Gross |
|
| 11,704.4 |
|
| 11,109.9 |
Less: Accumulated Depreciation |
|
|
|
|
|
|
Electric and Natural Gas Utility |
|
| (2,862.3) |
|
| (2,721.3) |
Other |
|
| (119.9) |
|
| (120.3) |
Total Accumulated Depreciation |
|
| (2,982.2) |
|
| (2,841.6) |
Property, Plant and Equipment, Net |
|
| 8,722.2 |
|
| 8,268.3 |
Construction Work in Progress |
|
| 845.5 |
|
| 571.7 |
Total Property, Plant and Equipment, Net |
| $ | 9,567.7 |
| $ | 8,840.0 |
(1)
These assets are primarily owned by RRR ($166 million and $143.8 million) and NUSCO ($126.6 million and $109 million) as of December 31, 2010 and 2009, respectively, and are mainly comprised of building improvements at RRR and software and equipment at NUSCO.
116
|
| As of December 31, | ||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Distribution |
| $ | 4,180.7 |
| $ | 1,375.4 |
| $ | 673.7 |
| $ | 3,960.1 |
| $ | 1,309.2 |
| $ | 654.9 |
Transmission |
|
| 2,668.4 |
|
| 476.1 |
|
| 233.5 |
|
| 2,573.2 |
|
| 450.2 |
|
| 195.7 |
Generation |
|
| - |
|
| 687.7 |
|
| 9.4 |
|
| - |
|
| 660.1 |
|
| - |
Total Property, Plant and Equipment, Gross |
|
| 6,849.1 |
|
| 2,539.2 |
|
| 916.6 |
|
| 6,533.3 |
|
| 2,419.5 |
|
| 850.6 |
Less: Accumulated Depreciation |
|
| (1,508.7) |
|
| (837.3) |
|
| (228.5) |
|
| (1,426.6) |
|
| (805.5) |
|
| (218.2) |
Property, Plant and Equipment, Net |
|
| 5,340.4 |
|
| 1,701.9 |
|
| 688.1 |
|
| 5,106.7 |
|
| 1,614.0 |
|
| 632.4 |
Construction Work in Progress |
|
| 246.1 |
|
| 351.4 |
|
| 129.0 |
|
| 233.9 |
|
| 200.7 |
|
| 73.4 |
Total Property, Plant and Equipment, Net |
| $ | 5,586.5 |
| $ | 2,053.3 |
| $ | 817.1 |
| $ | 5,340.6 |
| $ | 1,814.7 |
| $ | 705.8 |
PSNH charges planned major maintenance activities to Operating Expenses unless the cost represents the acquisition of additional components. PSNH capitalizes the cost of plant additions.
CL&P, PSNH and WMECO have entered into certain equipment purchase contracts that require the Company to make advance payments during the design, manufacturing, shipment and installation of equipment. As of December 31, 2010 and 2009, advance payments totaling $9.3 million and $27 million, respectively ($1.3 million and $5.4 million for CL&P, $4.9 million and $16.6 million for PSNH and $3.1 million and $5 million for WMECO, respectively) are included within CWIP in the table above and not subject to depreciation.
The following table summarizes average depreciable lives as of December 31, 2010:
|
| Average Depreciable Life | ||||||||||
(Years) |
|
| NU |
|
| CL&P |
|
| PSNH |
|
| WMECO |
Distribution |
|
| 36.8 |
|
| 36.0 |
|
| 37.0 |
|
| 32.5 |
Transmission |
|
| 43.2 |
|
| 42.3 |
|
| 44.6 |
|
| 54.2 |
Generation |
|
| 31.9 |
|
| - |
|
| 31.6 |
|
| 25.0 |
Other |
|
| 20.7 |
|
| - |
|
| - |
|
| - |
The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency (the DPUC, NHPUC, and the DPU for CL&P, PSNH, and WMECO, respectively). Depreciation rates are applied to plant-in-service from the time it is placed in service. When a plant is retired from service, the original cost of the plant is charged to the accumulated provision for depreciation, which includes cost of removal less salvage. Cost of removal is classified as a Regulatory Liability on the accompanying consolidated balance sheets. The depreciation rates for the several classes of utility plant-in-service are equivalent to composite rates as follows:
(Percent) |
| 2010 |
| 2009 |
| 2008 | |||
NU |
|
| 2.7 |
|
| 2.9 |
|
| 3.0 |
CL&P |
|
| 2.7 |
|
| 3.0 |
|
| 3.1 |
PSNH |
|
| 2.8 |
|
| 2.7 |
|
| 2.7 |
WMECO |
|
| 2.8 |
|
| 2.9 |
|
| 2.8 |
4.
DERIVATIVE INSTRUMENTS
The costs and benefits of derivative contracts that meet the definition of and are designated as "normal purchases or normal sales" (normal) are recognized in Operating Expenses or Operating Revenues on the accompanying consolidated statements of income, as applicable, as electricity or natural gas is delivered.
Derivative contracts that are not recorded as normal under the applicable accounting guidance, are recorded at fair value as current or long-term derivative assets or liabilities. Changes in fair values of NU Enterprises' derivatives are included in Net Income. For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as these contracts are part of current regulated operating costs, or have an allowed recovery mechanism, and management believes that these costs will continue to be recovered from or refunded to customers in cost-of-service, regulated rates. See below for discussion of "Derivatives not designated as hedges."
The Regulated companies are exposed to the volatility of the prices of energy and energy-related products in procuring energy supply for their customers. The costs associated with supplying energy to customers are recoverable through customer rates. The Company manages the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which are accounted for as normal (for WMECO all derivative contracts are accounted for as normal) and the use of nonderivative contracts.
CL&P mitigates the risks associated with the price volatility of energy and energy-related products through the use of SS or LRS contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for as normal. CL&P has entered into derivatives, including FTR contracts and bilateral basis swaps, to manage the risk of congestion costs associated with its respectiveSS and LRS contracts. As required by regulation, CL&P has also entered into derivative and
117
nonderivative contracts for the purchase of energy and energy-related products and contracts related to capacity. While the risks managed by these contracts are regional congestion costs and capacity price risks that are not specific to CL&P, Connecticut's electric distribution companies, including CL&P, are required to enter into these contracts. Management believes any costs or benefits from these contracts are recoverable from or will be refunded to CL&P's customers, and, therefore any changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying consolidated balance sheets.
WMECO mitigates the risks associated with the volatility of the prices of energy and energy-related products in procuring energy supply for its customers through the use of basic service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for as normal.
PSNH mitigates the risks associated with the volatility of energy prices in procuring energy supply for its customers through its generation facilities and the use of derivative contracts, including energy forward contracts, options and FTRs. PSNH enters into these contracts in order to stabilize electricity prices for customers. Management believes any costs or benefits from these contracts are recoverable from or will be refunded to PSNH's customers, and, therefore any changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying consolidated balance sheets.
NU, through Yankee Gas, mitigates the risks associated with supply availability and volatility of natural gas prices through the use of storage facilities and agreements to purchase natural gas supply for customers. The costs associated with mitigating these risks are recoverable from customers, and, therefore any changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying consolidated balance sheets.
NU Enterprises, through Select Energy, has one remaining fixed price forward sales contract to serve electrical load that is part of its wholesale energy marketing portfolio. NU Enterprises mitigates the price risk associated with this contract through the use of forward purchase and sales contracts. NU Enterprises' derivative contracts are accounted for at fair value, and changes in their fair values are recorded in Operating Expenses on the accompanying consolidated statements of income.
NU is also exposed to interest rate risk associated with its long-term debt. From time to time, various subsidiaries of the Company enter into forward starting interest rate swaps, accounted for as cash flow hedges, to mitigate the risk of changes in interest rates when they expect to issue long-term debt. NU parent has also entered into an interest rate swap on fixed rate long-term debt in order to manage the balance of its fixed and floating rate debt. This interest rate swap is accounted for as a fair value hedge.
118
The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with appropriate current and long-term portions, in the accompanying consolidated balance sheets. The following tables present the gross fair values of contracts and the net amounts recorded as current or long-term derivative assets or liabilities, by primary underlying risk exposures or purpose:
|
| As of December 31, 2010 | ||||||||||||||||
|
| Derivatives Not Designated as Hedges |
|
|
|
|
|
| ||||||||||
(Millions of Dollars) |
| Commodity |
| Commodity |
| Other |
| Hedging |
| Collateral |
| Net Amount | ||||||
Current Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Parent |
| $ | - |
| $ | - |
| $ | - |
| $ | 7.7 |
| $ | - |
| $ | 7.7 |
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises |
|
| - |
|
| 1.7 |
|
| - |
|
| - |
|
| - |
|
| 1.7 |
CL&P |
|
| 5.8 |
|
| - |
|
| 2.1 |
|
| - |
|
| - |
|
| 7.9 |
Total Current Derivative Assets |
| $ | 5.8 |
| $ | 1.7 |
| $ | 2.1 |
| $ | 7.7 |
| $ | - |
| $ | 17.3 |
|
|
|
|
|
|
|
|
| &nb sp; |
|
|
|
|
|
|
|
|
|
Long-Term Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Parent |
| $ | - |
| $ | - |
| $ | - |
| $ | 4.1 |
| $ | - |
| $ | 4.1 |
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises |
|
| - |
|
| 3.2 |
|
| - |
|
| - |
|
| - |
|
| 3.2 |
CL&P(1) |
|
| 195.9 |
|
| - |
|
| - |
|
| - |
|
| (80.0) |
|
| 115.9 |
Total Long-Term Derivative Assets |
| $ | 195.9 |
| $ | 3.2 |
| $ | - |
| $ | 4.1 |
| $ | (80.0) |
| $ | 123.2 |
|
|
|
|
|
|
|
|
| &nb sp; |
|
|
|
|
|
|
|
|
|
Current Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSNH |
| $ | - |
| $ | - |
| $ | (12.8) |
| $ | - |
| $ | - |
| $ | (12.8) |
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises(2) |
|
| - |
|
| (11.9) |
|
| - |
|
| - |
|
| 0.5 |
|
| (11.4) |
CL&P(1) |
|
| (54.3) |
|
| - |
|
| (0.2) |
|
| - |
|
| 7.7 |
|
| (46.8) |
Other |
|
| - |
|
| - |
|
| (0.5) |
|
| - |
|
| - |
|
| (0.5) |
Total Current Derivative Liabilities |
| $ | (54.3) |
| $ | (11.9) |
| $ | (13.5) |
| $ | - |
| $ | 8.2 |
| $ | (71.5) |
|
|
|
|
|
|
|
|
| &nb sp; |
|
|
|
|
|
|
|
|
|
Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises(1) |
| $ | - |
| $ | (26.5) |
| $ | - |
| $ | - |
| $ | 0.2 |
| $ | (26.3) |
CL&P |
|
| (883.1) |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (883.1) |
Other |
|
| - |
|
| - |
|
| (0.3) |
|
| - |
|
| - |
|
| (0.3) |
Total Long-Term Derivative Liabilities |
| $ | (883.1) |
| $ | (26.5) |
| $ | (0.3) |
| $ | - |
| $ | 0.2 |
| $ | (909.7) |
119
|
| As of December 31, 2009 | ||||||||||||||||
|
| Derivatives Not Designated as Hedges |
| |||||||||||||||
(Millions of Dollars) |
| Commodity |
| Commodity |
| Other |
| Hedging |
| Collateral |
| Net Amount | ||||||
Current Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Parent |
| $ | - |
| $ | - |
| $ | - |
| $ | 6.7 |
| $ | - |
| $ | 6.7 |
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P |
|
| 20.1 |
|
| - |
|
| 4.5 |
|
| - |
|
| - |
|
| 24.6 |
PSNH(3) |
|
| - |
|
| - |
|
| 0.4 |
|
| - |
|
| - |
|
| 0.4 |
Other |
|
| - |
|
| - |
|
| 0.1 |
|
| - |
|
| - |
|
| 0.1 |
Total Current Derivative Assets |
| $ | 20.1 |
| $ | - |
| $ | 5.0 |
| $ | 6.7 |
| $ | - |
| $ | 31.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Parent |
| $ | - |
| $ | - |
| $ | - |
| $ | 6.5 |
| $ | - |
| $ | 6.5 |
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P(1) |
|
| 259.0 |
|
| - |
|
| - |
|
| - |
|
| (75.8) |
|
| 183.2 |
Total Long-Term Derivative Assets |
| $ | 259.0 |
| $ | - |
| $ | - |
| $ | 6.5 |
| $ | (75.8) |
| $ | 189.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSNH |
| $ | - |
| $ | - |
| $ | (18.8) |
| $ | - |
| $ | - |
| $ | (18.8) |
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises(2) |
|
| - |
|
| (13.0) |
|
| - |
|
| - |
|
| 4.3 |
|
| (8.7) |
CL&P(4) |
|
| (10.3) |
|
| - |
|
| - |
|
| - |
|
| 0.5 |
|
| (9.8) |
Other |
|
| - |
|
| - |
|
| (0.4) |
|
| - |
|
| - |
|
| (0.4) |
Total Current Derivative Liabilities |
| $ | (10.3) |
| $ | (13.0) |
| $ | (19.2) |
| $ | - |
| $ | 4.8 |
| $ | (37.7) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSNH |
| $ | - |
| $ | - |
| $ | (7.6) |
| $ | - |
| $ | - |
| $ | (7.6) |
Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU Enterprises (1) |
|
| - |
|
| (41.1) |
|
| - |
|
| - |
|
| 6.7 |
|
| (34.4) |
CL&P |
|
| (913.3) |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (913.3) |
Other |
|
| - |
|
| - |
|
| (0.3) |
|
| - |
|
| - |
|
| (0.3) |
Total Long-Term Derivative Liabilities |
| $ | (913.3) |
| $ | (41.1) |
| $ | (7.9) |
| $ | - |
| $ | 6.7 |
| $ | (955.6) |
(1)
Amounts in Collateral and Netting represent derivative contracts that are netted against the fair value of the gross derivative asset/liability.
(2)
Collateral and Netting amounts as of December 31, 2010 for NU Enterprises current derivative liabilities represent cash collateral posted that is under master netting agreements. As of December 31, 2009, Collateral and Netting included derivative assets of $2.2 million that are netted against the fair value of derivative liabilities and cash collateral of $2.1 million posted under master netting agreements.
(3)
On PSNH's accompanying consolidated balance sheet, the current portion of the net derivative asset is shown in Prepayments and Other Current Assets.
(4)
Collateral and Netting amounts represent cash posted under master netting agreements.
The business activities of the Company that resulted in the recognition of derivative assets also create exposure to various counterparties. As of December 31, 2010, NU's and CL&P's derivative assets are exposed to counterparty credit risk. Of these amounts, $95.5 million ($83.6 million for CL&P) is contracted with investment grade entities and the remainder is contracted with multiple other counterparties.
For further information on the fair value of derivative contracts, see Note 1J, "Summary of Significant Accounting Policies - Derivative Accounting," Note 1I, "Summary of Significant Accounting Policies - Fair Value Measurements."
The following provides additional information about the derivatives included in the tables above, including volumes and cash flow information.
Derivatives not designated as hedges
NU Enterprises' commodity sales contract and related price and supply risk management: As of December 31, 2010 and 2009, NU Enterprises had approximately 0.3 million and 0.4 million MWh, respectively, of supply volumes remaining in its wholesale portfolio
120
when expected sales to an agency that is comprised of municipalities are compared with contracted supply, both of which extend through 2013.
CL&P commodity and capacity contracts required by regulation: As of December 31, 2010 and 2009, CL&P had contracts with two IPPs to purchase electricity monthly in amounts aggregating approximately 1.5 million MWh per year through March 2015 under one of these contracts and 0.1 million MWh per year through December 2020 under the second contract. CL&P also has two capacity-related CfDs to increase energy supply in Connecticut relating to one generating project that has been modified and one generating plant to be built. The total capacity of these CfDs and two additional CfDs entered into by UI is expected to be approximately 787 MW. CL&P has an agreement with UI, which is also accounted for as a derivative, under which UI will share the costs and benefits of the four CfDs, with 80 percent allocated to CL&P and 20 percent to UI. The four CfDs obligate the utilities to pay/rece ive monthly the difference between a set capacity price and the forward capacity market price that the projects receive in the ISO-NE capacity markets for periods of up to 15 years beginning in 2009.
Commodity price and supply risk management: As of December 31, 2010 and 2009, CL&P had 1.8 million and 2.7 million MWh, respectively, remaining under FTRs that extend through December 2011 and require monthly payments or receipts.
PSNH has electricity procurement contracts with delivery dates through 2011 to purchase an aggregate amount of 0.4 million and 1 million MWh of power as of December 31, 2010 and 2009, respectively, that is used to serve customer load and manage price risk of its electricity delivery service obligations. These contracts are settled monthly. PSNH also has two energy call options that it received in exchange for assigning its transmission rights in a direct current transmission line. The options give PSNH the right to purchase a de minimis amount and 0.6 million MWh of electricity through January 2011 as of December 31, 2010 and 2009, respectively. In addition, PSNH has entered into FTRs to manage the risk of congestion costs associated with its electricity delivery service. As of December 31, 2010 and 2009, there were 0.3 million and 0.4 million MWh, respectively, remaining under FTRs that extend through December 2011 and required monthly payments or receipts. The purpose of the PSNH derivative contracts is to provide stable rates for customers by mitigating price uncertainties associated with the New England electricity spot market.
The following table presents the realized and unrealized gains/(losses) associated with derivative contracts not designated as hedges:
|
|
|
| Amount of Gain/(Loss) | ||
Derivatives Not Designated |
| Location of Gain or Loss |
| For the Years Ended | ||
December 31, 2010 |
| December 31, 2009 | ||||
(Millions of Dollars) |
|
|
|
| ||
NU Enterprises: |
|
|
|
| ||
Commodity Sales Contract and |
| Fuel, Purchased and Net |
| $ 2.7 |
| $ 6.2 |
Regulated Companies: |
|
|
|
|
|
|
CL&P Commodity and Capacity |
| Regulatory Assets/Liabilities |
| (74.0) |
| (99.9) |
Other Commodity Price and Supply |
|
|
|
|
|
|
CL&P |
| Regulatory Assets/Liabilities |
| (6.2) |
| (7.8) |
PSNH |
| Regulatory Assets/Liabilities |
| (15.0) |
| (62.6) |
Other |
| Regulatory Assets/Liabilities |
| (0.5) |
| (2.8) |
For the Regulated companies, monthly settlement amounts are recorded as receivables or payables and as Operating Revenues or Fuel, Purchased and Net Interchange Power on the accompanying consolidated financial statements. Regulatory assets/liabilities are established with no impact to Net Income.
Derivatives designated as hedges
Interest Rate Risk Management: To manage the interest rate risk characteristics of NU parent's fixed rate long-term debt, NU parent has a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate senior notes maturing on April 1, 2012. This interest rate swap qualifies and was designated as a fair value hedge and requires semi-annual cash settlements. The changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in Interest Expense on the accompanying consolidated statements of income. There was no ineffectiveness recorded for the years ended December 31, 2010 and 2009. The cumulative changes in fair values of the swap and the Long-Term Debt are recorded as a Derivative Asset/Liability and an adjustment to Long-Term Debt. Interest receivable is recorded as a reduction of Interest Expense and is included in Prepa yments and Other Current Assets.
121
The realized and unrealized gains/(losses) related to changes in fair value of the swap and Long-Term Debt as well as pre-tax Interest Expense, recorded in Net Income, were as follows:
|
| For the Years Ended | ||||||||||
|
| December 31, 2010 |
| December 31, 2009 | ||||||||
|
| Swap |
| Hedged Debt |
|
| Swap |
| Hedged Debt | |||
Changes in Fair Value |
| $ | 9.5 |
| $ | (9.5) |
| $ | 1.6 |
| $ | (1.6) |
Interest Recorded in Net Income |
|
| - |
|
| 10.9 |
|
| - |
|
| 9.1 |
There were no cash flow hedges outstanding as of or during the years ended December 31, 2010 and 2009 and no ineffectiveness was recorded during these periods. From time to time, NU, including CL&P, PSNH and W MECO.WMECO, enters into forward starting interest rate swap agreements on proposed debt issuances that qualify and are designated as cash flow hedges. Cash flow hedges are recorded at fair value, and the changes in the fair value of the effective portion of those contracts are recognized in Accumulated Other Comprehensive Income/(Loss). Cash flow hedges impact Net Income when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is improbable of occurring, or when the transaction is settled. When a cash flow hedge is terminated, the settlement amount is recorded in Accumulated Other Comprehensive Income/(Loss) and is amortized into Net Income over the term of the unde rlying debt instrument.
2.Pre-tax gains/(losses) amortized from Accumulated Other Comprehensive Income/(Loss) into Interest Expense on the accompanying consolidated statements of income were as follows:
Short-Term Debt (All Companies)
|
| For the Years Ended | ||||
(Millions of Dollars) |
| December 31, 2010 |
| December 31, 2009 | ||
CL&P |
| $ | (0.7) |
| $ | (0.7) |
PSNH |
|
| (0.2) |
|
| (0.2) |
WMECO |
|
| 0.1 |
|
| 0.1 |
Other |
|
| 0.4 |
|
| 0.4 |
NU |
| $ | (0.4) |
| $ | (0.4) |
For further information, see Note 16, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.
Credit Risk
Certain derivative contracts that are accounted for at fair value, including PSNH's electricity procurement contracts and NU Enterprises' electricity sourcing contracts, contain credit risk contingent features. These features require these companies or, in NU Enterprises' case, NU parent, to maintain investment grade credit ratings from the major rating agencies and to post cash or standby LOCs as collateral for contracts in a net liability position over specified credit limits. NU parent provides standby LOCs under its revolving credit agreement for NU subsidiaries to post with counterparties. The following summarizes the fair value of derivative contracts that are in a liability position and subject to credit risk contingent features, and the fair value of cash collateral and standby LOCs posted with counterparties as of December 31, 2010 and 2009:
|
| As of December 31, 2010 | |||||||
(Millions of Dollars) |
| Fair Value Subject |
| Cash |
| Standby | |||
PSNH |
| $ | (12.8) |
| $ | - |
| $ | 24.0 |
NU Enterprises |
|
| (18.1) |
|
| 0.5 |
|
| - |
NU |
| $ | (30.9) |
| $ | 0.5 |
| $ | 24.0 |
|
| As of December 31, 2009 | |||||||
(Millions of Dollars) |
| Fair Value Subject |
| Cash |
| Standby | |||
PSNH |
| $ | (26.4) |
| $ | - |
| $ | 25.0 |
NU Enterprises |
|
| (20.0) |
|
| 2.1 |
|
| - |
NU |
| $ | (46.4) |
| $ | 2.1 |
| $ | 25.0 |
Additional collateral is required to be posted by NU Enterprises or PSNH, if the respective unsecured debt credit ratings of NU parent or PSNH are downgraded below investment grade. As of December 31, 2010, NU Enterprises and PSNH would not have been required to post any additional cash collateral if credit ratings had been downgraded below investment grade. However, if the senior unsecured debt of NU parent had been downgraded to below investment grade, additional standby LOCs in the amount of $18.5 million would have been required to be posted on derivative contracts for Select Energy. As of December 31, 2009, no additional cash collateral would have been required to be posted if credit ratings had been downgraded below investment grade.However, if the senior unsecured debt of PSNH or NU parent had been downgraded to below investment grade, additional standby LOCs in the amount of $1.8 million and $17.8 million would have been required to be posted on derivative contracts for PSNH and Select Energy, respectively.
For further information, see Note 1H, "Summary of Significant Accounting Policies - Special Deposits and Counterparty Deposits," to the consolidated financial statements.
122
Fair Value Measurements of Derivative Instruments:
Valuation of Derivative Instruments: Derivative contracts classified as Level 2 in the fair value hierarchy include Other Commodity Price and Supply Risk Management contracts and Interest Rate Risk Management contracts. Other Commodity Price and Supply Risk Management contracts include PSNH forward contracts to purchase energy for periods for which prices are quoted in an active market. Prices are obtained from broker quotes and based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach. The Interest Rate Risk Management contract represents an interest rate swap agreement and is valued using a market approach provided by the swap counterparty using a discounted cash flow approach utilizing forward interest rate curves.
The derivative contracts classified as Level 3 in the tables below include NU Enterprises' Sales Contract and Related Price and Supply Risk Management contracts, the Regulated companies' Commodity and Capacity Contracts Required by Regulation (which include CL&P's CfDs and contracts with certain IPPs), and Other Commodity Price and Supply Risk Management contracts (CL&P and PSNH FTRs). For Commodity and Capacity Contracts Required by Regulation and NU Enterprises' Commodity Sales contract, fair value is modeled using income techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices for which quoted prices in an active market exist. Significant unobservable inputs used in the valuations of these contracts include energy and energy-related product prices for futu re years for long-dated derivative contracts and future contract quantities under requirements and supplemental sales contracts. Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts include assumptions regarding the timing and likelihood of scheduled payments and also reflect nonperformance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities.
Other Commodity Price and Supply Risk Management contracts classified as Level 3 in the tables below are valued using income approaches. Observable inputs used in valuing options include prices for energy and energy-related products for years for which quoted prices in an active market exist. Unobservable inputs included in the valuation of options contracts include market volatilities related to future energy prices and the estimated likelihood that the option will be exercised. FTRs are valued using broker quotes based on prices in an inactive market.
Valuations using significant unobservable inputs: The following tables present changes for the years ended December 31, 2010 and 2009 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. The Company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model. In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly. Thus the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs. There were no transfers into or out of Level 3 assets and liabilities for th e years ended December 31, 2010 or 2009:
|
| For the Year Ended December 31, 2010 | ||||||||||
|
| NU | ||||||||||
(Millions of Dollars) |
| Commodity |
| Commodity |
| Other |
| Total Level 3 | ||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of Beginning of Year |
| $ | (720.3) |
| $ | (45.2) |
| $ | 4.3 |
| $ | (761.2) |
Net Realized/Unrealized Gains/(Losses) Included in: |
|
|
|
|
|
|
|
|
|
|
| |
Net Income(1) |
|
| - |
|
| 2.7 |
|
| - |
|
| 2.7 |
Regulatory Assets/Liabilities |
|
| (74.0) |
|
| - |
|
| (7.2) |
|
| (81.2) |
Purchases, Issuances and Settlements |
|
| (13.7) |
|
| 9.2 |
|
| 4.0 |
|
| (0.5) |
Fair Value as of End of Year |
| $ | (808.0) |
| $ | (33.3) |
| $ | 1.1 |
| $ | (840.2) |
Period Change in Unrealized Gains Included in |
| $ | - |
| $ | 1.2 |
| $ | - |
| $ | 1.2 |
123
|
| For the Year Ended December 31, 2010 | ||||||||||
|
| CL&P |
| PSNH | ||||||||
(Millions of Dollars) |
| Commodity |
| Other |
| Total Level 3 |
| Other | ||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of Beginning of Year |
| $ | (720.3) |
| $ | 4.5 |
| $ | (715.8) |
| $ | 0.4 |
Net Realized/Unrealized Gains/(Losses) Included in: |
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Assets/Liabilities |
|
| (74.0) |
|
| (6.2) |
|
| (80.2) |
|
| (0.2) |
Purchases, Issuances and Settlements |
|
| (13.7) |
|
| 3.6 |
|
| (10.1) |
|
| (0.2) |
Fair Value as of End of Year |
| $ | (808.0) |
| $ | 1.9 |
| $ | (806.1) |
| $ | - |
|
| For the Year Ended December 31, | |||||||
|
| 2009 | |||||||
(Millions of Dollars) |
| NU |
| CL&P |
| PSNH | |||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
Fair Value as of Beginning of Year |
| $ | (669.2) |
| $ | (611.1) |
| $ | 4.1 |
Net Realized/Unrealized Gains/(Losses) Included in: |
|
|
|
|
|
|
|
|
|
Net Income(1) |
|
| 6.2 |
|
| - |
|
| - |
Regulatory Assets/Liabilities |
|
| (114.3) |
|
| (107.8) |
|
| (3.6) |
Purchases, Issuances and Settlements |
|
| 16.1 |
|
| 3.1 |
|
| (0.1) |
Fair Value as of End of Year |
| $ | (761.2) |
| $ | (715.8) |
| $ | 0.4 |
Period Change in Unrealized Gains Included in Net |
| $ | 6.3 |
| $ | - |
| $ | - |
(1)
Realized and unrealized gains and losses on derivatives included in Net Income relate to the remaining NU Enterprises' marketing contracts and are reported in Fuel, Purchased and Net Interchange Power on the accompanying consolidated statements of income.
5.
MARKETABLE SECURITIES (NU, WMECO)
The Company elected to record exchange traded funds and mutual funds purchased during 2009 in the NU supplemental benefit trust at fair value in order to reflect the economic effect of changes in fair value of all newly purchased equity securities in Net Income.
These equity securities, classified as Level 1 in the fair value hierarchy, totaled $42.2 million and $35.3 million as of December 31,
2010 and 2009, respectively, and are included in current Marketable Securities. Gains on these securities of $6.9 million and $6.6 million for the years ended December 31, 2010 and 2009, respectively, were recorded in Other Income, Net on the accompanying consolidated statements of income. Dividend income is recorded when dividends are declared and are recorded in Other Income, Net on the accompanying consolidated statements of income. All other marketable securities are accounted for as available-for-sale.
Available-for-Sale Securities: The following is a summary by security type of NU's available-for-sale securities held in the NU supplemental benefit trust and WMECO's spent nuclear fuel trust. These securities are recorded at fair value and included in current and long-term portions of Marketable Securities on the accompanying consolidated balance sheets.
|
| As of December 31, 2010 | ||||||||||
(Millions of Dollars) |
| Amortized |
| Pre-Tax |
| Pre-Tax |
|
| ||||
NU Supplemental Benefit Trust |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Government Issued Debt Securities |
| $ | 11.7 |
| $ | 0.2 |
| $ | (0.1) |
| $ | 11.8 |
Corporate Debt Securities |
|
| 6.5 |
|
| 0.5 |
|
| (0.1) |
|
| 6.9 |
Asset Backed Debt Securities |
|
| 6.5 |
|
| 0.4 |
|
| - |
|
| 6.9 |
Municipal Bonds |
|
| 0.7 |
|
| - |
|
| - |
|
| 0.7 |
Money Market Funds and Other |
|
| 3.7 |
|
| 0.2 |
|
| - |
|
| 3.9 |
Total NU Supplemental Benefit Trust |
| $ | 29.1 |
| $ | 1.3 |
| $ | (0.2) |
| $ | 30.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
WMECO Spent Nuclear Fuel Trust |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Government Issued Debt Securities |
| $ | 6.0 |
| $ | - |
| $ | - |
| $ | 6.0 |
Corporate Debt Securities |
|
| 15.6 |
|
| - |
|
| - |
|
| 15.6 |
Asset Backed Debt Securities |
|
| 4.8 |
|
| - |
|
| (0.1) |
|
| 4.7 |
Municipal Bonds |
|
| 15.4 |
|
| - |
|
| - |
|
| 15.4 |
Money Market Funds and Other |
|
| 15.4 |
|
| - |
|
| - |
|
| 15.4 |
Total WMECO Spent Nuclear Fuel Trust |
| $ | 57.2 |
| $ | - |
| $ | (0.1) |
| $ | 57.1 |
Total NU |
| $ | 86.3 |
| $ | 1.3 |
| $ | (0.3) |
| $ | 87.3 |
124
|
| As of December 31, 2009 | ||||||||||
(Millions of Dollars) |
| Amortized |
| Pre-Tax |
| Pre-Tax |
|
| ||||
NU Supplemental Benefit Trust |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Government Issued Debt Securities |
| $ | 12.8 |
| $ | 0.3 |
| $ | (0.2) |
| $ | 12.9 |
Corporate Debt Securities |
|
| 7.4 |
|
| 0.4 |
|
| (0.1) |
|
| 7.7 |
Asset Backed Debt Securities |
|
| 5.2 |
|
| 0.1 |
|
| (0.1) |
|
| 5.2 |
Municipal Bonds |
|
| 0.2 |
|
| - |
|
| - |
|
| 0.2 |
Money Market Funds and Other |
|
| 3.0 |
|
| - |
|
| - |
|
| 3.0 |
Total NU Supplemental Benefit Trust |
| $ | 28.6 |
| $ | 0.8 |
| $ | (0.4) |
| $ | 29.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
WMECO Spent Nuclear Fuel Trust |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Government Issued Debt Securities |
| $ | 17.0 |
| $ | - |
| $ | - |
| $ | 17.0 |
Corporate Debt Securities |
|
| 17.4 |
|
| 0.1 |
|
| (0.1) |
|
| 17.4 |
Asset Backed Debt Securities |
|
| 1.1 |
|
| - |
|
| (0.2) |
|
| 0.9 |
Municipal Bonds |
|
| 10.6 |
|
| - |
|
| - |
|
| 10.6 |
Money Market Funds and Other |
|
| 10.9 |
|
| - |
|
| - |
|
| 10.9 |
Total WMECO Spent Nuclear Fuel Trust |
| $ | 57.0 |
| $ | 0.1 |
| $ | (0.3) |
| $ | 56.8 |
Total NU |
| $ | 85.6 |
| $ | 0.9 |
| $ | (0.7) |
| $ | 85.8 |
(1)
Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in Accumulated Other Comprehensive Income/(Loss) and Other Long-Term Assets, respectively, on the accompanying consolidated balance sheets. For information related to the change in unrealized gains and losses for the NU supplemental benefit trust included in Accumulated Other Comprehensive Income/(Loss), see Note 16, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.
Unrealized Losses and Other-than-Temporary Impairment: There have not been significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust or WMECO spent nuclear fuel trust. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset backed securities, underlying collateral and expected future cash flows are also evaluated. All but one of the corporate and asset backed securities held in the NU supplemental benefit trust are rated investment grade. All but one of the securities in the WMECO spent nuclear fuel trust are rated investment grade and credit losses have been recorded for those securities that are below investment grade.
Contractual Maturities: As of December 31, 2010, the contractual maturities of available-for-sale debt securities are as follows:
|
|
| NU |
| WMECO | |||||||
(Millions of Dollars) |
|
| Amortized |
|
|
|
|
| Amortized |
|
|
|
Less than one year |
| $ | 36.0 |
| $ | 36.1 |
| $ | 33.2 |
| $ | 33.2 |
One to five years |
|
| 15.1 |
|
| 15.2 |
|
| 9.1 |
|
| 9.1 |
Six to ten years |
|
| 6.6 |
|
| 7.0 |
|
| 1.0 |
|
| 1.0 |
Greater than ten years |
|
| 28.6 |
|
| 29.0 |
|
| 13.9 |
|
| 13.8 |
Total Debt Securities |
| $ | 86.3 |
| $ | 87.3 |
| $ | 57.2 |
| $ | 57.1 |
Sales of Securities: For the years ended December 31, 2010, 2009 and 2008, realized gains and losses recognized on the sale of available-for-sale securities are as follows:
|
| NU |
| WMECO | ||||||||||||||
|
|
| Realized |
|
| Realized |
|
| Net Realized |
|
| Realized |
|
| Realized |
|
| Net Realized |
2010 |
| $ | 0.6 |
| $ | (0.4) |
| $ | 0.2 |
| $ | - |
| $ | (0.2) |
| $ | (0.2) |
2009 |
|
| 15.9 |
|
| (6.2) |
|
| 9.7 |
|
| - |
|
| (0.8) |
|
| (0.8) |
2008 |
|
| 2.5 |
|
| (2.2) |
|
| 0.3 |
|
| 0.2 |
|
| (0.6) |
|
| (0.4) |
Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for the NU supplemental benefit trust and in Other Long-Term Assets for the WMECO spent nuclear fuel trust. NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities. Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $174.9 million, $208.9 million and $259.4 million for the years ended December 31, 2010, 2009 and 2008, respectively. WMECO's portion of these proceeds totaled $114.2 million, $106.3 million and $169.1 million for the yearsended December& nbsp;31, 2010, 2009 and 2008, respectively. Proceeds from the sales of securities are used to purchase new securities.
125
For further information regarding marketable securities, see Note 1K, "Summary of Significant Accounting Policies - Marketable Securities," to the consolidated financial statements.
Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:
|
| NU |
| WMECO | ||||||||
(Millions of Dollars) |
| As of |
| As of |
| As of |
| As of | ||||
Level 1: |
|
|
|
|
|
|
|
|
|
|
| |
Exchange Traded Funds |
| $ | 38.9 |
| $ | 32.0 |
| $ | - |
| $ | - |
High Yield Bond Fund |
|
| 3.3 |
|
| 3.3 |
|
| - |
|
| - |
Money Market Funds |
|
| 1.8 |
|
| 8.9 |
|
| 0.3 |
|
| 6.6 |
Total Level 1 |
|
| 44.0 |
|
| 44.2 |
|
| 0.3 |
|
| 6.6 |
Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Government Issued Debt Securities |
|
|
|
|
|
|
|
|
|
|
|
|
(Agency and Treasury) |
|
| 17.8 |
|
| 29.9 |
|
| 6.0 |
|
| 17.0 |
Corporate Debt Securities |
|
| 22.5 |
|
| 25.1 |
|
| 15.6 |
|
| 17.4 |
Asset Backed Debt Securities |
|
| 11.6 |
|
| 6.1 |
|
| 4.7 |
|
| 0.9 |
Municipal Bonds |
|
| 16.1 |
|
| 10.8 |
|
| 15.4 |
|
| 10.6 |
Other Fixed Income Securities |
|
| 17.5 |
|
| 5.0 |
|
| 15.1 |
|
| 4.3 |
Total Level 2 |
|
| 85.5 |
|
| 76.9 |
|
| 56.8 |
|
| 50.2 |
Total Marketable Securities |
| $ | 129.5 |
| $ | 121.1 |
| $ | 57.1 |
| $ | 56.8 |
U.S. Government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Asset backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.
Not included in the tables above are $0.6 million and $11.6 million of cash equivalents as of December 31, 2010 and 2009, respectively, held by NU parent in an unrestricted money market account and included in Cash and Cash Equivalents on the accompanying consolidated balance sheets of NU, which are classified as Level 1 in the fair value hierarchy.
6.
ASSET RETIREMENT OBLIGATIONS
In accordance with accounting guidance for conditional AROs, NU, including CL&P, PSNH and WMECO, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated and is conditional on a future event. The guidance provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available and provides direction on the definition and timing of sufficient information in determining expected cash flows and fair values. Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination. A fair value calculation, reflecting expected probabilities for settlement scenarios, has been performed.
The fair value of an ARO is recorded as a liability in Other Long-Term Liabilities with an offset included in Property, Plant and Equipment, Net on the accompanying consolidated balance sheets. As the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and the costs associated with the Regulated companies' AROs are included in Other Regulatory Assets as of December 31, 2010 and 2009. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively. Both the depreciation and accretion were recorded as increases to Regulatory Assets on the accompanying consolidated balance sheets as of December 31, 2010 and 2009.
126
The following tables present the ARO asset, the related accumulated depreciation, the regulatory asset, and the ARO liabilities as of December 31, 2010 and 2009:
|
| As of December 31, 2010 |
| As of December 31, 2009 | |||||||||||||||||||||
(Millions of Dollars) NU |
| ARO |
| Accumulated |
| Regulatory |
| ARO |
| ARO |
| Accumulated |
| Regulatory |
| ARO | |||||||||
Asbestos |
| $ | 2.6 |
| $ | (1.7) |
| $ | 22.8 |
| $ | (25.1) |
|
| $ | 2.7 |
| $ | (1.7) |
| $ | 21.8 |
| $ | (23.9) |
Hazardous Contamination |
|
| 4.9 |
|
| (1.5) |
|
| 17.3 |
|
| (21.5) |
|
|
| 4.9 |
|
| (1.4) |
|
| 16.2 |
|
| (20.2) |
Other AROs |
|
| 2.4 |
|
| (1.0) |
|
| 5.2 |
|
| (6.7) |
|
|
| 2.6 |
|
| (1.2) |
|
| 4.9 |
|
| (6.5) |
Total AROs |
| $ | 9.9 |
| $ | (4.2) |
| $ | 45.3 |
| $ | (53.3) |
|
| $ | 10.2 |
| $ | (4.3) |
| $ | 42.9 |
| $ | (50.6) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asbestos |
| $ | 1.6 |
| $ | (1.0) |
| $ | 13.2 |
| $ | (13.8) |
|
| $ | 1.6 |
| $ | (1.0) |
| $ | 12.6 |
| $ | (13.2) |
Hazardous Contamination |
|
| 3.8 |
|
| (1.1) |
|
| 10.1 |
|
| (12.8) |
|
|
| 3.9 |
|
| (1.1) |
|
| 9.4 |
|
| (12.2) |
Other AROs |
|
| 2.0 |
|
| (0.9) |
|
| 1.6 |
|
| (2.7) |
|
|
| 2.4 |
|
| (1.0) |
|
| 1.8 |
|
| (3.2) |
Total AROs |
| $ | 7.4 |
| $ | (3.0) |
| $ | 24.9 |
| $ | (29.3) |
|
| $ | 7.9 |
| $ | (3.1) |
| $ | 23.8 |
| $ | (28.6) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSNH |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asbestos |
| $ | 0.9 |
| $ | (0.5) |
| $ | 7.7 |
| $ | (9.3) |
|
| $ | 0.9 |
| $ | (0.5) |
| $ | 7.4 |
| $ | (8.7) |
Hazardous Contamination |
|
| 0.5 |
|
| (0.3) |
|
| 6.2 |
|
| (7.2) |
|
|
| 0.5 |
|
| (0.3) |
|
| 5.9 |
|
| (6.7) |
Other AROs |
|
| - |
|
| - |
|
| 0.8 |
|
| (1.1) |
|
|
| - |
|
| - |
|
| 0.7 |
|
| (1.0) |
Total AROs |
| $ | 1.4 |
| $ | (0.8) |
| $ | 14.7 |
| $ | (17.6) |
|
| $ | 1.4 |
| $ | (0.8) |
| $ | 14.0 |
| $ | (16.4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WMECO |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asbestos |
| $ | 0.2 |
| $ | (0.1) |
| $ | 1.9 |
| $ | (2.0) |
|
| $ | 0.2 |
| $ | (0.1) |
| $ | 1.8 |
| $ | (1.9) |
Hazardous Contamination |
|
| 0.6 |
|
| (0.2) |
|
| 1.1 |
|
| (1.5) |
|
|
| 0.5 |
|
| (0.1) |
|
| 1.0 |
|
| (1.4) |
Other AROs |
|
| 0.1 |
|
| - |
|
| - |
|
| (0.1) |
|
|
| - |
|
| - |
|
| - |
|
| - |
Total AROs |
| $ | 0.9 |
| $ | (0.3) |
| $ | 3.0 |
| $ | (3.6) |
|
| $ | 0.7 |
| $ | (0.2) |
| $ | 2.8 |
| $ | (3.3) |
A reconciliation of the beginning and ending carrying amounts of Regulated companies' ARO liabilities are as follows:
|
| As of December 31, | ||||
|
| 2010 |
| 2009 | ||
(Millions of Dollars) |
| NU |
| NU | ||
Balance as of Beginning of Year |
| $ | (50.6) |
| $ | (50.6) |
Liabilities Incurred During the Year |
|
| (0.2) |
|
| - |
Liabilities Settled During the Year |
|
| 1.2 |
|
| 2.3 |
Accretion |
|
| (3.3) |
|
| (3.3) |
Revisions in Estimated Cash Flows |
|
| (0.4) |
|
| 1.0 |
Balance as of End of Year |
| $ | (53.3) |
| $ | (50.6) |
|
| As of December 31, | ||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Balance as of Beginning of Year |
| $ | (28.6) |
| $ | (16.4) |
| $ | (3.3) |
| $ | (28.7) |
| $ | (15.9) |
| $ | (3.4) |
Liabilities Incurred During the Year |
|
| (0.1) |
|
| - |
|
| (0.1) |
|
| - |
|
| - |
|
| - |
Liabilities Settled During the Year |
|
| 1.2 |
|
| - |
|
| - |
|
| 2.0 |
|
| - |
|
| 0.3 |
Accretion |
|
| (1.8) |
|
| (1.1) |
|
| (0.2) |
|
| (1.9) |
|
| (1.0) |
|
| (0.2) |
Revisions in Estimated Cash Flows |
|
| - |
|
| (0.1) |
|
| - |
|
| - |
|
| 0.5 |
|
| - |
Balance as of End of Year |
| $ | (29.3) |
| $ | (17.6) |
| $ | (3.6) |
| $ | (28.6) |
| $ | (16.4) |
| $ | (3.3) |
7.
GOODWILL AND OTHER INTANGIBLE ASSETS (NU)
In accordance with GAAP, goodwill and intangible assets deemed to have indefinite useful lives are reviewed for impairment at least annually by applying a fair value-based test. NU uses October 1st as the annual goodwill impairment testing date. However, if an event occurs or circumstances change that would indicate that goodwill might be impaired, NU management would test the goodwill between the annual testing dates. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount.
NU's reporting units are consistent with the operating segments underlying the reportable segments identified in Note 21, "Segment Information," to the consolidated financial statements. The only reporting unit that maintains goodwill is the Yankee Gas reporting unit, which is classified under the Regulated companies – natural gas reportable segment and related to the acquisition of Yankee Energy System, Inc., parent of Yankee Gas. Such goodwill is not being recovered from the customers of Yankee Gas. The goodwill balance held by the Yankee Gas reporting unit as of December 31, 2010 and 2009 is $287.6 million.
NU completed its impairment analysis of the Yankee Gas goodwill balance as of October 1, 2010 and determined that no impairment exists. In completing this analysis, the fair value of the reporting unit was estimated using a discounted cash flow methodology and analyses of comparable companies and transactions.
127
8.
SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by CL&P PSNH and WMECO is subject to periodic approval by either the FERC orand short-term borrowings in excess of 10 percent of net plant by their respective state regulators.PSNH are subject to approval by the NHPUC. As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings. On December 12, 2007,22, 2009, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $450 million and $200$300 million, respectively, effective as of December 31, 2007,January 1, 2010 through December 31, 2009. By rule, the FERC has exempted all holding company system money pools from active regulation.2011.
PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant. In an order dated August 3, 2007,December 17 2010, the NHPUC increased the amount of short-term borrowings authorized for PSNH to a maximum of 10 percent of net fixed plant plus $35an additional $60 million throughuntil further ordered by the earlierNHPUC. As of December 31, 2008, or until PSNH utilized its long-term debt authorization. At December 31, 2008, after the expiration of this additional authority,2010, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled $146.6$224.4 million. As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings.
FS-52
CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur.incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. In November 2003, CL&P obtained from its preferred stockholders authorizationa waiver of such 10 percent limit for a ten-year period expiring in March 2014, to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's preferred stock provisions, provided that all unsecured indebtedness does not exceed 20 percent of total capitalization. As of December 31, 2008,2010, CL&P was permitted to incur $584.4had approximately $909.6 million of additional unsecured debt capacity available under this authorization.
Yankee Gas is not required to obtain approval from any state or federal authority to incur short-term debt.
Regulated Companies Credit Agreement:CL&P, PSNH, WMECO and Yankee Gas are parties toCredit Agreement: On September 24, 2010, CL&P, PSNH, WMECO and Yankee Gas jointly entered into a five-yearthree-year unsecured revolving credit facility in the nominal amount of $400 million, which expires on September 24, 2013. This facility replaced a five-year $400 million credit facility that expireswas scheduled to expire on November 6, 2010. CL&P and PSNH may draw up to $200$300 million each under this facility, with PSNH, WMECO and Yankee Gas able to draw up to $100$200 million each, subject to the $400 million maximum aggregate borrowing limit. This total commitment may be increased to $500 million at the request of the borrowers, subject to lender approval. There were $188 million, $45.2 million, $29.9 million and $52.3Under this facility, each company can borrow either on a short-term or a long-term basis subject to regulatory approval. As of December 31, 2010, PSNH had $30 million in short-term borrowings outstanding under this credit faci lity. The weighted average interest rate on such borrowings outstanding under this credit facility as of December 31, 2010 was 2.05 percent. There were no borrowings outstanding by CL&P, PSNH, WMECO and Yankee Gas respectively, outstanding under this facility as of December 31, 2008.2010. There were $45 million of long-termno borrowings by Yankee Gas outstanding under thisthe previous facility atas of December 31, 2007. There were $10 million and $27 million in short-term borrowings by PSNH and Yankee Gas, respectively, outstanding under this facility at December 31, 2007. The weighted-average interest rate on these short-term borrowings on December 31, 2008 and 2007 was 3.35 percent and 7.25 percent, respectively.2009.
NU Parent Credit Agreement: Effective December 31, 2006,On September 24, 2010, NU reduced the total commitments under its 5-yearparent entered into a three-year unsecured revolving credit agreement from $700 million tofacility in the amount of $500 million, which may be increased at NU's requestexpires on September 24, 2013. This facility replaced a five-year $500 million credit facility that was scheduled to $600 million, subject to lender approval. The decrease in the total commitment amount also resulted in a reduction in the letter of credit (LOC) commitment amount from $550 million to $500 million.expire on November 6, 2010. Subject to the amount of advances outstanding, LOCs maycan be issued under this facility for periods up to 364 days in the name of NU parent or any of its subsidiaries including Select Energy.up to the total amount of the facility. This agreement expires on November 6, 2010.
total commitment may be increased to $600 million at the request of NU parent, subject to lender approval. Under this facility, NU parent can borrow either on a short-term or a long-term basis. AtAs of December 31, 2008,2010, NU parent had $303.5 million in short-term borrowings outstanding under this facility. At December 31, 2007, there were $42$237 million in short-term borrowings outstanding under this facility. The weighted-average interest rate on such borrowings outstanding under thesethis credit agreements onfacility as of December 31, 2008 and 20072010 was 3.35 percent and 7.25 percent, respectively.2.85 percent. At December 31, 2009, NU had $100.3 million in short-term borrowings outstanding under the previous facility. The weighted-average interest rate on such borrowings outstanding as of December 31, 2009 was 0.63 percent. There were $87$32.1 million ($85 million for PSNH) and $27 million ($1930.1 million for PSNH) in LOCs outstanding atas of December 31, 2008 and 2007, respectively. 2010. There were $41 million ($39 million for PSNH) in LOCs outstanding under the previous facility as of December 31, 2009.
Under the regulated companies' andthese credit facilities, NU parent credit agreements, NU and the regulated companiesCL&P, PSNH, WMECO and Yankee Gas may borrow at prime rates or variableLIBOR-based rates, plus an applicable margin based upon the higher of Standard and Poor's (S&P)S&P's or Moody's Investors Service (Moody's) credit ratings assigned to the borrower.
A participating lender in both agreements, Lehman Brothers Commercial Bank, has declined to fund on its remaining aggregate $55 million commitment since September 2008. At December 31, 2008, $23.5 million of this commitment remained outstanding from prior borrowings.
In addition, NU parent and the regulated companiesCL&P, PSNH, WMECO and Yankee Gas must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. NU parent and the regulated companies areCL&P, PSNH, WMECO and Yankee Gas were in compliance with these covenants atas of December 31, 2008.2010. If NU parent or the regulated companiesCL&P, PSNH, WMECO or Yankee Gas were not in compliance with these covenants, they wouldnotan event of default would occur requiring all outstanding borrowings by such borrower to be allowed to borrow onrepaid and additional borrowings by such borrower would not be permitted under the revolvingrespective credit agreements.facility.
Amounts outstanding under these credit facilities excluding the $45 million of long-term borrowings by Yankee Gas at December 31, 2007, are classified as current liabilities as notes payableNotes Payable to banksBanks on the accompanying consolidated balance sheets, as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time.
Pool: NU Parent, CL&P, PSNH, WMECO, Yankee Gas and certain of NU’sNU's other companiessubsidiaries are members of the Pool. The Pool provides a morean efficient use of cash resources of NU and reduces outside short-term borrowings. NUSCO is permitted to borrow fromparticipates in the Pool and administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are met with available funds of other member companies, including funds borrowed by NU. NU may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on external loans of NU, however, bear interest at NU's cost and must be repaid based upon the terms of contributions toare payable on demand. In NU's original borrowing. On an NU consolidated level,financial statements, Pool a mountsamounts payable or receivable to or from members eliminateelimi nate in consolidation. AtBy order, the FERC has exempted all holding company system money pools from active regulation. As of December 31, 20082010 and 2007,2009, CL&P, PSNH and WMECO had the following borrowings from/(contributions to) the Pool with the respective weighted averageweighted-average interest rate on borrowings from the Pool for the years ended December 31, 2008 and 2007:
|
| As of and for the Years Ended December 31, | |||||||||||||||||
|
| 2008 |
| 2007 | |||||||||||||||
(Millions of Dollars, except percentage) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||
Borrowings from/(contributions to) |
| $ | 102.7 |
| $ | (53.8) |
| $ | 31.6 |
| $ | 38.8 |
| $ | 11.3 |
| $ | 14.9 |
|
Weighted average interest rate |
|
| 1.57 | % |
| 2.24 | % |
| 2.22 | % |
| 5.04 | % |
| 5.19 | % |
| 5.16 | % |
Pool:
FS-53128
3.
|
| As of and for the Years Ended December 31, | |||||||||||||||||
|
| 2010 |
| 2009 | |||||||||||||||
(Millions of Dollars, except percentages) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||
Borrowings from/(Contributions to) |
| $ | 6.2 |
| $ | 47.9 |
| $ | 20.4 |
| $ | (97.8) |
| $ | 26.7 |
| $ | 136.1 |
|
Weighted-Average Interest Rates |
|
| 0.19 | % |
| 0.18 | % |
| 0.14 | % |
| 0.22 | % |
| 0.15 | % |
| 0.15 | % |
Derivative Instruments (NU,The net borrowings from/(contributions to) the Pool are recorded in Notes Payable to/Notes Receivable from Affiliated Companies, respectively.
9.
LONG-TERM DEBT
Long-term debt maturities and cash sinking fund requirements on debt outstanding as of December 31, 2010, for the years 2011 through 2015 and thereafter, which include fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums or discounts and other fair value adjustments as of December 31, 2010, are as follows:
(Millions of Dollars) |
| NU | |
2011 |
| $ | 66.3 |
2012 |
|
| 267.3 |
2013 |
|
| 305.0 |
2014 |
|
| 275.0 |
2015 |
|
| 150.0 |
Thereafter |
|
| 3,327.9 |
Fees and Interest due for Spent Nuclear Fuel |
|
| 301.0 |
Net Unamortized Premiums and Discounts |
|
| 6.7 |
Total |
| $ | 4,699.2 |
Details of long-term debt outstanding for CL&P, PSNH Yankee Gas, Select Energy)and WMECO are as follows:
CL&P |
| As of December 31, | ||||
(Millions of Dollars) |
| 2010 |
| 2009 | ||
First Mortgage Bonds: |
|
|
|
|
|
|
7.875% 1994 Series D due 2024 |
| $ | 139.8 |
| $ | 139.8 |
4.800% 2004 Series A due 2014 |
|
| 150.0 |
|
| 150.0 |
5.750% 2004 Series B due 2034 |
|
| 130.0 |
|
| 130.0 |
5.000% 2005 Series A due 2015 |
|
| 100.0 |
|
| 100.0 |
5.625% 2005 Series B due 2035 |
|
| 100.0 |
|
| 100.0 |
6.350% 2006 Series A due 2036 |
|
| 250.0 |
|
| 250.0 |
5.375% 2007 Series A due 2017 |
|
| 150.0 |
|
| 150.0 |
5.750% 2007 Series B due 2037 |
|
| 150.0 |
|
| 150.0 |
5.750% 2007 Series C due 2017 |
|
| 100.0 |
|
| 100.0 |
6.375% 2007 Series D due 2037 |
|
| 100.0 |
|
| 100.0 |
5.650% 2008 Series A due 2018 |
|
| 300.0 |
|
| 300.0 |
5.500% 2009 Series A due 2019 |
|
| 250.0 |
|
| 250.0 |
Total First Mortgage Bonds |
|
| 1,919.8 |
|
| 1,919.8 |
Pollution Control Notes: |
|
|
|
|
|
|
5.85%-5.90%, Fixed Rate, due 2016-2022 |
|
| 46.4 |
|
| 46.4 |
5.85%-5.95%, Fixed Rate Tax Exempt, due 2028 |
|
| 315.5 |
|
| 315.5 |
One-Year Fixed Rate Tax Exempt, due 2031 (1) |
|
| 62.0 |
|
| 62.0 |
Total Pollution Control Notes |
|
| 423.9 |
|
| 423.9 |
Total First Mortgage Bonds and Pollution Control Notes |
|
| 2,343.7 |
|
| 2,343.7 |
Fees and Interest due for Spent Nuclear Fuel Disposal Costs |
|
| 243.8 |
|
| 243.5 |
Less Amounts due Within One Year (1) |
|
| (62.0) |
|
| (62.0) |
Unamortized Premiums and Discounts, Net |
|
| (4.4) |
|
| (4.8) |
Long-Term Debt |
| $ | 2,521.1 |
| $ | 2,520.4 |
(1)
On April 1, 2010, CL&P remarketed $62 million of tax-exempt PCRBs for a one-year period. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.4 percent during the current one-year fixed-rate period and are subject to a mandatory tender for purchase on April 1, 2011, at which time CL&P expects to remarket the bonds.
129
Contracts
PSNH |
| As of December 31, | ||||
(Millions of Dollars) |
| 2010 |
| 2009 | ||
First Mortgage Bonds: |
|
|
|
|
|
|
5.25% 2004 Series L, due 2014 |
| $ | 50.0 |
| $ | 50.0 |
5.60% 2005 Series M, due 2035 |
|
| 50.0 |
|
| 50.0 |
6.15% 2007 Series N, due 2017 |
|
| 70.0 |
|
| 70.0 |
6.00% 2008 Series O, due 2018 |
|
| 110.0 |
|
| 110.0 |
4.50% 2009 Series P, due 2019 |
|
| 150.0 |
|
| 150.0 |
Total First Mortgage Bonds |
|
| 430.0 |
|
| 430.0 |
Pollution Control Revenue Bonds: |
|
|
|
|
|
|
6.00% Tax-Exempt, Series D, due 2021 |
|
| 75.0 |
|
| 75.0 |
6.00% Tax-Exempt, Series E, due 2021 |
|
| 44.8 |
|
| 44.8 |
Adjustable Rate, Series A, due 2021 |
|
| 89.3 |
|
| 89.3 |
4.75% Tax-Exempt, Series B, due 2021 |
|
| 89.3 |
|
| 89.3 |
5.45% Tax-Exempt, Series C, due 2021 |
|
| 108.9 |
|
| 108.9 |
Total Pollution Control Revenue Bonds |
|
| 407.3 |
|
| 407.3 |
Unamortized Premiums and Discounts, Net |
|
| (0.9) |
|
| (1.0) |
Long-Term Debt |
| $ | 836.4 |
| $ | 836.3 |
WMECO |
| As of December 31, | ||||
(Millions of Dollars) |
| 2010 |
| 2009 | ||
Pollution Control Notes: |
|
|
|
|
|
|
Tax Exempt 1993 Series A, 5.85% due 2028 |
| $ | 53.8 |
| $ | 53.8 |
Other Notes: |
|
|
|
|
|
|
Senior Notes Series A, 5.00% due 2013 |
|
| 55.0 |
|
| 55.0 |
Senior Notes Series B, 5.90% due 2034 |
|
| 50.0 |
|
| 50.0 |
Senior Notes Series C, 5.24% due 2015 |
|
| 50.0 |
|
| 50.0 |
Senior Notes Series D, 6.70% due 2037 |
|
| 40.0 |
|
| 40.0 |
Senior Notes Series E, 5.10% due 2020 |
|
| 95.0 |
|
| - |
Total Pollution Control Notes and Other Notes |
|
| 343.8 |
|
| 248.8 |
Fees and Interest due for Spent Nuclear Fuel Disposal Costs |
|
| 57.2 |
|
| 57.1 |
Total Pollution Control Notes, Other Notes, and Fees and |
|
| 401.0 |
|
| 305.9 |
Unamortized Premiums and Discounts, Net |
|
| (0.7) |
|
| (0.4) |
Long-Term Debt |
| $ | 400.3 |
| $ | 305.5 |
Included in the NU amounts are $263 million of NU Parent Series A Senior Notes maturing in 2012 with a coupon rate of 7.25 percent and $250 million of NU Parent Series C Senior Notes maturing in 2013 with a coupon rate of 5.65 percent.
There are no cash sinking fund requirements or debt maturities for the years 2011 through 2013 for CL&P and PSNH; however, CL&P has $62 million of PCRBs that carry a coupon rate of 1.4 percent during the current one-year fixed-rate period and are derivativessubject to mandatory tender for purchase on April 1, 2011. There is a $263 million maturity in 2012 related to the NU parent Series A Senior notes. There are $55 million and do not$250 million of maturities in 2013 related to the WMECO Series A Senior Notes and the NU parent Series C Senior Notes, respectively. There are $150 million and $50 million of maturities in 2014 related to the CL&P 2004 Series A first mortgage bonds and the PSNH 2004 Series L first mortgage bonds, respectively. There are $100 million and $50 million of maturities in 2015 related to CL&P 2005 Series A first mortgage bonds and WMECO Series C Senior Notes, respectively. CL& amp;P, PSNH and WMECO have $2.032 billion, $787.3 million and $238.8 million, respectively, of long-term debt maturities in the period from 2016 through 2037.
There are annual renewal and replacement fund requirements equal to 2.25 percent of the average of net depreciable utility property owned by PSNH in 1992, plus cumulative gross property additions thereafter. PSNH expects to meet thethese future fund requirements by certifying property additions. Any deficiency would need to be treated as asatisfied by the deposit of cash flow hedge or normal purchase or normal sale are recorded at fair value with changes in fair value included in earnings. For those contracts that meetbonds.
Essentially all utility plant of CL&P, PSNH and Yankee Gas is subject to the definitionlien of a derivative and meet the cash flow hedge requirements, including those related to initial and ongoing documentation, the contract is recorded at fair value and the changes in the fair value of the effective portion of those contracts are recognized in accumulated other comprehensive income. Cash flow hedges include forward interest rate swap agreements on proposed debt issuances. When a cash flow hedge is settled, the settlement amount is recorded in accumulated other comprehensive income and is amortized into earnings over the term of the debt. Cash flow hedges impact net income when the hedged items affect earnings, when hedge ineffectiveness is measured an d recorded, or when the forecasted transaction being hedged is improbable of occurring. Derivative contracts designated as fair value hedges and the items they are hedging are both recorded at fair value with changes in fair value of both items recognized in earnings. Derivative contracts that meet the requirements of a normal purchase or sale, and are so designated, are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered. each company's respective first mortgage bond indenture.
The fair valueCL&P, PSNH and WMECO tax-exempt bonds contain call provisions providing call prices ranging between 100 percent and 102 percent of par. All other securities are subject to make-whole provisions.
As of December 31, 2010, CL&P had $423.9 million of tax-exempt PCRBs, $315.5 million of which is secured by second mortgage liens on transmission assets, junior to the liens of its first mortgage bond indenture. CL&P has $62 million of tax-exempt PCRBs secured by first mortgage bonds.
As of December 31, 2010, PSNH had $407.3 million in outstanding PCRBs. PSNH's obligation to repay each series of PCRBs is secured by first mortgage bonds and three series, the 2001 Series A, B and C, also carry bond insurance. Each such series of first
130
mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs. The 2001 Series A PCRBs, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. Since March 2008, a significant majority of this series of PCRBs has been held by the remarketing agent as a result of failed auctions due to general market concerns. The interest rate on this series of PCRBs has been reset by formula under the applicable documents every 35 days. The formula is based on a combination of the company's derivative contracts may not represent amounts that will be realized. For further informationratings on the fair valuePCRBs and an index rate. The interest rate has been between 0.16 percent and 4.03 percent since March 2008 and was 0.36 percent as of derivative contracts,December 31, 2010. The Company is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent. The weighted average effective interest rate on PSNH's Series A variable-rate PCRBs was 0.34 percent in 2010 and 0.25 percent for 2009.
NU's, including CL&P, PSNH and WMECO, long-term debt agreements provide that NU and certain of its subsidiaries must comply with certain financial and non-financial covenants as are customarily included in such agreements, including a consolidated debt to total capitalization ratio. NU and these subsidiaries are in compliance with these covenants as of December 31, 2010.
Yankee Gas has certain long-term debt agreements that contain cross-default provisions. These cross-default provisions apply to all of Yankee Gas’ outstanding first mortgage bond series. The cross-default provisions on Yankee Gas’ Series B Bonds would be triggered if Yankee Gas were to default in a payment due on indebtedness in excess of $2 million. The cross-default provisions on all other series of Yankee Gas’ first mortgage bonds would be triggered if Yankee Gas were to default in a payment due on indebtedness in excess of $10 million. PSNH would also be in default under its first mortgage indentures if it defaulted on any prior lien obligation exceeding $25 million. PSNH had no prior lien obligations as of December 31, 2010. There are no other debt issuances for CL&P, WMECO or NU parent with cross-default provisions as of December 31, 2010.
The accompanying consolidated statements of capitalization as of December 31, 2010 reflect the issuance in 2010 of bonds in the amount of $50 million at Yankee Gas, which are included in Long-Term Debt - First Mortgage Bonds and the issuance in 2010 of senior unsecured notes in the amount of $95 million at WMECO, which are included in Other Long-Term Debt.
For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 1F, "Summary of Significant Accounting Policies12B, "Commitments and Contingencies - Fair Value Measurements," and Note 4, "Fair Value Measurements,Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements. On the accompanying consolidated balance sheets at December 31, 2008 and 2007, these amounts are recorded as current or long-term derivative assets or liabilities and are summarized as follows:
|
| At December 31, 2008 | |||||||||||||
|
| Assets |
| Liabilities |
|
| |||||||||
(Millions of Dollars) |
| Current |
| Long-Term |
| Current |
| Long-Term |
| Net Total | |||||
NU Enterprises: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale |
| $ | - |
| $ | - |
| $ | (14.5) |
| $ | (49.4) |
| $ | (63.9) |
Regulated Companies - Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply |
|
| - |
|
| 1.9 |
|
| (0.2) |
|
| - |
|
| 1.7 |
Regulated Companies - Electric: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply/Stranded Costs |
|
| 31.4 |
|
| 219.1 |
|
| (86.2) |
|
| (863.0) |
|
| (698.7) |
NU Parent: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Hedging |
|
| - |
|
| 20.8 |
|
| - |
|
| - |
|
| 20.8 |
Totals |
| $ | 31.4 |
| $ | 241.8 |
| $ | (100.9) |
| $ | (912.4) |
| $ | (740.1) |
|
| At December 31, 2007 | |||||||||||||
|
| Assets |
| Liabilities |
|
| |||||||||
(Millions of Dollars) |
| Current |
| Long-Term |
| Current |
| Long-Term |
| Net Total | |||||
NU Enterprises: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale |
| $ | 36.2 |
| $ | 7.2 |
| $ | (64.9) |
| $ | (72.5) |
| $ | (94.0) |
Regulated Companies - Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply |
|
| 0.2 |
|
| - |
|
| - |
|
| - |
|
| 0.2 |
Interest Rate Hedging |
|
| 0.9 |
|
| - |
|
| - |
|
| - |
|
| 0.9 |
Regulated Companies - Electric: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply/Stranded Costs |
|
| 59.8 |
|
| 290.8 |
|
| (6.7) |
|
| (136.0) |
|
| 207.9 |
Interest Rate Hedging |
|
| 3.3 |
|
| - |
|
| - |
|
| - |
|
| 3.3 |
NU Parent: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Hedging |
|
| 5.1 |
|
| - |
|
| - |
|
| - |
|
| 5.1 |
Totals |
| $ | 105.5 |
| $ | 298.0 |
| $ | (71.6) |
| $ | (208.5) |
| $ | 123.4 |
For the regulated companies, except for interest rate swap agreements, offsetting regulatory assets or liabilities are recorded for the changesThe change in fair value of their contracts,totaling a positive $11.8 million and $13.3 million as these contracts were part of the stranded costs or are current regulated operating costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.
The business activities of NU Enterprises that result in the recognition of derivative assets also create exposures to credit risk of energy marketing and trading counterparties. At December 31, 2008, Select Energy had no derivative assets from wholesale activities that are exposed to counterparty credit risk. The business activities of the regulated companies that resulted in the recognition of derivative assets also create exposure to various counterparties. At December 31, 2008, NU consolidated had $273.2 million ($245.8 million for CL&P2010 and $4.7 million for PSNH) of regulated company and NU parent derivative assets exposed to counterparty credit risk that are contracted with multiple entities, of which $125.5 million ($104.7 million for CL&P) is contracted with investment grade entities, $4.6 million related to PSNH is contracted with a government-backed entity, $131.4 million related to CL&P is contra cted with a non-rated subsidiary of an investment grade company and the remainder are contracted with multiple other counterparties.
NU Enterprises - Wholesale: Certain electric derivative contracts are part of NU Enterprises' remaining wholesale marketing business. These contracts include short-term and long-term electric supply contracts and a contract to sell electricity to the New York Municipal Power Agency (NYMPA) (an agency that is comprised of municipalities) that expires in 2013. A portion of the contract's fair value is determined based upon a model. The model utilizes natural gas prices and a heat rate conversion factor to determine off-peak electricity prices for one New York routinely quoted hub zone for 2013. For the balance of the hub zones, broker quotes for electricity are generally available on-peak through 2013 and off-peak through 2012.
FS-54
The decision to exit the wholesale marketing business changed management's conclusion regarding the likelihood that these wholesale marketing contracts would result in physical delivery to customers and resulted in a change in the first quarter of 2005 from accrual accounting to mark-to-market accounting for the wholesale marketing contracts. For the years ended December 31, 2008, 2007 and 2006, NU recorded a pre-tax benefit of $7 million and pre-tax charges of $7.4 million and $11.7 million,2009, respectively, in fuel, purchased and net interchange power related to these contracts. In addition, NU recorded a benefit of $1 million to fuel, purchased and net interchange power related to wholesale marketing contracts for the year ended December 31, 2007.
Regulated Companies - Gas - Supply: Yankee Gas' supply derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery. These contracts are subject to fair value accounting as these contracts are derivatives that cannot be designated as normal purchases and sales because of the optionality in the contract terms. An offsetting regulatory liability/asset was recorded for these amounts as management believes that these costs will be refunded or recovered in rates.
Regulated Companies - Gas - Interest Rate Hedging: Yankee Gas had a forward interest rate swap agreement to hedge the interest cash outflows associated with its $100 million debt issuance in October 2008. The interest rate swap was based on a 10-year LIBOR swap rate and matched the index used for the debt issuance. As a cash flow hedge, the fair value of the hedge was recorded as a derivative asset on the accompanying consolidated balance sheets asstatements of December 31, 2007, with an offsetting amount, net of tax, included in accumulated other comprehensive income.The swap was terminated in September 2008.
Regulated Companies - Electric - Supply/Stranded Costs: CL&P has contracts with two IPPs to purchase power that contain pricing provisions that are not clearly and closely related tocapitalization reflects the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these derivatives at December 31, 2008 included short-term and long-term derivative assets with fair values of $20.8 million and $110.6 million, respectively, and short-term and long-term derivative liabilities with fair values of $6.5 million and $65.6 million, respectively. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates. At December 31, 2007, the fair values of these derivatives included short-term and long-t erm derivative assets with fair values of $53.3 million and $257.9 million, respectively, and short-term and long-term derivative liabilities with fair values of $2.9 million and $28.9 million, respectively.
CL&P has entered into FTR contracts and bilateral basis swaps to limit the congestion costs associated with its standard offer contracts. At December 31, 2008, the fair value of these contracts were recorded as a short-term derivative asset of $9.7 million, with an offset of $9.5 million recorded as a payable and included in other current liabilities and $0.2 million related to the mark-to-market adjustment recorded as a regulatory liability on the accompanying consolidated balance sheets. In addition, the fair value of the bilateral agreements has been recorded as a short-term derivative liability of $2.3 million with a $2.1 million offset to regulatory assets, net of the $0.2 million regulatory liability described above. Management believes that these costs will continue to be recovered or refunded in cost of service rates. At December 31, 2007, the fair value of these contracts was recorded as a shor t-term derivative asset of $1.4 million and a short-term derivative liability of $1.3 million on the accompanying consolidated balance sheets.
Pursuant to Public Act 05-01, "An Act Concerning Energy Independence," in August 2007, the DPUC approved two CL&P contracts associated with the capacity of two generating projects to be built or modified. The DPUC also approved two capacity-related contracts entered into by The United Illuminating Company (UI), one with a generating project to be built and one with a new demand response project. The total capacity of these four projects is expected to be approximately 787 megawatts (MW). The contracts, referred to as CfDs, obligate the utilities' customers to pay the difference between a set capacity price and the forward capacity market price that the projects receiveNU parent 7.25 percent amortizing note, due 2012 in the ISO-NE capacity markets for periodsamount of up to 15 years beginning in 2009. As directed by the DPUC, CL&P has an agreement$263 million, that is hedged with UI under which it will share the costs and benefits of these four CfDs, with 80 percent allocated to CL&P and 20 percent to UI. The ultimate cost to CL&P under the contracts will depend on the capacity prices that the projects receive in the ISO-NE capacity markets. At December 31, 2008, the fair value of the CL&P CfDs was recorded as a long-term derivative liability of $782.5 million. The fair values of UI's share of CL&P's contracts and CL&P's share of UI's contracts were recorded as a long-term derivative asset of $104.7 million. An offsetting regulatory asset of $677.8 million was recorded, as management believes these amounts will be recovered from or refunded to customers in cost-of-service, regulated rates. The value of CL&P's CfDs at December 31, 2008 included approximately $100 million of initial gains and losses, previously deferred due to the use of significant unobservable inputs in the valuation, that were recorded upon adoption of SFAS No. 157 on January 1, 2008. At December 31, 2007, changes in CfD fair values since inceptio n were recorded as a long-term derivative liability of $107.1 million, and UI's share and one CL&P CfD were recorded as long-term derivative assets of $20.8 million. Offsetting regulatory assets of $86.7 million and regulatory liabilities of $0.4 million were also recorded at December 31, 2007. A 2007 NRG Energy, Inc. (NRG) appeal of the DPUC's decision selecting the CfDs was taken into consideration in valuing the CfDs as of December 31, 2007, reducing the net negative derivative values by approximately $215 million. In February 2008, the appeal was denied, which increased derivative liabilities in 2008.
PSNH has electricity procurement contracts that are derivatives. The fair values of these contracts are calculated based on market prices and were recorded as short-term and long-term derivative liabilities totaling $76.8 million and $14.9 million, respectively, at December 31, 2008. At December 31, 2007, the fair value was recorded as a short-term derivative asset of $1.5 million and a short-term derivative liability of $2.5 million. An offsetting regulatory asset/liability was recorded as management believes that these costs will be recovered/refunded in rates as the energy is delivered.
PSNH has a contract to assign its transmission rights in a direct current transmission line in exchange for two energy call options that expire in 2010. These energy call options are derivatives that do not qualify for the normal purchases and sales exception and are accounted for at fair value based on option value modeling. At December 31, 2008, the options were recorded as a short-term and long-term derivative asset of $0.8 million and $3.8 million, respectively, which include mark-to-market losses of $11.1 million in 2008. The initial gain of $13.5 million on this transaction was recorded as a derivative asset and regulatory liability. Short-term and long-term
FS-55
derivative assets at December 31, 2007 were $3.6 million and $12.1 million, respectively, which include $2.2 million in mark-to-market gains in 2007. An offsetting regulatory liability was recorded, as management believes the benefit of this arrangement will be refunded to customers in rates.
PSNH has entered into FTR contracts to limit the congestion costs associated with its delivery service. At December 31, 2008, the FTRs were recorded as a short-term derivative asset of $0.1 million and a short-term derivative liability of $0.6 million. Offsetting these amounts are a payable and receivable to the ISO-NE of $0.1 million and $0.2 million, respectively, related to the initial auction price of the FTRs and a regulatory asset of $0.4 million related to the mark-to-market of the FTR. Management believes that these costs will continue to be recovered or refunded in cost-of-service rates. There were no similar amounts for 2007.
Regulated Companies - Electric - Interest Rate Hedging: At December 31, 2007, CL&P had two forward interest rate swap agreements to hedge the interest cash outflows associated with its debt issuance of $300 million in May 2008. PSNH had a forward interest rate swap agreement to hedge the interest cash outflows associated with its debt issuance of $110 million in May 2008. Prior to termination in May 2008, the interest rate swaps were based on a 10-year LIBOR swap rate and matched the index used for the debt issuances. As cash flow hedges, the fair values of these hedges were recorded as derivative assets at December 31, 2007 on the accompanying consolidated balance sheet with an offsetting amount, net of tax, included in accumulated other comprehensive income.
NU Parent - Interest Rate Hedging: In March 2003, to manage the interest rate characteristics of the company's long-term debt, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate senior notes that mature on April 1, 2012. Under fair value hedge accounting, the changesswap. The change in fair value of the swap and the interest component of the hedged long-term debt instrument arewas recorded in interest expense, which generally offset each other inas an adjustment to Long-Term Debt with an equal and offsetting adjustment to Derivative Assets for the consolidated statements of income. The cumulative change in the fair value of the swap and the long-term debt was recorded as a derivative asset and an increasefixed to long-term debt of $20.8 million and $4.2 million at December 31, 2008 and 2007, respectively. floating interest rate swap.
NU parent had a forward interest rate swap agreement to hedge the interest cash outflows associated with its planned debt issuance in June 2008. Prior to termination in June 2008, the interest rate swap was based on a 5-year LIBOR swap rate and a notional amount of $200 million, and matched the index used for the debt issuance. As a cash flow hedge at December 31, 2007, the fair value of the hedge was recorded as a $0.9 million derivative asset on the accompanying consolidated balance sheet with an offsetting amount, net of tax, included in accumulated other comprehensive income.10.
4.
Fair Value Measurements (All Companies)
Items Measured at Fair Value on a Recurring Basis: The company's assets and liabilities recorded at fair value on a recurring basis have been categorized based upon the fair value hierarchy in accordance with SFAS No. 157. See Note 1F, "Summary of Significant Accounting Policies - Fair Value Measurements," for further information regarding the hierarchy and fair value measurements.
The following table presents the amounts of assets and liabilities carried at fair value at December 31, 2008 by the level in which they are classified within the SFAS No. 157 valuation hierarchy:
|
| NU |
| CL&P |
| PSNH |
| WMECO |
| NU |
| Yankee Gas |
| NU Parent | |||||||
Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Level 1 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Level 2 |
|
| 20.8 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 20.8 |
Level 3 |
|
| 252.4 |
|
| 245.8 |
|
| 4.7 |
|
| - |
|
| - |
|
| 1.9 |
|
| - |
Total |
| $ | 273.2 |
| $ | 245.8 |
| $ | 4.7 |
| $ | - |
| $ | - |
| $ | 1.9 |
| $ | 20.8 |
Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Level 2 |
|
| (91.7) |
|
| - |
|
| (91.7) |
|
| - |
|
| - |
|
| - |
|
| - |
Level 3 |
|
| (921.6) |
|
| (856.9) |
|
| (0.6) |
|
| - |
|
| (63.9) |
|
| (0.2) |
|
| - |
Total |
| $ | (1,013.3) |
| $ | (856.9) |
| $ | (92.3) |
| $ | - |
| $ | (63.9) |
| $ | (0.2) |
| $ | - |
Marketable Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
| $ | 42.1 |
| $ | - |
| $ | - |
| $ | 10.3 |
| $ | - |
| $ | - |
| $ | 31.8 |
Level 2 |
|
| 67.1 |
|
| - |
|
| - |
|
| 45.4 |
|
| - |
|
| - |
|
| 21.7 |
Level 3 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Total |
| $ | 109.2 |
| $ | - |
| $ | - |
| $ | 55.7 |
| $ | - |
| $ | - |
| $ | 53.5 |
Not included in the table above are $81.6 million of cash equivalents held by NU parent in an unrestricted money market account and included in cash and cash equivalents on the accompanying consolidated balance sheet of NU consolidated, which are classified as Level 1 in the fair value hierarchy.
The following table presents changes for the year ended December 31, 2008 in the Level 3 category of assets and liabilities measured at fair value on a recurring basis. This category includes derivative assets and liabilities, which are presented net. The derivative amounts at January 1, 2008 reflect the fair values after initial adoption of SFAS No. 157. The company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model. In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly. Thus, the gains and losses presented below include changes in fair value that are
FS-56
attributable to both observable and unobservable inputs. There were no transfers into or out of Level 3 assets and liabilities for the year ended December 31, 2008:
|
| For the Year Ended December 31, 2008 | |||||||||||||
|
| NU |
| CL&P |
| PSNH |
| NU |
| Yankee | |||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
| |||||
Fair value at January 1, 2008(1) |
| $ | (511.1) |
| $ | (426.9) |
| $ | 15.7 |
| $ | (100.1) |
| $ | 0.2 |
Net realized/unrealized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings(2) |
|
| 12.0 |
|
| - |
|
| - |
|
| 12.0 |
|
| - |
Regulatory assets/liabilities |
|
| (138.0) |
|
| (128.0) |
|
| (11.5) |
|
| - |
|
| 1.5 |
Purchases, issuances and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at December 31, 2008 |
| $ | (669.2) |
| $ | (611.1) |
| $ | 4.1 |
| $ | (63.9) |
| $ | 1.7 |
Period change in unrealized gains |
|
| 7.0 |
|
| - |
|
| - |
|
| 7.0 |
|
| - |
(1)
Amounts as of January 1, 2008 reflect fair values after initial adoption of SFAS No. 157. As a result of implementing SFAS No. 157, the company recorded an increase to derivative liabilities and a pre-tax charge to earnings of $6.1 million as of January 1, 2008 related to NU Enterprises' remaining derivative contracts. The company also recorded changes in fair value of CL&P's CfD and IPP contracts, resulting in increases to CL&P's derivative liabilities of approximately $590 million, with an offset to regulatory assets and a decrease to CL&P's derivative assets of approximately $30 million with an offset to regulatory liabilities.
(2)
Realized and unrealized gains and losses on derivatives included in earnings relate to the remaining Select Energy wholesale marketing contracts and are reported in fuel, purchased and net interchange power on the accompanying consolidated statements of income.
5.
Employee Benefits (All Companies)EMPLOYEE BENEFITS
A.
Pension Benefits and Postretirement BenefitsOther Than Pensions
On December 31, 2006,Pursuant to GAAP, NU implemented SFAS No. 158, which applies to NU’s Pension Plan, SERP, and PBOP Plan andis required NU to record the funded status of theseits pension and PBOP plans on the accompanying consolidated balance sheets, based on the difference between the projected benefit obligation (PBO) for the Pension Plan and accumulated postretirement benefit obligation (APBO) for the PBOP Plan and the fair value of plan assets. At December 31, 2008, the fair values of plan assets are measured in accordance with SFAS No. 157. SFAS No. 158 requires the additional liability to befair value measurement accounting guidance. The funded status is recorded with an offset to accumulated other comprehensive income in shareholders’ equity.Accumulated Other Comprehensive Income/(Loss) on the accompanying consolidated balance sheets. This amount is remeasured annually, or as circumstances dictate.
AtAs of December 31, 20082010 and 2007,2009, NU recorded an after-tax charge/(benefit)charge totaling $38$0.5 million and $(8.6)$5.4 million, respectively, to accumulated other comprehensive incomeAccumulated Other Comprehensive Income/(Loss) for its unregulated subsidiaries. However, becauseCharges for the regulatedRegulated companies are cost-of-service, rate regulated entities under SFAS No. 71, regulatory assets were recorded in the amount of $1.1 billion ($537.7 million - CL&P; $142.9 million - PSNH; $113.5 million - WMECO),as Regulatory Assets and $201.4 million ($72.2 million - CL&P; $50.4 million - PSNH; $8.2 million - WMECO), respectively,included as deferred benefit costs as these benefits expense amounts have been and continue to be recoverable in cost-of-service, regulated rates. For further information see Note 2, "Regulatory Accounting," to the consolidated financial statements. Regulatory accounting was also applied to the portions of the NUSCO costs that support the regulatedRegulated companies, as these amounts are also recoverable.recoverable through rates charged to customers.
Pension Benefits: NUNUSCO sponsors a single uniform noncontributory defined benefit retirement plan (Pension Plan) under ERISA covering substantially all regularPension Plan, which is subject to the provisions of ERISA. The Pension Plan covers nonbargaining unit employees (and bargaining unit employees, as negotiated) of NU, including CL&P, PSNH, and its subsidiaries.WMECO, hired before 2006 (or as negotiated, for bargaining unit employees). Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. NU allocates net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked by the trustee for each subsidiary. The actual investment return for the trust each year is allocated to each of the subsidiaries in proportion to the investment return expected to be earned during the year. NU uses a December 31st measurement date for the Pension Plan. Pension expense/(income) affecting earningsNet Income is as follows:
NU Consolidated |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Total pension expense |
| $ | 2.4 |
| $ | 17.1 |
| $ | 50.2 |
Income/(expense) capitalized as utility plant |
|
| 4.9 |
|
| 1.0 |
|
| (11.5) |
Total pension expense, net of amounts capitalized |
| $ | 7.3 |
| $ | 18.1 |
| $ | 38.7 |
CL&P |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Total pension (income)/expense |
| $ | (21.3) |
| $ | (15.6) |
| $ | 0.3 |
Income capitalized as utility plant |
|
| 9.4 |
|
| 7.3 |
|
| 0.1 |
Total pension (income)/expense, net of amounts capitalized |
| $ | (11.9) |
| $ | (8.3) |
| $ | 0.4 |
FS-57131
PSNH |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Total pension expense |
| $ | 18.1 |
| $ | 19.5 |
| $ | 20.8 |
Expense capitalized as utility plant |
|
| (4.2) |
|
| (4.8) |
|
| (4.8) |
Total pension expense, net of amounts capitalized |
| $ | 13.9 |
| $ | 14.7 |
| $ | 16.0 |
(Millions of Dollars) |
| For the Years Ended December 31, | |||||||
NU |
| 2010 |
| 2009 |
| 2008 | |||
Total Pension Expense |
| $ | 80.4 |
| $ | 39.7 |
| $ | 2.4 |
(Expense)/Income Capitalized as Utility Plant |
|
| (16.9) |
|
| (6.2) |
|
| 4.9 |
Total Pension Expense, Net of Amounts Capitalized |
| $ | 63.5 |
| $ | 33.5 |
| $ | 7.3 |
WMECO |
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Total pension income |
| $ | (6.1) |
| $ | (5.0) |
| $ | (1.3) |
Income capitalized as utility plant |
|
| 2.1 |
|
| 1.9 |
|
| 0.5 |
Total pension income, net of amounts capitalized |
| $ | (4.0) |
| $ | (3.1) |
| $ | (0.8) |
Pension Curtailments and Termination Benefits: In December 2005, a new program was approved allowing then current employees to elect to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan. The approval of the new plan resulted in recording an estimated pre-capitalization, pre-tax curtailment expense in 2005, as a certain number of employees were expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Because the predicted level of elections of the new benefit did not occur, NU recorded a pre-capitalization, pre-tax reduction in the curtailment expense of $3.6 million in 2006.
As a result of its corporate reorganization in 2005, NU recorded a combined pre-capitalization, pre-tax curtailment expense and related termination benefits for the Pension Plan. Based on a revised estimate of expected head count reductions in 2006, NU recorded an adjustment to the curtailment and related termination benefits. This adjustment resulted in a pre-capitalization, pre-tax reduction in the curtailment expense of $1.2 million and an increase in termination benefits expense of $2.3 million totaling a net $1.1 million in additional pension expense. NU recorded an additional pre-capitalization, pre-tax reduction in termination benefit expense of $0.3 million in 2007.
Pension Plan COLA: On May 4, 2007, NU's Board of Trustees approved a cost of living adjustment (COLA) that increased retiree pension benefits for certain participants in the Pension Plan. The COLA was announced on May 8, 2007 at the annual meeting of NU's shareholders, which resulted in a plan amendment in 2007 and a remeasurement of the Pension Plan's benefit obligation as of May 8, 2007. The COLA increased the Pension Plan's benefit obligation by $40 million and was reflected as a prior service cost and as a decrease in the funded status of the Pension Plan. This amount will be amortized over a 12-year period representing average remaining service lives of employees.
CL&P |
|
|
|
|
|
| |||
Total Pension Expense/(Income) |
| $ | 8.5 |
| $ | (5.7) |
| $ | (21.3) |
(Expense)/Income Capitalized as Utility Plant |
|
| (3.8) |
|
| 2.6 |
|
| 9.4 |
Total Pension Expense/(Income), Net of Amounts Capitalized |
| $ | 4.7 |
| $ | (3.1) |
| $ | (11.9) |
|
|
|
|
|
|
|
|
|
|
PSNH |
|
| |||||||
Total Pension Expense |
| $ | 28.1 |
| $ | 23.3 |
| $ | 18.1 |
Expense Capitalized as Utility Plant |
|
| (6.9) |
|
| (6.0) |
|
| (4.2) |
Total Pension Expense, Net of Amounts Capitalized |
| $ | 21.2 |
| $ | 17.3 |
| $ | 13.9 |
|
|
|
|
|
|
|
|
|
|
WMECO |
|
|
|
|
|
|
|
|
|
Total Pension Income |
| $ | (0.1) |
| $ | (2.9) |
| $ | (6.1) |
Income Capitalized as Utility Plant |
|
| - |
|
| 1.2 |
|
| 2.1 |
Total Pension Income, Net of Amounts Capitalized |
| $ | (0.1) |
| $ | (1.7) |
| $ | (4.0) |
Actuarial Determination of Expense: Pension and PBOP expense consists of the service cost and prior service cost determined by actuaries, the interest cost based on the discounting of the obligations and the amortization of the net transition obligation, offset by the expected return on plan assets. Pension and PBOP expense also includes amortization of actuarial gains and losses, which represent differences between assumptions and actual or updated information.
The expected return on plan assets is calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. This calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return based on the change in the fair value of assets during the year. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized gains/losses. Unrecognized gains/losses are amortized as a component of pension and PBOP expense over approximately 1210 and 9 years, respectively, which is the average future service period of the employees at December 31, 2008.employees.
SERP: NU has maintained a SERP since 1987. The SERP provides its eligible participants, who are officers of NU, with benefits that would have been provided to them under NU's retirement planthe Pension Plan if certain Internal Revenue Code and other limitations were not imposed. NU allocates net periodic SERP benefit costs to its subsidiaries based upon actuarial calculations by participant.
Although the companyCompany maintains a trust to support the SERP with marketable securities held in the NU supplemental benefit trust, the plan itself does not contain any assets. For information regarding the investments in the NU supplemental benefit trust that are used to support the SERP liability, see Note 95, "Marketable Securities," to the consolidated financial statements.
PBOP Plan: NU providesOn behalf of NU's retirees, NUSCO also sponsors plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits through a PBOP Plan. These benefits are available for employees retiring from NU who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. NU uses a December 31st measurement date for the PBOP Plan.
NU annually funds postretirement costs through external trusts with amounts that have been and will continue to be recovered in rates and that are tax deductible.
NU allocates net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return for the trust each year is allocated to each of the subsidiaries in proportion to the investment return expected to be earned during the year.
FS-58132
PBOP Curtailments and Termination Benefits: NU recorded an estimated pre-tax curtailment expense in 2005 relating to its corporate reorganization. NU also accrued a pre-tax termination benefit in 2005 relating to certain benefits provided under the terms of the PBOP Plan. Based on refinements to its estimates, NU recorded an adjustment to the curtailment and related termination benefits in 2006. This adjustment resulted in a pre-capitalization, pre-tax reduction in the curtailment expense of $2.2 million and an increase to termination benefits of $0.3 million in 2006.
The following table represents information on NU's plansplan benefit obligations, fair values of plan assets, and funded status:
|
| At December 31, | ||||||||||||||||
|
| Pension Benefits |
| SERP Benefits |
| Postretirement Benefits | ||||||||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2008 |
| 2007 |
| 2008 |
| 2007 | ||||||
Change in benefit obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| $ | (2,256.9) |
| $ | (2,334.6) |
| $ | (32.1) |
| $ | (34.0) |
| $ | (459.6) |
| $ | (469.9) |
Service cost |
|
| (43.9) |
|
| (47.0) |
|
| (0.7) |
|
| (0.8) |
|
| (7.1) |
|
| (7.4) |
Interest cost |
|
| (144.0) |
|
| (136.4) |
|
| (2.0) |
|
| (1.9) |
|
| (28.3) |
|
| (25.7) |
Actuarial gain/(loss) |
|
| 19.5 |
|
| 178.4 |
|
| (1.7) |
|
| 2.6 |
|
| 20.2 |
|
| 3.3 |
Prior service cost |
|
| - |
|
| (40.0) |
|
| - |
|
| - |
|
| - |
|
| - |
Federal subsidy on benefits paid |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (3.4) |
|
| (3.8) |
Benefits paid - excluding lump sum payments |
|
| 127.1 |
|
| 122.2 |
|
| 2.3 |
|
| 2.0 |
|
| 42.2 |
|
| 43.9 |
Benefits paid - lump sum payments |
|
| 0.5 |
|
| 0.2 |
|
| - |
|
| - |
|
| - |
|
| - |
Termination benefits |
|
| - |
|
| 0.3 |
|
| - |
|
| - |
|
| - |
|
| - |
Benefit obligation at end of year |
| $ | (2,297.7) |
| $ | (2,256.9) |
| $ | (34.2) |
| $ | (32.1) |
| $ | (436.0) |
| $ | (459.6) |
Change in plan assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
| $ | 2,459.4 |
| $ | 2,356.2 |
| $ | N/A |
| $ | N/A |
| $ | 278.1 |
| $ | 266.6 |
Actual return on plan assets |
|
| (775.0) |
|
| 225.6 |
|
| N/A |
|
| N/A |
|
| (80.1) |
|
| 14.4 |
Employer contribution |
|
| - |
|
| - |
|
| N/A |
|
| N/A |
|
| 39.8 |
|
| 41.0 |
Benefits paid - excluding lump sum payments |
|
| (127.1) |
|
| (122.2) |
|
| N/A |
|
| N/A |
|
| (42.2) |
|
| (43.9) |
Benefits paid - lump sum payments |
|
| (0.5) |
|
| (0.2) |
|
| N/A |
|
| N/A |
|
| - |
|
| - |
Fair value of plan assets at end of year |
| $ | 1,556.8 |
| $ | 2,459.4 |
|
| N/A |
|
| N/A |
| $ | 195.6 |
| $ | 278.1 |
Funded status at December 31st |
| $ | (740.9) |
| $ | 202.5 |
| $ | (34.2) |
| $ | (32.1) |
| $ | (240.4) |
| $ | (181.5) |
|
| As of December 31, | ||||||||||||||||
|
| Pension Benefits |
| SERP Benefits |
| PBOP Benefits | ||||||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 | ||||||
Change in Benefit Obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligation as of Beginning of Year |
| $ | (2,571.0) |
| $ | (2,297.7) |
| $ | (39.3) |
| $ | (34.2) |
| $ | (475.7) |
| $ | (436.0) |
Service Cost |
|
| (50.3) |
|
| (45.0) |
|
| (0.7) |
|
| (0.8) |
|
| (8.5) |
|
| (7.2) |
Interest Cost |
|
| (150.3) |
|
| (153.4) |
|
| (2.3) |
|
| (2.3) |
|
| (26.8) |
|
| (29.1) |
Actuarial Loss |
|
| (139.3) |
|
| (203.8) |
|
| (1.3) |
|
| (4.3) |
|
| (17.5) |
|
| (44.5) |
Federal Subsidy on Benefits Paid |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (3.7) |
|
| (3.5) |
Benefits Paid - Excluding Lump Sum Payments |
|
| 130.2 |
|
| 128.9 |
|
| 2.5 |
|
| 2.3 |
|
| 42.3 |
|
| 44.6 |
Benefits Paid - Lump Sum Payments |
|
| 0.9 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Benefit Obligation as of End of Year |
| $ | (2,779.8) |
| $ | (2,571.0) |
| $ | (41.1) |
| $ | (39.3) |
| $ | (489.9) |
| $ | (475.7) |
Change in Plan Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Plan Assets as of Beginning of Year |
| $ | 1,789.6 |
| $ | 1,556.8 |
|
| N/A |
|
| N/A |
| $ | 240.3 |
| $ | 195.6 |
Actual Return on Plan Assets |
|
| 274.1 |
|
| 361.7 |
|
| N/A |
|
| N/A |
|
| 34.9 |
|
| 48.5 |
Employer Contribution |
|
| 45.0 |
|
| - |
|
| N/A |
|
| N/A |
|
| 45.6 |
|
| 40.8 |
Benefits Paid - Excluding Lump Sum Payments |
|
| (130.2) |
|
| (128.9) |
|
| N/A |
|
| N/A |
|
| (42.3) |
|
| (44.6) |
Benefits Paid - Lump Sum Payments |
|
| (0.9) |
|
| - |
|
| N/A |
|
| N/A |
|
| - |
|
| - |
Fair Value of Plan Assets as of End of Year |
| $ | 1,977.6 |
| $ | 1,789.6 |
|
| N/A |
|
| N/A |
| $ | 278.5 |
| $ | 240.3 |
Funded Status as of December 31st |
| $ | (802.2) |
| $ | (781.4) |
| $ | (41.1) |
| $ | (39.3) |
| $ | (211.4) |
| $ | (235.4) |
The amounts recognized on the accompanying consolidated balance sheets for the funded status above atas of December 31, 20082010 and 2007 is2009 are as follows (millions of dollars):follows:
|
| At December 31, | ||||||||||||||||
|
| Pension Benefits |
| SERP Benefits |
| Postretirement Benefits | ||||||||||||
NU Consolidated |
| 2008 |
| 2007 |
| 2008 |
| 2007 |
| 2008 |
| 2007 | ||||||
(Accrued)/prepaid pension |
| $ | (740.9) |
| $ | 202.5 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other current liabilities |
|
| - |
|
| - |
|
| (2.3) |
|
| (2.4) |
|
| - |
|
| - |
Other deferred credits and other liabilities |
|
| - |
|
| - |
|
| (31.9) |
|
| (29.7) |
|
| - |
|
| - |
Accrued postretirement benefits |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (240.4) |
|
| (181.5) |
|
| As of December 31, | ||||||||||||||||
(Millions of Dollars) |
| Pension Benefits |
| SERP Benefits |
| PBOP Benefits | ||||||||||||
NU |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 | ||||||
Accrued Pension |
| $ | (802.2) |
| $ | (781.4) |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other Current Liabilities |
|
| - |
|
| - |
|
| (4.1) |
|
| (2.9) |
|
| - |
|
| - |
Other Long-Term Liabilities |
|
| - |
|
| - |
|
| (37.0) |
|
| (36.4) |
|
| (211.4) |
|
| (235.4) |
CL&P |
|
| ||||||||||||||||
(Accrued)/prepaid pension |
| $ | (89.3) |
| $ | 334.8 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other current liabilities |
|
| - |
|
| - |
|
| (0.1) |
|
| (0.1) |
|
| - |
|
| - |
Other deferred credits and other liabilities |
|
| - |
|
| - |
|
| (2.5) |
|
| (2.3) |
|
| - |
|
| - |
Accrued postretirement benefits |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (98.6) |
|
| (78.6) |
CL&P |
|
| ||||||||||||||||
Accrued Pension |
| $ | (42.5) |
| $ | (51.3) |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other Current Liabilities |
|
| - |
|
| - |
|
| (0.4) |
|
| (0.3) |
|
| - |
|
| - |
Other Long-Term Liabilities |
|
| - |
|
| - |
|
| (3.0) |
|
| (3.1) |
|
| (81.6) |
|
| (94.9) |
PSNH |
|
| ||||||||||||||||
Accrued pension |
| $ | (236.3) |
| $ | (138.3) |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other deferred credits and other liabilities |
|
| - |
|
| - |
|
| (1.8) |
|
| (1.8) |
|
| - |
|
| - |
Accrued postretirement benefits |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (41.8) |
|
| (29.1) |
PSNH |
|
| ||||||||||||||||
Accrued Pension |
| $ | (261.1) |
| $ | (272.9) |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other Current Liabilities |
|
| - |
|
| - |
|
| (0.3) |
|
| (0.1) |
|
| - |
|
| - |
Other Long-Term Liabilities |
|
| - |
|
| - |
|
| (1.9) |
|
| (2.0) |
|
| (33.0) |
|
| (39.7) |
WMECO |
|
| ||||||||||||||||
(Accrued)/prepaid pension |
| $ | (3.6) |
| $ | 90.0 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other deferred credits and other liabilities |
|
| - |
|
| - |
|
| (0.7) |
|
| (0.6) |
|
| - |
|
| - |
Accrued postretirement benefits |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (18.1) |
|
| (12.7) |
WMECO |
|
| ||||||||||||||||
Prepaid Pension |
| $ | 13.6 |
| $ | 6.9 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Other Long-Term Liabilities |
|
| - |
|
| - |
|
| (0.4) |
|
| (0.4) |
|
| (15.0) |
|
| (17.4) |
ForThe accumulated benefit obligation for the Pension Plan and SERP as of December 31, 2010 and 2009 is as follows:
|
| Pension Benefits |
| SERP Benefits | ||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2010 |
| 2009 | ||||
NU |
| $ | 2,512.2 |
| $ | 2,034.7 |
| $ | 38.9 |
| $ | 36.9 |
CL&P |
|
| 864.9 |
|
| 725.8 |
|
| 3.4 |
|
| 3.3 |
PSNH |
|
| 395.8 |
|
| 312.4 |
|
| 2.1 |
|
| 1.9 |
WMECO |
|
| 177.0 |
|
| 146.4 |
|
| 0.4 |
|
| 0.3 |
The Company amortizes the company amortizes its transition obligation over the remainingprior service lives of its employees as calculatedcost on an individual subsidiary basis and amortizes the prior service cost and unrecognized net actuarial gain/(loss)gains/(losses) and any remaining transition obligation over the remaining service lives of its employees as calculated on an NU consolidated basis. ForThe pension transition obligation is fully amortized and the PBOP Plan, the company amortizes its transition obligation prior service cost, and unrecognized net actuarial gain/(loss) over the remaining service lives of its employees as calculated on an individual operating company basis.
The accumulated benefit obligation for the Pension Plan was $2 billion ($731.6 million - CL&P; $320.4 million - PSNH; $148.4 million - WMECO) and $2 billion ($723.2 million - CL&P; $308.3 million - PSNH; $145.3 million - WMECO) at December 31, 2008 and 2007, respectively, and was $32.1 million ($2.3 million - CL&P; $1.7 million - PSNH; $0.7 million - WMECO) and $30.2 million ($2.2 million - CL&P; $1.6 million - PSNH; $0.6 million - WMECO) for the SERP at December 31, 2008 and 2007, respectively.will be fully amortized in 2013.
FS-59133
The following is a summary of amounts recorded as regulatory assetsRegulatory Assets as a result of SFAS No. 158 at December 31, 20082010 and 20072009 and the changes in those amounts recorded during the years (millions of dollars):years:
NU Consolidated |
| At December 31, | |||||||||||||||||
|
| Pension |
| SERP |
| PBOP | |||||||||||||
|
| 2008 |
| 2007 |
| 2008 |
| 2007 |
| 2008 |
| 2007 | |||||||
Transition obligation at beginning of year |
| $ | 0.5 |
| $ | 0.7 |
| $ | - |
| $ | - |
| $ | 56.6 |
| $ | 67.9 | |
Amounts reclassified as net periodic benefit expense |
|
| (0.2) |
|
| (0.2) |
|
| - |
|
| - |
|
| (11.3) |
|
| (11.3) | |
Transition obligation at end of year |
| $ | 0.3 |
| $ | 0.5 |
| $ | - |
| $ | - |
| $ | 45.3 |
| $ | 56.6 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Prior service cost at beginning of year |
| $ | 67.2 |
| $ | 38.1 |
| $ | 0.5 |
| $ | 0.6 |
| $ | (3.6) |
| $ | (3.9) | |
Amounts reclassified as net periodic benefit (expense)/income |
|
| (9.6) |
|
| (8.6) |
|
| (0.1) |
|
| (0.1) |
|
| 0.3 |
|
| 0.3 | |
Prior service cost arising during the year |
|
| 0.2 |
|
| 37.7 |
|
| - |
|
| - |
|
| - |
|
| - | |
Prior service cost at end of year |
| $ | 57.8 |
| $ | 67.2 |
| $ | 0.4 |
| $ | 0.5 |
| $ | (3.3) |
| $ | (3.6) | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net actuarial (gains)/losses at beginning of year |
| $ | (24.2) |
| $ | 184.7 |
| $ | 1.8 |
| $ | 5.0 |
| $ | 102.6 |
| $ | 114.3 | |
Amounts reclassified as net periodic benefit expense |
|
| (5.6) |
|
| (19.9) |
|
| (0.2) |
|
| (0.6) |
|
| (10.4) |
|
| (12.0) | |
Actuarial losses/(gains) arising during the year |
|
| 897.0 |
|
| (189.0) |
|
| 1.6 |
|
| (2.6) |
|
| 77.8 |
|
| 0.3 | |
Actuarial losses/(gains) at end of year |
| $ | 867.2 |
| $ | (24.2) |
| $ | 3.2 |
| $ | 1.8 |
| $ | 170.0 |
| $ | 102.6 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total deferred benefit costs as regulatory assets |
| $ | 925.3 |
| $ | 43.5 |
| $ | 3.6 |
| $ | 2.3 |
| $ | 212.0 |
| $ | 155.6 |
|
| As of December 31, | |||||||||||||||||
NU |
| Pension |
| SERP |
| PBOP | |||||||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 | |||||||
Net Actuarial Losses as of Beginning of Year |
| $ | 869.4 |
| $ | 867.2 |
| $ | 7.5 |
| $ | 3.2 |
| $ | 175.9 |
| $ | 170.0 | |
Amounts Reclassified as Net Periodic Benefit Expense |
|
| (49.9) |
|
| (20.4) |
|
| (1.1) |
|
| (0.4) |
|
| (15.9) |
|
| (10.0) | |
Actuarial Losses Arising During the Year |
|
| 44.0 |
|
| 22.6 |
|
| 1.3 |
|
| 4.7 |
|
| 4.2 |
|
| 15.9 | |
Actuarial Losses as of End of Year |
| $ | 863.5 |
| $ | 869.4 |
| $ | 7.7 |
| $ | 7.5 |
| $ | 164.2 |
| $ | 175.9 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Prior Service Cost/(Credit) as of Beginning of Year |
| $ | 48.1 |
| $ | 57.8 |
| $ | 0.2 |
| $ | 0.4 |
| $ | (3.0) |
| $ | (3.3) | |
Amounts Reclassified as Net Periodic Benefit (Expense)/Income |
|
| (9.5) |
|
| (9.5) |
|
| - |
|
| (0.2) |
|
| 0.3 |
|
| 0.3 | |
Prior Service Credit Arising During the Year |
|
| - |
|
| (0.2) |
|
| - |
|
| - |
|
| - |
|
| - | |
Prior Service Cost/(Credit) as of End of Year |
| $ | 38.6 |
| $ | 48.1 |
| $ | 0.2 |
| $ | 0.2 |
| $ | (2.7) |
| $ | (3.0) | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Transition Obligation as of Beginning of Year |
| $ | - |
| $ | 0.3 |
| $ | - |
| $ | - |
| $ | 34.0 |
| $ | 45.3 | |
Amounts Reclassified as Net Periodic Benefit Expense |
|
| - |
|
| (0.3) |
|
| - |
|
| - |
|
| (11.3) |
|
| (11.3) | |
Transition Obligation as of End of Year |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 22.7 |
| $ | 34.0 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total Deferred Benefit Costs Recorded as Regulatory Assets |
| $ | 902.1 |
| $ | 917.5 |
| $ | 7.9 |
| $ | 7.7 |
| $ | 184.2 |
| $ | 206.9 |
The estimates of the above amounts that are expected to be recognized as portions of net periodic benefit expense in 20092011 are as follows (millions of dollars):follows:
NU Consolidated |
| Estimated Expense in 2009 | |||||||
|
| Pension |
| SERP |
| PBOP | |||
Transition obligation |
| $ | 0.3 |
| $ | - |
| $ | 11.3 |
Prior service cost |
|
| 9.5 |
|
| 0.1 |
|
| 0.3 |
Net actuarial loss |
|
| 20.6 |
|
| 0.5 |
|
| 9.8 |
Total |
| $ | 30.4 |
| $ | 0.6 |
| $ | 21.4 |
NU |
| Estimated Expense in 2011 | |||||||
(Millions of Dollars) |
| Pension |
| SERP |
| PBOP | |||
Net Actuarial Loss |
| $ | 78.3 |
| $ | 1.1 |
| $ | 17.3 |
Prior Service Credit |
|
| 9.5 |
|
| - |
|
| (0.3) |
Transition Obligation |
|
| - |
|
| - |
|
| 11.3 |
Total |
| $ | 87.8 |
| $ | 1.1 |
| $ | 28.3 |
The following is a summary of amounts recorded in accumulated other comprehensive income,Accumulated Other Comprehensive Loss as a result of SFAS No. 158 at December 31, 20082010 and 20072009 and the changes in those amounts recorded to other comprehensive income (millions of dollars)Other Comprehensive Income/(Loss):
|
| At December 31, | |||||||||||||||||
NU Consolidated |
| Pension |
| SERP |
| PBOP | |||||||||||||
|
| 2008 |
| 2007 |
| 2008 |
| 2007 |
| 2008 |
| 2007 | |||||||
Transition obligation at beginning of year |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 1.2 |
| $ | 1.5 | |
Amounts reclassified as net periodic benefit expense |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (0.3) |
|
| (0.3) | |
Transition obligation at end of year |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 0.9 |
| $ | 1.2 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Prior service cost at beginning of year |
| $ | 2.7 |
| $ | 0.6 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | |
Amounts reclassified as net periodic benefit expense |
|
| (0.3) |
|
| (0.2) |
|
| - |
|
| - |
|
| - |
|
| - | |
Prior service (credit)/cost arising during the year |
|
| (0.3) |
|
| 2.3 |
|
| - |
|
| - |
|
| - |
|
| - | |
Prior service cost at end of year |
| $ | 2.1 |
| $ | 2.7 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net actuarial (gains)/losses at beginning of year |
| $ | (17.4) |
| $ | 2.6 |
| $ | 0.2 |
| $ | 0.3 |
| $ | 5.5 |
| $ | 5.5 | |
Amounts reclassified as net periodic benefit income/(expense) |
|
| 0.9 |
|
| (0.2) |
|
| - |
|
| - |
|
| (0.2) |
|
| (0.3) | |
Actuarial losses/(gains) arising during the year |
|
| 58.9 |
|
| (19.8) |
|
| (0.1) |
|
| (0.1) |
|
| 3.5 |
|
| 0.3 | |
Actuarial losses/(gains) at end of year |
| $ | 42.4 |
| $ | (17.4) |
| $ | 0.1 |
| $ | 0.2 |
| $ | 8.8 |
| $ | 5.5 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total Pension, SERP and PBOP in accumulated other |
| $ | 44.5 |
| $ | (14.7) |
| $ | 0.1 |
| $ | 0.2 |
| $ | 9.7 |
| $ | 6.7 |
|
| As of December 31, | |||||||||||||||||
NU |
| Pension |
| SERP |
| PBOP | |||||||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 | |||||||
Net Actuarial Losses/(Gains) as of Beginning of Year |
| $ | 51.1 |
| $ | 42.4 |
| $ | (0.2) |
| $ | 0.1 |
| $ | 9.1 |
| $ | 8.8 | |
Amounts Reclassified as Net Periodic Benefit Expense |
|
| (2.7) |
|
| (0.1) |
|
| - |
|
| - |
|
| (0.8) |
|
| (0.5) | |
Actuarial Losses/(Gains) Arising During the Year |
|
| 3.6 |
|
| 8.8 |
|
| 0.1 |
|
| (0.3) |
|
| 0.7 |
|
| 0.8 | |
Actuarial Losses/(Gains) as of End of Year |
| $ | 52.0 |
| $ | 51.1 |
| $ | (0.1) |
| $ | (0.2) |
| $ | 9.0 |
| $ | 9.1 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Prior Service Cost as of Beginning of Year |
| $ | 2.0 |
| $ | 2.1 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | |
Amounts Reclassified as Net Periodic Benefit Expense |
|
| (0.3) |
|
| (0.3) |
|
| - |
|
| - |
|
| - |
|
| - | |
Prior Service Cost Arising During the Year |
|
| - |
|
| 0.2 |
|
| - |
|
| - |
|
| - |
|
| - | |
Prior Service Cost as of End of Year |
| $ | 1.7 |
| $ | 2.0 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Transition Obligation as of Beginning of Year |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 0.7 |
| $ | 0.9 | |
Amounts Reclassified as Net Periodic Benefit Expense |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (0.2) |
|
| (0.2) | |
Transition Obligation as of End of Year |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 0.5 |
| $ | 0.7 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total Pension, SERP and PBOP in |
| $ | 53.7 |
| $ | 53.1 |
| $ | (0.1) |
| $ | (0.2) |
| $ | 9.5 |
| $ | 9.8 |
The estimates of the above amounts that are expected to be recognized as portions of net periodic benefit expense in 20092011 are as follows (millions of dollars):follows:
|
| Estimated Expense in 2009 | |||||||
NU Consolidated |
| Pension |
| SERP |
| PBOP | |||
Transition obligation |
| $ | - |
| $ | - |
| $ | 0.2 |
Prior service cost |
|
| 0.3 |
|
| - |
|
| - |
Net actuarial loss |
|
| - |
|
| - |
|
| 0.2 |
Total |
| $ | 0.3 |
| $ | - |
| $ | 0.4 |
NU |
| Estimated Expense in 2011 | |||||||
(Millions of Dollars) |
| Pension |
| SERP |
| PBOP | |||
Net Actuarial Loss |
| $ | 4.6 |
| $ | - |
| $ | 0.9 |
Prior Service Cost |
|
| 0.3 |
|
| - |
|
| - |
Transition Obligation |
|
| - |
|
| - |
|
| 0.2 |
Total |
| $ | 4.9 |
| $ | - |
| $ | 1.1 |
For further information, see Note 14,16, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.
FS-60134
The following actuarial assumptions were used in calculating the plans’plans' year end funded status:
|
| At December 31, |
| |||||||||
|
| Pension Benefits and SERP |
|
| Postretirement Benefits |
| ||||||
Balance Sheets |
| 2008 |
|
| 2007 |
|
| 2008 |
|
| 2007 |
|
Discount rate |
| 6.89 | % |
| 6.60 | % |
| 6.90 | % |
| 6.35 | % |
Compensation/progression rate |
| 4.00 | % |
| 4.00 | % |
| N/A |
|
| N/A |
|
Health care cost trend rate |
| N/A |
|
| N/A |
|
| 8.00 | % |
| 8.50 | % |
|
| As of December 31, |
| |||||||||
|
| Pension Benefits and SERP |
|
| PBOP Benefits |
| ||||||
Balance Sheets |
| 2010 |
|
| 2009 |
|
| 2010 |
|
| 2009 |
|
Discount Rate |
| 5.57 | % |
| 5.98 | % |
| 5.28 | % |
| 5.73 | % |
Compensation/Progression Rate |
| 3.50 | % |
| 4.00 | % |
| N/A |
|
| N/A |
|
Health Care Cost Trend Rate |
| N/A |
|
| N/A |
|
| 7.00 | % |
| 7.50 | % |
The components of net periodic benefit expense/(income) are as follows:
|
| For the Years Ended December 31, | |||||||||||||||||||||||||
NU Consolidated |
| Pension Benefits |
| SERP Benefits |
| Postretirement Benefits | |||||||||||||||||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 |
| 2008 |
| 2007 |
| 2006 |
| 2008 |
| 2007 |
|
| 2006 | ||||||||
Service cost |
| $ | 43.9 |
| $ | 47.0 |
| $ | 49.4 |
| $ | 0.7 |
| $ | 0.8 |
| $ | 1.1 |
| $ | 7.1 |
| $ | 7.4 |
| $ | 8.3 |
Interest cost |
|
| 144.0 |
|
| 136.4 |
|
| 129.7 |
|
| 2.0 |
|
| 1.9 |
|
| 1.9 |
|
| 28.3 |
|
| 25.7 |
|
| 27.3 |
Expected return on plan assets |
|
| (200.2) |
|
| (195.2) |
|
| (174.0) |
|
| - |
|
| - |
|
| - |
|
| (21.1) |
|
| (18.2) |
|
| (14.0) |
Net transition obligation cost/(asset) |
|
| 0.2 |
|
| 0.2 |
|
| (0.1) |
|
| - |
|
| - |
|
| - |
|
| 11.6 |
|
| 11.6 |
|
| 11.6 |
Prior service cost/(credit) |
|
| 9.9 |
|
| 8.9 |
|
| 6.6 |
|
| 0.1 |
|
| 0.2 |
|
| 0.2 |
|
| (0.3) |
|
| (0.3) |
|
| (0.3) |
Actuarial loss |
|
| 4.6 |
|
| 20.1 |
|
| 41.1 |
|
| 0.3 |
|
| 0.7 |
|
| 0.9 |
|
| 10.6 |
|
| 12.2 |
|
| 17.8 |
Net periodic expense - before |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Curtailment benefits |
|
| - |
|
| - |
|
| (4.8) |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| (2.2) |
Termination (benefits)/expense |
|
| - |
|
| (0.3) |
|
| 2.3 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 0.3 |
Total curtailments and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total - net periodic expense |
| $ | 2.4 |
| $ | 17.1 |
| $ | 50.2 |
| $ | 3.1 |
| $ | 3.6 |
| $ | 4.1 |
| $ | 36.2 |
| $ | 38.4 |
| $ | 48.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P - net periodic (income)/expense |
| $ | (21.3) |
| $ | (15.6) |
| $ | 0.3 |
| $ | 0.3 |
| $ | 0.3 |
| $ | 0.3 |
| $ | 15.7 |
| $ | 16.1 |
| $ | 20.1 |
PSNH - net periodic expense |
| $ | 18.1 |
| $ | 19.5 |
| $ | 20.8 |
| $ | 0.2 |
| $ | 0.4 |
| $ | 0.2 |
| $ | 7.1 |
| $ | 7.9 |
| $ | 10.1 |
WMECO - net periodic (income)/expense |
| $ | (6.1) |
| $ | (5.0) |
| $ | (1.3) |
| $ | 0.1 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 2.8 |
| $ | 3.0 |
| $ | 4.1 |
| For the Years Ended December 31, | |||||||||||||||||||||||||
NU | Pension Benefits |
| SERP Benefits |
| PBOP Benefits | |||||||||||||||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
|
| 2008 | ||||||||
Service Cost | $ | 50.3 |
| $ | 45.0 |
| $ | 43.9 |
| $ | 0.7 |
| $ | 0.8 |
| $ | 0.7 |
| $ | 8.5 |
| $ | 7.2 |
| $ | 7.1 |
Interest Cost |
| 150.3 |
|
| 153.4 |
|
| 144.0 |
|
| 2.3 |
|
| 2.3 |
|
| 2.0 |
|
| 26.8 |
|
| 29.1 |
|
| 28.3 |
Expected Return on Plan Assets |
| (182.6) |
|
| (189.4) |
|
| (200.2) |
|
| - |
|
| - |
|
| - |
|
| (21.7) |
|
| (20.9) |
|
| (21.1) |
Net Transition Obligation Cost |
| - |
|
| 0.3 |
|
| 0.2 |
|
| - |
|
| - |
|
| - |
|
| 11.6 |
|
| 11.6 |
|
| 11.6 |
Prior Service Cost/(Credit) |
| 9.8 |
|
| 9.8 |
|
| 9.9 |
|
| 0.1 |
|
| 0.1 |
|
| 0.1 |
|
| (0.3) |
|
| (0.3) |
|
| (0.3) |
Actuarial Loss |
| 52.6 |
|
| 20.6 |
|
| 4.6 |
|
| 1.0 |
|
| 0.4 |
|
| 0.3 |
|
| 16.7 |
|
| 10.5 |
|
| 10.6 |
Total - Net Periodic Expense | $ | 80.4 |
| $ | 39.7 |
| $ | 2.4 |
| $ | 4.1 |
| $ | 3.6 |
| $ | 3.1 |
| $ | 41.6 |
| $ | 37.2 |
| $ | 36.2 |
| For the Years Ended December 31, | |||||||||||||||||||||||||
CL&P | Pension Benefits |
| SERP Benefits |
| PBOP Benefits | |||||||||||||||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
|
| 2008 | ||||||||
Service Cost | $ | 17.6 |
| $ | 16.0 |
| $ | 15.4 |
| $ | - |
| $ | - |
| $ | - |
| $ | 2.7 |
| $ | 2.2 |
| $ | 2.2 |
Interest Cost |
| 52.0 |
|
| 54.3 |
|
| 51.4 |
|
| 0.2 |
|
| 0.2 |
|
| 0.2 |
|
| 10.5 |
|
| 11.5 |
|
| 11.3 |
Expected Return on Plan Assets |
| (85.8) |
|
| (89.0) |
|
| (93.4) |
|
| - |
|
| - |
|
| - |
|
| (8.7) |
|
| (8.3) |
|
| (8.4) |
Net Transition Obligation Cost |
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 6.1 |
|
| 6.1 |
|
| 6.1 |
Prior Service Cost |
| 4.2 |
|
| 4.2 |
|
| 4.2 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Actuarial Loss |
| 20.5 |
|
| 8.8 |
|
| 1.1 |
|
| 0.2 |
|
| 0.1 |
|
| 0.1 |
|
| 6.3 |
|
| 4.0 |
|
| 4.5 |
Total - Net Periodic Expense/(Income) | $ | 8.5 |
| $ | (5.7) |
| $ | (21.3) |
| $ | 0.4 |
| $ | 0.3 |
| $ | 0.3 |
| $ | 16.9 |
| $ | 15.5 |
| $ | 15.7 |
| For the Years Ended December 31, | |||||||||||||||||||||||||
PSNH | Pension Benefits |
| SERP Benefits |
| PBOP Benefits | |||||||||||||||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
|
| 2008 | ||||||||
Service Cost | $ | 9.9 |
| $ | 8.8 |
| $ | 9.2 |
| $ | 0.1 |
| $ | 0.1 |
| $ | - |
| $ | 1.8 |
| $ | 1.5 |
| $ | 1.7 |
Interest Cost |
| 24.0 |
|
| 24.3 |
|
| 23.2 |
|
| 0.1 |
|
| 0.1 |
|
| 0.1 |
|
| 5.0 |
|
| 5.4 |
|
| 5.2 |
Expected Return on Plan Assets |
| (14.7) |
|
| (15.0) |
|
| (17.9) |
|
| - |
|
| - |
|
| - |
|
| (4.3) |
|
| (4.1) |
|
| (4.0) |
Net Transition Obligation Cost |
| - |
|
| 0.3 |
|
| 0.3 |
|
| - |
|
| - |
|
| - |
|
| 2.5 |
|
| 2.5 |
|
| 2.5 |
Prior Service Cost |
| 1.8 |
|
| 1.8 |
|
| 1.9 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Actuarial Loss |
| 7.1 |
|
| 3.1 |
|
| 1.4 |
|
| 0.1 |
|
| 0.1 |
|
| 0.1 |
|
| 2.7 |
|
| 1.7 |
|
| 1.7 |
Total - Net Periodic Expense | $ | 28.1 |
| $ | 23.3 |
| $ | 18.1 |
| $ | 0.3 |
| $ | 0.3 |
| $ | 0.2 |
| $ | 7.7 |
| $ | 7.0 |
| $ | 7.1 |
| For the Years Ended December 31, | |||||||||||||||||||||||||
WMECO | Pension Benefits |
| SERP Benefits |
| PBOP Benefits | |||||||||||||||||||||
(Millions of Dollars) | 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
|
| 2008 | ||||||||
Service Cost | $ | 3.5 |
| $ | 3.3 |
| $ | 3.2 |
| $ | - |
| $ | - |
| $ | - |
| $ | 0.6 |
| $ | 0.5 |
| $ | 0.5 |
Interest Cost |
| 10.7 |
|
| 11.1 |
|
| 10.4 |
|
| - |
|
| - |
|
| 0.1 |
|
| 2.3 |
|
| 2.5 |
|
| 2.4 |
Expected Return on Plan Assets |
| (19.5) |
|
| (20.0) |
|
| (20.7) |
|
| - |
|
| - |
|
| - |
|
| (2.1) |
|
| (2.0) |
|
| (2.1) |
Net Transition Obligation Cost |
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 1.3 |
|
| 1.3 |
|
| 1.4 |
Prior Service Cost |
| 0.9 |
|
| 0.9 |
|
| 0.9 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Actuarial Loss |
| 4.3 |
|
| 1.8 |
|
| 0.1 |
|
| - |
|
| - |
|
| - |
|
| 0.9 |
|
| 0.4 |
|
| 0.6 |
Total - Net Periodic Expense/(Income) | $ | (0.1) |
| $ | (2.9) |
| $ | (6.1) |
| $ | - |
| $ | - |
| $ | 0.1 |
| $ | 3.0 |
| $ | 2.7 |
| $ | 2.8 |
Not included in the Pension Plan, PBOP Plan and SERP amounts above for CL&P, PSNH and WMECO are related intercompany allocations as follows:
|
| For the Years Ended December 31, | |||||||||||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO | |||||||||||||||||||||
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
| 2008 |
| 2010 |
| 2009 |
|
| 2008 | ||||||||
Pension Benefits |
| $ | 23.2 |
| $ | 14.5 |
| $ | 8.9 |
| $ | 5.4 |
| $ | 3.1 |
| $ | 2.0 |
| $ | 4.2 |
| $ | 2.4 |
| $ | 1.5 |
PBOP Benefits |
|
| 7.9 |
|
| 7.3 |
|
| 6.7 |
|
| 2.0 |
|
| 1.7 |
|
| 1.5 |
|
| 1.4 |
|
| 1.1 |
|
| 1.1 |
SERP Benefits |
|
| 2.0 |
|
| 1.8 |
|
| 1.6 |
|
| 0.6 |
|
| 0.5 |
|
| 0.4 |
|
| 0.3 |
|
| 0.3 |
|
| 0.2 |
135
The following assumptions were used to calculate pension and postretirement benefitPBOP expense and income amounts:
|
| For the Years Ended December 31, |
| |||||||||||||||
Statements of Income |
| Pension Benefits and SERP |
|
| Postretirement Benefits |
| ||||||||||||
|
| 2008 |
|
| 2007 |
|
| 2006 |
|
| 2008 |
|
| 2007 |
|
| 2006 |
|
Discount rate |
| 6.60 | % |
| 5.95 | %(1) |
| 5.80 | % |
| 6.35 | % |
| 5.80 | % |
| 5.65 | % |
Expected long-term rate of return |
| 8.75 | % |
| 8.75 | % |
| 8.75 | % |
| N/A |
|
| N/A |
|
| N/A |
|
Compensation/progression rate |
| 4.00 | % |
| 4.00 | % |
| 4.00 | % |
| N/A |
|
| N/A |
|
| N/A |
|
Expected long-term rate of return - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health assets, net of tax |
| N/A |
|
| N/A |
|
| N/A |
|
| 6.85 | % |
| 6.85 | % |
| 6.85 | % |
Life assets and non-taxable health assets |
| N/A |
|
| N/A |
|
| N/A |
|
| 8.75 | % |
| 8.75 | % |
| 8.75 | % |
| For the Years Ended December 31, |
| |||||||||||||||
| Pension Benefits and SERP |
|
| PBOP Benefits |
| ||||||||||||
Statements of Income | 2010 |
|
| 2009 |
|
| 2008 |
|
| 2010 |
|
| 2009 |
|
| 2008 |
|
Discount Rate | 5.98 | % |
| 6.89 | % |
| 6.60 | % |
| 5.73 | % |
| 6.90 | % |
| 6.35 | % |
Expected Long-Term Rate of Return | 8.75 | % |
| 8.75 | % |
| 8.75 | % |
| N/A |
|
| N/A |
|
| N/A |
|
Compensation/Progression Rate | 4.00 | % |
| 4.00 | % |
| 4.00 | % |
| N/A |
|
| N/A |
|
| N/A |
|
Expected Long-Term Rate of Return - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health Assets, Taxable | N/A |
|
| N/A |
|
| N/A |
|
| 6.85 | % |
| 6.85 | % |
| 6.85 | % |
Life Assets and Non-Taxable Health Assets | N/A |
|
| N/A |
|
| N/A |
|
| 8.75 | % |
| 8.75 | % |
| 8.75 | % |
(1) The 2007 discount rate forFor 2011 through 2013, the SERP was 5.9 percent.
The following table represents the PBOP assumed health care trend cost assumption is 7 percent, subsequently decreasing one half percentage point per year to an ultimate rate of 5 percent in 2017. For the year ended December 31, 2010, the assumed healthcare trend was 7.5 percent, decreasing by 5 percent and reaching the ultimate trend rate for the next year and the assumed ultimate trend rate:of 5 percent in 2015.
|
| Year Following December 31, |
| |||
|
| 2008 |
|
| 2007 |
|
Health care cost trend rate assumed for next year |
| 8.00 | % |
| 8.50 | % |
Rate to which health care cost trend rate is assumed |
|
| % |
| 5.00 | % |
Year that the rate reaches the ultimate trend rate |
| 2015 |
|
| 2015 |
|
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in eachfor the year ended December 31, 2010 would have the following effects (millions of dollars):effects:
|
| One Percentage |
| One Percentage | ||
Effect on total service and interest cost components |
| $ | 1.0 |
| $ | (0.8) |
Effect on postretirement benefit obligation |
|
| 11.4 |
|
| (10.0) |
(Millions of Dollars) |
| One Percentage |
| One Percentage | ||
Effect on Postretirement Benefit Obligation |
| $ | 14.5 |
| $ | (12.1) |
Effect on Total Service and Interest Cost Components |
|
| 1.2 |
|
| (0.9) |
FS-61
NU’sFair Value of Pension and PBOP Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and PBOP payments. NU's investment strategy for its Pension Plan and PBOP PlanPlans is to maximize the long-term raterates of return on those plans’these plans' assets within an acceptable level of risk. The investment strategy for each asset category includes a diversification of asset types, fund strategy and fund managers and establishes target asset allocations whichthat are routinely reviewed and periodically rebalanced. NU’sNU's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan,Plans, NU also evaluated input from actuaries and consultants, as well as long-terml ong-term inflation assumptions and NU’s historical 25-year compoundedreturns. For 2010, management has assumed long-term rates of return of over 11 percent. The8.25 percent on Pension Plan’sPlan assets and PBOP Plan’sPlan life and nontaxable health assets and 6.45 percent for PBOP taxable health assets. These long-term rates of return are based on the assumed rates of return for the target asset allocation assumptions and expected long-term rate of return assumptions by asset category areallocations as follows:
|
| At December 31, | ||||||||
|
| Pension Benefits |
| Postretirement Benefits | ||||||
|
| 2008 and 2007 |
| 2008 and 2007 | ||||||
|
| Target |
| Assumed |
| Target |
| Assumed | ||
Equity Securities: |
|
|
|
|
|
|
|
| ||
United States |
| 40% |
| 9.25% |
| 55% |
| 9.25% | ||
Non-United States |
| 17% |
| 9.25% |
| 11% |
| 9.25% | ||
Emerging markets |
| 5% |
| 10.25% |
| 2% |
| 10.25% | ||
Private |
| 8% |
| 14.25% |
| - |
| - | ||
Debt Securities: |
|
|
|
|
|
|
|
| ||
Fixed income |
| 25% |
| 5.50% |
| 27% |
| 5.50% | ||
High yield fixed income |
| - |
| - |
| 5% |
| 7.50% | ||
Real Estate |
| 5% |
| 7.50% |
| - |
| - |
|
| As of December 31, | ||||||||||||||
|
| Pension and PBOP |
| PBOP |
| Pension |
| PBOP (Health and Life) | ||||||||
|
| 2010 |
| 2010 |
| 2009 |
| 2009 | ||||||||
|
| Target |
| Assumed |
| Target |
| Assumed |
| Target |
| Assumed |
| Target |
| Assumed |
Equity Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
| 24% |
| 9% |
| 55% |
| 9% |
| 24% |
| 9.25% |
| 55% |
| 9.25% |
International |
| 13% |
| 9% |
| 15% |
| 9% |
| 13% |
| 9.25% |
| 11% |
| 9.25% |
Emerging Markets |
| 3% |
| 10% |
| - |
| - |
| 3% |
| 10.25% |
| 2% |
| 10.25% |
Private Equity |
| 12% |
| 13% |
| - |
| - |
| 12% |
| 14.25% |
| - |
| - |
Debt Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Income |
| 20% |
| 5% |
| 30% |
| 5% |
| 20% |
| 5.7% |
| 27% |
| 5.7% |
High Yield Fixed Income |
| 3.5% |
| 7.5% |
| - |
| - |
| 3.5% |
| 7.7% |
| 5% |
| 7.7% |
Emerging Markets Debt |
| 3.5% |
| 7.5% |
| - |
| - |
| 3.5% |
| 7.7% |
| - |
| - |
Real Estate And Other Assets |
| 8% |
| 7.5% |
| - |
| - |
| 8% |
| 7.5% |
| - |
| - |
Hedge Funds |
| 13% |
| 7% |
| - |
| - |
| 13% |
| 8% |
| - |
| - |
136
The actual asset allocations at December 31, 2008 and 2007 approximated these target asset allocations. The plans’ actual weighted-average asset allocationsfollowing table presents, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are as follows: classified within the fair value hierarchy:
|
| At December 31, | ||||||
|
| Pension Benefits |
| Postretirement Benefits | ||||
Asset Category |
| 2008 |
| 2007 |
| 2008 |
| 2007 |
Equity Securities: |
|
|
|
|
|
|
|
|
United States |
| 34% |
| 40% |
| 57% |
| 55% |
Non-United States |
| 16% |
| 17% |
| 12% |
| 14% |
Emerging markets |
| 4% |
| 5% |
| 1% |
| 1% |
Private |
| 11% |
| 7% |
| - |
| - |
Debt Securities: |
|
|
|
|
|
|
|
|
Fixed income |
| 29% |
| 26% |
| 29% |
| 29% |
High yield fixed income |
| - |
| - |
| 1% |
| 1% |
Real Estate |
| 6% |
| 5% |
| - |
| - |
Totals |
| 100% |
| 100% |
| 100% |
| 100% |
| Pension Plan | ||||||||||||||||||||||
| Fair Value Measurements as of December 31, | ||||||||||||||||||||||
(Millions of Dollars) | 2010 |
| 2009 | ||||||||||||||||||||
Asset Category: | Level 1 |
| Level 2 |
| Level 3 |
| Total |
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||||||
Equity Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States(1) | $ | 256.3 |
| $ | 46.9 |
| $ | 266.0 |
| $ | 569.2 |
| $ | 135.2 |
| $ | 150.1 |
| $ | 252.1 |
| $ | 537.4 |
International(2) |
| 6.4 |
|
| 250.9 |
|
| - |
|
| 257.3 |
|
| 7.1 |
|
| 217.3 |
|
| - |
|
| 224.4 |
Emerging Markets(2) |
| - |
|
| 81.1 |
|
| - |
|
| 81.1 |
|
| - |
|
| 67.1 |
|
| - |
|
| 67.1 |
Private Equity(5) |
| 6.9 |
|
| - |
|
| 229.5 |
|
| 236.4 |
|
| 21.9 |
|
| - |
|
| 193.8 |
|
| 215.7 |
Fixed Income(3) |
| 7.6 |
|
| 261.6 |
|
| 247.6 |
|
| 516.8 |
|
| 49.4 |
|
| 251.9 |
|
| 174.0 |
|
| 475.3 |
Real Estate and |
| - |
|
| 26.0 |
|
| 43.7 |
|
| 69.7 |
|
| - |
|
| - |
|
| 38.5 |
|
| 38.5 |
Hedge Funds |
| - |
|
| - |
|
| 247.1 |
|
| 247.1 |
|
| - |
|
| - |
|
| 231.2 |
|
| 231.2 |
Total | $ | 277.2 |
| $ | 666.5 |
| $ | 1,033.9 |
| $ | 1,977.6 |
| $ | 213.6 |
| $ | 686.4 |
| $ | 889.6 |
| $ | 1,789.6 |
| PBOP Plan | ||||||||||||||||||||||
| Fair Value Measurements as of December 31, | ||||||||||||||||||||||
(Millions of Dollars) | 2010 |
| 2009 | ||||||||||||||||||||
Asset Category: | Level 1 |
| Level 2 |
| Level 3 |
| Total |
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||||||
Cash and Cash | $ | 4.4 |
| $ | - |
| $ | - |
| $ | 4.4 |
| $ | 4.2 |
| $ | - |
| $ | - |
| $ | 4.2 |
Equity Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
| 132.1 |
|
| - |
|
| 10.1 |
|
| 142.2 |
|
| 140.3 |
|
| - |
|
| - |
|
| 140.3 |
International |
| 34.8 |
|
| - |
|
| - |
|
| 34.8 |
|
| 28.0 |
|
| - |
|
| - |
|
| 28.0 |
Emerging Markets |
| 7.7 |
|
| - |
|
| - |
|
| 7.7 |
|
| - |
|
| - |
|
| - |
|
| - |
Debt Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Income(4) |
| - |
|
| 35.3 |
|
| 23.4 |
|
| 58.7 |
|
| - |
|
| 36.9 |
|
| 24.6 |
|
| 61.5 |
High Yield Fixed |
| - |
|
| 4.4 |
|
| - |
|
| 4.4 |
|
| 6.3 |
|
| - |
|
| - |
|
| 6.3 |
Emerging Market Debt |
| - |
|
| 4.8 |
|
| - |
|
| 4.8 |
|
| - |
|
| - |
|
| - |
|
| - |
Hedge Funds |
| - |
|
| - |
|
| 16.4 |
|
| 16.4 |
|
| - |
|
| - |
|
| - |
|
| - |
Private Equity |
| - |
|
| - |
|
| 0.3 |
|
| 0.3 |
|
| - |
|
| - |
|
| - |
|
| - |
Real Estate and Other |
| - |
|
| 4.8 |
|
| - |
|
| 4.8 |
|
| - |
|
| - |
|
| - |
|
| - |
Total | $ | 179.0 |
| $ | 49.3 |
| $ | 50.2 |
| $ | 278.5 |
| $ | 178.8 |
| $ | 36.9 |
| $ | 24.6 |
| $ | 240.3 |
(1)
United States Equities classified as Level 2 include investments in commingled funds totaling $34.8 million and $77.1 million and unrealized gains on holdings in equity index swaps totaling $12.1 million and $73 million for the years ended December 31, 2010 and 2009, respectively. Level 3 investments include hedge funds that are overlayed with equity index swaps and futures contracts. Level 1 investments represent primarily equity holdings and also includes unrealized gains and losses on equity index futures contracts.
(2)
The International and Emerging Markets Equities categorized as Level 2 represent investments in commingled funds.
(3)
Fixed Income securities classified as Level 2 include investments in debt securities, including high yield bond funds, U.S. government issued securities, corporate bonds, asset backed securities and insurance contracts totaling $261.6 million and $201.2 million for the years ended December 31, 2010 and 2009, respectively. In 2009, this amount above included unrealized gains on fixed income swaps of $50.7 million. Level 3 investments include fixed income funds totaling $147.1 million and $80.5 million that invest in senior credit distressed credit funds, and hedge funds totaling $100.5 million and $93.5 million that are overlayed with interest rate swaps and fixed income index swaps for the years ended December 31, 2010 and 2009, respectively. Level 1 investments include exchange traded funds and in 2009 also included unrealized gains on fixed income index futures contracts totaling $29.8 million.
(4)
Fixed Income investments classified as Level 2 include U.S. government issued securities, municipal bonds, corporate bonds and other debt securities. The amount classified in Level 3 represents funds that invests in senior credit distressed income securities totaling $7.6 million and $6.4 million and hedge funds totaling $15.8 million and $18.2 million for the years ended December 31, 2010 and 2009, respectively.
(5)
Private Equity amounts classified as Level 1 represent unrealized gains on futures contracts.
(6)
Level 2 investments relate to other assets not invested in real estate.
The Company values assets based on observable inputs when available. Equity securities and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date. Commingled funds included in Level 2 equity securities are recorded at the net asset value provided by the asset manager, which is based on the market prices of the underlying equity securities. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows. Fixed income securities included in Level 2 are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Hedge funds and investments in distressed credit funds are recorded at net asset value based on the values of the underlying assets. The assets in the hedge funds and distressed credit income funds are valued using observable inputs and are classified as Level 3 within the fair value hierarchy due to redemption restrictions. Private Equity investments and Real Estate and Other Assets are valued
137
using the net asset value provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or market approaches to the valuation of the underlying investments.These investments are classified as Level 3 due to redemption restrictions.
Fair Value Measurements Using Significant Unobservable Inputs (Level 3): The following tables present changes for the Level 3 category of Pension and PBOP Plan assets:
|
| Pension Plan | ||||||||||||||||
|
| As of December 31, 2010 | ||||||||||||||||
|
| United States |
| Private |
| Fixed |
| Real Estate |
| Hedge |
| Total | ||||||
Balance as of January 1, 2010 |
| $ | 252.1 |
| $ | 193.8 |
| $ | 174.0 |
| $ | 38.5 |
| $ | 231.2 |
| $ | 889.6 |
Actual Return on Plan Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to Assets Still Held as of |
|
| 13.9 |
|
| 10.9 |
|
| 21.0 |
|
| 0.5 |
|
| 15.9 |
|
| 62.2 |
Relating to Assets Distributed During |
|
| - |
|
| - |
|
| - |
|
| 0.5 |
|
| - |
|
| 0.5 |
Purchases, Sales and Settlements |
|
| - |
|
| 24.8 |
|
| 52.6 |
|
| 4.2 |
|
| - |
|
| 81.6 |
Balance as of December 31, 2010 |
| $ | 266.0 |
| $ | 229.5 |
| $ | 247.6 |
| $ | 43.7 |
| $ | 247.1 |
| $ | 1,033.9 |
|
| Pension Plan | ||||||||||||||||
|
| As of December 31, 2009 | ||||||||||||||||
|
| United States |
| Private |
| Fixed |
| Real Estate |
| Hedge |
| Total | ||||||
Balance as of January 1, 2009 |
| $ | 333.3 |
| $ | 175.2 |
| $ | 227.5 |
| $ | 58.2 |
| $ | - |
| $ | 794.2 |
Actual Return/(Loss) on Plan Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to Assets Still Held as of |
|
| 68.8 |
|
| 11.0 |
|
| 49.8 |
|
| (26.1) |
|
| 6.2 |
|
| 109.7 |
Relating to Assets Distributed During |
|
| - |
|
| (3.9) |
|
| - |
|
| - |
|
| - |
|
| (3.9) |
Purchases, Sales and Settlements |
|
| (15.0) |
|
| 11.5 |
|
| (13.3) |
|
| 6.4 |
|
| - |
|
| (10.4) |
Transfer Between Asset Categories |
|
| (135.0) |
|
| - |
|
| (90.0) |
|
| - |
|
| 225.0 |
|
| - |
Balance as of December 31, 2009 |
| $ | 252.1 |
| $ | 193.8 |
| $ | 174.0 |
| $ | 38.5 |
| $ | 231.2 |
| $ | 889.6 |
|
| PBOP Plan | ||||||||||||||||
|
| As of December 31, | ||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||
|
| United States |
| Private |
| Fixed |
| Hedge |
| Total |
| Fixed | ||||||
Balance as of Beginning of Year |
| $ | - |
| $ | - |
| $ | 24.6 |
| $ | - |
| $ | 24.6 |
| $ | 18.9 |
Actual Return/(Loss) on Plan Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to Assets Still Held at Year End |
|
| 0.5 |
|
| - |
|
| 3.2 |
|
| 0.4 |
|
| 4.1 |
|
| - |
Relating to Assets Sold During the Year |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 4.5 |
Purchases, Sales and Settlements |
|
| 9.6 |
|
| 0.3 |
|
| (4.4) |
|
| 16.0 |
|
| 21.5 |
|
| 1.2 |
Balance as of End of Year |
| $ | 10.1 |
| $ | 0.3 |
| $ | 23.4 |
| $ | 16.4 |
| $ | 50.2 |
| $ | 24.6 |
Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid/(received) for the Pension, SERP and PBOP Plans (millions of dollars):Plans:
|
| Pension |
| SERP |
| Postretirement |
| Government | ||||
NU Consolidated |
|
| ||||||||||
2009 |
| $ | 124.1 |
| $ | 2.3 |
| $ | 43.2 |
| $ | (3.9) |
2010 |
|
| 128.9 |
|
| 2.5 |
|
| 43.9 |
|
| (4.2) |
2011 |
|
| 132.4 |
|
| 2.7 |
|
| 44.2 |
|
| (4.6) |
2012 |
|
| 136.0 |
|
| 2.9 |
|
| 44.3 |
|
| (5.0) |
2013 |
|
| 140.8 |
|
| 3.1 |
|
| 44.6 |
|
| (5.3) |
2014-2018 |
|
| 805.1 |
|
| 17.4 |
|
| 224.8 |
|
| (31.3) |
NU |
| Pension |
| SERP |
| PBOP |
| Government | ||||
2011 |
| $ | 132.9 |
| $ | 2.9 |
| $ | 40.8 |
| $ | (4.1) |
2012 |
|
| 137.8 |
|
| 3.2 |
|
| 41.3 |
|
| (4.4) |
2013 |
|
| 143.4 |
|
| 3.3 |
|
| 41.8 |
|
| (4.8) |
2014 |
|
| 149.7 |
|
| 3.4 |
|
| 42.3 |
|
| (5.1) |
2015 |
|
| 155.7 |
|
| 3.4 |
|
| 42.7 |
|
| (5.5) |
2016-2020 |
|
| 886.8 |
|
| 18.6 |
|
| 216.4 |
|
| (31.8) |
The government benefits represent amounts expected to be received from the federal government for the new Medicare prescription drug benefit under the PBOP Plan related to the corresponding year's benefit payments.
Contributions: Currently, NU’sNU's policy is to annually fund the Pension Plan in an amount at least equal to an amount that will satisfy the requirements of ERISA and the Employee Retirement Income Security Act and Internal Revenue Code. NU's Pension Plan has historically been well funded, and a contribution has not been required to be made to the plan since 1991. Due to the underfunded balance at December 31, 2008,as of January 1, 2009, PSNH made a contribution of $45 million to the plan in the third quarter of 2010. Due to the underfunded balance as of January 1, 2010, NU is required to make aan additional contribution to the planPension Plan of approximately $150$145 million in 2011, which will be made in quarterly installments, to meet current minimum funding requirements. This contribution would be paid just prior to the 2009 federal income tax return filing in 2010.
For the PBOP Plan, it is currently NU's policy to annually fund an amount equal to the PBOP Plan’sPlan's postretirement benefit cost, excluding curtailment and termination benefits. NU contributed $36.2$41.8 million for the year ended December 31, 20082010 to fund the PBOP Plan and expects to make $37.3$42.8 million in contributions to the PBOP Plan in 2009. Beginning in 2007,2011. NU mademakes an additional contribution to the PBOP
138
Plan for the amounts received from the federal Medicare subsidy. This amount was $3.7$3.8 million in 20082010 and is estimated to be $3.4$4.1 million in 2009.2011.
FS-62
B.
Defined Contribution Plans
NU maintains a 401(k) Savings Plan for substantially all NU employees, including CL&P, PSNH and WMECO employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of three percent of eligible compensation with one percent in cash and two percent in NU common shares allocated from the Employee Stock Ownership Plan (ESOP).ESOP. The 401(k) matching contributions of cash and NU common shares made by NU were $12.7 million ($4 million for CL&P, $2.4 million for PSNH and $0.8 million for WMECO) in 2010, $12.2 million ($3.9 million for CL&P, $2.3 million for PSNH and $0.7 million for WMECO) in 2009, and $12 million ($4 million for CL&P, $2.3 million for PSNH and $0.7 million for WMECO) in 2008, $10.7 million ($3.6 million for CL&P, $2.2 million for PSNH and $0.7 million for WMECO) in 2007, and $11 million ($3.6 million for CL&P, $2.1 million for PSNH and $0.7 million for WMECO) in 2006.2008.
Effective on January 1, 2006, all newly hired, non-bargaining unit employees, and effective on January 1, 2007 or as subject to collective bargaining agreements, certain newly hired bargaining unit employees participate in a new program under the 401(k) savings planSavings Plan called the K-Vantage benefit. These employees are not eligible to participate in the existing defined benefit Pension Plan. In addition, participants in the Pension Plan atas of January 1, 2006 were given the opportunity to choose to become a participant in the K-Vantage benefit beginning in 2007, in which case their benefit under the Pension Plan would be frozen. NU makes contributions to the K-Vantage benefit based on a percentage of participants' eligible compensation, as defined by the benefit document. The contributions made by NU were $2$3.4 million ($173 thousand0.4 million for CL&P, $276 thousand$0.4 million for PSNH and $20 thousand$0.1 million for WMECO) in 2008, $12010, $2.6 million ($71 thousand(de minimis amounts for CL& amp;P and WMECO and $0.3 million for PSNH) in 2009, and $2 million (de minimis amounts for CL&P $139 thousandand WMECO and $0.3 million for PSNH and $9 thousand for WMECO)PSNH) in 2007 and $0.1 million ($6 thousand for CL&P, $23 thousand for PSNH and $2 thousand for WMECO) in 2006.2008.
C.
Employee Stock Ownership Plan
NU maintains an ESOP for purposes of allocating shares to NU, CL&P, PSNH, and WMECO's employees participating in NU’sNU's 401(k) Savings Plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were loaned to the ESOP trust (ESOP Notes) for the purchase of 10.8 million newly issued NU common shares (ESOP shares). The ESOP trust iswas obligated to make principal and interest payments to NU on the ESOP Notes at the same rate that ESOP shares arewere allocated to employees. Through December 31, 2008,employee accounts in the 401(k) Savings Plan. Under this arrangement, NU made annual contributions to the ESOP trust equal to the ESOP’sESOP's debt service, less dividends received by the ESOP. NU’sNU's contributions to the ESOP trust for the years ended December 31, 2010, 2009 and 2008 totaled $1.1 million, $6.1 million and $6 million, respectively. During 2010, the ESOP Notes were fully repaid and all ESOP s hares purchased with the proceeds of the ESOP Notes were fully allocated. Following complete allocation of the ESOP shares in 2008, $4.2 million2010, continuing allocations of NU common shares were made from NU treasury shares to satisfy the 401(k) Savings Plan obligation to provide a portion of the matching contribution in 2007NU common shares.
For treasury shares used to satisfy the 401(k) Savings Plan matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants. Any difference between the fair value and $8.2 million in 2006. Interest expense on the unsecured notes was $3.2 million in 2006.average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In. For the years ended December 31, 200 8, 20072010, 2009 and 2006,2008, NU recognized $8$8.5 million, $6.9$8.2 million and $7.4$8 million, respectively, of expense related to the ESOP, excluding the interest expense on the unsecured notes. The $75 million Series B note was fully repaid in March 2005. The $175 million Series A note was fully repaid in December 2006. As a result, no further interest expense is being incurred for the ESOP.
All dividends received by the ESOP on unallocated shares were used to pay debt service through December 31, 2006. Dividends on the ESOP unallocated shares are not considered dividends for financial reporting purposes. During the first and second quarters of 2007, NU paid a $0.1875 per share quarterly dividend. During the third quarter of 2007 through the second quarter of 2008, NU paid a $0.20 per share quarterly dividend. During the third and fourth quarters of 2008, NU paid a $0.2125 per share quarterly dividend. NU paid a $0.2375 per share quarterly dividend during the thirdin 2009 and fourth quarters of 2008.a $0.25625 per share quarterly dividend in 2010.
In 20082010 and 2007,2009, the ESOP trust allocated 469,601127,054 and 363,470542,724 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. AtAs of December 31, 2008 and 2007,2010, total allocated ESOP shares were 10,130,40710,800,185 and 9,660,806, respectively,there were no unallocated ESOP shares remaining. As of December 31, 2009, total allocated ESOP shares were 10,673,131 and total unallocated ESOP shares were 669,778 and 1,139,379, respectively.127,054. The fair market value of the unallocated ESOP shares atas of December 31, 2008 and 20072009 was $16.1 million and $35.7 million, respectively.$3.3 million.
D.
Share-Based Payments
NU maintains an Employee Share Purchase Plan (ESPP)ESPP and other long-term equity-based incentive plans under the Northeast UtilitiesNU Incentive Plan (Incentive Plan) in which NU, CL&P, PSNH, and WMECO employees and officers are entitled to participate. NU, CL&P, PSNH, and WMECO record compensation cost related to these plans, as applicable, for shares issued or sold to NU, CL&P, PSNH, and WMECO employees and officers, as well as the allocation of costs associated with shares issued or sold to NUSCO employees and officers that support CL&P, PSNH, and WMECO. In the first quarter of 2006, NU adopted SFAS No. 123(R), "Share-Based Payments," under the modified prospective method. Adoption of SFAS No. 123(R) had an immaterial effect on NU, CL&P, PSNH and WMECO’s financial statements and no effect on NU's EPS. For the years ended December 31, 2008 and 2007, tax expense in excess of compensat ion cost totaling $1.6 million and $3.2 million, respectively, increased cash flows from financing activities.
SFAS No. 123(R) requires thatIn accordance with accounting guidance for share-based payments, beshare-based compensation awards are recorded using the fair value-based method based on the fair value at the date of grant andgrant. This guidance applies to share-based compensation awards granted on or after January 1, 2006 or to awards for which the requisite service period has not been completed.
Under SFAS No. 123(R), NU accounts for its various share-based plans as follows:
·
For grants of restricted shares and restricted share units (RSUs),RSUs, NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the vesting period based upon the fair value of NU's common shares at the date of grant but records this expense net of estimated forfeitures.
·
grant. Dividend equivalents on RSUs are charged to retained earnings, net of estimated forfeitures.
·
For grants of performance shares, NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the vesting period. Performance shares vest based upon the achievement of Company targets. For the majority of performance shares, fair value is based upon the value of NU's common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets. The remaining performance shares are based upon
139
the achievement of the Company's share price as compared to an index of similar equity securities. The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the vesting period.
·
NU has not granted any stock options since 2002, and no compensation expense has been recorded. All options were fully vested prior to January 1, 2006.
·
For shares sold under the ESPP, an immaterial amountno compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan under relevant accounting guidance.
For the years ended December 31, 2010, 2009 and 2008, tax expense in excess of compensation expense was recorded in the first quarter of 2006,totaling $0.9 million, $0.9 million and no compensation expense will be recorded in future periods as a result of a plan amendment that was effective on February 1, 2006.
FS-63
$1.6 million, respectively, increased cash flows from financing activities.
NU Incentive Plan: Under the NU Incentive Plan, in which CL&P, PSNH and WMECO participate, NU is authorized to grant up to 4.5 million new shares for various types of awards, including restricted shares, RSUs, performance unitsshares and stock options to eligible employees and board members. AtAs of December 31, 20082010 and 2007,2009, NU had 2,705,6153,068,850 and 3,055,083 of2,363,521 common shares, respectively, available for issuance under the NU Incentive Plan.
Restricted Shares: NU has granted restricted shares under the 2002 through 2004 incentive programs that are subject to three-year and four-year graded vesting schedules. The remaining restricted shares of 6,250, with a per share and total weighted average grant-date fair value of $18.65 and $0.1 million, respectively,under these programs were fully vested in February 2008. The per shareas of December 31, 2008 and the total weighted average grant-date fair value for restricted shares vested was $14.14compensation cost recorded had a de minimis impact to NU, CL&P, PSNH and $0.8 million, respectively,WMECO for the year ended December 31, 2007 and $14.52 and $1.1 million, respectively, for the year ended December 31, 2006.
The total compensation cost recognized on an NU consolidated basis for restricted shares was $12 thousand, net of taxes of approximately $8 thousand for the year ended December 31, 2008, $58 thousand, net of taxes of approximately $39 thousand for the year ended December 31, 2007, and $0.6 million, net of taxes of approximately $0.4 million for the year ended December 31, 2006. In 2008, 2007 and 2006, the compensation cost had a de minimis impact to CL&P, PSNH and WMECO. 2008.
RSUs: NU has granted RSUs under the 2004 through 20082010 incentive programs that are subject to three-year and four-year graded vesting schedules for employees, and one-year graded vesting schedules for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings, subsequent to vesting. A summary of RSU transactions for the year ended December 31, 2008 is as follows:
|
| RSUs |
| Weighted |
| Total |
| Remaining |
| Weighted |
| RSUs |
| Weighted |
| Total |
Outstanding at December 31, 2007 |
| 831,000 |
| $22.99 |
|
|
|
|
|
| ||||||
Outstanding as of December 31, 2007 |
| 831,000 |
| $ 22.99 |
| $ 19.1 | ||||||||||
Granted |
| 352,482 |
| $26.82 |
| $ 9.5 |
|
|
|
|
| 352,482 |
| $ 26.82 |
| $ 9.5 |
Issued |
| (263,422) |
| $21.94 |
| $ 5.8 |
|
|
|
| ||||||
Shares issued |
| (263,422) |
| $ 21.94 |
| $ 5.8 | ||||||||||
Forfeited |
| (7,069) |
| $25.97 |
| $ 0.2 |
|
|
|
|
| (7,069) |
| $ 25.97 |
| $ 0.2 |
Outstanding at December 31, 2008 |
| 912,991 |
| $24.75 |
| $22.6 |
| $9.0 |
| 2.0 | ||||||
Outstanding as of December 31, 2008 |
| 912,991 |
| $ 24.75 |
| $ 22.6 | ||||||||||
Granted |
| 347,112 |
| $ 23.26 |
| $ 8.1 | ||||||||||
Shares issued |
| (203,888) |
| $ 25.55 |
| $ 5.2 | ||||||||||
Forfeited |
| (18,303) |
| $ 26.26 |
| $ 0.5 | ||||||||||
Outstanding as of December 31, 2009 |
| 1,037,912 |
| $ 24.07 |
| $ 25.0 | ||||||||||
Granted |
| 258,174 |
| $ 26.03 |
| $ 6.7 | ||||||||||
Shares issued |
| (267,951) |
| $ 25.05 |
| $ 6.7 | ||||||||||
Forfeited |
| (13,656) |
| $ 24.26 |
| $ 0.3 | ||||||||||
Outstanding as of December 31, 2010 |
| 1,014,479 |
| $ 24.31 |
| $ 24.7 |
The per share and total weighted average grant date fair value for RSUs granted was $28.83 and $9.5 million, respectively, for the year endedAs of December 31, 20072010 and $19.872009, the number and $7.4 million, respectively, for the year ended December 31, 2006. The weighted average grant-date fair value per share forof RSUs issuednot vested was $19.77519,900 and $18.50 for the years ended December 31, 2007$12.9 million, and 2006,571,673 and $15.2 million, respectively. The totalnumber and weighted average grant-date fair value of RSUs issuedvested during 2010 was $3.2317,866 and $8.3 million, and $2.2 million for the years endedrespectively. As of December 31, 20072010, 494,579 RSUs were fully vested and 2006, respectively. 493,905 are expected to vest.
On November 16, 2010, NU granted 192,309 RSUs to certain executives, contingent upon completion of the proposed merger with NSTAR, with a three year vesting period that would begin as of the date of completion of the merger.
140
Performance Shares: NU has granted performance shares under the 2009 and 2010 incentive programs that vest based upon the achievement of Company targets at the end of a three-year performance measurement period. Performance shares are paid in shares, subsequent to the performance measurement period. A summary of performance share transactions as follows:
Performance Shares |
| Performance |
| Weighted |
| Total |
Outstanding as of December 31, 2008 |
| - |
| $ - |
| $ - |
Granted |
| 104,150 |
| $ 23.93 |
| $ 2.5 |
Shares issued |
| - |
| $ - |
| $ - |
Forfeited |
| (5,064) |
| $ 23.96 |
| $ 0.1 |
Outstanding as of December 31, 2009 |
| 99,086 |
| $ 23.93 |
| $ 2.4 |
Granted |
| 149,520 |
| $ 25.24 |
| $ 3.8 |
Shares issued |
| - |
| $ - |
| $ - |
Forfeited |
| (47) |
| $ 23.96 |
| $ - |
Outstanding as of December 31, 2010 |
| 248,559 |
| $ 24.72 |
| $ 6.1 |
As of December 31, 2010, 120 percent of performance shares are expected to vest under the 2009 incentive program and 106 percent are expected to vest under the 2010 incentive program, based upon the probable outcome of certain performance metrics.
The total compensation cost recognized on anby NU consolidated basis (by CL&P, PSNH and WMECO) for RSUsshare-based compensation awards was $3.9$10.5 million ($2.46.2 million, $716 thousand$2.1 million and $407 thousand)$1.1 million), net of taxes of approximately$8.8 million ($5.3 million, $1.7 million and $0.9 million) and $6.5 million ($4 million, $1.2 million and $0.7 million) for the years ended December 31, 2010, 2009 and 2008, respectively. The associated future income tax benefit recognized was $4.2 million ($2.5 million, $0.9 million and $0.4 million), $3.5 million ($2.1 million, $0.7 million and $0.4 million) and $2.6 million ($1.6 million, $478 thousand$0.5 million and $271 thousand)$0.3 million) for the yearyears ended December 31, 2010, 2009 and 2008, $3.6 million ($2.3 million, $586 thousand and $387 thousand), netrespectively.
As of taxes of approximately $2.4 million ($1.5 million, $391 thousand and $258 thousand) for the year ended December 31, 20072010, there was $7.6 million of total unrecognized compensation cost related to nonvested share-based awards for NU, $4.5 million for CL&P, $1.4 million for PSNH and $2.8$0.9 million ($1.6 million, $440 thousandfor WMECO. This cost is expected to be recognized ratably over a weighted-average period of 1.75 years for NU, 1.76 years for CL&P, 1.69 years for PSNH and $271 thousand), net of taxes of approximately $1.9 million ($1 million, $290 thousand and $181 thousand)1.75 years for the year ended December 31, 2006.WMECO.
Stock Options: Prior to 2003, NU granted stock options to certain employees. The options expire ten years from the date of grant. These options were fully vested as of December 31, 2005. The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model. The weighted average remaining contractual lives for the options outstanding atas of December 31, 20082010 is 2.41.0 years. A summary of stock option transactions is as follows:
|
|
|
| Exercise Price Per Share |
|
|
|
|
| Exercise Price Per Share |
|
| ||||||||
|
|
|
|
|
| Weighted |
| Intrinsic |
| Options |
| Range |
| Weighted |
| Intrinsic Value | ||||
|
|
|
|
|
|
|
| (Millions) | ||||||||||||
Outstanding and exercisable - December 31, 2005 |
| 1,122,541 |
| $14.9375 | - | $22.2500 |
| $18.4484 |
|
| ||||||||||
Exercised |
| (331,943) |
|
|
|
|
| $18.3579 |
| $2.0 | ||||||||||
Forfeited and cancelled |
| (18,750) |
|
|
|
|
| $20.8885 |
|
| ||||||||||
Outstanding and exercisable - December 31, 2006 |
| 771,848 |
| $14.9375 | - | $22.2500 |
| $18.4245 |
|
| ||||||||||
Exercised |
| (372,168) |
|
|
|
|
| $18.5005 |
| $4.8 | ||||||||||
Forfeited and cancelled |
| (2,500) |
|
|
|
|
| $21.0300 |
|
| ||||||||||
Outstanding and exercisable - December 31, 2007 |
| 397,180 |
| $14.9375 | - | $21.0300 |
| $18.3369 |
|
|
| 397,180 |
| $ 14.9375 | - | $ 21.0300 |
| $ 18.3369 |
|
|
Exercised |
| (76,260) |
|
|
|
|
| $16.2473 |
| $0.6 |
| (76,260) |
|
|
|
|
| $ 16.2473 |
| $ 0.6 |
Forfeited and cancelled |
| - |
|
|
|
|
| - |
|
|
| - |
|
|
|
|
| $ - |
|
|
Outstanding and exercisable - December 31, 2008 |
| 320,920 |
| $14.9375 | - | $21.0300 |
| $18.8335 |
| $1.7 |
| 320,920 |
| $ 14.9375 | - | $ 21.0300 |
| $ 18.8335 |
|
|
Exercised |
| (95,704) |
|
|
|
|
| $ 18.5418 |
| $ 0.6 | ||||||||||
Forfeited and cancelled |
| - |
|
|
|
|
| $ - |
|
| ||||||||||
Outstanding and exercisable - December 31, 2009 |
| 225,216 |
| $ 17.4000 | - | $ 21.0300 |
| $ 18.9574 |
| |||||||||||
Exercised |
| (112,617) |
|
|
|
|
| $ 19.1196 |
| $ 1.0 | ||||||||||
Forfeited and cancelled |
| - |
|
|
|
|
| $ - |
| |||||||||||
Outstanding and exercisable - December 31, 2010 |
| 112,599 |
| $17.4000 | - | $21.0300 |
| $ 18.7952 |
| $ 1.5 |
Cash received for options exercised during the year ended December 31, 20082010 totaled $1.2$2.2 million. The tax benefit realized from stock options exercised totaled $0.3$0.4 million for the year ended December 31, 2008.
FS-64
2010.
Employee Share Purchase Plan: NU maintains an ESPP for all eligible NU, CL&P, PSNH, and WMECO employees, which allows for NU common shares to be purchased by employees at six-month intervals at 95 percent of the closing market price on the last day of each six-month period. Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the purchase period.period up to a limit of $25,000 per annum. The ESPP qualifies as a non-compensatory plan under SFAS No. 123(R),accounting guidance for share-based payments, and no compensation expense will beis recorded for ESPP purchases.
During 20082010 and 2007,2009, employees purchased 31,25038,672 and 26,45139,264 shares, respectively, at discounted prices of $26.40$26.45 and $23.90$24.05 in 20082010 and $26.27$22.61 and $25.97$21.86 in 2007. At2009. As of December 31, 20082010 and 2007, 1,010,1142009, 932,178 and 1,041,364970,850 shares, respectively, remained available for future issuance under the ESPP, respectively.ESPP.
An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards. The Company generally settles stock option exercises and fully vested RSUs and performance shares with the issuance of new common shares.
141
E.
Other Retirement Benefits
NU provides benefits for retirement and other benefits for certain current and past company officers.officers of NU, including CL&P, PSNH and WMECO. The actuarially-determined liability for these benefits, which is included in deferred credits and other liabilities - otherOther Long-Term Liabilities on the accompanying consolidated balance sheets, was $45.4$49.9 million ($0.4 million for CL&P, $2.4 million for PSNH and $46.4$0.2 million atfor WMECO) and $47.9 million ($0.4 million for CL&P, $2.4 million for PSNH and $0.2 million for WMECO) as of December 31, 20082010 and 2007,2009, respectively. During 2010, 2009 and 2008, 2007$4.2 million ($2.3 million for CL&P, $0.9 million for PSNH and 2006,$0.4 million for WMECO), $3.9 million ($2.2 million for CL&P, $0.9 million for PSNH and $0.4 million for WMECO) and $3.8 million $8.4($2.2 million for CL&P, $0.8 million for PSNH and $5.6$0.4 million for WMECO), respectively, was expensed related to these benefits. These benefits area re accounted for on an accrual basis and expensed over the service lives of the employees in accordance with the Accounting Principles Board Opinion (APB) No. 12, "Deferred Compensation Contracts."accounting guidance for deferred compensation contracts.
6.11.
Goodwill and Other Intangible Assets (Yankee Gas)INCOME TAXES
SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewedThe tax effect of temporary differences is accounted for impairment at least annually by applying a fair value-based test. NU uses October 1stasin accordance with the annual goodwill impairment testing date. However, if an event occurs or circumstances change that would indicate that goodwill might be impaired, NU management would test the goodwill between the annual testing dates. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair valuerate-making treatment of the reporting unitapplicable regulatory commissions and relevant accounting authoritative literature. Details of income tax expense and the components of the federal and state income tax provisions are as follows:
|
| For the Years Ended December 31, | |||||||
|
| 2010 |
| 2009 |
| 2008 | |||
(Millions of Dollars) |
| NU |
| NU |
| NU | |||
Current Income Taxes: |
|
|
|
|
|
|
|
|
|
Federal |
| $ | 9.0 |
| $ | 4.5 |
| $ | 6.0 |
State |
|
| (6.5) |
|
| 52.7 |
|
| 16.3 |
Total Current |
|
| 2.5 |
|
| 57.2 |
|
| 22.3 |
Deferred Income Taxes, Net: |
|
|
|
|
|
|
|
|
|
Federal |
|
| 201.2 |
|
| 155.1 |
|
| 100.2 |
State |
|
| 9.7 |
|
| (29.2) |
|
| (13.4) |
Total Deferred |
|
| 210.9 |
|
| 125.9 |
|
| 86.8 |
Investment Tax Credits, Net |
|
| (3.0) |
|
| (3.2) |
|
| (3.4) |
Income Tax Expense |
| $ | 210.4 |
| $ | 179.9 |
| $ | 105.7 |
|
| For the Years Ended December 31, | |||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | |||||||||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||||
Current Income Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Federal |
| $ | 20.7 |
| $ | 6.1 |
| $ | 3.1 |
| $ | 28.3 |
| $ | (8.9) |
| $ | (8.6) |
| $ | 13.9 |
| $ | 0.8 |
| $ | (1.4) |
State |
|
| (1.1) |
|
| 5.6 |
|
| 2.5 |
|
| 40.1 |
|
| 5.8 |
|
| 0.9 |
|
| 19.0 |
|
| (3.6) |
|
| - |
Total Current |
|
| 19.6 |
|
| 11.7 |
|
| 5.6 |
|
| 68.4 |
|
| (3.1) |
|
| (7.7) |
|
| 32.9 |
|
| (2.8) |
|
| (1.4) |
Deferred Income Taxes, Net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| &n bsp; |
|
Federal |
|
| 108.1 |
|
| 37.6 |
|
| 11.0 |
|
| 80.5 |
|
| 34.4 |
|
| 21.3 |
|
| 68.0 |
|
| 17.4 |
|
| 10.4 |
State |
|
| 7.0 |
|
| 1.6 |
|
| - |
|
| (27.6) |
|
| 0.8 |
|
| 1.6 |
|
| (20.4) |
|
| 7.6 |
|
| 1.8 |
Total Deferred |
|
| 115.1 |
|
| 39.2 |
|
| 11.0 |
|
| 52.9 |
|
| 35.2 |
|
| 22.9 |
|
| 47.6 |
|
| 25.0 |
|
| 12.2 |
Investment Tax Credits, Net |
|
| (2.3) |
|
| (0.1) |
|
| (0.3) |
|
| (2.5) |
|
| (0.1) |
|
| (0.3) |
|
| (2.6) |
|
| (0.2) |
|
| (0.2) |
Income Tax Expense |
| $ | 132.4 |
| $ | 50.8 |
| $ | 16.3 |
| $ | 118.8 |
| $ | 32.0 |
| $ | 14.9 |
| $ | 77.9 |
| $ | 22.0 |
| $ | 10.6 |
A reconciliation between income tax expense and the expected tax expense at the statutory rate is less than the carrying amount.as follows:
|
| For the Years Ended December 31, | ||||||||||
|
| 2010 |
| 2009 |
| 2008 | ||||||
(Millions of Dollars, except percentages) |
| NU |
| NU |
| NU | ||||||
Income Before Income Tax Expense |
| $ | 604.5 |
|
| $ | 515.5 |
|
| $ | 372.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statutory Federal Income Tax Expense at 35% |
|
| 211.6 |
|
|
| 180.4 |
|
|
| 130.2 |
|
Tax Effect of Differences: |
|
|
|
|
|
|
|
|
| &nb sp; |
|
|
Depreciation |
|
| (9.5) |
|
|
| (2.7) |
|
|
| (12.9) |
|
Investment Tax Credit Amortization |
|
| (3.0) |
|
|
| (3.2) |
|
|
| (3.4) |
|
Other Federal Tax Credits |
|
| (3.8) |
|
|
| (3.8) |
|
|
| (4.6) |
|
State Income Taxes, Net of Federal Impact |
|
| 12.5 |
|
|
| 11.5 |
|
|
| (9.5) |
|
Medicare Subsidy |
|
| 15.6 |
|
|
| (3.5) |
|
|
| (4.2) |
|
Tax Asset Valuation Allowance/Reserve Adjustments |
|
| (10.5) |
|
|
| 3.8 |
|
|
| 12.5 |
|
Other, Net |
|
| (2.5) |
|
|
| (2.6) |
|
|
| (2.4) |
|
Income Tax Expense |
| $ | 210.4 |
|
| $ | 179.9 |
|
| $ | 105.7 |
|
Effective Tax Rate |
|
| 34.8 | % |
|
| 34.9 | % |
|
| 28.4 | % |
142
NU’s reporting units are consistent with the operating segments underlying the reportable segments identified in Note 17, "Segment Information," to the consolidated financial statements. The only reporting unit that maintains goodwill is the Yankee Gas reporting unit, which was classified under the regulated companies - gas reportable segment. The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas. The goodwill balance held by the Yankee Gas reporting unit at December 31, 2008 and 2007 is $287.6 million.
|
| For the Years Ended December 31, | |||||||||||||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | |||||||||||||||||||||||||||||||
(Millions of Dollars, except percentages) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||||||||||||||||
Income Before Income Tax |
| $ | 376.6 |
|
| $ | 140.9 |
|
| $ | 39.4 |
|
| $ | 335.2 |
|
| $ | 97.6 |
|
| $ | 41.1 |
|
| $ | 269.0 |
|
| $ | 80.1 |
|
| $ | 28.9 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Statutory Federal Income Tax |
|
| 131.8 |
|
|
| 49.3 |
|
|
| 13.8 |
|
|
| 117.3 |
|
|
| 34.1 |
|
|
| 14.4 |
|
|
| 94.2 |
|
|
| 28.0 |
|
|
| 10.1 |
| |
Tax Effect of Differences: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depreciation |
|
| (6.1) |
|
|
| (3.2) |
|
|
| 0.2 |
|
|
| (1.7) |
|
|
| (1.2) |
|
|
| 0.3 |
|
|
| (11.1) |
|
|
| (1.8) |
|
|
| 0.1 |
| |
Investment Tax Credit |
|
| (2.3) |
|
|
| (0.1) |
|
|
| (0.3) |
|
|
| (2.5) |
|
|
| (0.1) |
|
|
| (0.3) |
|
|
| (2.6) |
|
|
| (0.2) |
|
|
| (0.2) |
| |
Other Federal Tax Credits |
|
| (0.1) |
|
|
| (3.6) |
|
|
| - |
|
|
| (0.1) |
|
|
| (3.7) |
|
|
| - |
|
|
| (1.2) |
|
|
| (3.4) |
|
|
| - |
| |
State Income Taxes, Net of |
|
| 8.5 |
|
|
| 4.7 |
|
|
| 1.6 |
|
|
|
|
|
|
| 4.3 |
|
|
| 1.6 |
|
|
| (18.5) |
|
|
| 2.6 |
|
|
| 1.2 |
| |
Medicare Subsidy |
|
| 7.8 |
|
|
| 3.8 |
|
|
| 1.5 |
|
|
| (1.3) |
|
|
| (0.6) |
|
|
| (0.3) |
|
|
| (1.5) |
|
|
| (0.8) |
|
|
| (0.4) |
| |
Tax Asset Valuation Allowance/ |
|
| (4.7) |
|
|
| - |
|
|
| - |
|
|
| (0.8) |
|
|
|
|
|
|
|
|
|
|
| 19.8 |
|
|
|
|
|
|
|
|
| |
Other, Net |
|
| (2.5) |
|
|
| (0.1) |
|
|
| (0.5) |
|
|
| (1.0) |
|
|
| (0.8) |
|
|
| (0.8) |
|
|
| (1.2) |
|
|
| (2.4) |
|
|
| (0.2) |
| |
Income Tax Expense |
| $ | 132.4 |
|
| $ | 50.8 |
|
| $ | 16.3 |
|
| $ | 118.8 |
|
| $ | 32.0 |
|
| $ | 14.9 |
|
| $ | 77.9 |
|
| $ | 22.0 |
|
| $ | 10.6 |
| |
Effective Tax Rate |
|
| 35.2 | % |
|
| 36.1 | % |
|
| 41.4 | % |
|
| 35.4 | % |
|
| 32.8 | % |
|
| 36.3 | % |
|
| 28.9 | % |
|
| 27.5 | % |
|
| 36.7 | % |
NU, completed its impairment analysis of the Yankee Gas goodwill balance as of October 1, 2008CL&P, PSNH, and determined that no impairment exists. In completing this analysis, the fair value of the reporting unit was estimated usingWMECO file a discounted cash flow methodologyconsolidated federal income tax return and analyses of comparable companiesunitary, combined and transactions.separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.
7.The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:
Commitments and Contingencies
|
| As of December 31, | ||||
|
| 2010 |
| 2009 | ||
(Millions of Dollars) |
| NU |
| NU | ||
Deferred Tax Liabilities - Current: |
|
|
|
|
|
|
Derivative Asset and Change in Fair Value of Energy Contracts |
| $ | 3.2 |
| $ | 8.5 |
Property Tax Accruals and Other |
|
| 63.1 |
|
| 49.3 |
Total Deferred Tax Liabilities - Current |
|
| 66.3 |
|
| 57.8 |
Deferred Tax Assets - Current: |
|
|
|
|
|
|
Derivative Liability and Change in Fair Value of Energy Contracts |
|
| 23.9 |
|
| 17.5 |
Allowance for Uncollectible Accounts and Other |
|
| 91.8 |
|
| 50.1 |
Total Deferred Tax Assets - Current |
|
| 115.7 |
|
| 67.6 |
Net Deferred Tax Assets - Current |
|
| 49.4 |
|
| 9.8 |
Deferred Tax Liabilities - Long-Term: |
|
|
|
|
|
|
Accelerated Depreciation and Other Plant-Related Differences |
|
| 1,612.6 |
|
| 1,351.0 |
Regulatory Amounts: |
|
|
|
|
|
|
Securitized Contract Termination Costs |
|
| 65.8 |
|
| 101.6 |
Other Regulatory Deferrals |
|
| 873.3 |
|
| 848.6 |
Tax Effect - Tax Regulatory Assets |
|
| 177.1 |
|
| 179.8 |
Derivative Assets |
|
| 44.8 |
|
| 71.6 |
Other |
|
| 18.3 |
|
| 28.2 |
Total Deferred Tax Liabilities - Long-Term |
|
| 2,791.9 |
|
| 2,580.8 |
Deferred Tax Assets – Long-Term: |
|
|
|
|
|
|
Regulatory Deferrals |
|
| 135.5 |
|
| 133.0 |
Employee Benefits |
|
| 457.8 |
|
| 493.1 |
Tax Effect - Tax Regulatory Assets |
|
| 17.0 |
|
| 25.8 |
Derivative Liability |
|
| 352.6 |
|
| 374.9 |
Other |
|
| 154.9 |
|
| 193.7 |
Total Deferred Tax Assets - Long-Term |
|
| 1,117.8 |
|
| 1,220.5 |
Less: Valuation Allowance |
|
| 19.8 |
|
| 19.8 |
Net Deferred Tax Assets - Long-Term |
|
| 1,098.0 |
|
| 1,200.7 |
Net Deferred Tax Liabilities - Long-Term |
|
| 1,693.9 |
|
| 1,380.1 |
Net Deferred Tax Liabilities |
| $ | 1,644.5 |
| $ | 1,370.3 |
|
|
|
|
|
|
|
Total Deferred Tax Assets |
| $ | 1,233.5 |
| $ | 1,288.1 |
Total Deferred Tax Liabilities |
| $ | 2,858.2 |
| $ | 2,638.6 |
143
A.
Regulatory Developments and Rate Matters (CL&P, Yankee Gas, PSNH, WMECO)
Connecticut:
|
| As of December 31, | ||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||
(Millions of Dollars) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Deferred Tax Assets - Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liability and Change in Fair Value |
| $ | 18.7 |
| $ | 5.1 |
| $ | - |
| $ | 2.6 |
| $ | 7.4 |
| $ | - |
Allowance for Uncollectible Accounts and Other |
|
| 60.2 |
|
| 11.2 |
|
| 2.0 |
|
| 25.3 |
|
| 6.0 |
|
| 2.8 |
Total Deferred Tax Assets – Current |
|
| 78.9 |
|
| 16.3 |
|
| 2.0 |
|
| 27.9 |
|
| 13.4 |
|
| 2.8 |
Deferred Tax Liabilities - Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets and Change in Fair Value |
|
| 3.1 |
|
| - |
|
| - |
|
| 8.3 |
|
| 0.2 |
|
| - |
Property Tax Accruals and Other |
|
| 43.4 |
|
| 5.6 |
|
| 3.7 |
|
| 31.2 |
|
| 5.1 |
|
| 3.0 |
Total Deferred Tax Liabilities – Current |
|
| 46.5 |
|
| 5.6 |
|
| 3.7 |
|
| 39.5 |
|
| 5.3 |
|
| 3.0 |
Net Deferred Tax Liabilities/(Assets) - Current |
|
| (32.4) |
|
| (10.7) |
|
| 1.7 |
|
| 11.6 |
|
| (8.1) |
|
| 0.2 |
Deferred Tax Assets - Long-Term: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Deferrals |
|
| 68.9 |
|
| 34.4 |
|
| 6.5 |
|
| 70.0 |
|
| 36.2 |
|
| 5.4 |
Employee Benefits |
|
| 63.9 |
|
| 121.8 |
|
| 1.8 |
|
| 85.2 |
|
| 135.1 |
|
| 8.3 |
Income Tax Gross-Up |
|
| 7.4 |
|
| 1.6 |
|
| 6.9 |
|
| 12.8 |
|
| 2.2 |
|
| 7.2 |
Derivative Liability |
|
| 352.5 |
|
| - |
|
| - |
|
| 364.5 |
|
| 3.0 |
|
| - |
Other |
|
| 56.8 |
|
| 8.5 |
|
| 14.3 |
|
| 88.8 |
|
| 9.5 |
|
| 8.4 |
Net Deferred Tax Assets – Long-Term |
|
| 549.5 |
|
| 166.3 |
|
| 29.5 |
|
| 621.3 |
|
| 186.0 |
|
| 29.3 |
Deferred Tax Liabilities - Long-Term: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accelerated Depreciation and Other |
|
| 917.0 |
|
| 309.8 |
|
| 168.4 |
|
| 754.1 |
|
| 263.1 |
|
| 152.8 |
Regulatory Amounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securitized Contract Termination Costs |
|
| (0.8) |
|
| 50.4 |
|
| 16.2 |
|
| 9.6 |
|
| 69.9 |
|
| 22.1 |
Other Regulatory Deferrals |
|
| 546.6 |
|
| 105.1 |
|
| 51.1 |
|
| 536.2 |
|
| 111.1 |
|
| 51.2 |
Income Tax Gross-Up |
|
| 138.5 |
|
| 14.0 |
|
| 13.7 |
|
| 145.3 |
|
| 10.9 |
|
| 14.0 |
Derivative Assets |
|
| 44.8 |
|
| - |
|
| - |
|
| 71.4 |
|
| - |
|
| - |
Other |
|
| 4.5 |
|
| 14.3 |
|
| 2.4 |
|
| 6.2 |
|
| 6.7 |
|
| 0.6 |
Total Deferred Tax Liabilities - Long-Term |
|
| 1,650.6 |
|
| 493.6 |
|
| 251.8 |
|
| 1,522.8 |
|
| 461.7 |
|
| 240.7 |
Net Deferred Tax Liabilities - Long-Term |
|
| 1,101.1 |
|
| 327.3 |
|
| 222.3 |
|
| 901.5 |
|
| 275.7 |
|
| 211.4 |
Net Deferred Tax Liabilities |
| $ | 1,068.7 |
| $ | 316.6 |
| $ | 224.0 |
| $ | 913.1 |
| $ | 267.6 |
| $ | 211.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Assets |
| $ | 628.4 |
| $ | 182.6 |
| $ | 31.5 |
| $ | 649.2 |
| $ | 199.4 |
| $ | 32.1 |
Total Deferred Tax Liabilities |
| $ | 1,697.1 |
| $ | 499.2 |
| $ | 255.5 |
| $ | 1,562.3 |
| $ | 467.0 |
| $ | 243.7 |
CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, suchNet Deferred Tax Liabilities/(Assets) - Current are recorded as securitization costs associated with its RRBs, amortization of regulatorycurrent liabilities or assets and IPP over-market costs, while the SBC allows CL&P to recover certain regulatoryare included in Other Current Liabilities or Prepayments and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.
On March 31, 2008, CL&P filed with the DPUC its 2007 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements. For the 12 months ended December 31, 2007, total CTA revenues exceeded CTA revenue requirements by $26.1 million, which has been recorded as a decrease to the CTA regulatory assetOther Current Assets, respectively, on the accompanying consolidated balance sheet. For the 12 months endedsheets.
As of December 31, 2007, the SBC cost2010, NU had state net operating loss carryforwards of service exceeded SBC revenues$317.7 million that expire between December 31, 2011 and December 31, 2027 and state credit carryforwards of $84.9 million that begin expiring in 2013. As of December 31, 2009, NU had state net operating loss carryforwards of $323.9 million that expire between December 31, 2010 and December 31, 2027 and state credit carryforwards of $88.7 million that expire by $39.4 million, whichDecember 31, 2014. The net operating loss carryforward deferred tax asset has been recorded asfully reserved by a regulatory asset on the accompanying consolidated balance sheet.
Onvaluation allowance. As of December 3, 2008, the DPUC issued a final decision in this docket31, 2010, CL&P had state tax credit carryforwards of $56.1 million that approved the 2007 CTA and SBC reconciliations with minor modifications. The decision referred to a potential change in the CTA rate effective January 1,expire by 2014. As of December 31, 2009, when new rates were to be determined for all CL&P rate components. By letter dated December 23, 2008, the DPUC approved CL&P’s recommendation to slightly decrease the base CTA rate and to establish a separate CTA refundhad state tax credit beginning January 1, 2009. The CTA refund credit is intended to return to customers over a twelve month period a projected 2008 CTA overrecoverycarryforwards of $46.2$61.1 million plus $1.8 million of incremental distribution revenues attributable to accelerating CL&P’s previously allowed 2009 distribution rate increase from a start date of February 1, 2009 to January 1, 2009. The DPUC also approved an increase in the SBC rate to bill an additional $1 1.7 million in 2009, which should enable CL&P to fully recover 2009 SBC expenses plus expenses that were underrecovered in prior periods.expire by 2014.
Procurement Fee Rate Proceedings:Unrecognized Tax Benefits:As of December 31, 2010, NU and CL&P was allowed to collect a fixed procurement feehad unrecognized tax benefits totaling $101.2 million and $80.8 million, respectively, all of 0.50 mills per kilowatt-hour (KWH) from customers that purchased TSO service from 2004 throughwhich would impact the endeffective tax rate if recognized. As of 2006. One mill is equal to one tenthDecember 31, 2009, NU and CL&P had unrecognized tax benefits totaling $124.3 million and $89 million, respectively, all of a cent. In prior years, CL&P submitted towhich would impact the DPUC its proposed methodology to calculateeffective tax rate if recognized. As of December 31, 2008, the variable incentive portion of its transition service procurementNU and CL&P unrecognized tax benefits that would impact the effective tax rate, if recognized, were $120 million and $87 million, respectively. A reconciliation of the activity in unrecognized tax benefits from January 1, 2008 to December 31, 2010 is as follows:
FS-65144
fee, which was effective through 2006,
(Millions of Dollars) |
| NU |
| CL&P |
| PSNH |
| WMECO | ||||
Balance as of January 1, 2008 |
| $ | 121.1 |
| $ | 75.9 |
| $ | 10.6 |
| $ | 2.9 |
Gross Increases - Current Year |
|
| 28.6 |
|
| 24.9 |
|
| - |
|
| - |
Gross Increases - Prior Year |
|
| 7.4 |
|
| 5.6 |
|
| 1.8 |
|
| 0.9 |
Lapse of Statute of Limitations |
|
| (0.8) |
|
| - |
|
| - |
|
| - |
Balance as of December 31, 2008 |
|
| 156.3 |
|
| 106.4 |
|
| 12.4 |
|
| 3.8 |
Gross Increases - Current Year |
|
| 12.3 |
|
| 8.6 |
|
| - |
|
| - |
Settlement |
|
| (44.2) |
|
| (26.0) |
|
| (12.4) |
|
| (3.8) |
Lapse of Statute of Limitations |
|
| (0.1) |
|
| - |
|
| - |
|
| - |
Balance as of December 31, 2009 |
|
| 124.3 |
|
| 89.0 |
|
| - |
|
| - |
Gross Increases - Current Year |
|
| 10.8 |
|
| 5.3 |
|
| - |
|
| - |
Gross Increases - Prior Year |
|
| 0.8 |
|
| - |
|
| - |
|
| - |
Settlement |
|
| (34.3) |
|
| (13.5) |
|
| - |
|
| - |
Lapse of Statute of Limitations |
|
| (0.4) |
|
| - |
|
| - |
|
| - |
Balance as of December 31, 2010 |
| $ | 101.2 |
| $ | 80.8 |
| $ | - |
| $ | - |
Interest and requested approvalPenalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense. However, when resolution of uncertainties results in the pre-tax $5.8 million 2004 incentive fee. CL&P has not recorded amountsCompany receiving interest income, any related to the 2005 or 2006 procurement fee in earnings.CL&P recovered the $5.8 million pre-tax amount, which wasinterest benefit is recorded in 2005 earnings throughOther Income, Net on the CTA reconciliation process. On January 15,accompanying consolidated statements of income. No penalties have been recorded. The components of interest on uncertain tax positions by company in 2010, 2009 the DPUC issued a final decision confirming its Decemberand 2008 draft decision in this docket that reversed its December 2005 draft decision and stated that CL&P was not eligible for the procurement incentive compensation for 2004. A $5.8 million pre-tax charge was recordedare as follows:
Other Interest |
| For the Years Ended December 31, |
| Accrued Interest |
| As of December 31, | |||||||||||
Expense/(Income) |
| 2010 |
| 2009 |
| 2008 |
| Expense/(Income) |
| 2010 |
| 2009 | |||||
(Millions of Dollars) |
|
|
|
|
|
|
|
|
|
| (Millions of Dollars) |
|
|
|
|
|
|
CL&P |
| $ | (7.4) |
| $ | (4.2) |
| $ | 4.8 |
| CL&P |
| $ | 6.4 |
| $ | 13.8 |
PSNH |
|
| 0.1 |
|
| (1.3) |
|
| - |
| PSNH |
|
| 0.6 |
|
| 0.5 |
WMECO |
|
| - |
|
| (0.4) |
|
| 0.2 |
| WMECO |
|
| - |
|
| - |
NU Parent and Other |
|
| (17.5) |
|
| 1.9 |
|
| 3.2 |
| NU Parent and Other |
|
| 2.9 |
|
| 20.4 |
Total |
| $ | (24.8) |
| $ | (4.0) |
| $ | 8.2 |
| Total |
| $ | 9.9 |
| $ | 34.7 |
Tax Positions: During 2010, NU settled various tax matters including state obligations, which resulted in the 2008 earningsrecognition during the year of an after-tax gain of approximately $35 million. This gain is recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $6 million and an obligation$4 million, respectively). NU is currently working to refundresolve the $5.8 milliontreatments of certain timing and other costs in the remaining open periods.
Tax Years: The following table summarizes NU, CL&P, PSNH and WMECO's tax years that remain subject to customers has been establishedexamination by major tax jurisdictions as of December 31, 2008.2010:
Description | Tax Years | |
Federal | 2009-2010 | |
Connecticut | 2005-2010 | |
New Hampshire | 2007-2010 | |
Massachusetts | 2007-2010 |
While tax audits are currently ongoing, it is reasonably possible that one or more of these open tax years could be resolved within the next twelve months. Management estimates that potential resolutions of differences of a non-timing nature, could result in a zero to $77 million decrease in unrecognized tax benefits by NU and a zero to $67 million decrease in unrecognized tax benefits by CL&P filed&P. These estimated changes could have an appealimpact on NU's and CL&P's 2011 earnings of this decision on February 26, 2009.zero to $38 million and zero to $34 million, respectively. Other companies’ impacts are not expected to be material.
C2 Prudency Audit: 2010 Federal Legislation:Pursuant On March 23, 2010, President Obama signed into law the 2010 Healthcare Act. The 2010 Healthcare Act was amended by a Reconciliation Bill signed into law on March 30, 2010. The 2010 Healthcare Act includes a provision that eliminated the tax deductibility of certain PBOP contributions equal to the decision in CL&P's 2007 rate case,amount of the DPUC has hired a consulting firm to perform a prudency audit of certain costs incurred in the implementation of a new customer service system (C2) at CL&P. The audit began on December 1, 2008 and will be ongoing through early 2009,federal subsidy received by companies like NU, which sponsor retiree health care benefit plans with a final reportprescription drug benefit that is actuarially equivalent to Medicare Part D. The tax deduction eliminated by this legislation represented a loss of previously recognized deferred income tax assets established through 2009 and as a result, these assets were written down by approximately $18 million in 2010. Since the DPUC due March 31, 2009. The DPUC has stated its intentions to openelectric and natural gas distribution companies are cost-of-service and rate-regulated, a docket to review the findingsportion of the audit after completion. Management continues to believe that its C2 expenses were prudent and will be recovered in rates.
Purchased Gas Adjustment: In 2005 and 2006, the DPUC issued decisions regarding Yankee Gas’ PGA clause charges and required an audit of previously recovered PGA revenues of approximately $11$18 million associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005. On June 11, 2008, the DPUC issued a final order requiring Yankee Gas to refund approximately $5.8 million in previous recoveries to its customers. The $5.8 million pre-tax charge was recorded in the 2008 earnings of Yankee Gas.
New Hampshire:
ES and SCRC Reconciliation: On an annual basis, PSNH files with the NHPUC an ES and stranded cost recovery charge (SCRC) reconciliation filing for the preceding year. On May 1, 2008, PSNH filed its 2007 ES and SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation activities. During 2007, ES and SCRC revenues exceeded ES and SCRC costs by $1.4 million and $6.8 million, respectively, and were deferred as a regulatory liabilityis able to be refunded to customers. On November 19, 2008, PSNHdeferred and the NHPUC Staff submitted a settlement agreement that resolved all outstanding issues. The NHPUC issued an order dated January 16, 2009 that accepted the settlement as filed. The settlement agreement and subsequent order did not have a material adverse impact on PSNH's financial position or results of operations.
Massachusetts:
Transition Cost Reconciliation: On July 18, 2008, WMECO filed its 2007 transition cost (TC) reconciliation with the DPU, which compared TC revenue and revenue requirements.recovered th rough future rates. For the twelve monthsyear ended December 31, 2007, total TC revenues along with carrying charges exceeded TC revenue requirements2010, NU deferred approximately $15 million of recoverable write-offs related to these businesses and reduced 2010 earnings on a net basis by $2.6approximately $3 million which has been recordedof non-recoverable costs. In addition, as a regulatory liability on the accompanying consolidated balance sheets. A public hearing and procedural conference was held on November 20, 2008. On December 22, 2008, the Massachusetts Attorney General filed testimony on two topics, the deferred return and carrying charges on the Capital Project Scheduling List and the recovery of Northeast Nuclear Company pension/PBOP costs. WMECO filed rebuttal testimony on December 30, 2008. A hearing was held January 29, 2009. The briefing period ended on February 26, 2009. There is no timeli ne for a DPU decision. Management does not expect the outcomeresult of the DPU's reviewelimination of this filingthe tax deduction in 2010, NU was not able to have a material adverse effect on WMECO's financial position or resultsrecognize approximately $2 million of operations.net annual benefits.
B.On September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010, which extends the bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009 to small and large businesses through 2010. This extended stimulus provided NU with cash flow benefits of approximately $100 million.
145
On December 17, 2010, President Obama signed into law the 2010 Tax Act, which, among other things, provides 100 percent bonus depreciation for tangible personal property placed in service after September 8, 2010, and through December 31, 2011. For tangible personal property placed in service after December 31, 2011, and through December 31, 2012, the 2010 Tax Act provides for 50 percent bonus depreciation.
12.
COMMITMENTS AND CONTINGENCIES
A.
Environmental Matters (CL&P, PSNH, WMECO, HWP)
General: NU, CL&P, PSNH, and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. As such, NU, CL&P, PSNH, and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.
These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of NU, CL&P, PSNH, and WMECO's responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
The amounts recorded as environmental liabilities included in Other Long-Term Liabilities on the accompanying consolidated balance sheets represent management’smanagement's best estimate of the liability for environmental costs, if reasonably estimable, and take into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2008, NU, Consolidated, CL&P, PSNH, and WMECO had $27.4 million, $2.8 million, $5.5 millionWMECO's environmental liability also takes into account recurring costs of managing hazardous substances and $0.3 million, respectively,pollutants, mandated expenditures to remediate previously contaminated sites and at December 31, 2007, $25.8 million, $2.9 million, $5.5 millionany other infrequent and $0.3 million, respectively, recorded as environmental reserves.non-recurring clean up costs. A tablereconciliation of the activity in thesethe environmental reserves at December 31, 2008 and 2007as is as follows:
FS-66
|
|
| NU |
|
|
|
|
|
|
|
|
|
(Millions of Dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006 |
| $ | 26.8 |
| $ | 2.8 |
| $ | 5.6 |
| $ | 0.3 |
Additions |
|
| 1.2 |
|
| 0.6 |
|
| 0.2 |
|
| 0.3 |
Payments |
|
| (2.2) |
|
| (0.5) |
|
| (0.3) |
|
| (0.3) |
Balance at December 31, 2007 |
|
| 25.8 |
|
| 2.9 |
|
| 5.5 |
|
| 0.3 |
Additions |
|
| 4.6 |
|
| 0.2 |
|
| 0.6 |
|
| 0.5 |
Payments |
|
| (3.0) |
|
| (0.3) |
|
| (0.6) |
|
| (0.5) |
Balance at December 31, 2008 |
| $ | 27.4 |
| $ | 2.8 |
| $ | 5.5 |
| $ | 0.3 |
As of December 31, 2008, the status of environmental sites are as follows:
|
| NU |
|
|
|
|
|
|
Environmental reserve |
| 54 |
| 14 |
| 17 |
| 9 |
Remediation or long-term monitoring phase |
| 27 |
| 4 |
| 11 |
| 7 |
Some site assessments completed |
| 22 |
| 9 |
| 2 |
| 2 |
Preliminary site assessment stage |
| 5 |
| 1 |
| 4 |
| - |
|
|
| NU |
|
| CL&P |
|
| PSNH |
|
| WMECO |
(Millions of Dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
| $ | 27.4 |
| $ | 2.8 |
| $ | 5.5 |
| $ | 0.3 |
Additions |
|
| 2.3 |
|
| 0.3 |
|
| 0.1 |
|
| 0.4 |
Payments |
|
| (3.7) |
|
| (0.4) |
|
| (0.3) |
|
| (0.3) |
Balance as of December 31, 2009 |
|
| 26.0 |
|
| 2.7 |
|
| 5.3 |
|
| 0.4 |
Additions |
|
| 18.2 |
|
| 0.5 |
|
| 8.9 |
|
| 0.1 |
Payments |
|
| (7.1) |
|
| (0.4) |
|
| (5.1) |
|
| (0.2) |
Balance as of December 31, 2010 |
| $ | 37.1 |
| $ | 2.8 |
| $ | 9.1 |
| $ | 0.3 |
These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. NU, CL&P, PSNH, and WMECO have not recorded any probable recoveries from third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.
AtIt is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.
As of December 31, 2008,2010, the status of environmental sites are as follows:
(Number of Sites) |
| NU |
|
| CL&P |
|
| PSNH |
|
| WMECO |
Remediation or long-term monitoring phase |
| 33 |
|
| 6 |
|
| 12 |
|
| 8 |
Some site assessment completed |
| 19 |
|
| 9 |
|
| 2 |
|
| 1 |
Preliminary site assessment stage |
| 6 |
|
| 2 |
|
| 4 |
|
| - |
Total environmental sites |
| 58 |
|
| 17 |
|
| 18 |
|
| 9 |
The environmental reserve related to these sites is as follows:
|
| As of December 31, | ||||||||||||||||||||||
|
| 2010 |
| 2009 | ||||||||||||||||||||
|
| NU |
| CL&P |
| PSNH |
| WMECO |
| NU |
| CL&P |
| PSNH |
| WMECO | ||||||||
Remediation or long-term |
| $ | 30.3 |
| $ | 0.8 |
| $ | 8.8 |
| $ | 0.2 |
| $ | 18.4 |
| $ | 0.5 |
| $ | 5.0 |
| $ | 0.2 |
Preliminary site assessment stage |
|
| 6.5 |
|
| 1.9 |
|
| 0.1 |
|
| 0.1 |
|
| 7.3 |
|
| 2.1 |
|
| 0.2 |
|
| 0.2 |
Some site assessment completed |
|
| 0.3 |
|
| 0.1 |
|
| - |
|
| - |
|
| 0.3 |
|
| 0.1 |
|
| 0.1 |
|
| - |
Total |
| $ | 37.1 |
| $ | 2.8 |
| $ | 0.3 |
| $ | 0.3 |
| $ | 26.0 |
| $ | 2.7 |
| $ | 5.3 |
|
| 0.4 |
146
The majority of the accruals for sites in additionremediation or long-term monitoring relate to MGP sites that were operated several decades ago and produced manufacturing gas from coal, which resulted in certain byproducts in the 54environment that may pose a risk to human health and the environment.
As of December 31, 2010, for 8 environmental sites (14 for CL&P, 17 for PSNH and 9 for WMECO), there were 10 sites (5(3 for CL&P, 2 for PSNH, and 1 for WMECO) that are included in the Company's reserve for environmental costs, the information known and nature of the remediation options at those sites allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2010, $8.4 million ($1.5 million for CL&P, $0.7 million for PSNH, and $0.1 million for WMECO) had been accrued as a liability for these sites, which represent management's best estimates of the liabilities for environmental costs. These amounts are the best estimates within estimated ranges of losses from $4.5 million to $25 million ($1.3 million to $5.7 million for CL&P, zero to $4.1 million for PSNH, and zero to $8.7 million for WMECO). For the 50 remaining sites (14 for CL&P, 16 for PSNH, and 8 for WMECO) that comprise the remaining $28.7 million of the environmental r eserve ($1.3 million for CL&P, $8.4 million for PSNH and $0.2 million for WMECO), determining an estimated range of loss is not possible at this time.
As of December 31, 2010, in addition to the sites identified above, there were 12 sites (7 for CL&P, 2 for PSNH, and 2 for WMECO) for which there are unasserted claims; however, any related site assessment or remediation costs are not probable or estimable at this time. NU, CL&P, PSNH and WMECO’s environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.
HWP:HWP, remains ina subsidiary of NU, continues to investigate the process of evaluatingpotential need for additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a manufactured gas plant (MGP)MGP site which itthat HWP sold to Holyoke Gas and Electric (HG&E),HG&E, a municipal electric utility, in 1902. HWP is at least partially responsibleshares responsibility for this site remediation with HG&E and has already conducted substantial investigative and remediation activities. HWP first established a reserve for this site in 1994. A pre-tax charge of approximately $3 million was recorded in 2008 to reflect the estimated cost of further tar delineation and site characterization studies, as well as certain remediation costs that are considered to be probable and estimable as of December 31, 2008. The cumulative expense recorded to the reserve for this reservesite since 1994 through December 31, 20082010 was approximately $15.9$19.5 million, of which $13.9$16.6 million had been spent, leaving approximately $2$2.9 million in the reserve as of December 31, 2008.
The Massachusetts Department2010. For the years ended December 31, 2010, 2009 and 2008, pre-tax charges of Environmental Protection (MA DEP) issued a letter on April 3, 2008$2.6 million, $1.1 million and $3 million, respectively, were recorded to HWP and HG&E, which share responsibility for the site, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 reports and proposals for further investigations. MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation. This letter represents guidance from the MA DEP, rather than mandates. HWP has developed and begun to implement plans for additional investigations in conformity with MA DEP’s guidance letter, includingreflect estimated costs and schedules. These matters are subject to ongoing discussionsassociated with MA DEP and HG&E and may change from time to time.
At this time, management believes that the $2 million remaining in the reserve is at the low end of a range of probable and estimable costs of approximately $2 million to $2.7 million and will be sufficient for HWP to conduct the additional tar delineation and site characterization studies, evaluate its approach to this matter and conduct certain soft tar remediation. The additional studies are expected to occur through 2009.
There are many outcomes that could affect management's estimates and require an increase to the reserve, or range of costs, and a reserve increase would be reflected as a charge to pre-tax earnings. However, management cannot reasonably estimate the range of additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time. Further developments may require a material increase to this reserve.
site. HWP's share of the remediation costs related to this site is not recoverable from customers.
MGP Sites: MGP sites compriseIn 2008, the largest portionMA DEP issued a letter to HWP and HG&E, representing guidance rather than a mandate, providing conditional authorization for additional investigatory and risk characterization activities and indicating that further removal of tar in certain areas was needed. HWP implemented several supplemental studies to further delineate and assess tar deposits in conformity with the MA DEP's guidance letter.
In 2010, HWP delivered a report to the MA DEP describing the results of its site investigation studies and testing. Subsequent communications and discussions with the MA DEP have focused on the course of action to achieve resolution of these matters, and are ongoing.
The $2.9 million reserve balance as of December 31, 2010 represents estimated costs that HWP considers probable over the remaining life of the environmental liabilities. MGPsproject, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are sites that manufactured gas from coal that producedexpected to be required by the MA DEP, and certain byproductssoft tar remediation activities. Various factors could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income. Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend, among other things, on the nature, extent and timing of additional investigation and remediation that may pose a risk to human health andbe required by the environment. At December 31, 2008 and 2007, $25.4 million and $23.6 million ($1.5 million and $1.5 million for CL&P, $4.8 million and $4.7 million for PSNH and $0.1 million and $0.2 million for WMECO), respectively, represent amounts for the site assessment and remediation of MGPs. At December 31, 2008 and 2007, the 5 (1 for PSNH) largest MGP sites comprise approximately 63 percent and 68 percent (76 percent and 94 percent for PSNH), respectively, of the total MGP environmental liability.
FS-67
For 7 of the 54 sites (3 of the 14 for CL&P, 2 of the 17 for PSNH and 1 of the 9 for WMECO) that are included in the company’s liability for environmental costs, the information known and nature of the remediation options at those sites allow for the company to estimate the range of losses for environmental costs. At December 31, 2008, $5.1 million ($1.8 million for CL&P, $0.7 million for PSNH and $0.1 million for WMECO) had been accrued as a liability for these sites, which represent management’s best estimates of the liabilities for environmental costs. These amounts are the best estimates within estimated ranges of losses from zero to $11 million ($1.6 million to $6 million for CL&P, zero to $4.2 million for PSNH and zero to $8.8 million for WMECO). For the 47 remaining sites (11 for CL&P, 15 for PSNH and 8 for WMECO) included in the environmental reserve, determining an estimated ran ge of loss is not possible at this time.MA DEP.
CERCLA Matters:CERCLA: The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)CERCLA and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. Of the 54total sites (14included in the remediation and long-term monitoring phase, 5 sites (3 for PSNH, 2 for CL&P, 17 for PSNH and 9 for WMECO), 5 (1 for CL&P, 3 for PSNH and 1 site having both CL&P and WMECO involved as a party)for WMECO) are superfund sites under CERCLA for which the companyCompany has been notified that it is a potentially responsible party (PRP) but for which the site assessment and remediation are not being managed by the company. AtCompany. As of December 31, 2008,2010, a liability of $0. 7$0.7 million ($0.4 million for CL&P, $0.3 million for PSNH, and $31 thousanda de minimis amount for WMECO) accrued on these sites represents management'sman agement's best estimate of its potential remediation costs with respect to these 5 (1 for CL&P, 3 for PSNH and 1 site having both CL&P and WMECO involved as a party) superfund sites.
It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.
Environmental Rate Recovery: PSNH and Yankee Gas have rate recovery mechanisms for environmental costs. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P’s&P's environmental reserves impact CL&P’s earnings.&P's Net Income. WMECO does not have a separate regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’sWMECO's environmental reserves impact WMECO’s earnings. HWP does not have the ability to recover environmental costs in rates, and changes in HWP's environmental reserves impact HWP's earnings.WMECO's Net Income.
C.B.
Spent Nuclear Fuel Disposal Costs (CL&P, WMECO)
Under the Nuclear Waste Policy Act of 1982, (the Act), CL&P and WMECO must pay the United States Department of Energy (DOE)DOE for the costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.
The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made by CL&P and WMECO to the DOE prior to the first delivery of spent fuel to the DOE. After the sale of Millstone, CL&P and WMECO remained responsible for their share of the disposal costs associated with the Prior Period Spent Nuclear Fuel. Until such payment to the DOE is made, the outstanding liability
147
will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2008 and 2007, feesFees due to the DOE for the disposal of Prior Period Spent Nuclear Fuel for the year endedas of December 31, 20082010 and 2007, respectively,2009 are included in lo ng-term debtLong-Term Debt and were $298.6$301 million and $294.3$300.6 million ($243243.8 million and $238.7$243.5 million for CL&P and $55.6$57.2 million and $55.6$57.1 million for WMECO), respectively, including accumulated interest costs of $217.9$218.9 million and $212.6$218.5 million ($176.5177.3 million and $172.2$177 million for CL&P and $41.4$41.6 million and $40.4$41.5 million for WMECO), respectively.
DuringIn 2004, WMECO established a trust that holds marketable securities to fund amounts due to the DOE for the disposal of WMECO’sWMECO's Prior Period Spent Nuclear Fuel. For further information on this trust, see Note 9,5, "Marketable Securities," to the consolidated financial statements.
FS-68
D.C.
Long-Term Contractual Arrangements (NU, CL&P, PSNH, WMECO, Yankee Gas, NU Enterprises)
Regulated Companies:
Estimated Future Annual Regulated Companies Costs: The estimated future annual costs of the regulated companies' significant long-term contractual arrangements atas of December 31, 20082010 are as follows:
NU Consolidated |
|
| |||||||||||||||||||
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter |
| Totals | |||||||
VYNPC |
| $ | 30.3 |
| $ | 29.6 |
| $ | 30.2 |
| $ | 7.2 |
| $ | - |
| $ | - |
| $ | 97.3 |
Supply/stranded cost contracts |
|
| 233.0 |
|
| 222.7 |
|
| 259.6 |
|
| 261.0 |
|
| 252.5 |
|
| 834.5 |
|
| 2,063.3 |
Renewable energy contracts |
|
| 2.8 |
|
| 36.8 |
|
| 64.6 |
|
| 119.0 |
|
| 118.9 |
|
| 1,667.5 |
|
| 2,009.6 |
Peaker CfDs |
|
| - |
|
| 5.2 |
|
| 15.0 |
|
| 21.6 |
|
| 20.8 |
|
| 35.5 |
|
| 98.1 |
Natural gas procurement contracts |
|
| 58.5 |
|
| 58.3 |
|
| 57.3 |
|
| 50.5 |
|
| 27.0 |
|
| 122.9 |
|
| 374.5 |
Wood, coal and transportation contracts |
|
| 141.5 |
|
| 87.6 |
|
| 82.5 |
|
| 56.1 |
|
| - |
|
| - |
|
| 367.7 |
PNGTS pipeline commitments |
|
| 2.1 |
|
| 2.0 |
|
| 2.0 |
|
| 2.0 |
|
| 2.0 |
|
| 7.9 |
|
| 18.0 |
Hydro-Québec support commitments |
|
| 20.2 |
|
| 20.5 |
|
| 20.6 |
|
| 20.3 |
|
| 19.9 |
|
| 136.5 |
|
| 238.0 |
Transmission segment project commitments |
|
| 186.6 |
|
| 156.0 |
|
| 153.4 |
|
| 131.1 |
|
| 48.0 |
|
| - |
|
| 675.1 |
Yankee Companies billings |
|
| 25.7 |
|
| 28.0 |
|
| 29.7 |
|
| 29.8 |
|
| 29.4 |
|
| 50.4 |
|
| 193.0 |
Clean air project commitments |
|
| 76.3 |
|
| 75.3 |
|
| 36.3 |
|
| 16.4 |
|
| 5.1 |
|
| - |
|
| 209.4 |
Vehicle/equipment commitments |
|
| 14.6 |
|
| 1.9 |
|
| 28.5 |
|
| - |
|
| - |
|
| - |
|
| 45.0 |
Totals |
| $ | 791.6 |
| $ | 723.9 |
| $ | 779.7 |
| $ | 715.0 |
| $ | 523.6 |
| $ | 2,855.2 |
| $ | 6,389.0 |
NU |
|
| |||||||||||||||||||
(Millions of Dollars) |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| Thereafter |
| Totals | |||||||
VYNPC |
| $ | 30.2 |
| $ | 7.6 |
| $ | 0.2 |
| $ | - |
| $ | - |
| $ | - |
| $ | 38.0 |
Supply/Stranded Cost Contracts/Obligations |
|
| 243.2 |
|
| 289.3 |
|
| 280.5 |
|
| 265.9 |
|
| 196.4 |
|
| 858.2 |
|
| 2,133.5 |
Renewable Energy Contracts |
|
| 16.6 |
|
| 87.4 |
|
| 112.0 |
|
| 142.0 |
|
| 147.8 |
|
| 2,044.7 |
|
| 2,550.5 |
Peaker CfDs |
|
| 27.7 |
|
| 54.0 |
|
| 60.6 |
|
| 63.6 |
|
| 62.9 |
|
| 297.4 |
|
| 566.2 |
Natural Gas Procurement Contracts |
|
| 61.4 |
|
| 55.5 |
|
| 31.3 |
|
| 29.3 |
|
| 25.3 |
|
| 90.6 |
|
| 293.4 |
Wood, Coal and Transportation Contracts |
|
| 118.5 |
|
| 116.9 |
|
| 10.1 |
|
| - |
|
| - |
|
| - |
|
| 245.5 |
PNGTS Pipeline Commitments |
|
| 3.1 |
|
| 3.1 |
|
| 3.1 |
|
| 3.1 |
|
| 3.1 |
|
| 9.8 |
|
| 25.3 |
Transmission Support Commitments |
|
| 20.6 |
|
| 20.4 |
|
| 20.3 |
|
| 19.8 |
|
| 20.7 |
|
| 103.4 |
|
| 205.2 |
Yankee Companies Billings |
|
| 27.4 |
|
| 28.4 |
|
| 28.1 |
|
| 26.8 |
|
| 22.4 |
|
| - |
|
| 133.1 |
Select Energy Purchase Agreements |
|
| 43.0 |
|
| 42.8 |
|
| 48.7 |
|
| - |
|
| - |
|
| - |
|
| 134.5 |
Clean Air Project Commitments |
|
| 49.5 |
|
| 14.0 |
|
| 2.0 |
|
| - |
|
| - |
|
| - |
|
| 65.5 |
Totals |
| $ | 641.2 |
| $ | 719.4 |
| $ | 596.9 |
| $ | 550.5 |
| $ | 478.6 |
| $ | 3,404.1 |
| $ | 6,390.7 |
CL&P
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter |
| Totals | ||||||||||||||||||||||||||
VYNPC |
| $ | 18.0 |
| $ | 17.6 |
| $ | 17.9 |
| $ | 4.3 |
| $ | - |
| $ | - |
| $ | 57.8 | |||||||||||||||||||
Supply/stranded cost contracts |
|
| 171.1 |
|
| 160.5 |
|
| 225.1 |
|
| 227.5 |
|
| 222.8 |
|
| 662.2 |
|
| 1,669.2 | |||||||||||||||||||
Renewable energy contracts |
|
| 2.8 |
|
| 36.8 |
|
| 64.6 |
|
| 119.0 |
|
| 118.9 |
|
| 1,667.5 |
|
| 2,009.6 | |||||||||||||||||||
Peaker CfDs |
|
| - |
|
| 5.2 |
|
| 15.0 |
|
| 21.6 |
|
| 20.8 |
|
| 35.5 |
|
| 98.1 | |||||||||||||||||||
Hydro-Québec support commitments |
|
| 11.6 |
|
| 11.7 |
|
| 11.8 |
|
| 11.6 |
|
| 11.4 |
|
| 78.1 |
|
| 136.2 | |||||||||||||||||||
Transmission segment project commitments |
|
| 145.6 |
|
| 148.5 |
|
| 137.7 |
|
| 129.3 |
|
| 48.0 |
|
| - |
|
| 609.1 | |||||||||||||||||||
Yankee Companies billings |
|
| 17.5 |
|
| 19.2 |
|
| 20.3 |
|
| 20.4 |
|
| 20.1 |
|
| 35.2 |
|
| 132.7 | |||||||||||||||||||
Vehicle/equipment commitments |
|
| 1.3 |
|
| 1.4 |
|
| 20.2 |
|
| - |
|
| - |
|
| - |
|
| 22.9 | |||||||||||||||||||
Totals |
| $ | 367.9 |
| $ | 400.9 |
| $ | 512.6 |
| $ | 533.7 |
| $ | 442.0 |
| $ | 2,478.5 |
| $ | 4,735.6 |
(Millions of Dollars) |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| Thereafter |
| Totals | ||||||||||||||||||||
VYNPC |
| $ | 17.9 |
| $ | 4.5 |
| $ | 0.1 |
| $ | - |
| $ | - |
| $ | - |
| $ | 22.5 | |||||||||||||
Supply/Stranded Cost Contracts/Obligations |
|
| 191.4 |
|
| 238.1 |
|
| 233.0 |
|
| 216.1 |
|
| 159.5 |
|
| 728.2 |
|
| 1,766.3 | |||||||||||||
Renewable Energy Contracts |
|
| 16.6 |
|
| 87.4 |
|
| 112.0 |
|
| 142.0 |
|
| 147.8 |
|
| 2,044.7 |
|
| 2,550.5 | |||||||||||||
Peaker CfDs |
|
| 27.7 |
|
| 54.0 |
|
| 60.6 |
|
| 63.6 |
|
| 62.9 |
|
| 297.4 |
|
| 566.2 | |||||||||||||
Transmission Support Commitments |
|
| 11.8 |
|
| 11.6 |
|
| 11.6 |
|
| 11.3 |
|
| 11.8 |
|
| 59.2 |
|
| 117.3 | |||||||||||||
Yankee Companies Billings |
|
| 18.8 |
|
| 19.5 |
|
| 19.2 |
|
| 18.5 |
|
| 15.7 |
|
| - |
|
| 91.7 | |||||||||||||
Totals |
| $ | 284.2 |
| $ | 415.1 |
| $ | 436.5 |
| $ | 451.5 |
| $ | 397.7 |
| $ | 3,129.5 |
| $ | 5,114.5 |
PSNH
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter |
| Totals | |||||||
VYNPC |
| $ | 7.6 |
| $ | 7.4 |
| $ | 7.6 |
| $ | 1.8 |
| $ | - |
| $ | - |
| $ | 24.4 |
Supply/stranded cost contracts |
|
| 59.6 |
|
| 59.9 |
|
| 34.5 |
|
| 33.5 |
|
| 29.7 |
|
| 172.3 |
|
| 389.5 |
Wood, coal and transportation contracts |
|
| 141.5 |
|
| 87.6 |
|
| 82.5 |
|
| 56.1 |
|
| - |
|
| - |
|
| 367.7 |
PNGTS pipeline commitments |
|
| 2.1 |
|
| 2.0 |
|
| 2.0 |
|
| 2.0 |
|
| 2.0 |
|
| 7.9 |
|
| 18.0 |
Hydro-Québec support commitments |
|
| 6.2 |
|
| 6.3 |
|
| 6.3 |
|
| 6.3 |
|
| 6.1 |
|
| 42.0 |
|
| 73.2 |
Transmission segment project commitments |
|
| 18.1 |
|
| 5.0 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 23.1 |
Yankee Companies billings |
|
| 3.4 |
|
| 3.6 |
|
| 3.8 |
|
| 3.8 |
|
| 3.7 |
|
| 5.5 |
|
| 23.8 |
Clean air project commitments |
|
| 76.3 |
|
| 75.3 |
|
| 36.3 |
|
| 16.4 |
|
| 5.1 |
|
| - |
|
| 209.4 |
Vehicle/equipment commitments |
|
| 13.0 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 13.0 |
Totals |
| $ | 327.8 |
| $ | 247.1 |
| $ | 173.0 |
| $ | 119.9 |
| $ | 46.6 |
| $ | 227.7 |
| $ | 1,142.1 |
(Millions of Dollars) |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| Thereafter |
| Totals | ||||||||||||||||||||
VYNPC |
| $ | 7.5 |
| $ | 1.9 |
| $ | 0.1 |
| $ | - |
| $ | - |
| $ | - |
| $ | 9.5 | |||||||||||||
Supply/Stranded Cost Contracts/Obligations |
|
| 51.8 |
|
| 51.2 |
|
| 47.5 |
|
| 49.8 |
|
| 36.9 |
|
| 130.0 |
|
| 367.2 | |||||||||||||
Wood, Coal and Transportation Contracts |
|
| 118.5 |
|
| 116.9 |
|
| 10.1 |
|
| - |
|
| - |
|
| - |
|
| 245.5 | |||||||||||||
PNGTS Pipeline Commitments |
|
| 3.1 |
|
| 3.1 |
|
| 3.1 |
|
| 3.1 |
|
| 3.1 |
|
| 9.8 |
|
| 25.3 | |||||||||||||
Transmission Support Commitments |
|
| 6.3 |
|
| 6.4 |
|
| 6.3 |
|
| 6.1 |
|
| 6.4 |
|
| 31.8 |
|
| 63.3 | |||||||||||||
Yankee Companies Billings |
|
| 3.4 |
|
| 3.6 |
|
| 3.6 |
|
| 3.2 |
|
| 2.3 |
|
| - |
|
| 16.1 | |||||||||||||
Clean Air Project Commitments |
|
| 49.5 |
|
| 14.0 |
|
| 2.0 |
|
| - |
|
| - |
|
| - |
|
| 65.5 | |||||||||||||
Totals |
| $ | 240.1 |
| $ | 197.1 |
| $ | 72.7 |
| $ | 62.2 |
| $ | 48.7 |
| $ | 171.6 |
| $ | 792.4 |
WMECO
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter |
| Totals | |||||||
VYNPC |
| $ | 4.7 |
| $ | 4.6 |
| $ | 4.7 |
| $ | 1.1 |
| $ | - |
| $ | - |
| $ | 15.1 |
Supply/stranded cost contracts |
|
| 2.3 |
|
| 2.3 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| 4.6 |
Transmission segment project commitments |
|
| 22.9 |
|
| 2.5 |
|
| 15.7 |
|
| 1.8 |
|
| - |
|
| - |
|
| 42.9 |
Hydro-Québec support commitments |
|
| 2.4 |
|
| 2.5 |
|
| 2.5 |
|
| 2.4 |
|
| 2.4 |
|
| 16.4 |
|
| 28.6 |
Yankee Companies billings |
|
| 4.8 |
|
| 5.2 |
|
| 5.6 |
|
| 5.6 |
|
| 5.6 |
|
| 9.7 |
|
| 36.5 |
Vehicle/equipment commitments |
|
| 0.2 |
|
| 0.3 |
|
| 4.5 |
|
| - |
|
| - |
|
| - |
|
| 5.0 |
Totals |
| $ | 37.3 |
| $ | 17.4 |
| $ | 33.0 |
| $ | 10.9 |
| $ | 8.0 |
| $ | 26.1 |
| $ | 132.7 |
(Millions of Dollars) |
| 2011 |
| 2012 |
| 2013 |
| 2014 |
| 2015 |
| Thereafter |
| Totals | ||||||||||||||||||||
VYNPC |
| $ | 4.7 |
| $ | 1.2 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
| $ | 5.9 | |||||||||||||
Transmission Support Commitments |
|
| 2.5 |
|
| 2.4 |
|
| 2.4 |
|
| 2.4 |
|
| 2.5 |
|
| 12.4 |
|
| 24.6 | |||||||||||||
Yankee Companies Billings |
|
| 5.2 |
|
| 5.3 |
|
| 5.3 |
|
| 5.1 |
|
| 4.4 |
|
| - |
|
| 25.3 | |||||||||||||
Totals |
| $ | 12.4 |
| $ | 8.9 |
| $ | 7.7 |
| $ | 7.5 |
| $ | 6.9 |
| $ | 12.4 |
| $ | 55.8 |
VYNPC: NU consolidated, CL&P, PSNH, and WMECO have commitments to buy approximately 16 percent, 9.5 percent, 4 percent, and 2.5 percent (16 percent in the aggregate for NU), respectively, of the Vermont Yankee Nuclear Power Corporation (VYNPC) plant’splant's output through March 2012 at a range of fixed prices. NU consolidated, CL&P, PSNH, and WMECO's total cost of purchases under contracts with VYNPC amounted to $26.5$16 million, $6.7 million, and $4.2 million, respectively, in 2010, $17.5 million, $7.3 million, and $4.6 million, respectively, in 2009, and $15.7 million, $6.6 million, and $4.2 million, respectively, in 2008 $25.6($26.9 million $15.2in 2010, $29.4 million $6.4in 2009 and $26.5 million and $4 million, respectively, in 2007 and $32.2 million, $19.1 million, $8.1 million and $5 million, respectively,2008 in 2006.the aggregate for NU).
Supply/Stranded Cost Contracts:Contracts/Obligations: CL&P and PSNH and WMECO have entered into various IPP contracts that extend through 2024or purchase obligations for CL&P, 2023 for PSNH and 2010 for WMECO for the purchase of electricity, including payment obligations resulting from the buydown of electricity purchase contracts. Excluding renewable and CfD contracts, which are discussed below, such contracts extend through 2024 for CL&P. At PSNH such contracts extend through 2023. The total cost of purchases and obligations under these contractscontracts/obligations amounted to $196.2 million, ($151.3 million for CL&P, $42.6 million for PSNH, and $2.3 million for WMECO) in 2010, $205.3 million, ($173.1 million for CL&P, $29.8 million for PSNH, and $2.4 million for WMECO) in 2009, and $237.6 million ($200.5 million for CL&P, $34.6 million for PSNH, and $2.5 million for WMECO) in 2008, $281.5 million ($206 million for CL&P, $72.9 million for PSNH and $2.6 million for WMECO) in 2007 and $331.9 million ($206.1 million for CL&P, $123.6 million for PSNH and $2.1 million for WMECO) in 2006. The majority of the contracts expire by 2014 for CL&P and 2018 for PSNH.2008.
FS-69148
In addition, CL&P and UI have entered into four CfDs for a total of approximately 787 MW of capacity with three generation projects to bebeing built or modified and one new demand response project. The capacity CfDs extend through 2026 and obligate the utilities to pay the difference between a set capacity price and the value that the projects receive in the ISO-NE capacity markets. The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI, whereby UI will share 20 percent of the costs and benefits of these contracts. CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers. The information in the table above includes 100 percent of the payments projected as of December 31, 2010 under the contracts entered into by CL&P and 80 percent of the payments projected under the contracts entered into by UI,UI. The amounts of t hese payments are subject to changes in capacity and forward reserve prices that the projects receive in the ISO-NE capacity markets andmarkets. On February 7, 2010, an explosion occurred at the construction site of Kleen Energy Systems, LLC's 620 MW generation project with which CL&P has a CfD. This event could delay or change CL&P's portion ofestimated payments under the costs and benefits of these co ntracts will be paid by or refunded to CL&P's customers.CfD contract.
These amounts do not include contractual commitments related to CL&P’s&P's standard or last resort service or WMECO’sWMECO's default service, both of which represent contractual commitments that are conditional upon CL&P and WMECO customers' use of energy, and PSNH’sPSNH's short-term power supply management.
Renewable Energy Contracts: CL&P has entered into various agreements to purchase energy, capacity and renewable energy credits from renewable energy facilities. Amounts payable under these contracts are subject to a sharing agreement with UI, whereby UI will share approximately 20 percent of the costs and benefits of these contracts. In addition, UI has entered into contracts that are subject to this cost sharing agreement under which CL&P will share in approximately 80 percent of the costs and benefits of the contract. The information in the table above includes 100 percent of the payments projected under the contracts entered into by CL&P and 80 percent of the payments projected under the contracts entered into by UI. CL&P’s&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P’s&P's customers.
Peaker CfDs: In 2008, CL&P has entered into three CfDs with developers of peaking generation units approved by the DPUC (Peaker CfDs). These units will have a total of approximately 500 MW of peaking capacity. As directed by the DPUC, CL&P and UI have entered into a sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. The information in the table above includes 100 percent of the estimated payments projected under the contracts, before reimbursement from UI under the sharing agreement. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive fo r capacityfor capa city and other products in the ISO-NE markets. CL&P’s&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P’s&P's customers.
Natural Gas Procurement Contracts: Yankee Gas has entered into long-term contracts for the purchase of a specified quantity of natural gas in the normal course of business as part of its portfolio of supplies to meet its actual sales commitments.supplies. These contracts extend through 2022. The total cost of Yankee Gas’Gas' procurement portfolio, including these contracts, amounted to $209.5 million in 2010, $236.3 million in 2009 and $352.5 million in 2008, $305.3 million in 2007 and $275.1 million in 2006.2008.
Wood, Coal and Transportation Contracts: PSNH has entered into various arrangements for the purchase of wood, coal and the transportation services for fuel supply for its electric generating assets in 2009. PSNH’sassets. PSNH's fuel and natural gas costs, excluding emissions allowances, amounted to approximately $168.3 million in 2010, $156.7 million in 2009 and $165.4 million in 2008, $183.8 million in 2007 and $149.1 million in 2006.2008.
PNGTS Pipeline Commitments: PSNH has a contract for capacity on the Portland Natural Gas Transmission System (PNGTS) pipeline that extends through 2018. The cost under this contract amounted to $2.8 million in 2010, $1.6 million in 2009 and $1.5 million in 2008, $3.1 million in 2007 and $1.4 million in 2006.2008. These costs are not recovered from PSNH's retail customers.
Hydro-QuébecTransmission Support Commitments: Along with other New England utilities, CL&P, PSNH and WMECO have entered into agreements in 1985 to support transmission and terminal facilities that were built to import electricity from the Hydro-Québec system in Canada. CL&P, PSNH and WMECO are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&Moperation and maintenance expenses and capital costs of those facilities. NU consolidated, CL&P, PSNH and WMECO's total cost of these agreements amounted to $18.3$10.8 million, $5.8 million and $2.3 million, respectively, in 2010, $10.7 million, $5.7 million and $2.2 million, respectively, in 2009, and $10.5 million, $5.6 million and $2.2 million, respectively, in 2008 $18.8($18.9 million $10.8in 2010, $18.6 million $5.8in 2009 and $18.3 million and $2.2 million, respectively, in 2007, and $20.5 million, $11.7 million, $6.4 million and $2.4 million, respectively,2008 in 2006.
Transmission Segment Project Commitments: These amounts primarily represent commitmentsthe aggregate for various services and materials associated with the NEEWS 115 kilovolt (KV) and 345 KV Overhead projects and the final closeout of CL&P's Middletown to Norwalk, Glenbrook Cables and Long Island Replacement project. The remaining amounts are for transmission projects at PSNH and WMECO.NU).
Yankee Companies Billings: NU consolidated, CL&P, PSNH and WMECO have significant decommissioning and plant closure cost obligations to the Yankee Companies. Each Yankee Company hasCompanies, which have each completed the physical decommissioning of its facilitytheir respective nuclear facilities and isare now engaged in the long-term storage of itstheir spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including NU’s electric utility companies, CL&P, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates. The tableCL&P, PSNH and WMECO's total cost of estimated future annual regulated companies costs includesthese billings amounted to $22.7 million, $4.1 million and $6.2 million, respectively, in 2010, $18.2 million, $3.7 million and $5 million, respectively, in 2009, and $20 million, $4.4 million and $5.4 million, respectively, in 2008 ($3 3 million in 2010, $26.9 million in 2009 and $29.8 million in 2008 in the estimated decommissioning and closure costsaggregate for CYAPC, YAEC and MYAPC.NU).
See Note 7E,12D "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements for information regarding the collection of the Yankee Companies' decommissioning costs.
FS-70149
Clean Air Project Commitments: These amounts represent commitments for engineering, program management services and major component supply and installation associated with PSNH's coal-fired 440 MW Merrimack Station clean air project, which also includes the addition of a wet scrubber to reduce mercury and SO2SO2 emissions at Merrimack Station Units 1 and 2. The total cost under these contracts amounted to $129.6 million in 2010, $107.5 million in 2009 and $20.5 million in 2008, $1.9 million in 2007 and $0.9 million in 2006.2008.
Vehicle/Equipment Commitments: CL&P, PSNH, WMECO and Yankee Gas have remaining obligations under master lease agreements that were terminated by the lessor in November 2008. As a result of the termination, in accordance with the lease agreements, remaining vehicle/equipment balances are required to be paid by November 2009 for PSNH totaling $13 million and by January 2011 for CL&P, WMECO, and Yankee Gas totaling $32 million. At the end of the lease, the lessee company will either purchase the vehicle/equipment or sell it at auction with the balances paid to the lessor.
NU Enterprises:
Estimated Future Annual NU Enterprises Costs: The estimated future annual costs of NU Enterprises' significant contractual arrangements are as follows:
(Millions of Dollars) |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter |
| Totals | |||||||
Select Energy purchase agreements |
| $ | 40.3 |
| $ | 41.9 |
| $ | 42.9 |
| $ | 38.8 |
| $ | 44.7 |
| $ | - |
| $ | 208.6 |
Select Energy Purchase Agreements: Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments. Most purchase commitments are recorded at their mark-to-market value with the exception of one non-derivativenonderivative contract, which is accounted for on the accrual basis.
Select Energy's purchase commitment amounts are reported on a net basis in fuel, purchasedFuel, Purchased and net interchange powerNet Interchange Power on the accompanying consolidated statements of income along with certain sales contracts and mark-to-market amounts. Accordingly, the amount included in fuel, purchasedFuel, Purchased and net interchange powerNet Interchange Power will be less than the amounts included in the table above. Select Energy also maintains certain energy commitments whose mark-to-market values have been recorded on the consolidated balance sheets as derivative assetsDerivative Assets and liabilities.Liabilities. These contracts are included in the table above.
The amount and timing of the costs associated with Select Energy's purchase agreements could be impacted by the exit from the NU Enterprises' businesses.
E.D.
Deferred Contractual Obligations (CL&P, PSNH, WMECO)
CL&P, PSNH and WMECO have decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.
CL&P, PSNH and WMECO’sWMECO's percentage share of the obligationobligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the ownership percentages.Yankee Companies. For further information on the ownership percentages, see Note 1J,1L, "Summary of Significant Accounting Policies - Equity Method Investments," to the consolidated financial statements.
CYAPC, YAEC and MYAPCThe Yankee Companies are currently collecting amounts that we believemanagement believes are adequate to recover the remaining decommissioning and closure cost estimates for the respective plants. We believeManagement believes CL&P and WMECO will recover their shares of these decommissioning and closure obligations from their customers. PSNH has already recovered its share of these costs from its customers.
Spent Nuclear Fuel Litigation: In 1998, CYAPC, YAEC and MYAPC filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE. In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001/2002.
In December 2006, the DOE appealed the ruling, and the Yankee Companies filed a cross-appeal.cross-appeals. The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court's findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages. The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.
On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010. The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010. Briefs will be due absent extensions during the first quarter of 2011. Interest on the judgments does not start to accrue until all appeals have been decided and/or all appeal periods have expired without appeals being filed. The application of any damages, which are ultimately recovered to benefit customers, is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.
The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE will be realized through the Yankee Companies' FERC-approved rate settlement agreements, subject to final determination of the FERC. CL&P, PSNH and WMECO cannot at this time determine the timing or amount of any ultimate recovery the Yankee Companies may obtain from the DOE through the Yankee Companies, on this matter. However, NU does believebelieves that any net settlement proceeds it receives would be incorporated into FERC-approved recoveries, which would be passed on to its customers, through reduced charges.
F.E.
Guarantees and Indemnifications (All Companies)
NU parent provides credit assurances on behalf of its subsidiaries, including CL&P, PSNH and WMECO, in the form of guarantees and LOCs in the normal course of business.
NU has also provided guarantees and various indemnifications on behalf of external parties as a result of the salessale of SESI, formerly a subsidiary of NU Enterprises' retail marketing businessEnterprises, with an aggregate fair value amount recorded of $0.3 million.Other indemnifications in connection with the sale of SESI include specific indemnifications for estimated costs to complete or modify specific projects, indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts, and its competitive generation business.surety bonds covering certain projects. The following table
FS-71150
summarizes NU and its subsidiaries' maximum exposure on these items is either not specified or not material, and no amounts are recorded as liabilities. NU parent also provided guarantees and various indemnifications on behalf of external parties as a result of the sales of NU Enterprises' former retail marketing business and competitive generation business. These included indemnifications for compliance with tax and environmental laws, and various claims for which the maximum exposure was not specified in the sale agreements.
In October 2010, NU issued a guaranty for the benefit of Hydro Renewable Energy under which NU guaranteed the financial obligations of NPT under the TSA in an amount not to exceed $18.8 million. NU's obligations under the guaranty arise at the time the Northern Pass Transmission line goes into commercial operation and expires upon the full, final and indefeasible payment of the guaranteed obligations.
Management does not anticipate a material impact to net income to result from these various guarantees and indemnifications. The following table summarizes the NU, including CL&P, PSNH, and WMECO, maximum exposure as of December 31, 2008,2010, in accordance with FIN 45, "Guarantor's Accountingguidance on guarantor's accounting and Disclosure Requirementsdisclosure requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,"guarantees and expiration dates, and fair value of amounts recorded.dates:
|
|
|
|
|
|
|
|
On behalf of external parties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SESI |
| General indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claims |
| Not Specified | (1) |
| None |
|
|
|
|
|
|
|
|
|
| Specific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects (2) |
| Not Specified | (1) |
| Through project completion |
|
|
|
|
|
|
|
|
|
| Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts (3) |
| $1.3 |
|
| 2017-2018 |
|
|
|
|
|
|
|
|
|
| Surety bonds covering certain projects |
| $10.5 |
|
| Through project |
|
|
|
|
|
|
|
|
Hess Corporation (Retail Marketing Business) |
| General indemnifications in connection with the sale including compliance with laws, completeness and accuracy of information provided and various claims |
| Not Specified | (1) |
| None |
|
|
|
|
|
|
|
|
Energy Capital Partners (Competitive Generation Business) |
| General indemnifications in connection with the sale of NGC and the generating assets of Mt. Tom including compliance with tax and environmental laws, and various claims |
| Not Specified | (1) |
| 2008-2009 |
|
|
|
|
|
|
|
|
On behalf of subsidiaries: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P |
| Surety bonds (4) |
| $3.2 |
|
| 2009-2010 |
|
|
|
|
|
|
|
|
PSNH |
| Surety bonds (4) |
| $3.9 |
|
| 2009-2010 |
|
| Letters of credit |
| $85.0 |
|
| 2009-2010 |
|
|
|
|
|
|
|
|
WMECO |
| Surety bonds (4) |
| $3.0 |
|
| 2009 |
|
|
|
|
|
|
|
|
HWP |
| Surety bonds (4) |
| $1.0 |
|
| 2009 |
|
|
|
|
|
|
|
|
NAESCO |
| Surety bonds (4) |
| $1.6 |
|
| 2009 |
|
|
|
|
|
|
|
|
RRR |
| Lease payments for real estate |
| $9.2 |
|
| 2024 |
|
|
|
|
|
|
|
|
NUSCO |
| Surety bonds (4) |
| $1.0 |
|
| 2009 |
|
| Lease payments for fleet of vehicles |
| $8.0 |
|
| None |
|
| Lease payments for real estate |
| $1.8 |
|
| 2019 |
|
|
|
|
|
|
|
|
Boulos |
| Surety bonds covering ongoing projects |
| $34.1 |
|
| Through project |
|
|
|
|
|
|
|
|
NGS |
| Performance guarantee and insurance bonds |
| $20.4 | (5) |
| 2020 (5) |
|
|
|
|
|
|
|
|
Select Energy |
| Performance guarantees and surety bonds for retail marketing contracts |
| $3.3 | (6) |
| None (7) |
|
| Performance guarantees for wholesale contracts |
| $17.1 | (6) |
| 2013 |
|
| Letters of credit |
| $2.0 |
|
| 2009 |
|
|
|
|
|
|
|
|
Other - CYAPC |
| Surety bonds (4) |
| $0.3 |
|
| 2010 |
Subsidiary |
| Description |
| Maximum |
|
| Expiration |
Various |
| Surety Bonds |
| $ 11.8 |
|
| January 2011 - |
|
|
|
|
|
|
|
|
PSNH and Select Energy |
| Letters of Credit |
| $ 32.1 |
|
| October 2011 - |
|
|
|
|
|
|
|
|
RRR and NUSCO |
| Lease Payments for Real Estate and Vehicles |
| $ 21.4 |
|
| 2019-2024 |
|
|
|
|
|
|
|
|
NU Enterprises |
| Surety Bonds, Insurance Bonds and Performance Guarantees |
| $ 121.5 | (2) |
| (2) |
(1)
There is no specified maximum exposure included in the related sale agreements.
(2)
The fair value for amounts recorded for these indemnifications was $0.2 million at December 31, 2008.
(3)
The fair value for amounts recorded for these indemnifications was $0.1 million at December 31, 2008.
FS-72
(4)
Surety bond expiration dates reflect bond termination dates, (which maythe majority of which will be renewed or extended) for specified term bonds and/or bill-to dates for bonds with no fixed term.extended.
(5)(2)
Included in theThe maximum exposure is $19.2includes $64.8 million related to performance guarantees on Select Energy's wholesale purchase contracts, which expire in 2013 assuming purchase contracts guaranteed have no value; however, actual exposures vary with underlying commodity prices. The maximum exposure also includes $17.5 million related to a performance guarantee of NGS'sNGS obligations for which thereno maximum exposure is no specified maximum exposure in the agreement. The maximum exposure iswas calculated as of December 31, 20082010 based on limits of NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020. The remaining $1.2 million ofAlso included in the maximum exposure relatesis $1.1 million related to insurance bonds at NGS with no expiration date that are billed annually on their anniversary date.
(6)
Maximum The remaining $38.1 million of maximum exposure is as of December 31, 2008; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.
(7)
NU does not currently anticipate that these remaining guarantees on behalf of Select Energy will result in significant guarantees of the performance of Hess Corporation. relates to suret y bonds covering ongoing projects at Boulos, which expire upon project completion.
CL&P, PSNH and WMECO have no guarantees ofdo not guarantee the performance of third parties.
Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that NU'sthe unsecured debt credit ratings of NU are downgraded below investment grade.
G.F.
NRG Energy, Inc. Exposures (CL&P, Yankee Gas)Litigation and Legal Proceedings
Certain subsidiaries of NU, including CL&P, and Yankee Gas, entered into transactions with NRG and certain of its subsidiaries. On May 14, 2003, NRG and certain subsidiaries of NRG filed voluntary bankruptcy petitions, and on December 5, 2003, NRG emerged from bankruptcy. NU's NRG-related exposures as a result of these transactions, among other things now resolved, relate to the recovery of approximately $30.2 million of CL&P's station service billings from NRG, and the recovery of, among other claimed damages, approximately $17.5 million of capital costs and expenses incurred by Yankee Gas related to an NRG subsidiary's generating plant construction project that has ceased.
On February 15, 2008, CL&P and NRG, as well as Yankee Gas and NRG, entered into settlement agreements with respect to the two matters mentioned above. The settlements were contingent upon the satisfaction of several conditions related to NRG's RNS service through the ISO-NE, which were materially satisfied in May 2008. The settlement did not have an adverse effect on NU's or CL&P's consolidated net income, financial position or cash flows in 2008.
H.
Consolidated Edison, Inc. Merger Litigation (NU)
On March 13, 2008, NU entered into a settlement agreement with Consolidated Edison, Inc. (Con Edison), which settled all claims under the civil lawsuit between NU and Con Edison relating to their proposed but unconsummated merger. Under the terms of the settlement agreement, NU paid Con Edison $49.5 million on March 26, 2008, which is included in other operating expenses in the accompanying consolidated statement of income for the year ended December 31, 2008. This amount is not recoverable from ratepayers.
I.
Other Litigation and Legal Proceedings (All Companies)
NU and its subsidiaries (including CL&P, PSNH and WMECO)WMECO, are involved in other legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management’smanagement's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss as defined by SFAS No. 5.loss. The companyCompany records and discloses losses when these losses are probable and reasonably estimable, in accordance with SFAS No. 5, discloses matters when losses are probable but not estimable or reasonably possible, and expenses legal costs related to the defense of loss contingencies as incurred.
8.13.
Fair Value of Financial Instruments (All Companies)
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Cash and Cash Equivalents and Special Deposits: The carrying amounts approximate fair value due to the short-term nature of these cash items.
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of NU, CL&P, PSNH, and WMECO's fixed-rate securities is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of NU, CL&P, PSNH, and WMECO’s financial instruments and the estimated fair values are as follows:
FS-73
|
| At December 31, | ||||||||||
|
| 2008 |
| 2007 | ||||||||
|
| NU Consolidated |
| NU Consolidated | ||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair | ||||
Preferred stock not subject |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
Long-term debt - |
|
|
|
|
|
|
|
|
|
|
|
|
First mortgage bonds |
|
| 2,312.0 |
|
| 2,399.4 |
|
| 1,806.3 |
|
| 1,792.4 |
Other long-term debt |
|
| 1,829.5 |
|
| 1,690.6 |
|
| 1,832.3 |
|
| 1,867.4 |
Rate reduction bonds |
|
| 686.5 |
|
| 689.4 |
|
| 917.4 |
|
| 975.2 |
|
| At December 31, 2008 | ||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO | ||||||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair | ||||||
Preferred stock not subject |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
Long-term debt - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First mortgage bonds |
|
| 1,669.8 |
|
| 1,737.2 |
|
| 280.0 |
|
| 286.3 |
|
| - |
|
| - |
Other long-term debt |
|
| 604.9 |
|
| 555.8 |
|
| 407.3 |
|
| 359.7 |
|
| 304.4 |
|
| 270.3 |
Rate reduction bonds |
|
| 378.2 |
|
| 373.7 |
|
| 235.1 |
|
| 240.7 |
|
| 73.2 |
|
| 75.0 |
|
| At December 31, 2007 | ||||||||||||||||
|
| CL&P |
| PSNH |
| WMECO | ||||||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair | ||||||
Preferred stock not subject |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
Long-term debt - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First mortgage bonds |
|
| 1,369.8 |
|
| 1,362.9 |
|
| 170.0 |
|
| 164.6 |
|
| - |
|
| - |
Other long-term debt |
|
| 662.6 |
|
| 674.1 |
|
| 407.3 |
|
| 420.6 |
|
| 304.4 |
|
| 298.1 |
Rate reduction bonds |
|
| 548.7 |
|
| 586.2 |
|
| 282.0 |
|
| 297.3 |
|
| 86.7 |
|
| 91.7 |
The NU consolidated other long-term debt includes $298.6 million and $294.3 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2008 and 2007, respectively. CL&P's portion of this obligation is $243 million and $238.7 million for the years ended December 31, 2008 and 2007. WMECO's portion of this obligation is $55.6 million at both December 31, 2008 and 2007.
Derivative Instruments: NU and its subsidiaries hold various derivative instruments that are carried at fair value. For further information, see Note 3, "Derivative Instruments," to the consolidated financial statements.
Other Financial Instruments: NU holds investments in a supplemental benefit trust for the benefit of the SERP and non-SERP obligation and WMECO holds investments in the spent nuclear fuel trust for the benefit of the spent nuclear fuel obligation. These investments are carried at fair value in the accompanying consolidated balance sheets. For further information regarding these investments, see Note 1U, "Summary of Significant Accounting Policies-Marketable Securities," Note 1F, "Summary of Significant Accounting Policies-Fair Value Measurements," and Note 9, "Marketable Securities," to the consolidated financial statements.
NU Parent holds a long-term government receivable related to SESI, a former subsidiary that has been sold. The carrying value of the receivable was $8.8 million at both December 31, 2008 and 2007 and is included in other deferred debits and other assets-other on the accompanying consolidated balance sheets. The fair value of this receivable was $11.5 million and $10.8 million at December 31, 2008 and 2007, respectively, and was determined based on discounted cash flows.
The carrying value of other financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value due to the short-term nature of these instruments.
9.
Marketable Securities (NU, WMECO)
The following is a summary of NU’s available-for-sale securities related to the supplemental benefit trust and WMECO's spent nuclear fuel trust assets, which are recorded at their fair values and are included in current and long-term marketable securities on the accompanying consolidated balance sheets.
|
| At December 31, | ||||
(Millions of Dollars) |
| 2008 |
| 2007 | ||
Supplemental benefit trust |
| $ | 53.5 |
| $ | 68.4 |
WMECO spent nuclear fuel trust |
|
| 55.7 |
|
| 55.7 |
Totals |
| $ | 109.2 |
| $ | 124.1 |
FS-74
At December 31, 2008 and 2007, marketable securities are comprised of the following:
|
| At December 31, 2008 | |||||||
|
| Amortized |
| Pre-Tax |
| Estimated | |||
Supplemental benefit trust |
|
|
|
|
|
|
|
|
|
United States equity securities |
| $ | 21.9 |
| $ | 1.1 |
| $ | 23.0 |
Non-United States equity securities |
|
| 5.6 |
|
| - |
|
| 5.6 |
U.S. government issued debt securities |
|
| 13.1 |
|
| 0.8 |
|
| 13.9 |
Corporate debt securities |
|
| 3.3 |
|
| 0.2 |
|
| 3.5 |
Asset backed securities |
|
| 3.4 |
|
| - |
|
| 3.4 |
Other |
|
| 4.1 |
|
| - |
|
| 4.1 |
Total supplemental benefit trust |
| $ | 51.4 |
| $ | 2.1 |
| $ | 53.5 |
|
|
|
|
|
|
|
|
|
|
|
| At December 31, 2008 | |||||||
|
| Amortized |
| Pre-Tax |
| Estimated | |||
WMECO spent nuclear fuel trust |
|
|
|
|
|
|
|
|
|
Short-term investments and money markets |
| $ | 16.3 |
| $ | - |
| $ | 16.3 |
U.S. government issued debt securities |
|
|
|
|
|
|
|
|
|
Corporate debt securities |
|
| 17.4 |
|
| 0.5 |
|
| 17.9 |
Asset backed securities |
|
| 2.4 |
|
| - |
|
| 2.4 |
Other |
|
| 3.6 |
|
| - |
|
| 3.6 |
Total WMECO Spent Nuclear Fuel Trust |
| $ | 55.1 |
| $ | 0.6 |
| $ | 55.7 |
|
|
|
|
|
|
|
|
|
|
Total NU Consolidated |
| $ | 106.5 |
| $ | 2.7 |
| $ | 109.2 |
|
| At December 31, 2007 | ||||||||
|
| Amortized |
| Pre-Tax |
|
| Estimated | |||
Supplemental benefit trust |
|
|
|
|
|
|
|
|
|
|
United States equity securities |
| $ | 23.5 |
| $ | 4.3 |
|
| $ | 27.8 |
Non-United States equity securities |
|
| 8.3 |
|
| - |
|
|
| 8.3 |
U.S. government issued debt securities (Agency and Treasury) |
|
|
|
|
|
|
|
|
|
|
Corporate debt securities |
|
| 6.4 |
|
| 0.1 |
|
|
| 6.5 |
Asset backed securities |
|
| 6.3 |
|
| - |
|
|
| 6.3 |
Other |
|
| 5.0 |
|
| - |
|
|
| 5.0 |
Total supplemental benefit trust |
| $ | 63.7 |
| $ | 4.7 |
|
| $ | 68.4 |
|
|
|
|
|
|
|
|
|
|
|
WMECO spent nuclear fuel trust |
|
|
|
|
|
|
|
|
|
|
Short-term investments and money markets |
| $ | 14.1 |
| $ | - |
|
| $ | 14.1 |
U.S. government issued debt securities |
|
|
|
|
|
|
|
|
|
|
Corporate debt securities |
|
| 29.2 |
|
| - |
|
|
| 29.2 |
Asset backed securities |
|
| 9.2 |
|
| 0.1 |
|
|
| 9.3 |
Other |
|
| 2.4 |
|
| - |
|
|
| 2.4 |
Total WMECO Spent Nuclear Fuel Trust |
| $ | 55.6 |
| $ | 0.1 |
|
| $ | 55.7 |
|
|
|
|
|
|
|
|
|
|
|
Total NU Consolidated |
| $ | 119.3 |
| $ | 4.8 |
|
| $ | 124.1 |
(1) Amortized cost amounts are net of unrealized losses that are recorded as other than temporary impairments.
For the years ended December 31, 2008 and 2007, NU recorded pre-tax charges of $15.3 million and $1.9 million, respectively, related to the unrealized losses on securities in the supplemental benefit trust portfolio, and $2.1 million and $0.6 million, respectively, offset to the spent nuclear fuel obligation in long-term debt related to the unrealized losses on securities in the WMECO spent nuclear fuel trust. Unrealized losses are considered other than temporary in nature because they are held in trusts and NU and WMECO do not have the ability to hold these securities to maturity.
FS-75
For information related to the change in unrealized gains included in accumulated other comprehensive income, see Note 14, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.
For the years ended December 31, 2008, 2007 and 2006, realized gains and losses recognized on the sale of available-for-sale securities are as follows:
|
| NU Consolidated |
| WMECO | ||||||||||||||
|
|
| Realized |
|
| Realized |
|
| Net Realized |
|
| Realized |
|
| Realized |
|
| Net Realized |
2008 |
| $ | 2.5 |
| $ | (2.2) |
| $ | 0.3 |
| $ | 0.2 |
| $ | (0.6) |
| $ | (0.4) |
2007 |
|
| 2.8 |
|
| (1.0) |
|
| 1.8 |
|
| 0.1 |
|
| (0.1) |
|
| - |
2006 |
|
| 5.2 |
|
| (1.3) |
|
| 3.9 |
|
| - |
|
| (0.3) |
|
| (0.3) |
The WMECO spent nuclear fuel trust net realized losses above offset the spent nuclear fuel obligation in long-term debt. For the years ended December 31, 2008, 2007 and 2006, all other net realized gains totaling $0.7 million, $1.9 million and $4.2 million, respectively, are included in other income, net on the accompanying consolidated statements of income. Included in the realized gain/(losses) is a pre-tax gain of $3.1 millionfor the year ended December 31, 2006 related to NU's investment in Globix Corporation (Globix), which was sold on April 6, 2006.
NU utilizes the specific identification basis method for the supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.
Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $259.4 million, $254.8 million and $193.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. WMECO's portion of these proceeds totaled $169.1 million, $196.9 million and $123.1 million for the years ended December 31, 2008, 2007 and 2006, respectively.
At December 31, 2008, the contractual maturities of the available-for-sale securities are as follows:
|
|
| NU Consolidated |
| WMECO | |||||||
|
|
| Amortized |
|
| Estimated |
|
| Amortized |
|
| Estimated |
Less than one year |
| $ | 49.2 |
| $ | 49.9 |
| $ | 45.9 |
| $ | 46.4 |
One to five years |
|
| 11.9 |
|
| 12.0 |
|
| 8.0 |
|
| 8.1 |
Six to ten years |
|
| 4.3 |
|
| 4.5 |
|
| - |
|
| - |
Greater than ten years |
|
| 13.6 |
|
| 14.2 |
|
| 1.2 |
|
| 1.2 |
Subtotal |
|
| 79.0 |
|
| 80.6 |
|
| 55.1 |
|
| 55.7 |
Equity securities |
|
| 27.5 |
|
| 28.6 |
|
| - |
|
| - |
Total |
| $ | 106.5 |
| $ | 109.2 |
| $ | 55.1 |
| $ | 55.7 |
For further information regarding marketable securities, see Note 1U, "Summary of Significant Accounting Policies - Marketable Securities," to the consolidated financial statements.
10.
Leases (All Companies)LEASES
Various NU subsidiaries, including CL&P, PSNH and WMECO, have entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. In addition, CL&P, PSNH and WMECO incur costs associated with leases entered into by NUSCO and RRR. These costs are included below in CL&P, PSNH and WMECO’sWMECO's operating lease payments charged to expense and amounts capitalized as well as future operating lease payments from 20092011 through 20132015 and thereafter. These amounts are eliminated foron an NU consolidated.consolidated basis. The provisions of these lease agreements generally contain renewal options. Certain lease agreements contain contingent lease payments. The contingent lease payments are based on various factors, such as the commercial paper rate plus a credit spread or the consumer price index.
Capital leaseFor the years ended December 31, 2010, 2009, and 2008, rental payments were $2.5 million ($2.1 million for CL&P and $0.4 million for PSNH) in 2008, $2.9 million ($2.5 million for CL&P and $0.4 million for PSNH) in 2007, and $3.3 million ($2.9 million for CL&P and $0.4 million for PSNH) in 2006. Interestmade on capital leases, interest included in capital lease rental payments, was $1.8 million in 2008 ($1.7 million for CL&P and $0.1 million for PSNH), $2 million ($1.8 million for CL&P and $0.2 million for PSNH) in 2007, and $1.9 million ($1.7 million for CL&P and $0.2 million for PSNH) in 2006. Capitalcapital lease asset amortization was $0.7 million ($0.4 million for CL&P and $0.3 million for PSNH) in 2008, $0.9 million ($0.7 million for CL&P and $0.2 million for PSNH) in both 2007 and 2006. were as follows:
(Millions of |
| Rental Payments |
| Interest |
| Asset Amortization | |||||||||||||||||||||
Dollars) |
| NU |
| CL&P |
| PSNH |
| NU |
| CL&P |
| PSNH |
| NU |
| CL&P |
| PSNH | |||||||||
2010 |
| $ | 2.5 |
| $ | 1.9 |
| $ | 0.5 |
| $ | 1.8 |
| $ | 1.5 |
| $ | 0.3 |
| $ | 0.7 |
| $ | 0.4 |
| $ | 0.2 |
2009 |
|
| 2.6 |
|
| 1.9 |
|
| 0.5 |
|
| 1.9 |
|
| 1.6 |
|
| 0.3 |
|
| 0.6 |
|
| 0.3 |
|
| 0.2 |
2008 |
|
| 2.5 |
|
| 2.1 |
|
| 0.4 |
|
| 1.8 |
|
| 1.7 |
|
| 0.1 |
|
| 0.7 |
|
| 0.4 |
|
| 0.3 |
151
There was a de minimis amount of capital leases held by WMECO in 2010, 2009, and 2008. There were no capital leases held by WMECO in 2007 or 2006.
OperatingFor the years ended December 31, 2010, 2009 and 2008, operating lease rental payments charged to expense were $19.1 million, $19.6 million and $10.9 million ($12.7 million, $13.2 million and $17.3 million for CL&P, $4.1 million, $3.5 million and $4.1 million for PSNH and $3.8 million, $4 million and $4 million for WMECO) in 2008, 2007 and 2006, respectively. In 2006, the NU consolidated amount includes $0.7 million included in income from discontinued operations on the accompanying consolidated statements of income for the year ended December 31, 2006. The capitalized portion of operating lease payments was approximately $10.8 million, $10.5 million and $10 million ($6.8 million, $6.5 million and $6.2 million for CL&P, $1.8 million, $2 million and $1.9 million for PSNH and $1.3 million, $1.2 million and $1.1 million for WMECO) for the years ended December 31, 2008, 2007 and 2006, respectively. were as follows:
FS-76
|
| Expensed |
|
| Capitalized | |||||||||||||||||||
(Millions of Dollars) |
| NU |
|
| CL&P |
|
| PSNH |
|
| WMECO |
|
| NU |
|
| CL&P |
|
| PSNH |
|
| WMECO | |
2010 |
| $ | 11.9 |
| $ | 10.0 |
| $ | 2.2 |
| $ | 2.6 |
| $ | 4.8 |
| $ | 3.8 |
| $ | 0.1 |
| $ | 0.1 |
2009 |
|
| 18.1 |
|
| 12.8 |
|
| 3.9 |
|
| 3.4 |
|
| 9.7 |
|
| 6.1 |
|
| 1.5 |
|
| 1.1 |
2008 |
|
| 19.1 |
|
| 12.7 |
|
| 4.1 |
|
| 3.8 |
|
| 10.8 |
|
| 6.8 |
|
| 1.8 |
|
| 1.3 |
Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, atas of December 31, 20082010 are as follows:
|
| NU |
|
|
|
|
|
| ||||
(Millions of Dollars) |
|
|
| NU |
| CL&P |
| PSNH | ||||
2009 |
| $ | 2.4 | |||||||||
2010 |
| 2.4 | ||||||||||
2011 |
| 2.5 |
| $ | 2.5 |
| $ | 1.9 |
| $ | 0.5 | |
2012 |
| 2.6 |
| 2.6 |
| 2.0 |
| 0.5 | ||||
2013 |
| 2.4 |
| 2.4 |
| 2.0 |
| 0.4 | ||||
2014 |
| 2.0 |
| 1.8 |
| 0.2 | ||||||
2015 |
| 2.0 |
| 1.8 |
| 0.2 | ||||||
Thereafter |
|
| 15.5 |
|
| 11.4 |
|
| 11.3 |
|
| 0.1 |
Future minimum lease payments |
| $ | 27.8 |
| 22.9 |
| 20.8 |
| 1.9 | |||
Less amount representing interest |
|
| 14.4 |
|
| 10.7 |
|
| 10.2 |
|
| 0.5 |
Present value of future minimum lease payments |
| $ | 13.4 |
| $ | 12.2 |
| $ | 10.6 |
| $ | 1.4 |
Capital Leases |
|
| CL&P |
|
| PSNH |
(Millions of Dollars) |
|
| ||||
2009 |
| $ | 1.9 |
| $ | 0.5 |
2010 |
|
| 1.9 |
|
| 0.5 |
2011 |
|
| 1.9 |
|
| 0.5 |
2012 |
|
| 2.0 |
|
| 0.5 |
2013 |
|
| 1.9 |
|
| 0.4 |
Thereafter |
|
| 14.9 |
|
| 0.5 |
Future minimum lease payments |
| $ | 24.5 |
| $ | 2.9 |
Less amount representing interest |
|
| 13.3 |
|
| 1.0 |
Present value of future minimum lease payments |
| $ | 11.2 |
| $ | 1.9 |
|
| NU | |
(Millions of Dollars) |
|
| |
2009 |
| $ | 24.6 |
2010 |
|
| 18.9 |
2011 |
|
| 7.1 |
2012 |
|
| 6.1 |
2013 |
|
| 5.9 |
Thereafter |
|
| 23.9 |
Future minimum lease payments |
| $ | 86.5 |
Operating Leases |
|
| CL&P |
|
| PSNH |
|
| WMECO |
|
|
|
|
|
|
|
| ||||
(Millions of Dollars) |
|
|
| NU |
| CL&P |
| PSNH |
| WMECO | |||||||||||
2009 |
| $ | 14.4 |
| $ | 4.4 |
| $ | 4.4 | ||||||||||||
2010 |
|
| 12.5 |
|
| 1.3 |
| 4.1 | |||||||||||||
2011 |
|
| 3.9 |
|
| 1.1 |
| 2.4 |
| $ | 7.9 |
| $ | 7.2 |
| $ | 2.0 |
| $ | 3.0 | |
2012 |
|
| 3.4 |
|
| 0.9 |
| 2.3 |
| 7.0 |
| 6.8 |
| 1.8 |
| 2.9 | |||||
2013 |
|
| 3.3 |
|
| 0.9 |
| 2.3 |
| 6.8 |
| 6.7 |
| 1.7 |
| 2.8 | |||||
2014 |
| 4.9 |
| 6.5 |
| 1.7 |
| 1.3 | |||||||||||||
2015 |
| 4.5 |
| 6.5 |
| 1.7 |
| 0.9 | |||||||||||||
Thereafter |
|
| 19.7 |
|
| 4.1 |
|
| 1.9 |
|
| 19.1 |
|
| 23.0 |
|
| 5.3 |
|
| 2.6 |
Future minimum lease payments |
| $ | 57.2 |
| $ | 12.7 |
| $ | 17.4 |
| $ | 50.2 |
| $ | 56.7 |
| $ | 14.2 |
| $ | 13.5 |
In November 2008, the lessor of CL&P, PSNH, WMECO and Yankee Gas’Gas' vehicle/equipment master lease agreements notified the companies that it was electing to terminate the lease agreements as permitted under the termination clause of the agreements. The remaining payments under the agreements will bewere made through Novemberin 2009 for PSNH and WMECO and January 2011 for CL&P WMECO, and Yankee Gas. See Note 7D, "Commitments and Contingencies - Long-Term Contractual Arrangements," for obligations relating to the termination.
NU (CL&P)CL&P entered into certain contracts for the purchase of energy that qualify as leases under EITF No. 01-8, "Determining Whether an Arrangement Contains a Lease."leases. These contracts do not have minimum lease payments and therefore are not included in the tables above. See Note 7D,12C, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the consolidated financial statements for further information regarding these contracts.
14.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. Carrying amounts and estimated fair values are as follows:
|
| As of December 31, 2010 | ||||||||||||||||||||||
|
| NU |
| CL&P |
| PSNH |
| WMECO | ||||||||||||||||
(Millions of Dollars) |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair Value | ||||||||
Preferred Stock Not |
| $ | 116.2 |
| $ | 93.7 |
| $ | 116.2 |
| $ | 93.7 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Long-Term Debt - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Mortgage Bonds |
|
| 2,703.4 |
|
| 2,998.7 |
|
| 1,919.8 |
|
| 2,148.3 |
|
| 430.0 |
|
| 462.8 |
|
| - |
|
| - |
Other Long-Term Debt |
|
| 1,989.0 |
|
| 2,045.1 |
|
| 667.7 |
|
| 668.4 |
|
| 407.3 |
|
| 408.6 |
|
| 401.0 |
|
| 417.0 |
Rate Reduction Bonds |
|
| 181.6 |
|
| 193.3 |
|
| - |
|
| - |
|
| 138.2 |
|
| 146.9 |
|
| 43.3 |
|
| 46.4 |
FS-77152
11.
|
| As of December 31, 2009 | ||||||||||||||||||||||
|
| NU |
| CL&P |
| PSNH |
| WMECO | ||||||||||||||||
(Millions of Dollars) |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair Value | ||||||||
Preferred Stock Not |
| $ | 116.2 |
| $ | 86.8 |
| $ | 116.2 |
| $ | 86.8 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Long-Term Debt - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Mortgage Bonds |
|
| 2,657.7 |
|
| 2,713.5 |
|
| 1,919.8 |
|
| 1,960.6 |
|
| 430.0 |
|
| 425.4 |
|
| - |
|
| - |
Other Long-Term Debt |
|
| 1,893.6 |
|
| 1,938.0 |
|
| 667.4 |
|
| 673.4 |
|
| 407.3 |
|
| 408.6 |
|
| 305.9 |
|
| 304.9 |
Rate Reduction Bonds |
|
| 442.4 |
|
| 487.3 |
|
| 195.6 |
|
| 220.1 |
|
| 188.1 |
|
| 203.5 |
|
| 58.7 |
|
| 63.7 |
The NU Other Long-Term Debt (All Companies)
Long-term debt maturitiesincludes $301 million and cash sinking fund requirements on debt outstanding at December 31, 2008, for the years 2009 through 2013 and thereafter, which include$300.6 million of fees and interest due for spent nuclear fuel disposal costs net unamortized premiums or discounts and other fair value adjustments at December 31, 2008, are as follows (millions of dollars):
| NU | ||
2009 |
| $ | 54.3 |
2010 |
|
| 4.3 |
2011 |
|
| 4.3 |
2012 |
|
| 267.3 |
2013 |
|
| 305.0 |
Thereafter |
|
| 3,207.8 |
Fees and interest due for spent nuclear fuel |
|
|
|
Net unamortized premiums and discounts and |
|
|
|
Total |
| $ | 4,157.5 |
Details of long-term debt outstanding for CL&P, PSNH and WMECO are as follows (millions of dollars):
CL&P |
| At December 31, | ||||
|
| 2008 |
| 2007 | ||
First Mortgage Bonds: |
|
|
|
|
|
|
7.875% 1994 Series D due 2024 |
| $ | 139.8 |
| $ | 139.8 |
4.800% 2004 Series A due 2014 |
|
| 150.0 |
|
| 150.0 |
5.750% 2004 Series B due 2034 |
|
| 130.0 |
|
| 130.0 |
5.000% 2005 Series A due 2015 |
|
| 100.0 |
|
| 100.0 |
5.625% 2005 Series B due 2035 |
|
| 100.0 |
|
| 100.0 |
6.350% 2006 Series A due 2036 |
|
| 250.0 |
|
| 250.0 |
5.375% 2007 Series A due 2017 |
|
| 150.0 |
|
| 150.0 |
5.750% 2007 Series B due 2037 |
|
| 150.0 |
|
| 150.0 |
5.750% 2007 Series C due 2017 |
|
| 100.0 |
|
| 100.0 |
6.375% 2007 Series D due 2037 |
|
| 100.0 |
|
| 100.0 |
5.650% 2008 Series A due 2018 |
|
| 300.0 |
|
| - |
Total First Mortgage Bonds |
|
| 1,669.8 |
|
| 1,369.8 |
Pollution Control Notes: |
|
|
|
|
|
|
5.85%-5.90%, fixed rate, due 2016-2022 |
|
| 46.4 |
|
| 46.4 |
5.85%-5.95%, fixed rate tax exempt, due 2028 |
|
| 315.5 |
|
| 315.5 |
Variable rate, tax exempt, due 2031 |
|
| - |
|
| 62.0 |
Total Pollution Control Notes |
|
| 361.9 |
|
| 423.9 |
Total First Mortgage Bonds and |
|
|
|
|
|
|
Fees and interest due for spent |
|
|
|
|
|
|
Less amounts due within one year |
|
| - |
|
| - |
Unamortized premiums and discounts, net |
|
| (4.3) |
|
| (3.9) |
Long-term debt |
| $ | 2,270.4 |
| $ | 2,028.5 |
PSNH |
| At December 31, | ||||||
|
| 2008 |
| 2007 | ||||
First Mortgage Bonds: |
|
|
|
|
|
| ||
5.25% 2004 Series L, due 2014 |
| $ | 50.0 |
| $ | 50.0 | ||
5.60% 2005 Series M, due 2035 |
|
| 50.0 |
|
| 50.0 | ||
6.15% 2007 Series N, due 2017 |
|
| 70.0 |
|
| 70.0 | ||
6.00% 2008 Series O, due 2018 |
|
| 110.0 |
|
| - | ||
Total First Mortgage Bonds |
|
| 280.0 |
|
| 170.0 | ||
Pollution Control Revenue Bonds: |
|
|
|
|
|
| ||
6.00% Tax-Exempt, Series D, due 2021 |
|
| 75.0 |
|
| 75.0 | ||
6.00% Tax-Exempt, Series E, due 2021 |
|
| 44.8 |
|
| 44.8 | ||
Adjustable Rate, Series A, due 2021 |
|
| 89.3 |
|
| 89.3 | ||
4.75% Tax-Exempt, Series B, due 2021 |
|
| 89.3 |
|
| 89.3 | ||
5.45% Tax-Exempt, Series C, due 2021 |
|
| 108.9 |
|
| 108.9 | ||
Total Pollution Control Revenue Bonds |
|
| 407.3 |
|
| 407.3 | ||
Less amounts due within a year |
|
| - |
|
| - | ||
Unamortized premiums and discounts, net |
|
| (0.5) |
|
| (0.3) | ||
Long-term debt |
| $ | 686.8 |
| $ | 577.0 |
FS-78
WMECO |
| At December 31, | ||||||
|
| 2008 |
| 2007 | ||||
Pollution Control Notes: |
|
|
|
|
|
| ||
Tax Exempt 1993 Series A, 5.85% due 2028 |
| $ | 53.8 |
| $ | 53.8 | ||
Other: |
|
|
|
|
|
| ||
Taxable Senior Series A, 5.00% due 2013 |
|
| 55.0 |
|
| 55.0 | ||
Taxable Senior Series B, 5.90% due 2034 |
|
| 50.0 |
|
| 50.0 | ||
Taxable Senior Series C, 5.24% due 2015 |
|
| 50.0 |
|
| 50.0 | ||
Taxable Senior Series D, 6.70% due 2037 |
|
| 40.0 |
|
| 40.0 | ||
Total Pollution Control Notes and Other |
|
| 248.8 |
|
| 248.8 | ||
Fees and interest due for spent nuclear fuel |
|
|
|
|
|
| ||
Total pollution control notes and fees and interest |
|
|
|
|
|
| ||
Less amounts due within one year |
|
| - |
|
| - | ||
Unamortized premiums and discounts, net |
|
| (0.5) |
|
| (0.5) | ||
Long-term debt |
| $ | 303.9 |
| $ | 303.9 |
There are no cash sinking fund requirements or debt maturities for the years 2009 through 2013 for CL&P and PSNH. There are $55 million and $250 million of maturities in 2013 related to the WMECO $55 million Senior Series A Notes and the NU parent $250 million Senior Series C Notes, respectively. CL&P, PSNH and WMECO have $2 billion, $687.3 million and $193.8 million, respectively, of long-term debt maturities in the period thereafter.
There are annual renewal and replacement fund requirements equal to 2.25 percent of the average of net depreciable utility property owned by PSNH in 1992, plus cumulative gross property additions thereafter. PSNH expects to meet these future fund requirements by certifying property additions. Any deficiency would need to be satisfied by the deposit of cash or bonds.
Essentially all utility plant of CL&P, PSNH and Yankee Gas is subject to the liens of each company’s respective first mortgage bond indenture.
The NU parent, CL&P, PSNH and WMECO tax-exempt bonds contain call provisions ranging between 100 percent and 102 percent of par. All other securities are subject to make-whole provisions.
CL&P has $423.9 million of tax-exempt Pollution Control Revenue Bonds (PCRBs), $315.5 million of which is secured by second mortgage liens on transmission assets, junior to the liens of its first mortgage bond indentures and the remaining $108.4 million of which is secured by its first mortgage bonds. One series of PCRBs, in the aggregate principal amount of $62 million, had a fixed interest rate for a five-year period that expired on September 30, 2008. As a result of poor liquidity in the tax-exempt market, CL&P chose to acquire this series of PCRBs on October 1, 2008. These PCRBs, which mature in 2031, have not been retired and are temporarily held by CL&P in a flexible rate mode with one day resets.
At December 31, 2008 PSNH had $407.3 million in outstanding PCRBs. PSNH’s obligation to repay each series of PCRBs is secured by first mortgage bonds and three series, the 2001 Series A, B and C, also carry bond insurance. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs. The 2001 Series B PCRBs, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. Since March 2008, a significant majority of this series of PCRBs has been held by remarketing agents as a result of failed auctions due to general market concerns. The interest rate on these PCRBs has been reset by formula under the applicable documents every 35 days and has been between 0.4 percent and 4 percent since March 2008. The formula is based on a combination of the ratings on the PCRBs and an index rate, which provides for an interest rate of 0.4 percent as of December 31, 2008. The company2010 and 2009, respectively. CL&P's portion of this obligation is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agents.
NU$243.8 million and its subsidiaries' long-term debt agreements provide that certain$243.5 million and WMECO's portion of its subsidiaries must comply with certain financialthis obligation is $57.2 million and non-financial covenants as are customarily included in such agreements, including a consolidated debt to capitalization ratio. These subsidiaries are in compliance with these covenants at December 31, 2008.
Yankee Gas has certain long-term debt agreements that contain cross-default provisions that would be triggered if Yankee Gas or any subsidiary default in a payment in excess of a predetermined amount. These cross-default provisions apply to Yankee Gas' Series B and Series E through J debt issuances. PSNH would also be in default under its long-term debt agreements if it defaulted on any prior lien obligation exceeding $25 million. PSNH has no prior lien obligations$57.1 million as of December 31, 2008. There are no other debt issuances for CL&P, WMECO or NU parent with cross-default provisions at December 31, 2008.2010 and 2009, respectively.
The weighted average effective interest rate on PSNH's Series A variable-rate PCRBs was 3.07 percent for 2008 and 3.87 percent for 2007. The CL&P PCRB due in 2031 had an interest rate of 3.35 percent effective through October 1, 2008, at which time the bonds were reacquired byDerivative Instruments: NU, including CL&P and PSNH, holds various derivative instruments that are now in a daily variable interest rate mode.carried at fair value. For further information, see Note 4, "Derivative Instruments," to the consolidated financial statements.
Long-term debt - First Mortgage BondsOther Financial Instruments: Investments in marketable securities are carried at fair value on the accompanying consolidated statements of capitalization at December 31, 2008 includes the issuance of $300 million and $110 million at CL&P and PSNH, respectively.
FS-79
Other long-term debt - other on the accompanying consolidated statements of capitalization at December 31, 2008 includes a senior unsecured note issuance of $250 million at NU parent, due 2013 with a coupon of 5.65 percent and the issuance of $100 million in Series J First Mortgage Bonds at Yankee Gas, due 2018 with a coupon of 6.9 percent.
balance sheets. For further information, regarding fees and interest due for spent nuclear fuel disposal costs, see Note 7C, "Commitments1I, "Summary of Significant Accounting Policies - Fair Value Measurements," and Contingencies - Spent Nuclear Fuel Disposal Costs,Note 5, "Marketable Securities," to the consolidated financial statements.
The changecarrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value totaling a positive $20.8 million and $4.2 million at December 31, 2008 and 2007, respectively, ondue to the accompanying consolidated statementsshort-term nature of capitalization reflects the NU parent 7.25 percent amortizing note, due 2012 in the amount of $263 million that is hedged with a fixed to floating interest rate swap. The change in fair value of the interest component of the debt was recorded as an adjustment to long-term debt with an equal and offsetting adjustment to derivative assets and liabilities for the change in fair value of the fixed to floating interest rate swap.these instruments.
12.15.
CL&P Preferred Stock Not Subject to Mandatory RedemptionPREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (CL&P)
CL&P's charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share) of which 2,234,0002,324,000 shares were outstanding atas of December 31, 20082010 and 2007.2009. In addition, CL&P's charter authorizes it to issue up to 8 million shares of Class A preferred stock ($25 par value per share). There were no Class A preferred shares outstanding atas of December 31, 20082010 and 2007.2009. The issuance of additional preferred shares would be subject to approval by the DPUC.
Preferred stockholders have liquidation rights equal to the par value for each class, which they would receive in preference to any distributions to any junior stock. Were there to be a shortfall, all preferred stockholders would share ratably in available liquidation assets. Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):
|
|
|
|
|
|
|
| December 31, 2010 |
| Shares Outstanding as of |
| As of December 31, | ||||||||
2008 |
| 2007 | 2010 |
| 2009 | |||||||||||||||
$1.90 Series of 1947 |
| $52.50 |
| 163,912 |
| $ | 8.2 |
| $ | 8.2 |
| $ 52.50 |
| 163,912 |
| $ | 8.2 |
| $ | 8.2 |
$2.00 Series of 1947 |
| 54.00 |
| 336,088 |
|
| 16.8 |
|
| 16.8 |
| $ 54.00 |
| 336,088 |
|
| 16.8 |
|
| 16.8 |
$2.04 Series of 1949 |
| 52.00 |
| 100,000 |
|
| 5.0 |
|
| 5.0 |
| $ 52.00 |
| 100,000 |
|
| 5.0 |
|
| 5.0 |
$2.20 Series of 1949 |
| 52.50 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
| $ 52.50 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
3.90% Series of 1949 |
| 50.50 |
| 160,000 |
|
| 8.0 |
|
| 8.0 |
| $ 50.50 |
| 160,000 |
|
| 8.0 |
|
| 8.0 |
$2.06 Series E of 1954 |
| 51.00 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
| $ 51.00 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
$2.09 Series F of 1955 |
| 51.00 |
| 100,000 |
|
| 5.0 |
|
| 5.0 |
| $ 51.00 |
| 100,000 |
|
| 5.0 |
|
| 5.0 |
4.50% Series of 1956 |
| 50.75 |
| 104,000 |
|
| 5.2 |
|
| 5.2 |
| $ 50.75 |
| 104,000 |
|
| 5.2 |
|
| 5.2 |
4.96% Series of 1958 |
| 50.50 |
| 100,000 |
|
| 5.0 |
|
| 5.0 |
| $ 50.50 |
| 100,000 |
|
| 5.0 |
|
| 5.0 |
4.50% Series of 1963 |
| 50.50 |
| 160,000 |
|
| 8.0 |
|
| 8.0 |
| $ 50.50 |
| 160,000 |
|
| 8.0 |
|
| 8.0 |
5.28% Series of 1967 |
| 51.43 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
| $ 51.43 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
$3.24 Series G of 1968 |
| 51.84 |
| 300,000 |
|
| 15.0 |
|
| 15.0 |
| $ 51.84 |
| 300,000 |
|
| 15.0 |
|
| 15.0 |
6.56% Series of 1968 |
| 51.44 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
| $ 51.44 |
| 200,000 |
|
| 10.0 |
|
| 10.0 |
Totals |
|
|
| 2,324,000 |
| $ | 116.2 |
| $ | 116.2 |
|
|
| 2,324,000 |
| $ | 116.2 |
| $ | 116.2 |
Dividends totaling $6.1 million for 2010 and $5.6 million for 2009 and 2008 were declared and dividends of $5.6 million were paid to the preferred stockholders in both 20082010, 2009 and 2007.2008.
13.16.
Dividend Restrictions (NU,ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
The accumulated balance for each component of other comprehensive income/(loss), net of tax, is as follows:
(Millions of Dollars) |
|
| December 31, |
|
| 2009 |
|
| December 31, |
|
| 2010 |
|
| December 31, |
Qualified Cash Flow Hedging Instruments |
| $ | (4.6) |
| $ | 0.2 |
| $ | (4.4) |
| $ | 0.2 |
| $ | (4.2) |
Unrealized Gains/(Losses) on Other Securities |
|
| 1.2 |
|
| (1.0) |
|
| 0.2 |
|
| 0.4 |
|
| 0.6 |
Pension, SERP and PBOP Benefits |
|
| (33.9) |
|
| (5.4) |
|
| (39.3) |
|
| (0.5) |
|
| (39.8) |
Accumulated Other Comprehensive Income/(Loss) |
| $ | (37.3) |
| $ | (6.2) |
| $ | (43.5) |
| $ | 0.1 |
| $ | (43.4) |
153
CL&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| $ | (3.6) |
| $ | 0.4 |
| $ | (3.2) |
| $ | 0.5 |
| $ | (2.7) |
Unrealized Gains/(Losses) on Other Securities |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Accumulated Other Comprehensive Income/(Loss) |
| $ | (3.6) |
| $ | 0.4 |
| $ | (3.2) |
| $ | 0.5 |
| $ | (2.7) |
PSNH |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| $ | (0.8) |
| $ | 0.1 |
| $ | (0.7) |
| $ | 0.1 |
| $ | (0.6) |
Unrealized Gains/(Losses) on Other Securities |
|
| 0.1 |
|
| (0.1) |
|
| - |
|
| - |
|
| - |
Accumulated Other Comprehensive Income/(Loss) |
| $ | (0.7) |
| $ | - |
| $ | (0.7) |
| $ | 0.1 |
| $ | (0.6) |
WMECO |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| $ | 0.1 |
| $ | (0.1) |
| $ | - |
| $ | (0.1) |
| $ | (0.1) |
Unrealized Gains/(Losses) on Other Securities |
|
| 0.1 |
|
| (0.1) |
|
| - |
|
| - |
|
| - |
Accumulated Other Comprehensive Income/(Loss) |
| $ | 0.2 |
| $ | (0.2) |
| $ | - |
| $ | (0.1) |
| $ | (0.1) |
Qualified cash flow hedging items impacting Net Income in the tables above represent amounts that were reclassified from Accumulated Other Comprehensive Income/(Loss) into Net Income in connection with the consummation of interest rate swap agreements and the amortization of existing interest rate hedges.
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
(Millions of Dollars) |
| 2010 |
| 2009 |
| 2008 | |||
Qualified Cash Flow Hedging Instruments |
| $ | (0.2) |
| $ | (0.2) |
| $ | 4.5 |
Change in Unrealized Gains/(Losses) on Other Securities |
|
| (0.2) |
|
| 0.7 |
|
| 1.1 |
Pension, SERP and PBOP Benefits |
|
| - |
|
| 2.9 |
|
| 24.2 |
Total |
| $ | (0.4) |
| $ | 3.4 |
| $ | 29.8 |
|
|
|
|
|
|
|
|
|
|
CL&P |
|
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| $ | (0.3) |
| $ | (0.3) |
| $ | 2.2 |
|
|
|
|
|
|
|
|
|
|
PSNH |
|
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| $ | (0.1) |
| $ | - |
| $ | 1.0 |
|
|
|
|
|
|
|
|
|
|
WMECO |
|
|
|
|
|
|
|
|
|
Qualified Cash Flow Hedging Instruments |
| $ | - |
| $ | 0.1 |
| $ | 0.1 |
It is estimated that a charge of $0.2 million will be reclassified from Accumulated Other Comprehensive Income/(Loss) as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements, which have been settled. Included in this amount are estimated charges of $0.4 million and $0.1 million for CL&P and PSNH, WMECO, Yankee Gas)respectively, and a benefit of $0.1 million for WMECO. As of December 31, 2010, it is estimated that a pre-tax amount of $6 million included in the Accumulated Other Comprehensive Income/(Loss) balance will be reclassified as a decrease to Net Income over the next 12 months related to Pension, SERP and PBOP adjustments for NU.
17.
DIVIDEND RESTRICTIONS
NU parent's ability to pay dividends is not regulated under the Federal Power Act, but may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total debt to total capitalization ratio requirement in its revolving credit agreement, and the ability of NU’s subsidiaries to pay common dividends to it.agreement.
CL&P, PSNH, and WMECO are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account." Management believes that this Federal Power Act restriction, as applied to CL&P, PSNH and WMECO, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from retained earnings. In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas. Such state law restrictions do not restrict payment of dividends from retained earnings or net income. CL&P, PSNH, WMECO and Yankee Gas also have a revolving credit agreement that imposes leverage restrictions including consolidated total debt to total capitalization ratio requirements. The retained earningsRetained Earnings balances subject to these lev eragelever age restrictions are $1.079$1.453 billion for NU, consolidated, $617.3$734.6 million for CL&P, $283.2$347.5 million for PSNH and $82.5$98.8 million for WMECO.WMECO as of December 31, 2010. PSNH is further required to reserve an additional amount under its FERC hydroelectric license conditions. Approximately $11As of December 31, 2010, approximately $11.6 million of PSNH's retained earningsRetained Earnings is subject to restriction under its FERC hydroelectric license conditions. AtAs of December 31, 2008,2010, NU, CL&P, PSNH, WMECO and Yankee Gas were in compliance with all such provisions of its credit agreement that may restrict the payment of dividends.
FS-80154
14.18.
Accumulated Other Comprehensive Income/(Loss) (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas)
The accumulated balance for each other comprehensive income/(loss), net of tax, item is as follows:
NU Consolidated |
|
| December 31, |
|
| 2007 |
|
| December 31, |
|
| 2008 |
|
| December 31, 2008 |
Qualified cash flow hedging instruments |
| $ | 5.9 |
| $ | (3.6) |
| $ | 2.3 |
| $ | (6.9) |
| $ | (4.6) |
Unrealized gains on securities |
|
| 3.0 |
|
| (0.1) |
|
| 2.9 |
|
| (1.7) |
|
| 1.2 |
Pension, SERP and other postretirement plans benefit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income/(loss) |
| $ | 4.5 |
| $ | 4.9 |
| $ | 9.4 |
| $ | (46.7) |
| $ | (37.3) |
CL&P |
|
| December 31, |
|
| 2007 |
|
| December 31, |
|
| 2008 |
|
| December 31, 2008 |
Qualified cash flow hedging instruments |
| $ | 4.5 |
| $ | (4.8) |
| $ | (0.3) |
| $ | (3.3) |
| $ | (3.6) |
Unrealized gains on securities |
|
| 0.1 |
|
| - |
|
| 0.1 |
|
| (0.1) |
|
| - |
Accumulated other comprehensive income/(loss) |
| $ | 4.6 |
| $ | (4.8) |
| $ | (0.2) |
| $ | (3.4) |
| $ | (3.6) |
The unrealized gains on securities above relate to $1.8 million and $2.4 million of securities held in the supplemental benefit trust at December 31, 2008 and 2007, respectively. The fair value of these securities is included in prepayments and other on the accompanying consolidated balance sheets.
PSNH |
|
| December 31, |
|
| 2007 |
|
| December 31, |
|
| 2008 |
|
| December 31, 2008 |
Qualified cash flow hedging instruments |
| $ | - |
| $ | 0.6 |
| $ | 0.6 |
| $ | (1.4) |
| $ | (0.8) |
Unrealized gains on securities |
|
| 0.2 |
|
| - |
|
| 0.2 |
|
| (0.1) |
|
| 0.1 |
Accumulated other comprehensive income/(loss) |
| $ | 0.2 |
| $ | 0.6 |
| $ | 0.8 |
| $ | (1.5) |
| $ | (0.7) |
The unrealized gains on securities above relate to $3.2 million and $4 million of securities held in the supplemental benefit trust at December 31, 2008 and 2007, respectively. The fair value of these securities is included in prepayments and other on the accompanying consolidated balance sheets.
WMECO |
|
| December 31, |
|
| 2007 |
|
| December 31, |
|
| 2008 |
|
| December 31, 2008 |
Qualified cash flow hedging instruments |
| $ | 0.9 |
| $ | (0.7) |
| $ | 0.2 |
| $ | (0.1) |
| $ | 0.1 |
Unrealized gains on securities |
|
| - |
|
| - |
|
| - |
|
| 0.1 |
|
| 0.1 |
Accumulated other comprehensive income/(loss) |
| $ | 0.9 |
| $ | (0.7) |
| $ | 0.2 |
| $ | - |
| $ | 0.2 |
The unrealized gains on securities above relate to the investments in the WMECO spent nuclear fuel trust included in marketable securities and $0.5 million and $0.7 million as of December 31, 2008 and 2007, respectively, of securities held in the supplemental benefit trust, which are included in prepayments and other and marketable securities, respectively, on the accompanying consolidated balance sheets.
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
NU Consolidated |
| 2008 |
| 2007 |
| 2006 | |||
Qualified cash flow hedging instruments |
| $ | 4.5 |
| $ | 2.5 |
| $ | 6.9 |
Unrealized gains on securities |
|
| 1.1 |
|
| 0.1 |
|
| (0.5) |
Minimum SERP liability |
|
| - |
|
| - |
|
| (0.3) |
Pension, SERP and other postretirement plans benefit |
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income/(loss) |
| $ | 29.8 |
| $ | (7.2) |
| $ | 12.2 |
CL&P |
| 2008 |
| 2007 |
| 2006 | |||
Qualified cash flow hedging instruments |
| $ | 2.2 |
| $ | 3.2 |
| $ | (3.1) |
Minimum SERP liability |
|
| - |
|
| - |
|
| (0.2) |
Accumulated other comprehensive income/(loss) |
| $ | 2.2 |
| $ | 3.2 |
| $ | (3.3) |
PSNH |
| 2008 |
| 2007 |
| 2006 | |||
Qualified cash flow hedging instruments |
| $ | 1.0 |
| $ | 0.4 |
| $ | - |
Accumulated other comprehensive income |
| $ | 1.0 |
| $ | 0.4 |
| $ | - |
WMECO (Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Qualified cash flow hedging instruments |
| $ | 0.1 |
| $ | (0.5) |
| $ | (0.1) |
Unrealized losses on securities |
|
| - |
|
| - |
|
| 0.2 |
Accumulated other comprehensive income/(loss) |
| $ | 0.1 |
| $ | (0.5) |
| $ | 0.1 |
FS-81
Fair value adjustments included in accumulated other comprehensive income/(loss) for NU consolidated, CL&P, PSNH, and WMECO qualified cash flow hedging instruments are as follows:
| At December 31, 2008 | ||||||
|
| 2008 |
| 2007 | |||
|
| NU |
| NU | |||
Balance at beginning of year |
| $ | 2.3 |
| $ | 5.9 | |
Hedged transactions recognized into earnings |
|
| 0.4 |
|
| 0.2 | |
Change in fair value of interest rate swap agreements |
|
| (7.0) |
|
| - | |
Cash flow transactions entered into for period |
|
| (0.3) |
|
| (3.8) | |
Net change associated with hedging transactions |
|
| (6.9) |
|
| (3.6) | |
Total fair value adjustments included in |
| $ |
|
| $ |
|
|
| At December 31, | ||||||||||||||||
|
| 2008 |
| 2007 | ||||||||||||||
(Millions of Dollars, Net of Tax) |
| CL&P |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO | ||||||
Balance at beginning of year |
| $ | (0.3) |
| $ | 0.6 |
| $ | 0.2 |
| $ | 4.5 |
| $ | - |
| $ | 0.9 |
Hedged transactions recognized into earnings |
|
| 0.4 |
|
| 0.2 |
|
| (0.1) |
|
| 0.1 |
|
| - |
|
| (0.1) |
Change in fair value of interest rate swap agreements |
|
| (3.7) |
|
| (1.4) |
|
| - |
|
| - |
|
| - |
|
| - |
Cash flow transactions entered into for period |
|
| - |
|
| (0.2) |
|
| - |
|
| (4.9) |
|
| 0.6 |
|
| (0.6) |
Net change associated with hedging transactions |
|
| (3.3) |
|
| (1.4) |
|
| (0.1) |
|
| (4.8) |
|
| 0.6 |
|
| (0.7) |
Total fair value adjustments included in |
| $ |
|
|
|
|
|
|
|
| $ |
|
|
|
|
|
|
|
Hedged transactions recognized into earnings in the tables above represent amounts that were reclassified from accumulated other comprehensive income into earnings in connection with the consummation of interest rate swap agreements and the amortization of existing interest rate hedges. These amounts are net of income taxes of approximately $0.2 million, $0.2 million, $0.1 million and $(0.1) million for NU consolidated, CL&P, PSNH and WMECO, respectively, for the year ended December 31, 2008.COMMON SHARES
The following table providessets forth the forward starting interest rate swap transactions entered into byNU common shares and the company,shares of CL&P, PSNH and WMECO common stock authorized and Yankee Gas to hedge interest rate risk associated with theirissued and the respective long-term debt issuances in 2008par values as of December 31, 2010 and 2007:2009:
|
| 2008 |
|
| 2007 | |||||||||||||||
|
| NU parent |
|
| CL&P |
|
| PSNH |
|
| Yankee Gas |
|
| CL&P |
|
| CL&P |
|
| WMECO |
Long-term debt issued (in millions) |
| $250 |
|
| $300 |
|
| $110 |
|
| $100 |
|
| $150 and $150 |
|
| $100 and $100 |
|
| $40 |
Date entered into swap transaction |
| 12/3/07 |
|
| 12/5/07 |
|
| 12/4/07 |
|
| 12/4/07 |
|
| 2/22/07 |
|
| 7/16/07 |
|
| 7/17/07 |
Term |
| 5-year |
|
| 10-year |
|
| 10-year |
|
| 10-year |
|
| 10-year and |
|
| 10-year and |
|
| 30-year |
Termination date |
| 6/2/08 |
|
| 5/19/08 |
|
| 3/24/08 | (3) |
| 9/23/08 | (4) |
| 3/27/07 |
|
| 09/10/07 |
|
| 8/15/07 |
Loaded LIBOR swap percentage |
| 4.102 | (1) |
| 4.590 and |
|
| 4.5575 and 4.147 |
|
| 4.635 and |
|
| 5.229 and |
|
| 5.718 and |
|
|
|
Charge to accumulated other |
| $0.1 |
|
| $2.3 |
|
| $0.9 | (6) |
| $0.7 |
|
| $1.6 |
|
| $4.7 | (8) |
| $0.6 |
|
|
|
|
| Shares | ||||
|
|
| Per Share |
| Authorized |
| Issued | ||
|
|
| Par Value |
| 2010 and 2009 |
| 2010 |
| 2009 |
NU |
| $ | 5 |
| 225,000,000 |
| 195,781,740 |
| 195,455,214 |
CL&P |
| $ | 10 |
| 24,500,000 |
| 6,035,205 |
| 6,035,205 |
PSNH |
| $ | 1 |
| 100,000,000 |
| 301 |
| 301 |
WMECO |
| $ | 25 |
| 1,072,471 |
| 434,653 |
| 434,653 |
(1)
The interest rate swap was entered into with a notional amountOn March 20, 2009, NU issued approximately 19 million common shares. As of $200 million and had a positive fair value of $0.6 million at December 31, 2007.2010 and 2009, 19,333,659 and 19,708,136 NU common shares were held as treasury shares, respectively.
(2)19.
The two locked rates reflect two forward starting interest rate swap transactions, each with a notional amount of $150 million and were recorded at a fair value of a positive $1.4 million at December 2007.COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)
(3)
The first swap transaction had a fair value of a positive $0.6 million at December 31, 2007. This swap was replaced at its scheduled termination date on March 24, 2008 with a new swap to extend the hedging relationship to the revised pricing dateA summary of the long-term debt to May 19, 2008.
(4)
The first swap transaction had a positive fair valuechanges in Common Shareholders' Equity and Noncontrolling Interests of $0.5 million at December 31, 2007 and was replaced at its scheduled termination date of September 23, 2008 with a new swap to extend the hedging relationship to the revised pricing date of the long-term debt on October 7, 2008. On September 26, 2008, the debt was priced and the second swap was unwound.
(5)
The charge to accumulated other comprehensive income will be amortized into earnings over the terms of each respective long-term debt.
(6)
The amount charged to accumulated other comprehensive income is net of ineffectiveness of $0.2 million related to the settlement of the March 2008 forward starting swap agreement.
(7)
The two locked rates reflect two forward starting interest rate swap transactions, each with a notional amount of $75 million.
FS-82
(8)
The amount charged to accumulated other comprehensive income is net of ineffectiveness of $67 thousand incurred upon termination of the hedge.
(9)
The two locked rates reflect two forward starting interest rate swap transactions, each with a notional amount of $50 million.
For NU consolidated, it is estimated that a charge of $0.2 million will be reclassified from accumulated other comprehensive income as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements, which have been settled. Included in this amount are estimated charges of $0.4 million and $0.1 million for CL&P and PSNH, respectively, and a benefit of $0.1 million for WMECO. At December 31, 2008, it is estimated that a pre-tax amount of $0.7 million included in the accumulated other comprehensive income balance will be reclassified as a decrease to earnings over the next 12 months related to Pension, SERP and other postretirement benefits adjustments for NU consolidated.
15.
Restructuring and Impairment Charges and Discontinued Operations (NU, NU Enterprises)
Restructuring and Impairment Charges:NU Enterprises recorded $0.2 million and $27.6 million of pre-tax restructuring and impairment charges for the years ended December 31, 2007 and 2006, respectively, relating to the decision to exit NU Enterprises. There were no restructuring and impairment charges recorded in 2008. These charges are included as part of the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements.
In 2006, $22.7 million of restructuring charges and $0.3 million of impairment charges were recorded related to Select Energy’s wholesale marketing, retail marketing and competitive generation businesses. The restructuring charges were recorded for consulting fees, legal fees, sale-related environmental fees and employee related and other costs. The impairment costs related to the divestiture of the competitive generation business. In addition, $4.6 million of restructuring charges were recorded related to the remaining services businesses. Included in this amount are restructuring charges of $1 million related to the termination of NU parent's guarantee of SESI's performance under government contracts. Of these amounts $19.1 million are included in discontinued operations and $8.5 million are included as other operating expenses. In 2007, $0.2 million of restructuring charges were recorded relating to the remaining services businesses.
The following table summarizes the liabilities related to restructuring costs, which are recorded in accounts payable and other current liabilities on the accompanying consolidated balance sheets since the decision to exit NU Enterprises in 2005:
|
| Employee- |
| Professional |
|
| |||
Restructuring liability as of January 1, 2005 |
| $ | - |
| $ | - |
| $ | - |
Costs incurred |
|
| 2.3 |
|
| 7.4 |
|
| 9.7 |
Cash payments and other deductions/reversals |
|
| (0.5) |
|
| (3.2) |
|
| (3.7) |
Restructuring liability as of December 31, 2005 |
|
| 1.8 |
|
| 4.2 |
|
| 6.0 |
Costs incurred |
|
| 3.3 |
|
| 24.0 |
|
| 27.3 |
Cash payments and other deductions/reversals |
|
| (3.7) |
|
| (25.9) |
|
| (29.6) |
Restructuring liability as of December 31, 2006 |
|
| 1.4 |
|
| 2.3 |
|
| 3.7 |
Costs incurred |
|
| - |
|
| 0.2 |
|
| 0.2 |
Cash payments and other deductions/reversals |
|
| (1.4) |
|
| (2.2) |
|
| (3.6) |
Restructuring liability as of December 31, 2007 and 2008 |
| $ | - |
| $ | 0.3 |
| $ | 0.3 |
Discontinued Operations: NU's consolidated statements of income for the years ended December 31, 2007 and 2006 present NGC, Mt. Tom, SESI, Woods Electrical and SECI as discontinued operations. Under discontinued operations presentation, revenues and expenses of the businesses classified as discontinued operations are classified in income from discontinued operations on the accompanying consolidated statements of income.
Summarized financial information for the discontinued operations is as follows:
|
| For the Years Ended December 31, | |||||||
(Millions of Dollars) |
| 2008 |
| 2007 |
| 2006 | |||
Operating revenue |
| $ | - |
| $ | 1.3 |
| $ | 180.7 |
Income before income taxes |
|
| - |
|
| 0.4 |
|
| 31.3 |
Gains from sale/disposition of discontinued operations |
|
| - |
|
| 2.1 |
|
| 504.3 |
Income tax expense |
|
| - |
|
| 1.9 |
|
| 198.0 |
Net income |
|
| - |
|
| 0.6 |
|
| 337.6 |
|
| For the Years Ended December 31, | ||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | ||||||||||||||||||
(Millions of Dollars) |
| Common |
| Noncontrolling |
| Total |
| Preferred Stock |
| Total |
| Preferred Stock |
| Total |
| Preferred Stock | ||||||||
Balance as of Beginning of Year |
| $ | 3,577.9 |
| $ | - |
| $ | 3,577.9 |
| $ | 116.2 |
| $ | 3,020.3 |
| $ | 116.2 |
| $ | 2,913.8 |
| $ | 116.2 |
Net Income |
|
| 394.1 |
|
| - |
|
| 394.1 |
|
| - |
|
| 335.6 |
|
| - |
|
| 266.4 |
|
| - |
Dividends on Common Shares |
|
| (181.7) |
|
| - |
|
| (181.7) |
|
| - |
|
| (162.8) |
|
| - |
|
| (129.0) |
|
| - |
Dividends on Preferred Stock |
|
| (6.1) |
|
| - |
|
| (6.1) |
|
| (6.1) |
|
| (5.6) |
|
| (5.6) |
|
| (5.6) |
|
| (5.6) |
Issuance of Common Shares |
|
| 7.4 |
|
| - |
|
| 7.4 |
|
| - |
|
| 389.7 |
|
| - |
|
| 5.5 |
|
| - |
Capital Stock Expenses, Net |
|
| (0.3) |
|
| - |
|
| (0.3) |
|
| - |
|
| (12.5) |
|
| - |
|
| 0.1 |
|
| - |
Contributions to NPT |
|
| - |
|
| 1.4 |
|
| 1.4 |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Other Transactions, Net |
|
| 19.9 |
|
| - |
|
| 19.9 |
|
| - |
|
| 18.7 |
|
| - |
|
| 15.7 |
|
| - |
Net Income Attributable to |
|
| (0.1) |
|
| 0.1 |
|
| - |
|
| 6.1 |
|
| - |
|
| 5.6 |
|
| - |
|
| 5.6 |
Other Comprehensive |
|
| 0.1 |
|
| - |
|
| 0.1 |
|
| - |
|
| (5.5) |
|
| - |
|
| (46.6) |
|
| - |
Balance as of End of Year |
| $ | 3,811.2 |
| $ | 1.5 |
| $ | 3,812.7 |
| $ | 116.2 |
| $ | 3,577.9 |
| $ | 116.2 |
| $ | 3,020.3 |
| $ | 116.2 |
In 2007, gains from sale/disposition of discontinued operations of $2.1 million primarily relates to the favorable resolution of legal and contract issues from businesses sold of $4.2 million, partially offset by charges related to the sale of the competitive generation business, including a $1.9 million charge resulting from a purchase price adjustment from the sale of the competitive generation business recorded in the first quarter of 2007. The 2006 gains from sale/disposition of discontinued operations of $504.3 million relates to the gain on the sale of NGC and Mt. Tom of $511.1 million and a $1.6 million gain on the sale of the Massachusetts location of SECI, partially offset by an $8.4 million loss on the sale of SESI. The sale of a portion of the former Woods Electrical had a de minimis impact on earnings in 2006. In addition, in 2006, NU recorded a pre-tax loss on the sale of SENY of $0.3 million, which is re corded as other operating expenses as part of continuing operations on the accompanying consolidated statement of income. 20.
FS-83
Included in the 2007 income tax expense amount above is a $0.8 million charge recognized to adjust the estimated income tax accrual for actual taxes paid on the gains related to businesses sold in 2006.
No intercompany revenues were included in discontinued operations for the years ended December 31, 2008 or 2007. For the year ended December 31, 2006, included in discontinued operations are $161 million of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations. Of this amount, $160.7 million represents revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy. NGC's and Mt. Tom's revenues and earnings related to these contracts are included in discontinued operations while Select Energy's related expenses and losses are included in continuing operations. Select Energy's obligation to NGC and Mt. Tom ended at the time of sale in 2006.
At December 31, 2008, NU did not have or expect to have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.
16.
Earnings Per ShareEARNINGS PER SHARE (NU)
EPS is computed based upon the monthly weighted average number of common shares outstanding, excluding unallocated ESOP shares, during each year. Diluted EPS is computed on the basis of the monthly weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. The computation of diluted EPS excludes the effect of the potential exercise of share awards when the average market price of the common shares is lower than the exercise price of the related awards during the period. These outstanding share awards are not included in the computation of diluted EPS because the effect would have been antidilutive. In 2006, 2,500 options2010 and 2009, there were 1,578 and 17,637 share awards excluded from the following tablecomputation, respectively, as these optionsawards were antidilutive. In 2008, and 2007, there were no antidilutive optionsshare awards outstanding.
The following table sets forth the components of basic and diluted EPS:
(Millions of Dollars, except share information) |
| 2008 |
| 2007 |
| 2006 | |||
Income from continuing operations |
| $ | 260.8 |
| $ | 245.9 |
| $ | 132.9 |
Income from discontinued operations |
|
| - |
|
| 0.6 |
|
| 337.7 |
Net income |
| $ | 260.8 |
| $ | 246.5 |
| $ | 470.6 |
|
|
|
|
|
|
|
|
|
|
Basic common shares outstanding (average) |
|
| 155,531,846 |
|
| 154,759,727 |
|
| 153,767,527 |
Dilutive effect |
|
| 467,394 |
|
| 544,634 |
|
| 379,142 |
Fully diluted common shares outstanding (average) |
|
| 155,999,240 |
|
| 155,304,361 |
|
| 154,146,669 |
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
Income from continuing operations |
| $ | 1.68 |
| $ | 1.59 |
| $ | 0.86 |
Income from discontinued operations |
|
| - |
|
| - |
|
| 2.20 |
Net income |
| $ | 1.68 |
| $ | 1.59 |
| $ | 3.06 |
|
|
|
|
|
|
|
|
|
|
Fully Diluted EPS: |
|
|
|
|
|
|
|
|
|
Income from continuing operations |
| $ | 1.67 |
| $ | 1.59 |
| $ | 0.86 |
Income from discontinued operations |
|
| - |
|
| - |
|
| 2.19 |
Net income |
| $ | 1.67 |
| $ | 1.59 |
| $ | 3.05 |
(Millions of Dollars, except share information) |
| 2010 |
| 2009 |
| 2008 | |||
Net Income Attributable to Controlling Interests |
| $ | 387.9 |
| $ | 330.0 |
| $ | 260.8 |
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
|
Basic |
|
| 176,636,086 |
|
| 172,567,928 |
|
| 155,531,846 |
Dilutive Effect |
|
| 249,301 |
|
| 149,318 |
|
| 467,394 |
Diluted |
|
| 176,885,387 |
|
| 172,717,246 |
|
| 155,999,240 |
Basic EPS |
| $ | 2.20 |
| $ | 1.91 |
| $ | 1.68 |
Diluted EPS |
| $ | 2.19 |
| $ | 1.91 |
| $ | 1.67 |
RSUs and performance shares are included in basic common shares outstanding when shares are both vested and issued.as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of outstanding RSUs granted butand performance shares for which common shares have not been issued is calculated using the treasury stock method. Assumed proceeds of RSUsthe units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the RSUsunits (the difference between the market value of RSUsthe average units outstanding for the year, using the average market price during the year, and the grant date market value).
The dilutive effect of stock options is also calculated using the treasury stock method. Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit. The
155
theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the year, using the average market price during the year, and the grant price).
Allocated ESOP shares are included in basic common shares outstanding in the above table.
17.21.
Segment Information (All Companies)SEGMENT INFORMATION
Presentation: NU is organized between the regulated companies andRegulated companies' segments, NU Enterprises businessesand Other based on a combination of factors, including the characteristics of each business' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. Segment information for all years presented has been reclassified to conform to the current period presentation, except as indicated.
The regulated companiesRegulated companies' segments includinginclude the electric distribution and transmission segments, as well assegment, the natural gas distribution segment (Yankee Gas),and the electric transmission segment. The electric distribution segment includes the generation activities of PSNH and WMECO. The Regulated companies' segments represented approximately 99 percent, 99 percent and 87 percentsubstantially all of NU's total consolidated revenues for each of the years ended December 31, 2008, 20072010, 2009 and 2006, respectively.2008.
FS-84
The NU Enterprises segment is comprised of the following: 1) Select Energy (wholesale contracts), 2) Boulos, 3) NGS, 4) NGS Mechanical, 5) SECI, and 6) NU Enterprises parent.
Other in the segment tables below primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of RRR and the Quinnehtuk Company (real(a real estate subsidiaries)subsidiary), Mode 1 Communications, Inc. and the results of the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company,Company) and NorConn Properties, Inc.).
Effective on January 1, 2007, financial information for the remaining operations of HWP that were not exited as part of the sale of the competitive generation business was included as part of the Other reportable segment as these operations were no longer considered part of NU Enterprises subsequent to the sale. Accordingly, HWP’s remaining operations have been presented as part of the Other reportable segment for the year ended December 31, 2007. Effective December 31, 2008, HWP and HP&E transferred $4 million in transmission related assets to WMECO and are included in WMECO's transmission segment.
As a result of the sale of NU Enterprises' retail marketing and competitive generation businesses, the financial information used by management was reduced to the remaining wholesale contracts, the operations of the remaining energy services businesses and NU Enterprises parent. As a result of exiting these businesses in 2006 the operations of NU Enterprises have been aggregated and presented as one reportable segment for the years ended December 31, 2008, 2007 and 2006.
NU's consolidated statements of income for the years ended December 31, 2007 and 2006 present the operations for NGC, including certain components of NGS, Mt. Tom, SESI, a portion of the former Woods Electrical and SECI as discontinued operations. For further information and information regarding the exit from these businesses, see Note 15, "Restructuring and Impairment Charges and Discontinued Operations," to the consolidated financial statements.
Intercompany Transactions: Total Select Energy revenues from CL&P represented approximately $6.1 million of total NU Enterprises’ revenues for the year ended December 31, 2006. Total CL&P purchases from Select Energy related to nontraditional standard offer contracts are eliminated in consolidation. There were no such transactions in 2008 or 2007.
Select Energy purchases from NGC and Mt. Tom represented $160.7 million through November 1, 2006, at which time NU completed the sale of its 100 percent ownershiptransmission business to WMECO in NGC stock and Mt. Tom.
Customer Concentrations: Select Energy provided basic generation service in the New Jersey market through 2007. In 2006 and 2005, Select Energy also provided service in the Maryland market. Select Energy billings related to these contracts represented $116.1 million and $404.4 million for the years ended December 31, 2007 and 2006, respectively, of total NU Enterprises' billings. No other individual customer represented in excess of 10 percent of NU Enterprises' billings for the years ended December 31, 2008, 2007 and 2006. As these contracts expire, billings under a long-term contract with NYMPA will likely exceed 10 percent of NU Enterprises' billings in future periods.
Select Energy reported the settlement of all derivative contracts of the wholesale marketing business, including full requirements sales contracts and intercompany revenues, in fuel, purchased and net interchange power. This net presentation is a result of applying mark-to-market accounting to those contracts due to the decision to exit the wholesale marketing business.2008.
Regulated companiescompanies' revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.
NU’sNU's segment information for the years ended December 31, 2010, 2009 and 2008, 2007with the distribution segment segregated between electric and 2006natural gas, is as follows (some amounts may not agree between the financial statements and the segment schedules due to rounding):
|
| For the Year Ended December 31, 2008 | |||||||||||||||||||
|
| Regulated Companies |
|
| |||||||||||||||||
|
| Distribution (1) |
|
|
|
| |||||||||||||||
|
| Electric |
| Gas |
| Transmission |
| NU |
| Other |
|
|
|
| |||||||
Operating revenues |
| $ | 4,716.1 |
| $ | 577.4 |
| $ | 424.8 |
| $ | 114.1 |
| $ | 416.6 |
| $ | (448.9) |
| $ | 5,800.1 |
Depreciation and amortization |
|
| (581.5) |
|
| (26.2) |
|
| (49.3) |
|
| (0.6) |
|
| (13.1) |
|
| 0.9 |
|
| (669.8) |
Other operating expenses |
|
| (3,828.6) |
|
| (487.3) |
|
| (138.5) |
|
| (89.6) |
|
| (431.2) |
|
| 435.7 |
|
| (4,539.5) |
Operating income/(loss) |
|
| 306.0 |
|
| 63.9 |
|
| 237.0 |
|
| 23.9 |
|
| (27.7) |
|
| (12.3) |
|
| 590.8 |
Interest expense, net of AFUDC |
|
| (164.3) |
|
| (21.6) |
|
| (51.8) |
|
| (5.6) |
|
| (35.4) |
|
| 9.6 |
|
| (269.1) |
Interest income |
|
| 14.1 |
|
| 0.5 |
|
| 2.1 |
|
| 1.0 |
|
| 8.5 |
|
| (10.6) |
|
| 15.6 |
Other income, net |
|
| 13.1 |
|
| 0.3 |
|
| 21.8 |
|
| - |
|
| 227.5 |
|
| (227.9) |
|
| 34.8 |
Income tax (expense)/benefit |
|
| (41.6) |
|
| (16.0) |
|
| (68.8) |
|
| (6.2) |
|
| 28.7 |
|
| (1.8) |
|
| (105.7) |
Preferred dividends |
|
| (3.6) |
|
| - |
|
| (2.0) |
|
| - |
|
| - |
|
| - |
|
| (5.6) |
Net income |
| $ | 123.7 |
| $ | 27.1 |
| $ | 138.3 |
| $ | 13.1 |
| $ | 201.6 |
| $ | (243.0) |
| $ | 260.8 |
Total assets (2) |
| $ | 11,968.0 |
| $ | 1,424.8 |
| $ | - |
| $ | 85.2 |
| $ | 5,060.1 |
| $ | (4,549.6) |
| $ | 13,988.5 |
Cash flows for total |
| $ |
|
| $ |
|
| $ | 678.9 |
| $ |
|
| $ |
|
|
|
|
|
|
|
|
| For the Year Ended December 31, 2010 | |||||||||||||||||||
|
| Regulated Companies |
|
| |||||||||||||||||
|
| Distribution |
|
|
|
| |||||||||||||||
(Millions of Dollars) |
| Electric |
| Natural |
| Transmission |
| NU |
| Other |
|
|
|
| |||||||
Operating Revenues |
| $ | 3,802.0 |
| $ | 434.3 |
| $ | 625.6 |
| $ | 80.3 |
| $ | 441.3 |
| $ | (485.3) |
| $ | 4,898.2 |
Depreciation and Amortization |
|
| (506.7) |
|
| (23.8) |
|
| (86.7) |
|
| (0.3) |
|
| (15.5) |
|
| 3.8 |
|
| (629.2) |
Other Operating Expenses |
|
| (2,919.6) |
|
| (340.0) |
|
| (192.1) |
|
| (62.6) |
|
| (442.8) |
|
| 488.0 |
|
| (3,469.1) |
Operating Income/(Loss) |
|
| 375.7 |
|
| 70.5 |
|
| 346.8 |
|
| 17.4 |
|
| (17.0) |
|
| 6.5 |
|
| 799.9 |
Interest Expense |
|
| (133.4) |
|
| (17.9) |
|
| (73.2) |
|
| (2.2) |
|
| (15.2) |
|
| 4.6 |
|
| (237.3) |
Interest Income |
|
| 0.7 |
|
| - |
|
| 1.8 |
|
| - |
|
| 5.3 |
|
| (6.3) |
|
| 1.5 |
Other Income, Net |
|
| 24.4 |
|
| 0.8 |
|
| 14.3 |
|
| (0.3) |
|
| 436.7 |
|
| (435.5) |
|
| 40.4 |
Income Tax (Expense)/Benefit |
|
| (90.3) |
|
| (20.7) |
|
| (109.3) |
|
| (6.6) |
|
| 17.6 |
|
| (1.1) |
|
| (210.4) |
Net Income |
|
| 177.1 |
|
| 32.7 |
|
| 180.4 |
|
| 8.3 |
|
| 427.4 |
|
| (431.8) |
|
| 394.1 |
Net Income Attributable to |
|
| (3.6) |
|
| - |
|
| (2.6) |
|
| - |
|
| - |
|
| - |
|
| (6.2) |
Net Income Attributable to |
| $ | 173.5 |
| $ | 32.7 |
| $ | 177.8 |
| $ | 8.3 |
| $ | 427.4 |
|
| (431.8) |
|
| 387.9 |
Total Assets (as of) |
| $ | 8,968.9 |
| $ | 1,451.5 |
| $ | 3,418.3 |
| $ | 86.7 |
| $ | 6,197.9 |
| $ | (5,601.3) |
| $ | 14,522.0 |
Cash Flows for Total |
| $ | 560.1 |
| $ | 82.5 |
| $ | 239.2 |
| $ | - |
| $ | 72.7 |
|
| - |
|
| 954.5 |
FS-85156
|
| For the Year Ended December 31, 2007 | |||||||||||||||||||
|
| Regulated Companies |
|
| |||||||||||||||||
|
| Distribution (1) |
|
|
|
| |||||||||||||||
|
| Electric |
| Gas |
| Transmission |
| NU |
| Other |
|
|
|
| |||||||
Operating revenues |
| $ | 4,930.8 |
| $ | 514.1 |
| $ | 298.7 |
| $ | 97.7 |
| $ | 389.8 |
| $ | (408.9) |
| $ | 5,822.2 |
Depreciation and amortization |
|
| (428.5) |
|
| (24.7) |
|
| (37.4) |
|
| (0.5) |
|
| (16.7) |
|
| 0.8 |
|
| (507.0) |
Other operating expenses |
|
| (4,192.5) |
|
| (437.1) |
|
| (115.5) |
|
| (77.9) |
|
| (358.3) |
|
| 405.6 |
|
| (4,775.7) |
Operating income |
|
| 309.8 |
|
| 52.3 |
|
| 145.8 |
|
| 19.3 |
|
| 14.8 |
|
| (2.5) |
|
| 539.5 |
Interest expense, net of AFUDC |
|
| (167.9) |
|
| (19.0) |
|
| (36.7) |
|
| (8.9) |
|
| (33.3) |
|
| 25.6 |
|
| (240.2) |
Interest income |
|
| 6.0 |
|
| - |
|
| 3.8 |
|
| 2.4 |
|
| 34.3 |
|
| (26.6) |
|
| 19.9 |
Other income, net |
|
| 27.6 |
|
| 1.2 |
|
| 13.0 |
|
| - |
|
| 158.3 |
|
| (158.4) |
|
| 41.7 |
Income tax expense |
|
| (47.9) |
|
| (11.9) |
|
| (41.8) |
|
| (1.7) |
|
| (3.0) |
|
| (3.1) |
|
| (109.4) |
Preferred dividends |
|
| (4.0) |
|
| - |
|
| (1.6) |
|
| - |
|
| - |
|
| - |
|
| (5.6) |
Income from |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Income from |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
| $ | 123.6 |
| $ | 22.6 |
| $ | 82.5 |
| $ | 11.7 |
| $ | 171.1 |
| $ | (165.0) |
| $ | 246.5 |
Total assets (2) |
| $ | 9,977.1 |
| $ | 1,309.1 |
| $ | - |
| $ | 150.6 |
| $ | 4,154.3 |
| $ | (4,009.3) |
| $ | 11,581.8 |
Cash flows for total |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
|
|
|
|
|
|
|
| For the Year Ended December 31, 2009 | |||||||||||||||||||
|
| Regulated Companies |
|
| |||||||||||||||||
|
| Distribution |
|
|
|
| |||||||||||||||
(Millions of Dollars) |
| Electric |
| Natural |
| Transmission |
| NU |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues |
| $ | 4,358.4 |
| $ | 449.6 |
| $ | 577.9 |
| $ | 81.3 |
| $ | 400.8 |
| $ | (428.6) |
| $ | 5,439.4 |
Depreciation and Amortization |
|
| (431.5) |
|
| (26.8) |
|
| (71.0) |
|
| (0.4) |
|
| (13.0) |
|
| 1.9 |
|
| (540.8) |
Other Operating Expenses |
|
| (3,604.6) |
|
| (368.1) |
|
| (170.9) |
|
| (53.8) |
|
| (382.1) |
|
| 432.3 |
|
| (4,147.2) |
Operating Income |
|
| 322.3 |
|
| 54.7 |
|
| 336.0 |
|
| 27.1 |
|
| 5.7 |
|
| 5.6 |
|
| 751.4 |
Interest Expense |
|
| (149.1) |
|
| (22.1) |
|
| (72.5) |
|
| (2.8) |
|
| (33.4) |
|
| 6.3 |
|
| (273.6) |
Interest Income |
|
| 4.5 |
|
| - |
|
| 1.0 |
|
| - |
|
| 7.7 |
|
| (7.6) |
|
| 5.6 |
Other Income, Net |
|
| 24.0 |
|
| 0.3 |
|
| 7.6 |
|
| - |
|
| 371.6 |
|
| (371.4) |
|
| 32.1 |
Income Tax (Expense)/Benefit |
|
| (60.2) |
|
| (11.9) |
|
| (105.5) |
|
| (8.5) |
|
| 8.6 |
|
| (2.4) |
|
| (179.9) |
Net Income |
|
| 141.5 |
|
| 21.0 |
|
| 166.6 |
|
| 15.8 |
|
| 360.2 |
|
| (369.5) |
|
| 335.6 |
Net Income Attributable to |
|
| (3.3) |
|
| - |
|
| (2.3) |
|
| - |
|
| - |
|
| - |
|
| (5.6) |
Net Income Attributable to |
| $ | 138.2 |
| $ | 21.0 |
| $ | 164.3 |
| $ | 15.8 |
| $ | 360.2 |
| $ | (369.5) |
| $ | 330.0 |
Total Assets (as of) |
| $ | 8,881.1 |
| $ | 1,379.0 |
| $ | 3,263.0 |
| $ | 71.9 |
| $ | 5,857.8 |
| $ | (5,395.1) |
| $ | 14,057.7 |
Cash Flows for Total |
| $ | 521.5 |
| $ | 54.8 |
| $ | 286.0 |
| $ | - |
| $ | - |
| $ | 45.8 |
| $ | 908.1 |
|
| For the Year Ended December 31, 2006 | |||||||||||||||||||
|
| Regulated Companies |
|
| |||||||||||||||||
|
| Distribution (1) |
|
|
|
| |||||||||||||||
|
| Electric |
| Gas |
| Transmission |
| NU |
| Other |
|
|
|
| |||||||
Operating revenues |
| $ | 5,336.0 |
| $ | 453.9 |
| $ | 216.0 |
| $ | 901.8 |
| $ | 355.0 |
| $ | (385.0) |
| $ | 6,877.7 |
Depreciation and amortization |
|
| (387.2) |
|
| (22.7) |
|
| (29.8) |
|
| (0.7) |
|
| (18.8) |
|
| 14.1 |
|
| (445.1) |
Other operating expenses |
|
| (4,652.5) |
|
| (401.0) |
|
| (93.6) |
|
| (1,076.8) |
|
| (335.9) |
|
| 363.2 |
|
| (6,196.6) |
Operating income/(loss) |
|
| 296.3 |
|
| 30.2 |
|
| 92.6 |
|
| (175.7) |
|
| 0.3 |
|
| (7.7) |
|
| 236.0 |
Interest expense, net of AFUDC |
|
| (160.1) |
|
| (16.5) |
|
| (22.4) |
|
| (26.9) |
|
| (37.1) |
|
| 24.8 |
|
| (238.2) |
Interest income |
|
| 8.4 |
|
| - |
|
| 0.4 |
|
| 5.1 |
|
| 32.8 |
|
| (28.3) |
|
| 18.4 |
Other income, net |
|
| 31.9 |
|
| 1.4 |
|
| 6.8 |
|
| 0.1 |
|
| 205.2 |
|
| (199.5) |
|
| 45.9 |
Income tax benefit/(expense) |
|
| 13.4 |
|
| (3.2) |
|
| (16.4) |
|
| 78.1 |
|
| 5.0 |
|
| (0.6) |
|
| 76.3 |
Preferred dividends |
|
| (4.3) |
|
| - |
|
| (1.2) |
|
| - |
|
| - |
|
| - |
|
| (5.5) |
Income/(loss) from |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Income from |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
| $ | 185.6 |
| $ | 11.9 |
| $ | 59.8 |
| $ | 211.3 |
| $ | 206.2 |
| $ | (204.2) |
| $ | 470.6 |
Cash flows for total |
| $ |
|
| $ |
|
| $ |
|
| $ |
|
| $ |
|
|
|
|
|
|
|
|
| For the Year Ended December 31, 2008 | |||||||||||||||||||
|
| Regulated Companies |
|
| |||||||||||||||||
|
| Distribution |
|
|
|
| |||||||||||||||
(Millions of Dollars) |
| Electric |
| Natural |
| Transmission |
| NU |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues |
| $ | 4,716.1 |
| $ | 577.4 |
| $ | 424.8 |
| $ | 114.1 |
| $ | 416.6 |
| $ | (448.9) |
| $ | 5,800.1 |
Depreciation and Amortization |
|
| (581.5) |
|
| (26.2) |
|
| (49.3) |
|
| (0.6) |
|
| (13.1) |
|
| 0.9 |
|
| (669.8) |
Other Operating Expenses |
|
| (3,828.6) |
|
| (487.3) |
|
| (138.5) |
|
| (89.6) |
|
| (431.2) |
|
| 435.7 |
|
| (4,539.5) |
Operating Income/(Loss) |
|
| 306.0 |
|
| 63.9 |
|
| 237.0 |
|
| 23.9 |
|
| (27.7) |
|
| (12.3) |
|
| 590.8 |
Interest Expense |
|
| (164.3) |
|
| (21.6) |
|
| (51.8) |
|
| (5.6) |
|
| (35.4) |
|
| 9.6 |
|
| (269.1) |
Interest Income |
|
| 14.1 |
|
| 0.5 |
|
| 2.1 |
|
| 1.0 |
|
| 8.5 |
|
| (10.6) |
|
| 15.6 |
Other Income, Net |
|
| 13.1 |
|
| 0.3 |
|
| 21.8 |
|
| - |
|
| 227.5 |
|
| (227.9) |
|
| 34.8 |
Income Tax (Expense)/Benefit |
|
| (41.6) |
|
| (16.0) |
|
| (68.8) |
|
| (6.2) |
|
| 28.7 |
|
| (1.8) |
|
| (105.7) |
Net Income |
|
| 127.3 |
|
| 27.1 |
|
| 140.3 |
|
| 13.1 |
|
| 201.6 |
|
| (243.0) |
|
| 266.4 |
Net Income Attributable to |
|
| (3.6) |
|
| - |
|
| (2.0) |
|
| - |
|
| - |
|
| - |
|
| (5.6) |
Net Income Attributable to |
| $ | 123.7 |
| $ | 27.1 |
| $ | 138.3 |
| $ | 13.1 |
| $ | 201.6 |
| $ | (243.0) |
| $ | 260.8 |
Cash Flows for Total |
| $ |
|
| $ | 58.4 |
| $ | 678.9 |
| $ | - |
| $ | 30.3 |
| $ | - |
| $ | 1,255.4 |
(1)
IncludesThe information related to the distribution and transmission segments for CL&P, PSNH generation activities.
(2)
and WMECO for the years ended December 31, 2010, 2009 and 2008 is included below. Information for segmenting total assets between electric distribution and transmission is not available atas of December 31, 2008 and 2007. On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution columns above.2008.
(3)
Cash flows for total investments in plant included in the segment information above are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.
|
| CL&P - For the Years Ended December 31, | ||||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | ||||||||||||||||||||||
(Millions of Dollars) | Distribution |
| Transmission |
| Totals |
| Distribution |
| Transmission |
| Totals |
| Distribution |
| Transmission |
| Totals | |||||||||||
Operating Revenues |
| $ | 2,500.3 |
| $ | 498.8 |
| $ | 2,999.1 |
| $ | 2,954.6 |
| $ | 469.9 |
| $ | 3,424.5 |
| $ | 3,218.5 |
| $ | 339.9 |
| $ | 3,558.4 | |
Depreciation and |
|
| (355.5) |
|
| (67.6) |
|
| (423.1) |
|
| (330.3) |
|
| (58.4) |
|
| (388.7) |
|
| (433.1) |
|
| (39.4) |
|
| (472.5) | |
Other Operating Expenses |
|
| (1,942.4) |
|
| (146.0) |
|
| (2,088.4) |
|
| (2,441.7) |
|
| (129.0) |
|
| (2,570.7) |
|
| (2,610.5) |
|
| (102.0) |
|
| (2,712.5) | |
Operating Income |
|
| 202.4 |
|
| 285.2 |
|
| 487.6 |
|
| 182.6 |
|
| 282.5 |
|
| 465.1 |
|
| 174.9 |
|
| 198.5 |
|
| 373.4 | |
Interest Expense |
|
| (77.6) |
|
| (60.1) |
|
| (137.7) |
|
| (93.1) |
|
| (62.7) |
|
| (155.8) |
|
| (102.1) |
|
| (44.1) |
|
| (146.2) | |
Interest Income |
|
| 1.9 |
|
| 1.5 |
|
| 3.4 |
|
| 2.7 |
|
| 0.8 |
|
| 3.5 |
|
| 9.2 |
|
| 1.6 |
|
| 10.8 | |
Other Income, Net |
|
| 14.6 |
|
| 8.6 |
|
| 23.2 |
|
| 16.2 |
|
| 6.1 |
|
| 22.3 |
|
| 12.4 |
|
| 18.7 |
|
| 31.1 | |
Income Tax Expense |
|
| (43.6) |
|
| (88.8) |
|
| (132.4) |
|
| (31.1) |
|
| (87.7) |
|
| (118.8) |
|
| (20.8) |
|
| (57.1) |
|
| (77.9) | |
Net Income |
| $ | 97.7 |
| $ | 146.4 |
| $ | 244.1 |
| $ | 77.3 |
| $ | 139.0 |
| $ | 216.3 |
| $ | 73.6 |
| $ | 117.6 |
| $ | 191.2 | |
Total Assets (as of) |
| $ | 5,687.9 |
| $ | 2,599.7 |
| $ | 8,287.6 |
| $ | 5,771.1 |
| $ | 2,593.5 |
| $ | 8,364.6 |
| $ | - |
| $ | - |
| $ | - | |
Cash Flows for Total |
| $ | 270.2 |
| $ | 110.1 |
| $ | 380.3 |
| $ | 270.8 |
| $ | 164.9 |
| $ | 435.7 |
| $ | 294.3 |
| $ | 555.2 |
| $ | 849.5 |
FS-86
The segment information related to the distribution and transmission businesses for CL&P for the years ended December 31, 2008, 2007 and 2006 is as follows:
|
| CL&P - For the Year Ended December 31, 2008 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 3,218.5 |
| $ | 339.9 |
| $ | 3,558.4 |
Depreciation and amortization |
|
| (433.1) |
|
| (39.4) |
|
| (472.5) |
Other operating expenses |
|
| (2,610.5) |
|
| (102.0) |
|
| (2,712.5) |
Operating income |
|
| 174.9 |
|
| 198.5 |
|
| 373.4 |
Interest expense, net of AFUDC |
|
| (102.1) |
|
| (44.1) |
|
| (146.2) |
Interest income |
|
| 9.2 |
|
| 1.6 |
|
| 10.8 |
Other income, net |
|
| 12.4 |
|
| 18.7 |
|
| 31.1 |
Income tax expense |
|
| (20.8) |
|
| (57.1) |
|
| (77.9) |
Net income |
| $ | 73.6 |
| $ | 117.6 |
| $ | 191.2 |
Cash flows for total investments in plant (3) |
| $ | 294.3 |
| $ | 555.2 |
| $ | 849.5 |
|
| CL&P - For the Year Ended December 31, 2007 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 3,452.8 |
| $ | 229.0 |
| $ | 3,681.8 |
Depreciation and amortization |
|
| (279.5) |
|
| (29.0) |
|
| (308.5) |
Other operating expenses |
|
| (3,004.7) |
|
| (84.1) |
|
| (3,088.8) |
Operating income |
|
| 168.6 |
|
| 115.9 |
|
| 284.5 |
Interest expense, net of AFUDC |
|
| (108.1) |
|
| (30.3) |
|
| (138.4) |
Interest income |
|
| 3.0 |
|
| 2.5 |
|
| 5.5 |
Other income, net |
|
| 22.6 |
|
| 11.8 |
|
| 34.4 |
Income tax expense |
|
| (20.7) |
|
| (31.7) |
|
| (52.4) |
Net income |
| $ | 65.4 |
| $ | 68.2 |
| $ | 133.6 |
Cash flows for total investments in plant (3) |
| $ | 242.3 |
| $ | 583.9 |
| $ | 826.2 |
|
| CL&P - For the Year Ended December 31, 2006 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 3,825.2 |
| $ | 154.6 |
| $ | 3,979.8 |
Depreciation and amortization |
|
| (241.0) |
|
| (22.1) |
|
| (263.1) |
Other operating expenses |
|
| (3,416.3) |
|
| (64.3) |
|
| (3,480.6) |
Operating income |
|
| 167.9 |
|
| 68.2 |
|
| 236.1 |
Interest expense, net of AFUDC |
|
| (100.5) |
|
| (17.4) |
|
| (117.9) |
Interest income |
|
| 6.6 |
|
| 0.4 |
|
| 7.0 |
Other income, net |
|
| 24.6 |
|
| 6.2 |
|
| 30.8 |
Income tax benefit/(expense) |
|
| 53.3 |
|
| (9.3) |
|
| 44.0 |
Net income |
| $ | 151.9 |
| $ | 48.1 |
| $ | 200.0 |
Cash flows for total investments in plant (3) |
| $ | 183.8 |
| $ | 383.4 |
| $ | 567.2 |
The segment information related to the distribution (including generation) and transmission businesses for PSNH for the years ended December 31, 2008, 2007 and 2006 is as follows:
|
| PSNH - For the Year Ended December 31, 2008 | |||||||
(Millions of Dollars) |
| Distribution (1) |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 1,082.2 |
| $ | 59.0 |
| $ | 1,141.2 |
Depreciation and amortization |
|
| (104.0) |
|
| (7.2) |
|
| (111.2) |
Other operating expenses |
|
| (882.8) |
|
| (24.3) |
|
| (907.1) |
Operating income |
|
| 95.4 |
|
| 27.5 |
|
| 122.9 |
Interest expense, net of AFUDC |
|
| (44.6) |
|
| (5.6) |
|
| (50.2) |
Interest income |
|
| 2.9 |
|
| 0.5 |
|
| 3.4 |
Other income, net |
|
| 1.4 |
|
| 2.6 |
|
| 4.0 |
Income tax expense |
|
| (13.7) |
|
| (8.3) |
|
| (22.0) |
Net income |
| $ | 41.4 |
| $ | 16.7 |
| $ | 58.1 |
Cash flows for total investments in plant (3) |
| $ | 158.6 |
| $ | 80.3 |
| $ | 238.9 |
FS-87157
|
| PSNH - For the Year Ended December 31, 2007 | |||||||
(Millions of Dollars) |
| Distribution (1) |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 1,036.5 |
| $ | 46.6 |
| $ | 1,083.1 |
Depreciation and amortization |
|
| (107.3) |
|
| (5.8) |
|
| (113.1) |
Other operating expenses |
|
| (832.3) |
|
| (20.9) |
|
| (853.2) |
Operating income |
|
| 96.9 |
|
| 19.9 |
|
| 116.8 |
Interest expense, net of AFUDC |
|
| (42.0) |
|
| (4.3) |
|
| (46.3) |
Interest income |
|
| 1.5 |
|
| 0.6 |
|
| 2.1 |
Other income, net |
|
| 3.5 |
|
| 1.1 |
|
| 4.6 |
Income tax expense |
|
| (16.2) |
|
| (6.6) |
|
| (22.8) |
Net income |
| $ | 43.7 |
| $ | 10.7 |
| $ | 54.4 |
Cash flows for total investments in plant (3) |
| $ | 100.1 |
| $ | 67.6 |
| $ | 167.7 |
|
| PSNH - For the Years Ended December 31, | ||||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | ||||||||||||||||||||||
(Millions of Dollars) | Distribution |
| Transmission |
| Totals |
| Distribution |
| Transmission |
| Totals |
| Distribution |
| Transmission |
| Totals | |||||||||||
Operating Revenues |
| $ | 951.0 |
| $ | 82.4 |
| $ | 1,033.4 |
| $ | 1,035.8 |
| $ | 73.8 |
| $ | 1,109.6 |
| $ | 1,082.2 |
| $ | 59.0 |
| $ | 1,141.2 | |
Depreciation and |
|
| (118.4) |
|
| (10.4) |
|
| (128.8) |
|
| (70.5) |
|
| (9.3) |
|
| (79.8) |
|
| (104.0) |
|
| (7.2) |
|
| (111.2) | |
Other Operating Expenses |
|
| (696.0) |
|
| (32.4) |
|
| (728.4) |
|
| (865.8) |
|
| (29.4) |
|
| (895.2) |
|
| (882.8) |
|
| (24.3) |
|
| (907.1) | |
Operating Income |
|
| 136.6 |
|
| 39.6 |
|
| 176.2 |
|
| 99.5 |
|
| 35.1 |
|
| 134.6 |
|
| 95.4 |
|
| 27.5 |
|
| 122.9 | |
Interest Expense |
|
| (38.6) |
|
| (8.5) |
|
| (47.1) |
|
| (39.8) |
|
| (6.7) |
|
| (46.5) |
|
| (44.6) |
|
| (5.6) |
|
| (50.2) | |
Interest Income/(Loss) |
|
| (1.7) |
|
| 0.2 |
|
| (1.5) |
|
| 2.1 |
|
| 0.1 |
|
| 2.2 |
|
| 2.9 |
|
| 0.5 |
|
| 3.4 | |
Other Income, Net |
|
| 11.6 |
|
| 1.7 |
|
| 13.3 |
|
| 6.0 |
|
| 1.3 |
|
| 7.3 |
|
| 1.4 |
|
| 2.6 |
|
| 4.0 | |
Income Tax Expense |
|
| (38.6) |
|
| (12.2) |
|
| (50.8) |
|
| (20.2) |
|
| (11.8) |
|
| (32.0) |
|
| (13.7) |
|
| (8.3) |
|
| (22.0) | |
Net Income |
| $ | 69.3 |
| $ | 20.8 |
| $ | 90.1 |
| $ | 47.6 |
| $ | 18.0 |
| $ | 65.6 |
| $ | 41.4 |
| $ | 16.7 |
| $ | 58.1 | |
Total Assets (as of) |
| $ | 2,399.3 |
| $ | 490.5 |
| $ | 2,889.8 |
| $ | 2,255.0 |
| $ | 442.2 |
| $ | 2,697.2 |
| $ | - |
| $ | - |
| $ | - | |
Cash Flows for Total |
| $ | 252.2 |
| $ | 44.1 |
| $ | 296.3 |
| $ | 207.8 |
| $ | 58.6 |
| $ | 266.4 |
| $ | 158.6 |
| $ | 80.3 |
| $ | 238.9 |
|
| PSNH - For the Year Ended December 31, 2006 | |||||||
(Millions of Dollars) |
| Distribution (1) |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 1,100.1 |
| $ | 40.8 |
| $ | 1,140.9 |
Depreciation and amortization |
|
| (147.1) |
|
| (5.2) |
|
| (152.3) |
Other operating expenses |
|
| (856.2) |
|
| (19.5) |
|
| (875.7) |
Operating income |
|
| 96.8 |
|
| 16.1 |
|
| 112.9 |
Interest expense, net of AFUDC |
|
| (42.4) |
|
| (3.3) |
|
| (45.7) |
Interest income |
|
| 1.1 |
|
| - |
|
| 1.1 |
Other income, net |
|
| 5.7 |
|
| 0.5 |
|
| 6.2 |
Income tax expense |
|
| (34.2) |
|
| (5.0) |
|
| (39.2) |
Net income |
| $ | 27.0 |
| $ | 8.3 |
| $ | 35.3 |
Cash flows for total investments in plant (3) |
| $ | 92.3 |
| $ | 34.4 |
| $ | 126.7 |
|
| WMECO - For the Years Ended December 31, | ||||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2008 | ||||||||||||||||||||||
(Millions of Dollars) | Distribution |
| Transmission |
| Totals |
| Distribution |
| Transmission |
| Totals |
| Distribution |
| Transmission |
| Totals | |||||||||||
Operating Revenues |
| $ | 350.9 |
| $ | 44.3 |
| $ | 395.2 |
| $ | 368.2 |
| $ | 34.2 |
| $ | 402.4 |
| $ | 415.6 |
| $ | 25.9 |
| $ | 441.5 | |
Depreciation and |
|
| (32.9) |
|
| (8.6) |
|
| (41.5) |
|
| (30.8) |
|
| (3.2) |
|
| (34.0) |
|
| (44.4) |
|
| (2.7) |
|
| (47.1) | |
Other Operating Expenses |
|
| (281.3) |
|
| (13.8) |
|
| (295.1) |
|
| (297.3) |
|
| (12.5) |
|
| (309.8) |
|
| (335.5) |
|
| (12.4) |
|
| (347.9) | |
Operating Income |
|
| 36.7 |
|
| 21.9 |
|
| 58.6 |
|
| 40.1 |
|
| 18.5 |
|
| 58.6 |
|
| 35.7 |
|
| 10.8 |
|
| 46.5 | |
Interest Expense |
|
| (17.1) |
|
| (4.7) |
|
| (21.8) |
|
| (16.1) |
|
| (3.2) |
|
| (19.3) |
|
| (17.5) |
|
| (2.1) |
|
| (19.6) | |
Interest Income |
|
| 0.4 |
|
| 0.2 |
|
| 0.6 |
|
| (0.3) |
|
| - |
|
| (0.3) |
|
| 1.9 |
|
| 0.1 |
|
| 2.0 | |
Other Income, Net |
|
| (1.8) |
|
| 3.8 |
|
| 2.0 |
|
| 1.8 |
|
| 0.3 |
|
| 2.1 |
|
| (0.7) |
|
| 0.6 |
|
| (0.1) | |
Income Tax Expense |
|
| (8.1) |
|
| (8.2) |
|
| (16.3) |
|
| (8.8) |
|
| (6.1) |
|
| (14.9) |
|
| (7.1) |
|
| (3.4) |
|
| (10.5) | |
Net Income |
| $ | 10.1 |
| $ | 13.0 |
| $ | 23.1 |
| $ | 16.7 |
| $ | 9.5 |
| $ | 26.2 |
| $ | 12.3 |
| $ | 6.0 |
| $ | 18.3 | |
Total Assets (as of) |
| $ | 884.2 |
| $ | 315.4 |
| $ | 1,199.6 |
| $ | 863.2 |
| $ | 238.6 |
| $ | 1,101.8 |
| $ | - |
| $ | - |
| $ | - | |
Cash Flows for Total |
| $ | 37.6 |
| $ | 77.6 |
| $ | 115.2 |
| $ | 42.9 |
| $ | 62.5 |
| $ | 105.4 |
| $ | 34.9 |
| $ | 43.4 |
| $ | 78.3 |
The segment information related to the distribution and transmission businesses for WMECO for the years ended December 31, 2008, 2007 and 2006 is as follows:22.
|
| WMECO - For the Year Ended December 31, 2008 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 415.6 |
| $ | 25.9 |
| $ | 441.5 |
Depreciation and amortization |
|
| (44.4) |
|
| (2.7) |
|
| (47.1) |
Other operating expenses |
|
| (335.5) |
|
| (12.4) |
|
| (347.9) |
Operating income |
|
| 35.7 |
|
| 10.8 |
|
| 46.5 |
Interest expense, net of AFUDC |
|
| (17.5) |
|
| (2.1) |
|
| (19.6) |
Interest income |
|
| 1.9 |
|
| 0.1 |
|
| 2.0 |
Other income, net |
|
| (0.7) |
|
| 0.6 |
|
| (0.1) |
Income tax benefit |
|
| (7.1) |
|
| (3.4) |
|
| (10.5) |
Net income |
| $ | 12.3 |
| $ | 6.0 |
| $ | 18.3 |
Cash flows for total investments in plant (3) |
| $ | 34.9 |
| $ | 43.4 |
| $ | 78.3 |
|
| WMECO - For the Year Ended December 31, 2007 | |||||||
(Millions of Dollars) |
| Distribution |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 441.6 |
| $ | 23.1 |
| $ | 464.7 |
Depreciation and amortization |
|
| (41.7) |
|
| (2.5) |
|
| (44.2) |
Other operating expenses |
|
| (355.6) |
|
| (10.7) |
|
| (366.3) |
Operating income |
|
| 44.3 |
|
| 9.9 |
|
| 54.2 |
Interest expense, net of AFUDC |
|
| (17.7) |
|
| (2.1) |
|
| (19.8) |
Interest income |
|
| 1.5 |
|
| 0.7 |
|
| 2.2 |
Other income, net |
|
| 1.6 |
|
| - |
|
| 1.6 |
Income tax benefit |
|
| (11.2) |
|
| (3.4) |
|
| (14.6) |
Net income |
| $ | 18.5 |
| $ | 5.1 |
| $ | 23.6 |
Cash flows for total investments in plant (3) |
| $ | 29.9 |
| $ | 17.4 |
| $ | 47.3 |
|
| WMECO - For the Year Ended December 31, 2006 | |||||||
|
| Distribution |
| Transmission |
| Totals | |||
Operating revenues (2) |
| $ | 410.9 |
| $ | 20.6 |
| $ | 431.5 |
Depreciation and amortization |
|
| 0.7 |
|
| (2.4) |
|
| (1.7) |
Other operating expenses |
|
| (380.0) |
|
| (9.8) |
|
| (389.8) |
Operating income |
|
| 31.6 |
|
| 8.4 |
|
| 40.0 |
Interest expense, net of AFUDC |
|
| (17.1) |
|
| (1.8) |
|
| (18.9) |
Interest income |
|
| 0.7 |
|
| - |
|
| 0.7 |
Other income, net |
|
| 1.4 |
|
| 0.2 |
|
| 1.6 |
Income tax benefit |
|
| (5.6) |
|
| (2.2) |
|
| (7.8) |
Net income |
| $ | 11.0 |
| $ | 4.6 |
| $ | 15.6 |
Cash flows for total investments in plant (3) |
| $ | 29.7 |
| $ | 13.1 |
| $ | 42.8 |
FS-88
(1)
Includes PSNH generation activities.
(2)
CL&P, PSNH and WMECO revenues are primarily derived from residential, commercial and industrial customers and are not dependent on any single customer.
(3)
Cash flows for total investments in plant included in the segment information above are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.
18.
Subsequent Event (NU, CL&P)SUBSEQUENT EVENT (WMECO)
On February 13, 2009, CL&PJanuary 31, 2011, the DPU issued $250a final decision on WMECO's distribution rate case approving an annualized rate increase of $16.8 million of Series A first and refunding mortgage bonds with a coupon rate of 5.5 percent and a maturity date ofeffective February 1, 2019.2011, an authorized distribution segment regulatory ROE of 9.6 percent, a decoupling plan with no inflation adjustment, and recovery of certain 2008 and 2010 major storm costs over five years and recovery of certain hardship costs. The proceeds from this issuance will be used to repay short-term debt and to fund CL&P's ongoing capitalDPU did not approve WMECO’s request for rate recovery of increased reliability infrastructure investment programs.averaging approximately $20 million per year.
FS-89The decision clarified which customer hardship balances should be recovered through rates, which resulted in an increase to WMECO’s uncollectible accounts receivable reserves and bad debt expense, both of which have been reflected on the accompanying consolidated financial statements. The decision also disallowed recovery of certain previously deferred rate case filing costs and allowed recovery of an additional amount not previously deferred for 2010 tax benefits lost as a result of the 2010 Health Care Act; these amounts were recorded in Net Income, with offsets to Regulatory Assets, both of which have also been reflected on the accompanying consolidated financial statements. For the year ended December 31, 2010, the net effect of these impacts was a pre-tax charge of approximately $1.8 million.
23.
QUARTERLY FINANCIAL DATA (UNAUDITED)
NU Consolidated Statements of Quarterly Financial Data |
| Quarter Ended (a) | ||||||||||
(Millions of Dollars, except per share information) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2010 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 1,339.4 |
| $ | 1,111.4 |
| $ | 1,243.3 |
| $ | 1,204.1 |
Operating Income |
|
| 226.7 |
|
| 178.3 |
|
| 199.6 |
|
| 195.3 |
Net Income |
|
| 87.6 |
|
| 73.3 |
|
| 101.9 |
|
| 131.3 |
Net Income Attributable to Controlling Interests |
|
| 86.2 |
|
| 71.9 |
|
| 100.5 |
|
| 129.3 |
Basic and Diluted Earnings Per Common Share |
| $ | 0.49 |
| $ | 0.41 |
| $ | 0.57 |
| $ | 0.73 |
NU Consolidated Statements of Quarterly Financial Data (Unaudited) | ||||||||||||
| ||||||||||||
|
| Quarter Ended (a) | ||||||||||
(Thousands of Dollars, except per share information) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2008 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 1,519,967 |
| $ | 1,325,345 |
| $ | 1,506,897 |
| $ | 1,447,886 |
Operating Income |
|
| 132,272 |
|
| 138,119 |
|
| 149,077 |
|
| 171,297 |
Net Income |
|
| 58,393 |
|
| 57,848 |
|
| 72,689 |
|
| 71,898 |
Basic and Fully Diluted Earnings Per Common Share |
| $ | 0.38 |
| $ | 0.37 |
| $ | 0.47 |
| $ | 0.46 |
2007 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 1,703,518 |
| $ | 1,391,772 |
| $ | 1,450,977 |
| $ | 1,275,959 |
Operating Income |
|
| 155,733 |
|
| 116,808 |
|
| 123,360 |
|
| 143,580 |
Income from Continuing Operations |
|
| 76,407 |
|
| 46,012 |
|
| 50,182 |
|
| 73,295 |
(Loss)/Income from Discontinued Operations |
|
| (1,313) |
|
| 2,541 |
|
| (58) |
|
| (583) |
Net Income |
|
| 75,094 |
|
| 48,553 |
|
| 50,124 |
|
| 72,712 |
Basic and Fully Diluted Earnings/(Loss) Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations |
| $ | 0.50 |
| $ | 0.30 |
| $ | 0.32 |
| $ | 0.47 |
(Loss)/Income from Discontinued Operations |
|
| (0.01) |
|
| 0.01 |
|
| - |
|
| - |
Net Income |
| $ | 0.49 |
| $ | 0.31 |
| $ | 0.32 |
| $ | 0.47 |
2009 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 1,593.5 |
| $ | 1,224.4 |
| $ | 1,306.2 |
| $ | 1,315.3 |
Operating Income |
|
| 217.3 |
|
| 179.2 |
|
| 162.5 |
|
| 192.4 |
Net Income |
|
| 99.1 |
|
| 84.2 |
|
| 66.2 |
|
| 86.1 |
Net Income Attributable to Controlling Interests |
|
| 97.7 |
|
| 82.9 |
|
| 64.8 |
|
| 84.7 |
Basic and Diluted Earnings Per Common Share |
| $ | 0.60 |
| $ | 0.47 |
| $ | 0.37 |
| $ | 0.48 |
(a)
The summation of quarterly EPS data may not equal annual data due to rounding.
158
CL&P Consolidated Statements of Quarterly Financial Data |
| Quarter Ended | ||||||||||
(Millions of Dollars) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2010 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 795.0 |
| $ | 707.9 |
| $ | 789.2 |
| $ | 707.0 |
Operating Income |
|
| 125.5 |
|
| 106.2 |
|
| 131.4 |
|
| 124.6 |
Net Income |
|
| 48.4 |
|
| 44.1 |
|
| 69.0 |
|
| 82.6 |
2009 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 954.5 |
| $ | 784.9 |
| $ | 859.3 |
| $ | 825.8 |
Operating Income |
|
| 115.4 |
|
| 118.1 |
|
| 110.1 |
|
| 121.6 |
Net Income |
|
| 53.1 |
|
| 58.4 |
|
| 46.5 |
|
| 58.2 |
PSNH Consolidated Statements of Quarterly Financial Data |
| Quarter Ended | ||||||||||
(Millions of Dollars) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2010 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 258.6 |
| $ | 238.3 |
| $ | 277.0 |
| $ | 259.5 |
Operating Income |
|
| 39.9 |
|
| 43.4 |
|
| 49.8 |
|
| 43.1 |
Net Income |
|
| 15.8 |
|
| 21.6 |
|
| 28.8 |
|
| 23.9 |
2009 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 307.7 |
| $ | 262.9 |
| $ | 275.1 |
| $ | 263.9 |
Operating Income |
|
| 36.1 |
|
| 31.2 |
|
| 34.1 |
|
| 33.2 |
Net Income |
|
| 17.5 |
|
| 16.6 |
|
| 16.2 |
|
| 15.3 |
WMECOConsolidated Statements of Quarterly Financial Data |
| Quarter Ended | ||||||||||
(Millions of Dollars) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
| $ | 100.2 |
| $ | 92.5 |
| $ | 103.7 |
| $ | 98.8 |
Operating Income |
|
| 16.4 |
|
| 14.3 |
|
| 14.9 |
|
| 13.1 |
Net Income |
|
| 5.7 |
|
| 5.2 |
|
| 7.3 |
|
| 4.9 |
2009 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 118.1 |
| $ | 95.1 |
| $ | 96.6 |
| $ | 92.6 |
Operating Income |
|
| 15.3 |
|
| 13.2 |
|
| 17.1 |
|
| 13.0 |
Net Income |
|
| 6.1 |
|
| 5.8 |
|
| 8.5 |
|
| 5.7 |
159
Item 8A.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
No events that would be described in response to this item have occurred with respect to NU, CL&P, PSNH or WMECO.
Item 8B.
Controls and Procedures
Management, on behalf of NU, CL&P, PSNH and WMECO, is responsible for the preparation, integrity, and fair presentation of the accompanying Consolidated Financial Statements and other sections of this combined Annual Report on Form 10-K. NU, CL&P, PSNH and WMECO’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management, on behalf of NU, CL&P, PSNH and WMECO, is responsible for establishing and maintaining adequate internal controls over financial reporting. The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officers and principal financial officer, an evaluation of the effective ness of internal controls over financial reporting was conducted based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at NU, CL&P, PSNH and WMECO were effective as of December 31, 2010.
Management, on behalf of NU, CL&P, PSNH and WMECO, undertook a separate evaluation of the design and operation of disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and forms of the SEC. This evaluation was made under management’s supervision and with management’s participation, including the principal executive officers and principal financial officer, as of the end of the period covered by this report on Form 10-K. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 i) is recorded, processed , summarized, and reported within the time periods specified in SEC rules and forms and ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH and WMECO during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
Item 9.
Other Information
No information is required to be disclosed under this item as of December 31, 2010, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2010.
FS-90160
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
The information in Item 10 is provided as of February 24, 2011 except where otherwise indicated.
Certain information required by this Item 10 is omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.
NU
In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information to be contained in the sections captioned "Election of Trustees," "Governance of Northeast Utilities" and the related subsections, "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of NU's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 30, 2011.
NU and CL&P
The following table sets forth certain information as of February 24, 2011 concerning NU’s and CL&P’s executive officers:
Name | Age | Title | ||
Jay S. Buth | 41 | Vice President - Accounting and Controller of NU and CL&P. | ||
Gregory B. Butler | 53 | Senior Vice President and General Counsel of NU and CL&P. | ||
Jeffrey D. Butler* | 55 | President and Chief Operating Officer of CL&P | ||
Jean M. LaVecchia** | 59 | Vice President - Human Resources of NUSCO. | ||
David R. McHale | 50 | Executive Vice President and Chief Financial Officer of NU and CL&P. | ||
Leon J. Olivier | 62 | Executive Vice President and Chief Operating Officer of NU; Chief Executive Officer of CL&P. | ||
James B. Robb** | 50 | Senior Vice President, Enterprise Planning and Development of NUSCO. | ||
Charles W. Shivery | 65 | Chairman of the Board, President and Chief Executive Officer of NU; Chairman of CL&P. |
*
Mr. Butler is President and Chief Operating Officer and Director of CL&P and is therefore an executive officer solely of CL&P.
**
Deemed executive officer of NU and CL&P pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.
Jay S. Buth. Mr. Buth was elected Vice President - Accounting and Controller of NU, CL&P, PSNH and WMECO, effective June 9, 2009. Previously, Mr. Buth served as Controller, and Vice President and Controller at NJR Service Corporation, a subsidiary of New Jersey Resources Corporation, a gas utility holding company, from June 2006 to January 2009. He also served as Director - Finance at Allegheny Energy, Inc. from May 2004 to May 2006.
Gregory B. Butler. Mr. Butler was elected Senior Vice President and General Counsel of NU effective December 1, 2005, and of CL&P, PSNH and WMECO, subsidiaries of NU, effective March 9, 2006, and was elected a Director of CL&P, PSNH and WMECO April 22, 2009 and a Director of Northeast Utilities Foundation, Inc. effective December 1, 2002. Previously Mr. Butler served as Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005 and Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.
Jeffrey D. Butler. Mr. Butler was elected President and Chief Operating Officer and a Director of CL&P effective July 1, 2009. Previously, Mr. Butler was employed by Pacific Gas & Electric Company for approximately 28 years, most recently as Senior Vice President - Energy Delivery, before retiring in March 2008. Prior to his last assignment, Mr. Butler also held the positions of Senior Vice President - Transmission and Distribution, Vice President - Operations, Maintenance and Construction, and Vice President - Distribution Operations, Maintenance and Construction beginning in July 1997.
Jean M. LaVecchia. Ms. LaVecchia was elected Vice President - Human Resources of NUSCO, effective January 1, 2005 and was elected a Director of CL&P, PSNH and WMECO April 22, 2009 and a Director of Northeast Utilities Foundation, Inc. effective January 30, 2007. Previously Ms. LaVecchia served as Vice President - Human Resources and Environmental Services from May 1, 2001 to December 31, 2004.
David R. McHale. Mr. McHale was elected Executive Vice President and Chief Financial Officer of NU, CL&P, WMECO and PSNH, effective January 1, 2009, elected a Director of PSNH and WMECO, effective January 1, 2005, of CL&P effective January 15, 2007 and of Northeast Utilities Foundation, Inc. effective January 1, 2005. Previously, Mr. McHale served as Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO from January 1, 2005 to December 31, 2008 and Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.
Leon J. Olivier. Mr. Olivier was elected Executive Vice President and Chief Operating Officer of NU effective May 13, 2008; He also has served as Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; a Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001. Previously, Mr. Olivier served as Executive Vice President - Operations of NU from February 13, 2007 to May 12, 2008; Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; and President and Chief Operating Officer of CL&P from September 2001 to January 2005.
161
CL&P Consolidated Quarterly Financial Data (Unaudited) | ||||||||||||
|
| Quarter Ended | ||||||||||
(Thousands of Dollars) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2008 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 885,499 |
| $ | 821,875 |
| $ | 980,507 |
| $ | 870,480 |
Operating Income |
|
| 89,814 |
|
| 89,635 |
|
| 98,153 |
|
| 95,789 |
Net Income |
|
| 46,068 |
|
| 46,255 |
|
| 55,535 |
|
| 43,300 |
|
|
|
|
|
|
|
|
| ||||
2007 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 1,043,686 |
| $ | 870,379 |
| $ | 918,418 |
| $ | 849,334 |
Operating Income |
|
| 78,964 |
|
| 63,951 |
|
| 71,423 |
|
| 70,204 |
Net Income |
|
| 34,994 |
|
| 25,786 |
|
| 34,976 |
|
| 37,808 |
James B. Robb. Mr. Robb was elected Senior Vice President, Enterprise Planning and Development of NUSCO on September 4, 2007 and was elected a Director of CL&P, PSNH and WMECO April 22, 2009. Previously, Mr. Robb served as Managing Director, Russell Reynolds Associates from December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; and Senior Vice President, Performance Management, Reliant Resources, Inc. from November 2002 to December 2003.
PSNH Consolidated Quarterly Financial Data (Unaudited) |
|
| ||||||||||
|
| Quarter Ended | ||||||||||
(Thousands of Dollars) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2008 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 291,765 |
| $ | 274,039 |
| $ | 301,033 |
| $ | 274,365 |
Operating Income |
|
| 34,865 |
|
| 30,045 |
|
| 29,364 |
|
| 28,675 |
Net Income |
|
| 16,689 |
|
| 13,691 |
|
| 14,318 |
|
| 13,369 |
Charles W. Shivery. Mr. Shivery was elected Chairman of the Board, President and Chief Executive Officer of NU effective March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO effective January 19, 2007 and a Director of Northeast Utilities Foundation effective March 3, 2004. Previously, Mr. Shivery served as President (interim) of NU from January 1, 2004 to March 29, 2004; and President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.
2007 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 277,096 |
| $ | 250,233 |
| $ | 284,326 |
| $ | 271,417 |
Operating Income |
|
| 24,077 |
|
| 31,568 |
|
| 32,666 |
|
| 28,520 |
Net Income |
|
| 9,967 |
|
| 15,245 |
|
| 13,016 |
|
| 16,206 |
There are no family relationships between any director or executive officer and any other trustee, director or executive officer of NU or CL&P and none of the above executive officers or directors serves as an executive officer or director pursuant to any agreement or understanding with any other person. Our executive officers hold the offices set forth opposite their names until the next annual meeting of the Board of Trustees, in the case of NU, and the Board of Directors, in the case of CL&P, and until their successors have been elected and qualified.
WMECOConsolidated Quarterly Financial Data (Unaudited) | ||||||||||||
|
| Quarter Ended | ||||||||||
(Thousands of Dollars) |
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
| $ | 115,759 |
| $ | 104,215 |
| $ | 112,280 |
| $ | 109,273 |
Operating Income |
|
| 15,179 |
|
| 9,643 |
|
| 10,771 |
|
| 10,954 |
Net Income |
|
| 6,320 |
|
| 3,249 |
|
| 5,236 |
|
| 3,525 |
CL&P obtains audit services from the independent registered public accounting firm engaged by the Audit Committee of NU's Board of Trustees. CL&P does not have its own audit committee or, accordingly, an audit committee financial expert. CL&P relies on NU, which has an audit committee and an audit committee expert.
2007 |
|
|
|
|
|
|
|
| ||||
Operating Revenues |
| $ | 129,558 |
| $ | 112,363 |
| $ | 113,500 |
| $ | 109,324 |
Operating Income |
|
| 15,435 |
|
| 12,314 |
|
| 13,562 |
|
| 12,840 |
Net Income |
|
| 6,917 |
|
| 4,590 |
|
| 5,340 |
|
| 6,757 |
CODE OF ETHICS AND STANDARDS OF BUSINESS CONDUCT
Each of NU, CL&P, PSNH and WMECO has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and the Standards of Business Conduct, which are applicable to all Trustees, directors, officers, employees, contractors and agents of NU, CL&P, PSNH and WMECO. The Code of Ethics and the Standards of Business Conduct have both been posted on the NU web site and are available at www.nu.com/investors/corporate_gov/default.asp on the Internet. Any amendments to or waivers from the Code of Ethics and Standards of Business Conduct for executive officers, directors or Trustees will be posted on the website. Any such amendment or waiver would require the prior consent of the Board of Trustees or an applicable committee thereof.
Printed copies of the Code of Ethics and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:
Ms. O. Kay Comendul
Assistant Secretary
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141
Item 11.
Executive Compensation
NU
The information required by this Item 11 for NU is incorporated herein by reference to certain information contained in NU’s definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about March 30, 2011, under the sections captioned "Compensation Discussion and Analysis" plus the related subsections, and "Compensation Committee Report" plus the related subsections following such Report.
PSNH and WMECO
Certain information required by this Item 11 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
CL&P
The information in this Item 11 relates solely to CL&P.
FS-91162
NU Selected Consolidated Sales Statistics (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Regulated companies: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 2,525,635 |
| $ | 2,558,547 |
| $ | 2,409,414 |
| $ | 2,080,395 |
| $ | 1,707,434 |
| |
Commercial |
|
| 1,607,224 |
|
| 1,735,923 |
|
| 1,977,444 |
|
| 1,727,278 |
|
| 1,429,608 |
| |
Industrial |
|
| 399,753 |
|
| 412,381 |
|
| 589,742 |
|
| 577,834 |
|
| 513,999 |
| |
Wholesale |
|
| 545,127 |
|
| 392,675 |
|
| 388,635 |
|
| 411,361 |
|
| 344,254 |
| |
Streetlighting and Railroads |
|
| 38,522 |
|
| 45,880 |
|
| 52,853 |
|
| 47,769 |
|
| 41,976 |
| |
Miscellaneous and eliminations |
|
| 24,673 |
|
| 84,043 |
|
| 133,925 |
|
| 159,402 |
|
| 143,431 |
| |
Total Electric |
|
| 5,140,934 |
|
| 5,229,449 |
|
| 5,552,013 |
|
| 5,004,039 |
|
| 4,180,702 |
| |
Total Gas |
|
| 577,390 |
|
| 514,185 |
|
| 453,894 |
|
| 503,303 |
|
| 407,812 |
| |
Total - Regulated companies |
| $ | 5,718,324 |
| $ | 5,743,634 |
| $ | 6,005,907 |
| $ | 5,507,342 |
| $ | 4,588,514 |
| |
NU Enterprises: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Retail |
| $ | - |
| $ | - |
| $ | 583,829 |
| $ | 1,212,176 |
| $ | 857,355 |
| |
Wholesale |
|
| 31,882 |
|
| 25,992 |
|
| 20,163 |
|
| 644,541 |
|
| 1,722,603 |
| |
Generation |
|
| - |
|
| - |
|
| 258,178 |
|
| 210,833 |
|
| 196,191 |
| |
Services |
|
| 78,625 |
|
| 68,324 |
|
| 39,887 |
|
| 102,327 |
|
| 117,500 |
| |
Miscellaneous and eliminations |
|
| 3,574 |
|
| 3,354 |
|
| (243) |
|
| (257,750) |
|
| (245,745) |
| |
Total - NU Enterprises |
| $ | 114,081 |
| $ | 97,670 |
| $ | 901,814 |
| $ | 1,912,127 |
| $ | 2,647,904 |
| |
Other miscellaneous and eliminations |
|
| (32,310) |
|
| (19,078) |
|
| (30,034) |
|
| (73,243) |
|
| (755,734) |
| |
Total |
| $ | 5,800,095 |
| $ | 5,822,226 |
| $ | 6,877,687 |
| $ | 7,346,226 |
| $ | 6,480,684 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Regulated companies - Sales: (GWH) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 14,509 |
|
| 15,051 |
|
| 14,652 |
|
| 15,518 |
|
| 14,866 |
| |
Commercial |
|
| 14,885 |
|
| 15,103 |
|
| 14,886 |
|
| 15,234 |
|
| 14,710 |
| |
Industrial |
|
| 5,149 |
|
| 5,635 |
|
| 5,750 |
|
| 6,023 |
|
| 6,274 |
| |
Wholesale |
|
| 3,576 |
|
| 3,855 |
|
| 8,777 |
|
| 4,856 |
|
| 5,787 |
| |
Streetlighting and Railroads |
|
| 340 |
|
| 353 |
|
| 332 |
|
| 348 |
|
| 348 |
| |
Total |
|
| 38,459 |
|
| 39,997 |
|
| 44,397 |
|
| 41,979 |
|
| 41,985 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Regulated companies - Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 1,700,207 |
|
| 1,697,073 |
|
| 1,686,169 |
|
| 1,674,563 |
|
| 1,659,419 |
| |
Commercial |
|
| 190,067 |
|
| 189,727 |
|
| 188,281 |
|
| 195,844 |
|
| 194,233 |
| |
Industrial |
|
| 7,342 |
|
| 7,291 |
|
| 7,406 |
|
| 7,638 |
|
| 7,752 |
| |
Streetlighting and Railroads |
|
| 4,605 |
|
| 3,855 |
|
| 3,873 |
|
| 3,912 |
|
| 3,930 |
| |
Total Electric |
|
| 1,902,221 |
|
| 1,897,946 |
|
| 1,885,729 |
|
| 1,881,957 |
|
| 1,865,334 |
| |
Gas |
|
| 204,834 |
|
| 202,743 |
|
| 199,377 |
|
| 196,870 |
|
| 194,212 |
| |
Total |
|
| 2,107,055 |
|
| 2,100,689 |
|
| 2,085,106 |
|
| 2,078,827 |
|
| 2,059,546 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPENSATION DISCUSSION AND ANALYSIS
CL&P Selected Consolidated Sales Statistics (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 1,811,845 |
| $ | 1,854,404 |
| $ | 1,709,700 |
| $ | 1,440,142 |
| $ | 1,155,492 |
| |
Commercial |
|
| 1,042,077 |
|
| 1,182,196 |
|
| 1,405,281 |
|
| 1,170,038 |
|
| 939,579 |
| |
Industrial |
|
| 190,723 |
|
| 208,087 |
|
| 380,479 |
|
| 327,598 |
|
| 275,730 |
| |
Wholesale |
|
| 484,843 |
|
| 347,514 |
|
| 318,958 |
|
| 344,650 |
|
| 295,833 |
| |
Streetlighting and Railroads |
|
| 28,710 |
|
| 35,370 |
|
| 42,099 |
|
| 37,054 |
|
| 31,897 |
| |
Miscellaneous |
|
| 163 |
|
| 54,246 |
|
| 123,294 |
|
| 146,938 |
|
| 134,393 |
| |
Total |
| $ | 3,558,361 |
| $ | 3,681,817 |
| $ | 3,979,811 |
| $ | 3,466,420 |
| $ | 2,832,924 |
| |
Sales: (GWH) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 9,913 |
|
| 10,336 |
|
| 10,053 |
|
| 10,760 |
|
| 10,305 |
| |
Commercial |
|
| 9,993 |
|
| 10,128 |
|
| 9,995 |
|
| 10,307 |
|
| 9,922 |
| |
Industrial |
|
| 2,945 |
|
| 3,264 |
|
| 3,306 |
|
| 3,501 |
|
| 3,623 |
| |
Wholesale |
|
| 3,637 |
|
| 3,563 |
|
| 3,749 |
|
| 4,179 |
|
| 5,375 |
| |
Streetlighting and Railroads |
|
| 294 |
|
| 304 |
|
| 284 |
|
| 298 |
|
| 298 |
| |
Total |
|
| 26,782 |
|
| 27,595 |
|
| 27,387 |
|
| 29,045 |
|
| 29,523 |
| |
Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 1,094,991 |
|
| 1,091,799 |
|
| 1,084,937 |
|
| 1,078,723 |
|
| 1,071,249 |
| |
Commercial |
|
| 102,464 |
|
| 102,411 |
|
| 101,563 |
|
| 108,558 |
|
| 108,865 |
| |
Industrial |
|
| 3,613 |
|
| 3,743 |
|
| 3,848 |
|
| 3,976 |
|
| 4,078 |
| |
Other |
|
| 2,883 |
|
| 2,583 |
|
| 2,592 |
|
| 2,630 |
|
| 2,694 |
| |
Total |
|
| 1,203,951 |
|
| 1,200,536 |
|
| 1,192,940 |
|
| 1,193,887 |
|
| 1,186,886 |
|
OVERALL OBJECTIVES OF EXECUTIVE COMPENSATION PROGRAM
General
CL&P is a wholly-owned subsidiary of NU with a board of directors made up entirely of executive officers of NU system companies. CL&P does not have a compensation committee, and the Compensation Committee of NU’s Board of Trustees determines compensation for the executive officers of CL&P, including their salaries, annual incentive awards and long-term incentive awards. All of CL&P’s "Named Executive Officers," as defined below, also serve as officers of NU and one or more other subsidiaries of NU. Compensation set by the Compensation Committee of NU and set forth herein is for services rendered to NU and its subsidiaries by such officers in all capacities.
The fundamental objective of NU’s Executive Compensation Program is to motivate executives and key employees to support NU’s strategy of investing in and operating businesses that benefit customers, employees, and shareholders. We are also responsible to our franchise customers to provide energy services reliably, safely, with respect for the environment and our employees, and at a reasonable cost.
NU’s Executive Compensation Program supports its fundamental objective through the following design principles:
·
Attract and retain key executives by providing total compensation competitive with that of other executives employed by companies of similar size and complexity in the utility and general industries. The program relies on compensation data obtained from consultants’ surveys of companies and from a customized peer group to ensure that compensation opportunities are competitive and capable of attracting and retaining executives with the experience and talent required to achieve NU’s strategic objectives. As NU continues to grow and improve its transmission, distribution, and generation systems, having the right talent will be critical.
·
Establish performance-based compensation that balances rewards for short-term and long-term business results. The program motivates executives to run the business well in the short term, while executing the long-term business plan to benefit both NU’s customers and NU shareholders. The program aims to strike a balance between the short- and long-term programs so that they work in tandem. It also ensures that long-term objectives are not sacrificed to achieve short-term goals or vice versa.
Incentive plan performance criteria are based on a combination of financial, operational, stewardship, and strategic goals that are essential to the achievement of NU’s business strategies. This linkage to critical goals helps to align executives with NU’s key stakeholders: customers, employees, and shareholders. The long-term program also compares performance relative to a group of comparable utility companies.
·
Reward corporate and individual performance. Overall compensation has many metrics based on NU corporate performance but is also highly differentiated based on individual performance. The annual incentive program rewards both NU corporate performance (measured by NU adjusted net income) and individual performance (including individualized financial, operational, stewardship and strategic metrics). Long-term incentives consist of performance units (performance shares and performance cash) and restricted share units (RSUs). Performance units are paid out based on the achievement of NU corporate goals (cumulative net income, average return on equity, average credit rating and relative total shareholder return). The size of RSU grants may reflect corporate performance during the preceding fiscal year as well as individual performance and contribution, but the ultimate value of the RSUs is based o n total NU shareholder return.
·
Encourage long-term commitment to NU. Utility companies provide a public service and have a long-term commitment to ensure that customers receive reliable service day after day. Meeting this commitment requires specialized skills and institutional knowledge that are learned over time through local industry experience. These skills include familiarity with the regions and communities that we serve, government regulations, and long-term energy policies. In addition, utility companies rely on long-term capital investments to serve their customers.
As a result, public utilities benefit from long-term service employees. NU has structured its executive compensation programs to build long-term commitment as well as shareholder alignment. Providing competitive compensation opportunities and offering programs such as RSUs and supplemental retirement benefits that vest and have the ability to increase in value over time encourage long-term employment. Executive share ownership guidelines are another program component intended to build long-term shareholder alignment and commitment.
NAMED EXECUTIVE OFFICERS
The executive officers of CL&P listed in the Summary Compensation Table in this Item 11 whose compensation is discussed in this Compensation Discussion and Analysis (CD&A) are CL&P’s Chief Executive Officer (CEO), Executive Vice President and Chief Financial Officer (CFO), and the three other most highly compensated executive officers other than CL&P’s CEO and CFO who were serving as executive officers at the end of 2010 (collectively, referred to as the "Named Executive Officers" or "NEOs"). Each Named Executive Officer of CL&P also serves as an executive officer of NU and one or more other subsidiaries of NU. Compensation for such
FS-92163
NEOs discussed in this CD&A was for all services provided by such individuals in all capacities to NU and its subsidiaries. For 2010, CL&P’s Named Executive Officers are:
·
Leon J. Olivier, Chief Executive Officer of CL&P
·
David R. McHale, Executive Vice President and Chief Financial Officer
·
Charles W. Shivery, Chairman of the Board, President and Chief Executive Officer of NU, and Chairman of CL&P
·
Gregory B. Butler, Senior Vice President and General Counsel
·
James B. Robb, Senior Vice President-Enterprise Planning and Development of NUSCO
RISK ANALYSIS OF EXECUTIVE COMPENSATION PROGRAM
The overall compensation program features a mix of compensation elements ranging from a fixed base salary that is risk-neutral to annual and long-term incentive compensation programs intended to motivate officers and eligible employees to achieve individual and corporate performance goals that reflect the appropriate assessment of risk. The fundamental objective of the compensation program is to foster the continued growth and success of NU’s business. The design and implementation of the overall compensation program provides NU’s Compensation Committee with opportunities throughout the year to assess risks within the compensation program that may have a material effect on NU and its shareholders.
Each year, as part of its annual planning process, NU’s Board of Trustees and its Finance Committee review NU’s comprehensive annual operating and five-year strategic plans. The annual operating plan consists of the goals and objectives for the year, key performance indicators and financial forecasts. The strategic plan consists of long-term corporate goals and objectives, specific strategies to achieve those goals, and action plans designed to implement each strategy. The Enterprise Risk Management (ERM) process is integrated into the annual operating planning and the strategic planning processes. The most significant enterprise-wide financial risks are identified during development of the annual operating plans, and are updated and presented monthly to NU’s Finance Committee. Enterprise strategic risks are identified and presented to the Board during development of the five-year strategic plans. Follo wing review and approval of the annual operating and strategic plans by the Board of Trustees and the Finance Committee, the Compensation Committee reviews the overall compensation program in the context of both plans. In particular, the Compensation Committee designs the annual and long-term incentive compensation programs for officers and eligible employees to promote the achievement of the goals and objectives of the annual operating plan and the strategic plan that were each previously subjected to ERM review.
In 2009, the Compensation Committee assessed the risks associated with the executive compensation program proposed for 2010 by specifically reviewing the various elements of the incentive compensation programs. The annual incentive program was reviewed to ensure an appropriate balance between the individual and corporate goals and that the goals were appropriate to support the annual business plan. Similarly, the long-term incentive program was reviewed to ensure that the performance metrics were properly weighted and supported NU’s strategic plan. Both the annual and long-term incentive programs were reviewed to ensure that mechanisms exist to mitigate risk, which mechanisms include goal setting and discretion with respect to actual payments, share ownership guidelines, clawback of incentive compensation under certain circumstances, and deferral of certain long-term incentive awards. Key elements of the executive compensati on program have not changed since the review in 2009.
ELEMENTS OF 2010 COMPENSATION
Set forth below is a brief description and the objective of each material element of NU’s executive compensation program:
Compensation Element | Description | Objective | ||
Base Salary | Fixed compensation Subject to increase annually during the first quarter based on individual performance, competitive market levels, strategic importance of the role and experience in the position | Compensate officers for fulfilling their basic job responsibilities Provide base pay commensurate with salaries paid to executive officers holding comparable positions in other utility companies and companies in general industry Aid in attracting and retaining qualified personnel | ||
Annual Incentive Program | Variable compensation based on performance against pre-established annual NU corporate and individual goals that is paid in cash in the first quarter following the end of the program year | Promote the achievement of annual performance objectives that represent business success for the company, the executive, and his or her business unit or function | ||
164
Long-Term Incentive Program | Variable compensation consisting of 25% RSUs and 75% Performance Units (see below) | |||
· Restricted share units (RSUs) | Common share units, which vest over a three-year period, may be granted based on NU corporate performance and individual performance and contribution | Align executive and shareholder interests through NU share performance and NU share ownership Encourage a long-term commitment to the company | ||
· Performance units | Long-term incentive, one-half of which is performance cash and one-half of which is performance shares, that rewards individuals for NU corporate performance over a three-year period based on achieving pre-established levels of: · NU Cumulative net income · NU Average return on equity · NU Average credit rating · Total NU shareholder return relative to a group of comparable utility companies | Reward performance on key corporate priorities that are also key drivers of total NU shareholder return performance Align executive and shareholder interests through NU share performance and NU share ownership Strengthen the link between long-term compensation and total shareholder return performance Encourage long-term thinking and commitment to the company | ||
Supplemental Benefits | Supplemental Executive Retirement Plan, Nonqualified Deferred Compensation, and Perquisites | Supplemental benefits intended to help NU attract and retain executive officers critical to NU’s success by reflecting competitive practices | ||
· Supplemental Executive Retirement Plan (Supplemental Plan) | · Non-qualified pension plan, providing additional retirement income to officers beyond payments provided in NU’s standard defined benefit retirement plan, consisting of: · A defined benefit "make-whole" plan · A supplemental "target" benefit (certain senior vice presidents and above only) · Executives hired after 2005 are ineligible for these benefits | Compensate for Internal Revenue Code limits on qualified plans Aid in retention of executives and enhance long-term commitment to the company | ||
· Other Nonqualified Deferred Compensation (Deferral Plan) | Opportunity to defer base salary and annual incentives, using the same investment vehicles as NU’s 401(k) plan, and receive matching contributions otherwise capped by Internal Revenue Code limits on qualified plans Each year’s matching contribution vests after three years or at retirement For executives hired after 2005, who are ineligible to participate in NU’s defined benefit pension plan, NU makes contributions of 2.5%, 4.5% and 6.5%, as applicable based on the relevant bracket for the sum of the officer’s age and years of service, of cash compensation that would otherwise be capped by Internal Revenue Code limits on qualified plans | Aid executives in tax planning by allowing them to defer taxes on certain compensation Compensate for Internal Revenue Code limits on qualified plans Provide a competitive benefit Aid in retention and enhance long-term commitment to the company | ||
165
· Med-Vantage Plan | For executives hired after 2005, who are ineligible to participate in NU’s defined benefit pension plan, starting at age 40 NU makes contributions of $1,000 per year to a qualified retiree medical savings account. | Designed to help build tax-free savings for post-employment health care expenses. | ||
· Perquisites | Tax preparation and financial planning reimbursement benefit (certain senior executives) Executive physical examination reimbursement plan Reimbursement of relocation expenses for newly hired and transferred executives Reimbursement of spousal travel expenses only for business purposes | Encourage use of a professional tax advisor to properly prepare complex tax returns and leverage the value of NU’s compensation programs Encourage executives to undergo regular health checks to reduce the risk of losing critical employees Discretionary benefits intended to help NU’s executive officers be more productive and efficient | ||
Employment Agreements | Employment or other agreements with certain of our Named Executive Officers provide benefits and payments upon involuntary termination and termination following a change of control. Mr. Olivier participates in a "Special Severance Program" (SSP) that provides other benefits and payments upon termination of employment resulting from a change-in-control | Meet competitive expectation of employment Help focus executive on shareholder interests Provide income protection in the event of involuntary loss of employment |
MIX OF COMPENSATION ELEMENTS
NU strives to provide executive officers with base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with the market. The Compensation Committee of NU’s Board of Trustees determines the Total Direct Compensation for our Named Executive Officers as described under the caption entitled "Market Analysis," below. As a result, the annual and long-term incentive target percentages for the NEOs listed in the Summary Compensation Table are approximately equal to competitive median incentives.
With respect to incentive compensation, the Compensation Committee believes it is important to balance short-term goals, such as generating earnings, with longer term goals, such as long-term value creation and maintaining a strong balance sheet. As our executive officers are promoted to more senior positions, they assume increased responsibility for implementing NU’s long-term business plans and strategies, and a greater proportion of their total compensation is based on performance with a long-term focus.
The Compensation Committee determines the compensation for each executive officer based on the relative authority, duties and responsibilities of each office. Mr. Shivery’s responsibilities for the daily operations and management of the Northeast Utilities System companies, as Chairman, President and Chief Executive Officer of NU and Chairman of each of the Regulated companies, are significantly greater than the duties and responsibilities of our other executive officers. As a result, Mr. Shivery’s compensation is significantly higher than the compensation of our other executive officers. NU regularly reviews market compensation data for executive officer positions similar to those held by our executive officers, including Mr. Shivery, and this market data continues to indicate that chief executive officers are typically paid significantly more than other executive officers. For 2010, target annual incen tive and long-term incentive compensation opportunities for Mr. Shivery were 100 percent and 300 percent of base salary, respectively. For the remaining NEOs, target annual incentive compensation opportunities ranged from 50 percent to 65 percent of base salary and target long-term incentive compensation opportunities ranged from 100 percent to 150 percent of base salary.
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The following table sets forth the contribution to 2010 Total Direct Compensation (TDC) of each element of compensation, at target, reflected as a percentage of TDC, for each Named Executive Officer.
|
| Percentage of TDC at Target |
| ||||||||
|
|
|
| Performance Based (1) |
|
|
| ||||
|
|
|
|
|
| Long-Term Incentives (2) |
|
| |||
Named Executive Officer |
| Base |
| Annual |
| Performance |
| RSUs (3) |
| TDC | |
Leon J. Olivier, CEO, CL&P |
| 32% |
| 20% |
| 36% |
| 12% |
| 100% | |
David R. McHale |
| 32% |
| 20% |
| 36% |
| 12% |
| 100% | |
Charles W. Shivery |
| 20% |
| 20% |
| 45% |
| 15% |
| 100% | |
Gregory B. Butler |
| 32% |
| 20% |
| 36% |
| 12% |
| 100% | |
James B. Robb |
| 40% |
| 20% |
| 30% |
| 10% |
| 100% |
(1)
The annual incentive compensation element and performance units under the long-term incentive compensation element are performance-based.
(2)
Long-term incentive compensation at target consists of 75 percent performance units and 25 percent RSUs.
(3)
RSUs vest over three years contingent upon continued employment.
MARKET ANALYSIS
The Compensation Committee strives to provide our executive officers with compensation opportunities over time at or above the median compensation levels for executive officers of companies comparable to NU. The Committee determined executive officer TDC levels in two steps. First, the Committee determined the "market" values of executive officer compensation elements (base salaries, annual incentives and long-term incentives) as well as total compensation using compensation data obtained from other companies. The Committee reviewed compensation data obtained primarily from utility and general industry surveys and, secondarily, from a customized group of peer utility companies. The Committee then reviewed the compensation elements for each executive officer with respect to the median of these market values, and considered individual performance, experience and internal pay equity to determine the amount, if any, by which the various compensation elements should differ from median market values. Significantly, the Committee has not made an explicit commitment to compensate our executive officers through a firm and direct connection between the compensation paid by NU and the compensation paid by any of the companies in the utility and general industry surveys or in the customized group of peer utilities.
Set forth below is a description of the sources of the compensation data used by the Compensation Committee when reviewing 2010 compensation:
·
Utility and general industry survey data. The Committee analyzed compensation information obtained from surveys of diverse groups of utility and general industry companies that represent NU’s market for executive officer talent. The Committee used size-adjusted utility and general industry survey data to determine base salaries and incentive opportunities. Then the Committee compared utility-specific executive officer positions, including NU’s Executive Vice President and Chief Operating Officer, to utility-specific market values. For executive officer positions that have counterparts in general industry, including NU’s CEO; Executive Vice President and Chief Financial Officer; Senior Vice President and General Counsel; and Senior Vice President-Enterprise Planning and Development, the Committee averaged general industry comparisons with utility industry comparisons weigh ted equally, as both groups represent the talent market for these executive officers.
·
Customized peer group data. The Committee also evaluated compensation data obtained from reviews of proxy statements from NU’s customized group of peer utility companies. Periodically, the Committee assesses the composition of NU’s customized peer group to ensure that the number of companies is sufficient and the companies have reasonably similar revenues. The Committee reviewed the composition of NU’s customized peer group in 2010 and compared the group against NU’s size guidelines of revenues between approximately $3 billion and $12 billion. Keeping in mind the Compensation Committee’s desire to maintain a consistent set of peer companies from year to year to avoid volatility in competitive compensation findings used for comparison across companies, the Committee maintained the same peer group for 2010 that it used in 2009. As a result, in support of executive pay decisions during 2009, NU’s customized peer group consisted of utilities with annual revenues that ranged from $1.7 billion to $14 billion with median annual revenues of $6.1 billion. NU will continue to monitor their size to determine if they should be removed from the peer group in the future. The Committee considered data only for those executive officer positions where there is a title match, which in 2010 included the holding company CEO, Chief Operating Officer, Chief Financial Officer, and General Counsel. For 2010, the peer group consisted of the following 20 companies:
Allegheny Energy, Inc. | Great Plains Energy, Incorporated | Pinnacle West Capital Corporation | |||
Alliant Energy Corporation | Integrys Energy Group, Inc. | Progress Energy, Inc. | |||
Ameren Corporation | NiSource Inc. | SCANA Corporation | |||
CenterPoint Energy, Inc. | NSTAR | TECO Energy, Inc. | |||
CMS Energy Corporation | NV Energy, Inc. | Wisconsin Energy Corporation | |||
Consolidated Edison, Inc. | OGE Energy Corp. | Xcel Energy Inc. | |||
DTE Energy Company | Pepco Holdings, Inc. |
167
The Committee used compensation data obtained from these companies for insights into incentive compensation design practices and compensation levels, although no specific actions were taken in 2010 directly as a result of this information. In 2010, the Committee also used this group for performance comparisons under the 2010 – 2012 Long-Term Incentive Program. The Committee periodically adjusts the target percentages of annual and long-term incentives based on the survey data to ensure that they continue to represent market median levels. Adjustments are made gradually over time to avoid radical changes.
The Compensation Committee also sets supplemental benefits at levels that provide market-based compensation opportunities to the executive officers. Compensation includes perquisites to the extent they serve business purposes. The Committee periodically reviews the general market for supplemental benefits and perquisites using utility and general industry survey data, sometimes including data obtained from companies in the customized peer group. Benefits are adjusted occasionally to help maintain market parity. When the market trend for supplemental benefits reflects a general reduction (e.g., the elimination of defined benefit pension plans), the Committee has reduced these benefits only for newly hired officers. The Committee reviewed NU’s supplemental retirement practices most recently in 2005 and 2006, as described in more detail below under the caption entitled "Supplemental Benefits.&q uot;
BASE SALARY
The Compensation Committee reviews executive officers’ base salaries annually. The Committee considers the following specific factors when setting or adjusting base salaries:
·
Annual individual performance appraisals
·
Market pay movement across industries (determined through market analysis)
·
Targeted market pay positioning for each executive officer
·
Individual experience and years of service
·
Changes in corporate focus with respect to strategic importance of a position
·
Internal equity
Individuals who are performing well in strategic positions are likely to have their base salaries increased more significantly than other individuals. From time-to-time, economic conditions and corporate performance has caused salary increases to be postponed. The Committee prefers to reflect subpar corporate performance through the variable pay components.
In 2010, given the continuing uncertainty in the capital markets and weakened economic conditions, the Committee determined to continue to the base salary freeze for the NEOs, first implemented in 2009.
INCENTIVE COMPENSATION
The annual incentive program and the long-term incentive program are provided under the Northeast Utilities Incentive Plan, which was approved by NU’s shareholders at its 2007 Annual Meeting of Shareholders. The annual incentive program provides cash compensation intended to reward performance under NU’s annual operating plans. The long-term incentive program is designed to reward demonstrated performance and leadership, motivate future superior performance, align the interests of the executive officers with those of NU’s shareholders and retain the executive officers during the term of grants. The annual and long-term programs are intended to work in tandem so that achievement of NU’s annual goals leads NU towards attainment of its long-term financial goals. Similar to 2009, grants under the long-term incentive program consisted of three elements of compensation: RSUs, performance cash, and performance shares . For the 2010 – 2012 Long-Term Incentive Program, the grant value consisted of 25 percent RSUs, 37.5 percent performance shares, and 37.5 percent performance cash, reflecting the Committee’s desire to balance the roles of total NU shareholder return and NU’s corporate financial performance in its compensation programs.
Incentive grants are based on objective financial performance goals established by the Compensation Committee with the advice of the Finance Committee. The Compensation Committee sets the performance goals annually for new annual incentive and long-term incentive program performance periods, depending on NU’s business focus for the then-current year and the long-term strategic plan.
2010 ANNUAL INCENTIVE PROGRAM
The 2010 Annual Incentive Program consisted of an NU corporate goal plus individual goals for each NEO. The Compensation Committee set the annual incentive compensation targets for 2010 at 100 percent of base salary for Mr. Shivery, and at 50 percent to 65 percent of base salary for the other NEOs. The annual incentive compensation targets are used as guidelines for the determination of annual incentive payments, but actual annual incentive payments may vary significantly from these targets, depending on individual and NU corporate performance. Actual annual incentive payments may equal up to two times target if NU achieves superior financial and operational results. The opportunity to earn up to two times the incentive target reflects the Compensation Committee’s belief that executive officers have significant ability to affect performance outcomes. However, NU does not pay annual incentive awards if minimum leve ls of financial performance are not met. A total of 33 NU system company officers, including CL&P’s NEOs, participated in the 2010 Annual Incentive Program.
2010 Corporate Goal
The objective of the 2010 Annual Incentive Program corporate goal for the NEOs was to achieve an NU adjusted net income (ANI) target established by the Compensation Committee. ANI is defined as consolidated Northeast Utilities net income adjusted to exclude the effect of certain nonrecurring income and expense items or events. The Committee uses ANI because it believes that ANI
168
serves as an indicator of ongoing operating performance. The minimum payout under the corporate goal was set at 50 percent of target and would have occurred if actual ANI had been at least 90 percent of the ANI target. The maximum payout under the corporate goal was set at 200 percent of target and would have occurred if actual ANI had been at least 110 percent of the ANI target.
For 2010, the Compensation Committee established the ANI target at $346.8 million. The ANI target reflects the midpoint of the range of internal ANI estimates calculated at the beginning of the year. The ANI thresholds for the individual and corporate goals appear below (dollars in millions):
| Threshold for |
| Minimum Corporate |
| 2010 |
| Maximum Corporate |
| Actual |
| $ 277.4 |
| $ 312.1 |
| $ 346.8 |
| $ 381.5 |
| $ 400.6 |
The Compensation Committee set the ANI threshold for achieving individual goals and the minimum and maximum corporate goals in its discretion based on the following factors:
·
An assessment of the potential volatility in results through an evaluation of critical elements of the strategic business plan, both individually and in combination with each other;
·
The degree of difficulty in achieving the ANI target; and
·
The minimum acceptable ANI.
At the time that the Compensation Committee established the performance goals for 2010, the Committee also considered and agreed upon exclusions from ANI consisting of certain nonrecurring income and expense items or events that were either beyond the control of management generally or related to a decision by the Committee not to penalize executive officers for making correct strategic business decisions. The Compensation Committee approved all final exclusions from ANI. In addition, using its discretion, the Compensation Committee excluded the positive effect on earnings that resulted from the delay of a planned asset transaction. The income and expense items set forth below were excluded from ANI in 2010.
Excluded Categories | Specific 2010 | |
Changes to net income as the result of accounting or tax law changes | $ (5.1) | |
Delay in planned asset transactions | $ 1.8 | |
Incremental NSTAR merger costs | $ (9.4) | |
Net Adjustments: | $ (12.7) |
2010 Individual Goals
The 2010 Annual Incentive Program individual goals included various financial, operational, stewardship, and strategic metrics that are drivers of overall corporate performance. The achievement of individual goals would result in an annual incentive payment only if actual ANI is at least 80 percent of the ANI target. Upon achieving this ANI threshold, the maximum payout is possible for individual goals for every participant.
This 80 percent ANI threshold satisfies the requirements of Section 162(m) of the Internal Revenue Code. The Committee acts in its discretion under Section 162(m) and related Internal Revenue Service rules and regulations to ensure that incentive compensation payments are "qualified performance based compensation" not subject to the $1 million limitation on deductibility.
The Compensation Committee, acting jointly with NU’s Corporate Governance Committee, determines Mr. Shivery’s proposed annual incentive program payment based on the extent to which individual and corporate goals have been achieved. The Compensation Committee recommends to NU’s Board of Trustees for approval the proposed award for Mr. Shivery. For the remaining NEOs, Mr. Shivery recommends annual incentive awards to the Compensation Committee for its approval. NEOs are eligible to receive up to two times the annual incentive compensation target for the individual portion of the award.
Goal Weightings and Individual Goals for 2010
The following table sets forth the weighting of the annual incentive program corporate goal and individual goals of each NEO’s compensation for 2010. These weightings reflect the Compensation Committee’s desire to balance individual accountability with teamwork across NU’s organization. Individual goals for our NEOs range from 40 percent to 50 percent of the total annual incentive program target. Certain of our NEOs’ individual performance goals are subjective in nature and cannot be measured either by reference to existing financial metrics or by using pre-determined mathematical formulas. The Committee believes that it is important to exercise judgment and discretion when determining the extent to which each NEO satisfies subjective individual performance goals. The Committee considers these goals along with several factors, including overall individual performance, corporate performanc e, prior year compensation and the other factors discussed below.
169
PSNH Selected Consolidated Sales Statistics (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 472,486 |
| $ | 457,616 |
| $ | 467,517 |
| $ | 450,230 |
| $ | 384,667 |
| |
Commercial |
|
| 431,461 |
|
| 413,196 |
|
| 439,828 |
|
| 423,884 |
|
| 361,603 |
| |
Industrial |
|
| 169,785 |
|
| 156,258 |
|
| 166,132 |
|
| 190,299 |
|
| 175,921 |
| |
Wholesale |
|
| 35,935 |
|
| 25,030 |
|
| 52,255 |
|
| 34,688 |
|
| 19,712 |
| |
Streetlighting and Railroads |
|
| 6,515 |
|
| 6,018 |
|
| 5,729 |
|
| 5,685 |
|
| 5,297 |
| |
Miscellaneous |
|
| 25,020 |
|
| 24,954 |
|
| 9,439 |
|
| 23,641 |
|
| 21,549 |
| |
Total |
| $ | 1,141,202 |
| $ | 1,083,072 |
| $ | 1,140,900 |
| $ | 1,128,427 |
| $ | 968,749 |
| |
Sales: (GWH) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 3,105 |
|
| 3,176 |
|
| 3,087 |
|
| 3,162 |
|
| 3,015 |
| |
Commercial |
|
| 3,361 |
|
| 3,403 |
|
| 3,342 |
|
| 3,342 |
|
| 3,235 |
| |
Industrial |
|
| 1,435 |
|
| 1,528 |
|
| 1,582 |
|
| 1,612 |
|
| 1,716 |
| |
Wholesale |
|
| (243) |
|
| 105 |
|
| 985 |
|
| 501 |
|
| 242 |
| |
Streetlighting and Railroads |
|
| 25 |
|
| 24 |
|
| 23 |
|
| 24 |
|
| 25 |
| |
Total |
|
| 7,683 |
|
| 8,236 |
|
| 9,019 |
|
| 8,641 |
|
| 8,233 |
| |
Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 418,107 |
|
| 417,420 |
|
| 413,980 |
|
| 408,959 |
|
| 403,088 |
| |
Commercial |
|
| 70,807 |
|
| 70,341 |
|
| 69,528 |
|
| 68,232 |
|
| 66,572 |
| |
Industrial |
|
| 2,978 |
|
| 2,770 |
|
| 2,761 |
|
| 2,768 |
|
| 2,783 |
| |
Other |
|
| 970 |
|
| 602 |
|
| 592 |
|
| 600 |
|
| 572 |
| |
Total |
|
| 492,862 |
|
| 491,133 |
|
| 486,861 |
|
| 480,559 |
|
| 473,015 |
|
Name and Principal Position | Corporate | Individual | Brief Description of Material Individual Goals |
Charles W. Shivery | 60% | 40% | Ensure the effective execution of NU’s articulated 2010 operating and capital plans as approved. Special emphasis should be given to ensuring that operational leadership continues to transition to the appropriate level within the organization, through the use of well defined expectations and metrics. Implement NU’s new safety initiatives and make measurable improvement in safety related results (20 percent of individual goals). Ensure the effective execution of NU’s articulated strategic plan for 2010-2014. Continue to shape the implementation of energy policy in New England, consistent with NU’s strategic plan to benefit its customers (20 percent of individual goals). Identify a strategic vision and the associated opportunities that are in addition to the current transmission-centric strategy and ensure the appropriate organizational structure, resources and culture to position NU for future success (20 percent of individual goals). Continue to embed sustainability into NU’s operations and relationships with its key stakeholders. Achieve improvement in NU’s reputation among its various stakeholders. (10 percent of individual goals). Implement cultural changes necessary for NU to succeed in an increasingly customer-centric environment. Continue to advance NU’s succession planning and leadership development program to improve the depth and breadth of leadership talent. Lead through tone and actions NU’s efforts to realize its vision to create an inclusive environment and a diverse workforce (10 percent of individual goals) Assist the Committee on Succession Planning and the Board of Trustees to ensure the smooth implementation of the succession planning process and to provide a seamless transition of leadership for NU and its stakeholders (20 percent of individual goals). |
|
|
|
|
David R. McHale | 60% | 40% | Successfully execute operating plans: support NU’s strategy, 2010 operating plan, and competitive businesses, and improve effectiveness of shared services (40 percent of individual goals). Provide critical subject matter and execution expertise to advance NU’s strategy while ensuring integrity of its financial position (20 percent of individual goals). Manage department budgets and expenditures; continue to execute internal customer focus strategy (15 percent of individual goals). Effectively communicate NU’s strategy and financial position to stakeholders, with particular emphasis on investors, and throughout NU (15 percent of individual goals). Achieve organization development goals: continue to ensure the effective organizational design of the finance and shared services organizations; manage for an inclusive environment and diverse workforce (10 percent of individual goals). |
170
WMECO Selected Consolidated Sales Statistics (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2008 |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| ||||||
Revenues: (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
| $ | 241,303 |
| $ | 246,526 |
| $ | 232,197 |
| $ | 190,023 |
| $ | 167,275 |
| |
Commercial |
|
| 133,686 |
|
| 140,531 |
|
| 132,336 |
|
| 133,356 |
|
| 128,425 |
| |
Industrial |
|
| 39,245 |
|
| 48,036 |
|
| 43,131 |
|
| 59,937 |
|
| 62,347 |
| |
Wholesale |
|
| 24,349 |
|
| 20,131 |
|
| 17,421 |
|
| 19,064 |
|
| 8,646 |
| |
Streetlighting and Railroads |
|
| 3,297 |
|
| 4,492 |
|
| 5,025 |
|
| 5,030 |
|
| 4,782 |
| |
Miscellaneous |
|
| (353) |
|
| 5,029 |
|
| 1,399 |
|
| 1,983 |
|
| 7,754 |
| |
Total |
| $ | 441,527 |
| $ | 464,745 |
| $ | 431,509 |
| $ | 409,393 |
| $ | 379,229 |
| |
Sales: (GWH) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 1,491 |
|
| 1,539 |
|
| 1,511 |
|
| 1,596 |
|
| 1,546 |
| |
Commercial |
|
| 1,547 |
|
| 1,589 |
|
| 1,574 |
|
| 1,616 |
|
| 1,583 |
| |
Industrial |
|
| 769 |
|
| 842 |
|
| 862 |
|
| 910 |
|
| 935 |
| |
Wholesale |
|
| 179 |
|
| 178 |
|
| 189 |
|
| 176 |
|
| 169 |
| |
Streetlighting and Railroads |
|
| 22 |
|
| 25 |
|
| 25 |
|
| 25 |
|
| 25 |
| |
Total |
|
| 4,008 |
|
| 4,173 |
|
| 4,161 |
|
| 4,323 |
|
| 4,258 |
| |
Customers: (Average) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Residential |
|
| 187,109 |
|
| 187,854 |
|
| 187,252 |
|
| 186,882 |
|
| 185,083 |
| |
Commercial |
|
| 16,916 |
|
| 17,096 |
|
| 17,310 |
|
| 19,174 |
|
| 18,917 |
| |
Industrial |
|
| 751 |
|
| 777 |
|
| 798 |
|
| 894 |
|
| 892 |
| |
Other |
|
| 785 |
|
| 703 |
|
| 705 |
|
| 714 |
|
| 695 |
| |
Total |
|
| 205,561 |
|
| 206,430 |
|
| 206,065 |
|
| 207,664 |
|
| 205,587 |
|
|
|
|
|
Leon J. Olivier | 50% | 50% | Advance NU’s strategic objectives (40 percent of individual goals). Achieve NU’s 2010 utility operating plans emphasizing execution, improvement, and Regulated company operational objectives (30 percent of individual goals). Work with NU’s chief executive officer and members of NU’s executive team to build stakeholder confidence (10 percent of individual goals). Achieve 2010 Customer Experience goals and objectives (10 percent of individual goals). Implement planned safety initiatives and make measureable improvements in overall safety results; continue to build and maintain a diverse and quality workforce (10 percent of individual goals). |
|
|
|
|
Gregory B. Butler | 50% | 50% | Manage NU’s Legal Department to enable NU to achieve its strategic plan and 2010 operating and capital financing objectives; provide leadership with respect to uncollectibles expense and HWP Company site remediation (30 percent of individual goals). Develop Legislative, Regulatory, Legal, and Communications plans and provide expertise for NU’s strategic initiatives and emerging opportunities (30 percent of individual goals). Achieve successful outcomes in federal and state energy regulatory legislative proceedings; contribute to positioning NU as a leading regional and national expert on energy issues (25 percent of individual goals). Provide quality internal customer support; execute talent management and development plans; manage budget (15 percent of individual goals). |
|
|
|
|
James B. Robb | 50% | 50% | Develop comprehensive energy productivity and renewable generation strategies that align NU’s objectives, shareholder aspirations, and customer needs; finalize key commitments established for the northern transmission opportunities (75 percent of individual goals). Continue to build NU’s reputation for sustainability and build on its emerging reputation as a thought leader on energy issues; evolve NU’s thinking regarding key policy issues in the energy sector, including policies around electric vehicles. (25 percent of individual goals). |
2010 Results
The 2010 actual ANI was $400.6 million, which exceeded the maximum ANI amount. As a result, a portion of the total annual incentive payment to each NEO was attributable to achieving the corporate goal at 200 percent of target. In addition, the 2010 actual ANI exceeded the individual goal threshold. Accordingly, the balance of the annual incentive payment to each NEO was based on the extent to which each NEO achieved his individual goals.
Mr. Shivery’s Annual Incentive Payment
The Compensation Committee and the Corporate Governance Committee assessed Mr. Shivery’s performance on his individual goals described in the table above. The Committee determined that Mr. Shivery’s execution of NU’s long-term strategic plan as well as NU’s 2010 operating and capital plans exceeded expectations. NU's financial performance improved over 2009 due in part to cost controls while at the same time, energy rates paid by NU's customers continued to trend downward. Additionally, NU invested approximately $1
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billion in 2010 strengthening and expanding the energy infrastructure of Connecticut, Massachusetts and New Hampshire. This investment supports the provision of reliable energy service, as well as the region's economic development. While NU began the year with a number of operational and economic uncertainties, it achieved fair and reasonable outcomes in multiple-year electric distribution rate cases, reached key milestones for the Northern Pass transmission project, secured key approvals to advance the New England East-West Solutions projects for improved interstate reliability, and achieved significant improvements in safety and Customer Experience. Mr. Shivery continued to improve the depth and breadth of NU’s leadership talent and to advance NU’s succession planning programs. With Mr. Shivery’s leadership, NU is well positioned for the future as it plans for the proposed merger with NSTAR.
Coupled with NU’s overall corporate performance measured by ANI, the Compensation Committee members applied judgment to determine their recommendation for Mr. Shivery’s annual incentive payment. Following a detailed review of these factors without Mr. Shivery present, the Board of Trustees awarded Mr. Shivery an annual incentive payment of $1,987,200 for 2010, consisting of $1,242,000 attributable to the achievement of 200 percent of the corporate goal and an additional $745,200 attributable to Mr. Shivery’s performance of his individual goals. The Board of Trustees determined that this annual incentive payment was consistent with Mr. Shivery’s above-expectations performance based on corporate, financial and individual criteria established for 2010. Mr. Shivery’s annual incentive payment exceeds that of the other NEOs because of his significantly greater duties and responsibilities as NU’s chief executive officer.
NEO Annual Incentive Payments
In addition to NU’s corporate ANI goal described above, the Compensation Committee considered individual performance goals and other factors in determining the annual incentive payments for each of the other NEOs. These factors included the annual incentive payment recommendations made by Mr. Shivery with respect to each of the other NEOs and the scope of such NEO’s responsibilities, performance, and impact on or contribution to NU’s corporate success and growth. The annual incentives paid to each of the other NEOs as described below include the corporate ANI goal component for 2010.
Name and Principal Position | Annual | 2010 Accomplishments |
Leon J. Olivier | $601,494 | The Compensation Committee determined that Mr. Olivier and his team effectively executed NU’s operating plan within a challenging economy. Accomplishments included attainment of milestones related to Northern Pass transmission project, NEEWS, Yankee Gas pipeline expansion initiatives, customer service enhancements, and effective completion of the year’s capital program. |
David R. McHale | $608,517 | The Compensation Committee determined that Mr. McHale and his organization successfully issued debt on favorable terms, maintaining and enhancing liquidity through a period of continued economic contraction. Mr. McHale and his team also achieved higher than expected margins from NU’s competitive businesses. Mr. McHale and his organization provided critical subject matter expertise and financial, analytical and risk management support for NU’s major strategic initiatives, allowing it to successfully pursue new opportunities, including the Northern Pass transmission project and the proposed merger with NSTAR. |
Gregory B. Butler | $458,320 | The Compensation Committee determined that Mr. Butler and his team contributed significantly to NU’s operational and strategic accomplishments by achieving fair and reasonable outcomes in various federal and state regulatory proceedings and by providing extensive support for various strategic initiatives, including the Northern Pass transmission project and the proposed merger with NSTAR. His team continued to position NU as a leading regional and national expert on energy issues. |
James B. Robb | $339,000 | The Compensation Committee determined that Mr. Robb and his team were instrumental in finalizing and executing agreements on the Northern Pass transmission project. Mr. Robb and his team have continued to develop smart grid and electric vehicle strategies to better meet NU’s customers’ needs and improve the efficiency of NU’s operations. |
FS-93172
LONG-TERM INCENTIVE PROGRAMS
General
Under NU’s Long-Term Incentive Programs, the Compensation Committee of NU’s Board of Trustees acting jointly with the Corporate Governance Committee of NU’s Board of Trustees recommends to the NU Board of Trustees a long-term incentive target grant value for Mr. Shivery as a percentage of base salary on the date of grant. This recommendation is presented to the Board of Trustees for approval. The Compensation Committee also approves long-term incentive target grant values for each of the other NEOs as a percentage of base salary on the date of grant. For the 2010 – 2012 Long-Term Incentive Program, at target, each grant generally consisted of 25 percent RSUs and 75 percent performance units (one-half of which was performance cash and one-half of which were performance shares), subject to adjustment by the Compensation Committee (except the Compensation Committee acts jointly with the Corporate Governance Committ ee in recommending to the Board of Trustees adjustments to Mr. Shivery’s targets), reflecting the Committee’s desire to balance the roles of total shareholder return and NU’s corporate financial performance in NU’s compensation programs.
For the 2010 – 2012 program, the Compensation Committee acting jointly with the Corporate Governance Committee recommended to the Board of Trustees a long-term incentive compensation target for Mr. Shivery at 300 percent of base salary, which the Board approved. The Compensation Committee established long-term incentive compensation targets at 100 percent to 150 percent of base salary for the remaining NEOs.
Restricted Share Units (RSUs)
Each RSU granted under the long-term incentive program entitles the holder to receive one NU common share at the time of vesting. All RSUs granted in 2010 will vest in equal annual installments over three years. RSU holders are eligible to receive reinvested dividend units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares. Reinvested dividend units are accounted for as additional RSUs that accrue and are distributed with the common shares issued upon vesting and distribution of the underlying RSUs. Common shares, including any additional common shares in respect of reinvested dividend units, are not issued for any RSUs that do not vest.
General
Annually, the Compensation Committee determines RSU grants for each officer participating in the long-term incentive program. Initially, the target RSU grants are equal to 25 percent of the long-term incentive compensation target for each officer. RSU grants are based on a percentage of base salary and measured in dollars. The percentage used for each officer is based on the officer’s position in the company and ranges from 9 percent to 75 percent of salary. The Committee reserves the right to increase or decrease the RSU grant from target for each officer under special circumstances. The Compensation Committee acting jointly with the Corporate Governance Committee recommends to the Board of Trustees the final RSU grant for Mr. Shivery. Based on input from Mr. Shivery, the Compensation Committee determines the final RSU grants for each of the other officers, including the other NEOs.
All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from dollars into NU common share equivalents by dividing the value of each grant by the average closing price for NU common shares during the last ten trading days in January in the year of the grant.
RSU Grants under the 2010 – 2012 Program
Under the 2010 – 2012 program, the target RSU grant totaled approximately $2.4 million for all 31 officers participating in the long-term incentive program. The Committee did not adjust any officer’s RSU grant from target for the 2010 – 2012 program. Accordingly, the final total RSU grant for officers, including Mr. Shivery, was unchanged from target. Dividing the final total RSU grant by $25.74, the average closing price for NU common shares during the last ten trading days in January 2010, resulted in an aggregate of 93,843 RSUs. The following RSU grants at 100 percent of target were approved, reflected in RSUs: Mr. Shivery: 30,157; Mr. McHale: 7,649; Mr. Olivier: 8,103; Mr. Butler: 5,929; and Mr. Robb: 3,885.
Performance Units
General
Performance units are a performance-based component of NU’s long-term incentive program. A new three-year program commences every year. Performance unit grants are equal to 75 percent of total individual long-term incentive grants at target. The performance-based component of NU’s long-term incentive programs has continued to evolve over the three prior years by shifting a portion of performance cash in earlier programs to performance shares in more recent programs to further strengthen the alignment of the performance elements with NU’s shareholders.
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Long-Term |
| Percentage of |
| Percentage of |
2008 - 2010 |
| 100% |
| 0% |
2009 - 2011 |
| 67% |
| 33% |
2010 - 2012 |
| 50% |
| 50% |
2011 - 2013 |
| 0% |
| 100% |
The Committee approved the 2010 - 2012 program in early 2010. One-half of the performance unit grant in the 2010 - 2012 program consisted of a performance cash grant and the remaining one-half of each performance unit grant consisted of a performance share grant. Consequently, performance cash grants and performance share grants were each equal to 37.5 percent of the total individual long-term incentive grants at target. Under all of NU’s long-term programs, both performance cash grants and performance share grants are measured in dollars. Performance share grants are subsequently converted from dollars into NU common share equivalents by dividing the value of each grant by the average closing price for NU common shares during the last ten trading days in January in the year of the grant. During the three-year performance program period, the dividends that would have been paid with respect to the performance shares to holders of performance share grants are accounted for as additional common shares that accrue and are distributed with the common shares, if any, at the end of the program.
Awards under a program are earned to the extent to which NU achieves goals in the four metrics described below during each year of the program, except as reduced in the discretion of the Compensation Committee. The Compensation Committee determines the actual awards, if any, only after the end of the final year in the respective program.
·
Cumulative Adjusted Net Income, which is consolidated NU net income adjusted by the Compensation Committee to exclude the effects of certain nonrecurring income and expense items or events (which are defined as ANI under the annual incentive program) over the three years in a program. (20%)
·
Average adjusted ROE, which is the average of the annual return on equity for NU for the three years in a program. The Committee adjusts average ROE on the same basis as cumulative adjusted net income. (20%)
·
Average credit rating of NU (excluding the regulated companies), which is the time-weighted average daily credit rating by the rating agencies Standard & Poor’s, Moody’s, and Fitch. The metric is calculated by assigning numerical values, or "points," to credit ratings (A or A2: 5; A- or A3: 4; BBB+ or Baa1: 3; BBB or Baa2: 2; and BBB- or Baa3: 1) so that a large point value represents a high credit rating. In addition to average credit rating objectives, the ratings of NU by S&P and Moody’s must remain above investment grade. (20%)
·
Relative total shareholder return of NU as compared to the return of the utility companies listed in the performance peer group identified for each long term incentive program. (40%)
The selection of these four metrics reflects the Compensation Committee’s belief that these areas are critical measurements of corporate success. Each metric was weighted equally in the 2009 - 2011 program. In the 2010 - 2012 program, the weighting of the total shareholder return metric was increased to 40 percent and the remaining three metrics were reduced to 20 percent each, to strengthen the alignment between executives and shareholders. The Committee measures performance against the cumulative adjusted net income, average adjusted ROE, and average credit rating, because these metrics are directly related to NU’s multi-year business plan in effect at the beginning of the three-year program. The Committee also measures performance against relative total shareholder return to emphasize to the plan participants the importance of achieving total shareholder returns that are comparable to the returns for companies listed in the performance peer group. Before any amount is payable with respect to a metric, NU must achieve a minimum level of performance under that metric. If NU achieves the minimum level of performance for any goal, then the resulting payout will equal 50 percent of the target for that goal. If NU achieves the maximum level of performance for any goal, then the resulting payout will equal 150 percent of target for that goal. The Committee fixed the minimum opportunity at 50 percent of target and the maximum opportunity at 150 percent of target because the Committee believes this range is consistent with the ranges used by companies listed in the performance peer group.
Upon closing of the proposed merger with NSTAR, the extent of satisfaction of the performance goals applicable to Performance Units for performance periods not yet completed in the 2009 - 2011 program and the 2010 - 2012 program generally will be measured based on performance up to the closing of the merger and payment generally will be made on a pro-rata basis (based on the portion of the applicable performance period that had been completed upon closing of the merger) following the end of the original performance period conditioned upon continued employment through such date. Performance Units outstanding immediately before the closing of the merger that are attributable to the portion of the applicable performance periods extending beyond the closing of the merger will be forfeited. However, if an executive officer experiences a qualifying termination of employment (a termination of employment before age 65 without “cause” or by the e xecutive officer for “good reason”) before completion of the original performance period, the awards will be vested at target performance levels and paid out without pro-ration upon such termination.
Subject to the closing of the merger, the Committee intends to grant to each executive officer whose awards are paid on a pro-rated basis as described in the preceding paragraph a “make-whole” award of RSUs with a value equal to the value of the executive officer’s Performance Units outstanding at target immediately before the closing of the merger that are attributable to the portion of the applicable performance periods extending beyond the closing of the merger.
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Set forth below are descriptions of each of the three long-term performance programs that were in effect during 2010. The peer groups used by the Committee for performance comparisons under each program are listed in footnote 1 to the table that accompanies each description. The performance peer groups represent companies with investment profiles, including growth potential, business models and areas of focus substantially similar to NU’s. The Committee compared NU’s total shareholder return to the total shareholder returns of the companies in the performance peer group. Prior to the 2009 - 2011 program, the customized peer group had been larger than the performance peer groups because NU competes for talent with more companies than those with which it competes for investment. However, beginning with the 2009 - 2011 Long-Term Incentive Program, to simplify the peer group structure, the Committee ev aluates the total shareholder return metric using the same customized group of peer utilities described above under "Market Analysis."
2008 - 2010 Performance Cash
The Compensation Committee approved the 2008 - 2010 performance cash grants in early 2008. Upon completion of NU’s fiscal year ended 2010, the Committee determined that NU achieved goals under each of the four metrics during the three-year program and, accordingly, that awards under the program were payable at an overall level of 114 percent of target.
The 2008 – 2010 program included goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2008 – 2010 program, cumulative adjusted net income and average adjusted ROE excluded the positive and negative effects of the following nonrecurring income and expense items or events:
Excluded Categories | Specific 2010 | |
Changes to net income as the result of accounting or tax law changes | $ (5.1) | |
Delay in planned asset transactions | $ 1.8 | |
Incremental NSTAR merger costs | $ (9.4) | |
Net Adjustments: | $ (12.7) |
The table set forth below describes the goals under the 2008 – 2010 program and NU’s actual results during that period:
|
| 2008 – 2010 Program Goals |
|
|
|
| ||
Goal |
| Minimum |
| Target |
| Maximum |
| Actual Results |
Cumulative Adjusted Net Income ($ in millions) |
| $ 845.7 |
| $ 939.7 |
| $ 1,033.7 |
| $ 1,023.2 |
Average Adjusted ROE |
| 8.6% |
| 9.5% |
| 10.5% |
| 10.1% |
Average Credit Rating Points |
| 1.2 |
| 1.7 |
| 2.2 |
| 1.7 |
Relative Total Shareholder Return |
| 40th |
| 60th |
| 80th |
| 53rd |
(1)
Goals were evenly weighted in the 2008 -2010 program.
(2)
The performance peer group for the 2008 - 2010 program includes Northeast Utilities and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, Consolidated Edison, Inc., NiSource, Inc., NSTAR, NV Energy, Inc., Pepco Holdings, Inc., Pinnacle West Capital Corporation, SCANA Corporation, TECO Energy, Inc., Wisconsin Energy Corporation and Xcel Energy Inc.
Based on NU’s financial performance during the three-year performance period, the total payout under the 2008 - 2010 Long-Term Incentive Program equaled 114 percent of target. As a result, the Committee approved the following performance cash awards: Mr. Shivery: $1,769,850; Mr. McHale: $427,500; Mr. Olivier: $381,188; Mr. Butler: $347,975; and Mr. Robb: $228,000. The payments were determined pursuant to formulas set forth in the 2008 - 2010 Long-Term Incentive Program and were not subject to the discretion of the Compensation Committee.
2009 – 2011 Performance Units
The Committee approved the 2009 – 2011 performance unit goals in early 2009. No awards have been paid under this program, and the Committee will not determine whether any awards are payable until the end of NU’s 2011 fiscal year, which is the final year in the three-year program.
As described above, under the 2009 – 2011 program, two-thirds of each performance unit grant consists of a performance cash grant and the remaining one-third of each performance unit grant consists of a performance share grant. The 2009 – 2011 program also includes goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2009 – 2011 program, cumulative adjusted net income and average adjusted ROE exclude the positive and negative effects of the following nonrecurring income and expense items or events: accounting or tax law changes; unusual Internal Revenue Service or regulatory issues; unexpected changes in costs related to nuclear decommissioning; unexpected changes in costs related to environmental remediation of HWP Company; divestiture or discontinuance of a segment or component of NU’s busine ss; the acquisition of shares or assets of another entity comprising an additional segment or component of NU’s business; and impairments on goodwill acquired before 2003 (more than six years prior to the beginning of this program cycle).
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The table set forth below describes the goals under the 2009 – 2011 program:
|
| 2009 – 2011 Program Goals |
|
| ||
Goal |
| Minimum |
| Target |
| Maximum |
Cumulative Adjusted Net Income ($ in millions) |
| $ 899.3 |
| $ 999.2 |
| $ 1,099.1 |
Average Adjusted ROE |
| 8.4% |
| 9.3% |
| 10.1% |
Average Credit Rating Points |
| 1.2 |
| 1.7 |
| 2.2 |
Relative Total Shareholder Return |
| 40th |
| 60th |
| 80th |
(1)
Goals were evenly weighted in the 2009 – 2011 program.
(2)
The performance peer group for the 2009 – 2011 program includes Northeast Utilities and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, Consolidated Edison, Inc., DTE Energy Company, Great Plains Energy Incorporated, Integrys Energy Group Inc., NiSource, Inc., NSTAR, NV Energy, Inc., OGE Energy Corp., Pepco Holdings, Inc., Pinnacle West Capital Corporation, Progress Energy Inc., SCANA Corporation, TECO Energy, Inc., Wisconsin Energy Corporation and Xcel Energy Inc.
2010 – 2012 Performance Units
The Committee approved the 2010 – 2012 performance unit goals in early 2010. No awards have been paid under this program, and the Committee will not determine whether any awards are payable until the end of NU’s 2012 fiscal year, which is the final year in the three-year program.
As described above, under the 2010 – 2012 program, one-half of each performance unit grant consists of a performance cash grant and the remaining one-half of each performance unit grant consists of a performance share grant. The 2010 – 2012 program also includes goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2010 – 2012 program, cumulative adjusted net income and average adjusted ROE exclude the positive and negative effects of the following nonrecurring income and expense items or events: accounting or tax law changes; unusual Internal Revenue Service or regulatory issues; unexpected changes in costs related to nuclear decommissioning; unexpected changes in costs related to environmental remediation of HWP Company; divestiture or discontinuance of a segment or component of NU’s business; the acquisition of shares or assets of another entity comprising an additional segment or component of NU’s business; and impairments on goodwill acquired before 2003 (more than seven years prior to the beginning of this program cycle).
The table set forth below describes the goals under the 2010 – 2012 program:
|
| 2010 – 2012 Program Goals |
|
| ||
Goal |
| Minimum |
| Target |
| Maximum |
Cumulative Adjusted Net Income ($ in millions) |
| $ 1,051.6 |
| $ 1,168.4 |
| $ 1,285.2 |
Average Adjusted ROE |
| 9.0% |
| 9.9% |
| 10.7% |
Average Credit Rating Points |
| 1.2 |
| 1.7 |
| 2.2 |
Relative Total Shareholder Return |
| 40th |
| 60th |
| 80th |
(1)
Relative total shareholder return accounted for 40 percent of the performance units granted in the 2010 – 2012 program while the cumulative adjusted net income, average adjusted ROE, and average credit rating metrics each accounted for 20 percent of the performance units granted.
(2)
The performance peer group for the 2010 – 2012 program includes Northeast Utilities and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, Consolidated Edison, Inc., DTE Energy Company, Great Plains Energy Incorporated, Integrys Energy Group Inc., NiSource, Inc., NSTAR, NV Energy, Inc., OGE Energy Corp., Pepco Holdings, Inc., Pinnacle West Capital Corporation, Progress Energy Inc., SCANA Corporation, TECO Energy, Inc., Wisconsin Energy Corporation and Xcel Energy Inc.
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2011 CHANGES
2011 – 2013 Long-Term Incentive Program
In late-2010, the Compensation Committee changed the performance component of the 2011 – 2013 Long-Term Incentive Program to 100 percent performance shares to further strengthen the alignment of the performance component with NU’s shareholders. For the 2011 – 2013 program, the grant value at target will consist of 75 percent performance shares. RSUs will continue to constitute the remaining 25 percent of the grant value at target, unchanged from the 2010 – 2012 program. Upon the closing of the proposed merger with NSTAR, all outstanding 2011 – 2013 performance shares will be converted to RSUs assuming a target level of performance. These RSUs will vest according to the schedule that applies to the RSU component already granted as part of the 2011 – 2013 Long-Term Incentive Program.
NORTHEAST UTILITIES RETENTION PLAN
In light of the extraordinary nature of the proposed merger between NU and NSTAR, on November 16, 2010, the NU Board of Trustees established a retention pool in an aggregate amount of $10 million to be allocated to key employees, including some or all executive officers, to help ensure their continued dedication to NU both before and after completion of the merger. Awards to executive officers are established by the Committee, are in the form of restricted share units and generally vest subject to three years of continuous service following completion of the merger. Full payment will also be made if an eligible executive dies, becomes disabled, or is terminated without “cause” before the end of the retention period, in which case the retention payment will be reduced by the amount of any cash severance payable to the executive upon or during the year following termination. On November 16, 2010, the Committee granted retention a wards to the following Named Executive Officers: Mr. Butler: 48,077 RSUs; Mr. McHale: 64,103 RSUs; Mr. Olivier: 48,077 RSUs; and Mr. Robb: 32,052 RSUs.
CLAWBACKS
If our earnings were to be restated as a result of noncompliance with accounting rules caused by fraud or misconduct, the Sarbanes-Oxley Act of 2002 would require our CEO and our Chief Financial Officer to reimburse NU for certain incentive compensation received by each of them. To the extent that reimbursement were not required under Sarbanes-Oxley, NU’s Incentive Plan would require any employee whose misconduct or fraud caused such restatement, as determined by the Board of Trustees, to reimburse NU for any incentive compensation received by him or her. To date, there have been no restatements to which either the Sarbanes-Oxley clawback provisions or the Incentive Plan clawback provisions would apply.
SHARE OWNERSHIP GUIDELINES
Effective in 2006, the Compensation Committee approved share ownership guidelines to emphasize the importance of share ownership by certain of NU’s executive officers. The Committee most recently reviewed the guidelines for these executive officers in 2010 and determined that they remain reasonable and require no modification. The guidelines call for Mr. Shivery to own 200,000 NU common shares, which is currently valued at approximately five- to six-times base salary, and the other executive officers to own a minimum number of common shares valued at approximately two- to three-times base salary.
Executive Officer | Ownership Guidelines | Approximate | |||
Mr. Shivery | 200,000 | 5-6 | |||
EVPs/SVPs | 30,000 – 45,000 | 2-3 | |||
VPs | 3,000 – 17,500 | 1.2 |
At the time the share ownership guidelines were implemented, the Committee required NU’s executive officers to attain these ownership levels within five years. The Committee requires all newly-elected executive officers to attain the ownership levels within five to seven years. All of our executive officers, including our NEOs, have satisfied, or are expected to satisfy, the share ownership guidelines within the applicable time frame. Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs satisfy the guidelines. Unexercised stock options and unvested performance shares do not count toward the ownership guidelines.
SUPPLEMENTAL BENEFITS
NU provides a variety of basic and supplemental benefits designed to assist it in attracting and retaining executive officers critical to NU’s success by reflecting competitive practices. The Compensation Committee endeavors to adhere to a high level of propriety in managing executive benefits and perquisites. NU does not provide permanent lodging or personal entertainment for any executive officer or employee, and our executive officers are eligible to participate in substantially the same health care and benefit programs available to NU employees.
RETIREMENT BENEFITS
NU provides retirement income benefits for employees, including executive officers, who commenced employment before 2006 under the Northeast Utilities Service Company Retirement Plan (Retirement Plan) and, for officers, under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (Supplemental Plan). Each plan is a defined benefit pension
177
plan, which determines retirement benefits based on years of service, age at retirement, and "plan compensation." Plan compensation for the Retirement Plan, which is a qualified plan under the Internal Revenue Code, includes primarily base pay and nonofficer annual incentives up to the Internal Revenue Code limits for qualified plans. Beginning in 2006, newly-hired nonunion employees, including Mr. Robb and other executive officers, participate in an enhanced defined contribution retirement program in the Northeast Utilities Service Company 401k Plan (401k Plan), called the K-Vantage benefit, instead of participating in the Retirement Plan.
For NEOs who participate in the Retirement Plan, the Supplemental Plan adds to plan compensation: base pay over the Internal Revenue Code limits; deferred base salary; annual executive incentive program awards; and, for certain participants, long-term incentive program awards, as explained in the narrative accompanying the Pension Benefits Table.
The Supplemental Plan consists of two parts. The first part, called the make-whole benefit, compensates for benefits lost due to Internal Revenue Code limitations on benefits provided under the Retirement Plan. The second part, called the target benefit, is available to all NEOs except Mr. Olivier and Mr. Robb. The target benefit supplements the Retirement Plan and make-whole benefit under the Supplemental Plan so that, upon attaining at least 25 years of service, total retirement benefits from these plans will equal a target percentage of the final average compensation. To receive the target benefit, a participant must remain employed by NU or its subsidiaries at least for five years and until age 60, unless the Board of Trustees establishes a lower age.
The value of the target benefit was reduced in 2005 to reflect changes in competitive practices, which indicated general reductions in the prevalence of defined benefit plans and the value of special retirement benefits to senior executives. Individuals who began serving as officers before February 2005 are eligible to receive a target benefit with the target percentage fixed at 60 percent. Individuals who began serving as officers from and after February 2005 are eligible to receive a target benefit with the target percentage fixed at 50 percent. As a result, Messrs. Shivery and Butler have target benefits at 60 percent while Mr. McHale has a target benefit at 50 percent.
Mr. Shivery’s employment agreement provides for a special total retirement benefit determined using the Supplemental Plan target benefit formula plus three additional years of company service. This benefit will be reduced by two percent per year for each year Mr. Shivery retires before age 65. Upon retirement, Mr. Shivery will be eligible to receive retirement health benefits. In addition, the Named Executive Officers are eligible to receive certain health and welfare benefits upon termination of employment following a change of control or, for Messrs. Shivery, Olivier, McHale and Butler, an involuntary termination of employment. To the extent such benefits may not be provided through NU’s tax qualified plans, the executive is entitled to participate in a non-qualified health plan that will be treated as taxable compensation to the executive officer to the extent of company contributions a nd will be provided with a tax gross-up so that the value to the executive is equivalent to a tax qualified plan benefit. See the Pension Benefits Table and the accompanying narrative for more details of these arrangements.
NU entered into an employment agreement with Mr. Olivier that includes retirement benefits similar to the benefits provided by his previous employer. Accordingly, Mr. Olivier is entitled to receive separate retirement benefits in lieu of the Supplemental Plan benefits described above. Pursuant to his agreement, Mr. Olivier will receive a targeted pension value if he meets certain eligibility requirements. See the Pension Benefits Table and the accompanying narrative for more details of this arrangement.
401K PLAN
NU provides an opportunity for employees to save money for retirement on a tax-favored basis through the 401k Plan. The 401k Plan is a defined contribution qualified plan under the Internal Revenue Code and contains a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code. Participants with at least six months of service receive employer matching contributions, not to exceed 3 percent of base compensation, one-third of which are in cash available for investment in various mutual fund alternatives and two-thirds of which are in the form of NU common shares (ESOP shares).
The K-Vantage benefit provides for employer contributions to the 401k Plan in amounts between 2.5 percent and 6.5 percent of plan compensation based on an eligible employee’s age and years of service. These contributions are in addition to employer matching contributions. Mr. Robb and other executive officers hired beginning in 2006 also participate in a companion nonqualified K-Vantage benefit in the Nonqualified Deferred Compensation Plan (Deferral Plan) that provides defined contribution benefits above Internal Revenue Code limits on qualified plans.
MED-VANTAGE PLAN
NU automatically enrolls K-Vantage employees who have attained at least age 40 in the Med-Vantage Plan to help pay for medical expenses, including healthcare premiums on a tax-favored basis upon the employee's termination of employment. Eligible full-time employees receive employer contributions of $1,000 per year.
NONQUALIFIED DEFERRED COMPENSATION PLAN
Our executive officers participate in the Deferral Plan to provide additional retirement benefits not available in NU’s 401k Plan because of Internal Revenue Code limits on qualified plans. Under the Deferral Plan, executive officers are entitled to defer up to 100 percent of base salary and annual incentive awards. NU matches officer deferrals in an amount equal to 3 percent of the amount of base salary above Internal Revenue Code limits on qualified plans. The matching contribution is deemed to be invested in NU common shares and vests at the end of the third year after the calendar year in which the matching contribution was earned, or at retirement, whichever occurs first. Participants are entitled to select deemed investments for all deferred amounts from the same investments available in the 401k Plan, except for investments in NU’s common shares. NU also credits the Deferral Plan in amounts equal to the K-Vantage
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benefit that would have been provided under the 401k Plan but for Internal Revenue Code limits on qualified plans. This nonqualified plan is unfunded. Please see the Nonqualified Deferred Compensation Table and the accompanying notes for additional plan details.
PERQUISITES
It is NU’s philosophy that perquisites should be provided to executive officers only as needed for business reasons, and not simply in reaction to prevalent market practices.
Senior executive officers, including the NEOs, are eligible to receive reimbursement for financial planning and tax preparation services. This benefit is intended to help ensure that executive officers seek competent tax advice, properly prepare complex tax returns, and leverage the value of NU’s compensation programs. Reimbursement is limited to $4,000 every two years for financial planning services and $1,500 per year for tax preparation services.
All executive officers receive a special annual physical examination benefit to help ensure serious health issues are detected early. The benefit is limited to the reimbursement of up to $800 for fees incurred beyond those covered by NU’s medical plan.
When hiring a new executive officer or transferring an executive officer to a new location, NU sometimes reimburses executive officers for reasonable temporary living and relocation expenses, or provides a lump sum payment in lieu of specific reimbursement. These expenses are grossed-up for income taxes attributable to such reimbursements so that relocation or transfer is cost neutral to the executive officer.
When required for a valid business purpose, an executive officer may be accompanied by his or her spouse, in which case NU will reimburse the executive officer for all spousal travel expenses.
Effective beginning in 2009, NU no longer pays gross-ups for taxes on any perquisites other than for taxes on reimbursement of relocation expenses for newly-hired or transferred executives.
CONTRACTUAL AGREEMENTS
NU has entered into employment and other agreements with certain executive officers, including the NEOs. The agreements specify all or part of the following: compensation and benefits during the employment term, benefits payable upon involuntary termination of employment, and benefits payable upon termination of employment following a change of control. These termination and change of control benefits were customary at the time the agreements were signed and were necessary to attract and retain competent and capable executive talent. NU continues to believe that these benefits help to ensure the executive officers’ dedication and objectivity at a time when they might otherwise be concerned about their future employment.
The agreements with Messrs. McHale, Butler and Robb provide for enhanced cash severance benefits in the event of a “change of control” and subsequent termination of employment without “cause” (as defined in the employment agreement, generally involving a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to NU property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement) or upon termination of employment by the executive for "good reason" (as defined in the employment agreement, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control) . The Compensation Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. The change of control provisions in Mr. Shivery’s employment agreement expired when Mr. Shivery reached age 65. Mr. Olivier’s employment agreement does not provide for severance payments in the event that his employment terminates following a change of control. Mr. Olivier participates instead in the Special Severance Program.
For Messrs. McHale and Butler, a "change of control" is defined in their employment agreements as a change in ownership or control effected through (i) the acquisition of 20 percent or more of the combined voting power of NU’s common shares or other voting securities, (ii) a change in the majority of NU’s Board of Trustees over a 24-month period, unless approved by a majority of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50 percent of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of NU’s assets other than to an entity with respect to which following completion of the transaction more tha n 50 percent of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction. For Mr. Robb, a "change of control" is as defined in the shareholder-approved Northeast Utilities Incentive Plan.
Pursuant to the change of control provisions in the employment agreements, each NEO except for Mr. Olivier and Mr. Robb would be reimbursed for the full amount of any excise taxes imposed on severance payments and any other payments under Section 4999 of the Internal Revenue Code. This "gross-up" is intended to preserve the aggregate amount of the severance payments by compensating the executive officers for any adverse tax consequences to which they may become subject under the Internal Revenue Code. NU has not included gross-up provisions in any employment arrangements entered into with executive officers hired after Mr. Robb. Mr. Olivier’s and Mr. Robb’s severance payments may be reduced to avoid excise taxes.
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We describe and explain how the appropriate payment and benefit levels are determined under the various circumstances that trigger payments or provision of benefits in the tables and accompanying footnotes appearing in the section captioned "Potential Payments Upon Termination or Change of Control," below.
To help protect NU after the termination of an executive officer’s employment, the employment agreements include non-competition and non-solicitation covenants pursuant to which the executive officers have agreed not to compete with NU system companies or solicit NU companies’ employees for a period of two years (one year for Mr. Olivier pursuant to the Special Severance Program and one year for Mr. Robb pursuant to his agreement) after termination of employment.
In the event of termination of employment without "cause" or upon termination of employment by an NEO for good reason, in each case following a change of control, the expiration date of all vested unexercised stock options held by our NEOs would be extended automatically for up to an additional 36 months, but not beyond the original expiration date, to provide these holders with an opportunity to benefit from increased shareholder value created by the change of control. Also, in the event of a change of control, the long-term incentive programs provide for the vesting, pro rata based on the number of days of employment during the performance period, and payment at target of performance cash, whether or not the executive’s employment terminates, unless the Committee determines otherwise.
Finally, in the event of a change of control, the Deferral Plan provides for the immediate vesting of any employer matches, although these matches would be paid according to the schedule defined by the executive’s original election.
As discussed under the caption entitled "Supplemental Benefits," above, the employment agreements with Messrs. Shivery and Olivier also include additional retirement benefits payable upon voluntary termination of employment.
With respect to NU’s proposed merger with NSTAR, Mr. Shivery is not entitled to severance benefits because he ceased being entitled to such benefits upon attaining age 65. Messrs. McHale and Butler are entitled to severance benefits upon a qualifying termination of employment without regard to whether the merger is completed because the merger does not constitute a change in control within the meaning of their employment agreements. Mr. Olivier will be entitled to benefits under the Special Severance Program in the event of a qualifying termination of employment within two years following the approval by NU’s shareholders of the proposed merger. Pursuant to a supplemental agreement between NU and Mr. Olivier, Mr. Olivier is also entitled to a special retirement payment upon a qualifying termination of employment within two years following the approval by NU’s shareholders of the merger. Mr. Robb will be entitle d to benefits under his employment agreement in the event of a qualifying termination of employment within two years following the approval by NU’s shareholders of the merger.
TAX AND ACCOUNTING CONSIDERATIONS
Tax Considerations. All executive compensation for 2010 was fully deductible by NU for federal income tax purposes, except for: (i) approximately $67,000 paid to Mr. Shivery, consisting primarily of RSU distributions.
Section 162(m) of the Internal Revenue Code limits the tax deduction for compensation paid to a company’s CEO and certain other executives. NU is entitled to deduct compensation payments above $1 million as compensation expense only to the extent that these payments are "performance based" in accordance with Section 162(m) of the Internal Revenue Code. NU’s annual incentive program and performance unit grants qualify as performance-based compensation under the Internal Revenue Code. As required by Section 162(m), the Compensation Committee reports to the Board of Trustees annually the extent to which various performance goals have been achieved. RSUs do not qualify as performance-based compensation.
Currently, Messrs. Shivery and Olivier are the only NEOs to exceed the Section 162(m) limit. To preserve an employee compensation tax deduction, Mr. Shivery agreed, for as long as it is beneficial to NU, to defer the distribution to him of NU common shares in respect of all vested RSUs until the calendar year after he leaves NU’s employment, at which time Section 162(m) will no longer apply to him. The non-deductible RSU distributions for Mr. Shivery in 2010 described above relate to RSUs granted before Mr. Shivery was elected as NU’s CEO.
Section 409A of the Internal Revenue Code provides that amounts deferred under nonqualified deferred compensation plans are includable in an employee’s income when vested unless certain requirements are met. If these requirements are not met, employees are also subject to additional income tax and interest penalties. All of NU’s supplemental retirement plans, executive employment agreements, severance arrangements, and other nonqualified deferred compensation plans were amended in 2008 to satisfy the requirements of Section 409A.
Section 280G of the Internal Revenue Code disallows a tax deduction for "excess parachute payments" in connection with the termination of employment related to a change of control (as defined in the Internal Revenue Code), and Section 4999 of the Internal Revenue Code imposes a 20 percent excise tax on any person who receives excess parachute payments. As discussed above, our NEOs are entitled to receive certain payments upon termination of their employment, including termination following a change of control. Under the terms of the agreements, all NEOs except Mr. Olivier and Mr. Robb are entitled to receive tax gross-ups for any payments that constitute an excess parachute payment. Accordingly, a tax deduction would be disallowed under Section 280G for all excess parachute payments as well as tax gross-ups. Not all of the payments to which NEOs are entitled are excess parachute payments. The a mounts of the payments that constitute excess parachute payments are set forth in the tables found under the caption entitled "Potential Payments at Termination or Change of Control," below.
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In the event of a change of control in which NU is not the surviving entity, RSUs granted to executive officers provide that the acquirer will assume or replace the grants, even if the executive remains employed after the change of control.
Accounting Considerations. RSUs and performance shares disclosed in the Grants of Plan-Based Awards Table are accounted for based on their grant date fair value, as determined under FASB ASC Topic 718, which is recognized over the service period, or the three-year vesting period applicable to the grant. Assumptions used in the calculation of this amount appear under the caption entitledManagement’s Discussion and Analysis and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Forfeitures are estimated, and the compensation cost of the grants will be reversed if the employee does not remain employed by NU throughout the three-year vesting period. Performance unit grants are accounted for on a variable basis based on the most likely payment outcome.
SUMMARY COMPENSATION TABLE
The table below summarizes the total compensation paid or earned by CL&P’s NEOs. As explained in the footnotes below, the amounts reflect the economic benefit to each Named Executive Officer of the compensation item paid or accrued on his behalf for the fiscal year ended December 31, 2010. All salaries, annual incentive amounts and long-term incentive amounts shown for each Named Executive Officer were paid for all services rendered to NU and its subsidiaries, including CL&P, in all capacities.
(1)
Includes amounts deferred in 2010 by the Named Executive Officers under the Deferral Plan, as follows: Mr. Shivery: $31,050; Mr. McHale: $8,400; Mr. Olivier: $110,000; and Mr. Robb: $8,000. For more information, see the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.
NU pays each of its salaried employees, including each of the Named Executive Officers, 1/26th of their annual base salary every two weeks. This bi-weekly pay schedule typically results in one extra pay date per year approximately once every twelve years. One additional pay date occurred in 2008. Accordingly, the amounts reported for Salary for each Named Executive Officer in 2008 reflect 27 pay dates, as compared to 26 pay dates in each of 2009 and 2010.
(2)
No discretionary bonus awards were made to any of the Named Executive Officers in the fiscal years ended 2008, 2009 and 2010.
(3)
Reflects the aggregate grant date fair value of restricted share units (RSUs) and performance shares granted in each fiscal year, calculated in accordance with FASB ASC Topic 718.
In 2008, 2009 and 2010, certain Named Executive Officers were granted RSUs that vest in equal annual installments over three years as long-term incentive compensation. NU deferred the distribution of common shares upon vesting of RSUs granted to Mr. Shivery until the calendar year after he leaves employment. RSU holders are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU’s common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.
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In 2010, certain Named Executive Officers were granted performance shares as long-term compensation. These performance shares will vest on December 31, 2012, based on the extent to which four performance conditions are achieved. The grant date values for the performance shares, assuming achievement of the highest level of all four performance conditions, are as follows: Mr. Shivery: $1,726,250; Mr. McHale: $437,820; Mr. Olivier: $458,657; Mr. Butler: $339,404; and Mr. Robb: $222,402.
In 2010, NU established a retention pool in an aggregate amount of $10 million to be allocated to key employees, including some or all of the executive officers, to help ensure their continued dedication to NU both before and after completion of the proposed merger with NSTAR. Awards to executive officers are determined by the Committee, are in the form of RSUs and generally vest subject to three years of continuous service following completion of the merger. Full payment will also be made if an eligible executive dies, becomes disabled, or his or her employment is terminated by NU without “cause” before the end of the retention period, in which case the retention payment will be reduced by the amount of any cash severance payable to the executive upon or during the year following termination. On November 16, 2010, the Committee granted retention awards to the following executive officers: Mr. McHale: 64,103 RSUs; Mr. Olivier: 48,077 RSUs; Mr. Butler: 48,077 RSUs; and Mr. Robb: 32,052 RSUs.
(4)
NU did not grant stock options to any of the Named Executive Officers in 2010. NU has not granted any stock options since 2002.
(5)
Includes payments to the Named Executive Officers under the 2010 Annual Incentive Program (Mr. Shivery: $1,987,200; Mr. McHale: $608,517; Mr. Olivier: $601,494; Mr. Butler: $458,320; and Mr. Robb: $339,000). Also includes performance cash payments under the 2008 – 2010 Long-Term Incentive Program (Mr. Shivery: $1,769,850; Mr. McHale: $427,500; Mr. Olivier: $381,188; Mr. Butler: $347,975; and Mr. Robb: $228,000). Performance goals under the 2010 Annual Incentive Program were communicated to each officer by Mr. Shivery or, in the case of Mr. Shivery, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2010. The Compensation Committee acting jointly with the Corporate Governance Committee determined the extent to which these goals were satisfied (based on input from Mr. Shivery, in the case of the other Named Executive Officers) in February 2011. Performance goals under the 2008 – 2010 Long-Term Incentive Program were communicated to each officer by Mr. Shivery or, in the case of Mr. Shivery, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2008. The Compensation Committee determined the extent to which the long-term goals were satisfied in February 2011.
(6)
Includes the actuarial increase in the present value from December 31, 2009 to December 31, 2010 of the Named Executive Officer’s accumulated benefits under all of NU’s defined benefit pension plans determined using interest rate and mortality rate assumptions consistent with those appearing under the caption entitled “Management’s Discussion and Analysis and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010. The Named Executive Officer may not be fully vested in such amounts. More information on this topic is set forth in the notes to the Pension Benefits table, appearing further below. Mr. Robb does not participate in NU’s defined benefit pension plan. There were no above-market earnings on deferrals in 2010.
(7)
Includes matching contributions of $7,350 allocated by NU to the account of each of the Named Executive Officers under the 401k Plan; plus Med-Vantage employer contributions (Mr. Robb: $1,000); plus qualified K-Vantage employer contributions under the 401k Plan (Mr. Robb: $11,025); plus nonqualified K-Vantage employer contributions under the Deferral Plan (Mr. Robb: $21,218); and employer matching contributions under the Deferral Plan for the Named Executive Officers who deferred part of their salary in the fiscal year ended December 31, 2010 (Mr. Shivery: $23,700; Mr. McHale: $8,400; Mr. Olivier: $9,150; and Mr. Robb: $4,650). Mr. Butler did not participate in the Deferral Plan in 2010.
(8)
Mr. McHale was elected Executive Vice President and Chief Financial Officer of CL&P effective January 1, 2009. He served as Senior Vice President and Chief Financial Officer of CL&P from January 1, 2005 until January 1, 2009.
(9)
Mr. Olivier was elected Executive Vice President and Chief Operating Officer of NU on May 13, 2008. He served as Executive Vice President – Operations of NU from February 13, 2007 until May 13, 2008.
(10)
Mr. Robb did not meet the requirements for inclusion in the Summary Compensation Table and was not a Named Executive Officer for 2008. Mr. Robb became a Named Executive Officer in 2009.
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GRANTS OF PLAN-BASED AWARDS DURING 2010
The Grants of Plan-Based Awards Table provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, 2010. The table also discloses the underlying stock awards and the grant date for equity-based awards. NU has not granted any stock options since 2002. Accordingly, NU did not grant stock options to any of the Named Executive Officers in 2010.
Name | Grant Date | Estimated Future Payouts Under | All Other Stock | Grant Date | ||
Threshold ($) | Target ($) | Maximum ($) | ||||
Charles W. Shivery |
|
|
|
|
|
|
Annual Incentive (3) | 2/9/2010 | 517,500 | 1,035,000 | 2,070,000 | ― | ― |
Long-Term Incentive (4) | 2/9/2010 | 582,192 | 1,164,384 | 1,746,576 | 75,393 | 1,905,964 |
|
|
|
|
|
|
|
David R. McHale |
|
|
|
|
|
|
Annual Incentive (3) | 2/9/2010 | 170,625 | 341,250 | 682,500 | ― | ― |
Long-Term Incentive (4) | 2/9/2010 | 147,650 | 295,300 | 442,950 | 19,122 | 483,411 |
Retention Award (5) | 11/16/2010 | ― | ― | ― | 64,103 | 2,000,014 |
|
|
|
|
|
|
|
Leon J. Olivier |
|
|
|
|
|
|
Annual Incentive (3) | 2/9/2010 | 178,750 | 357,500 | 715,000 | ― | ― |
Long-Term Incentive (4) | 2/9/2010 | 154,688 | 309,376 | 464,064 | 20,032 | 506,417 |
Retention Award (5) | 11/16/2010 | ― | ― | ― | 48,077 | 1,500,002 |
|
|
|
|
|
|
|
Gregory B. Butler |
|
|
|
|
|
|
Annual Incentive (3) | 2/9/2010 | 132,271 | 264,542 | 529,085 | ― | ― |
Long-Term Incentive (4) | 2/9/2010 | 114,469 | 228,938 | 343,407 | 14,823 | 374,731 |
Retention Award (5) | 11/16/2010 | ― | ― | ― | 48,077 | 1,500,002 |
|
|
|
|
|
|
|
James B. Robb |
|
|
|
|
|
|
Annual Incentive (3) | 2/9/2010 | 100,000 | 200,000 | 400,000 | ― | ― |
Long-Term Incentive (4) | 2/9/2010 | 74,994 | 149,987 | 224,981 | 9,713 | 245,548 |
Retention Award (5) | 11/16/2010 | ― | ― | ― | 32,052 | 1,000,022 |
(1)
Includes the number of RSUs and performance shares granted to each of the Named Executive Officers on February 9, 2010 under the 2010 – 2012 Long-Term Incentive Program. Performance shares were granted with a three-year Performance Period that ends on December 31, 2012. At the end of the Performance Period, common shares will be awarded based on performance compared to goals, subject to reduction for applicable withholding taxes. RSUs vest in equal installments on February 25, 2011, 2012 and 2013. Except for Messrs. Shivery and Robb, NU will distribute common shares in respect to vested RSUs on a one-for-one basis immediately upon vesting, after reduction for applicable withholding taxes. For Mr. Shivery, NU will distribute common shares, after reduction for applicable withholding taxes, in respect of vested RSUs in three approximately equal annual installments begin ning the later of (i) six months after he leaves the Company and (ii) January of the calendar year after he leaves the Company. For Mr. Robb, NU will distribute common shares after reduction for applicable withholding taxes, in respect of vested RSUs beginning the earlier of (i) fifteen years beyond the vesting date or (ii) six months after he leaves the Company. Holders of RSUs and performance shares are eligible to receive dividend equivalent units on outstanding RSUs and performance shares held by them to the same extent that dividends are declared and paid on NU’s common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares distributed in respect of the underlying RSUs or performance shares. The Annual Incentive Program does not include an equity component.
Also includes the number of RSUs granted to certain Named Executive Officers on November 16, 2010 pursuant to the retention pool established in connection with the proposed merger with NSTAR. See note 3 to the Summary Compensation Table.
(2)
Reflects the grant-date fair value of RSUs and performance shares granted to the Named Executive Officers on February 9, 2010, under the 2010 – 2012 Long-Term Incentive Program determined pursuant to generally accepted accounting principles. The Annual Incentive Program does not include an equity component.
(3)
Amounts reflect the range of potential payouts, if any, under the 2010 Annual Incentive Program for each Named Executive Officer, as described in the Compensation Discussion and Analysis. The payment in 2011 for performance in 2010 is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. The threshold payment under the Annual Incentive Program is 50 percent of target. However, based on Adjusted Net Income and individual performance, the actual payment under the Annual Incentive Program could be zero.
(4)
Reflects the range of potential payouts, if any, pursuant to performance cash awards under the 2010 – 2012 Long-Term Incentive Program, as described in the Compensation Discussion and Analysis. Grants of three-year performance cash awards were made in 2010 under the 2010 – 2012 Long-Term Incentive Program. Performance cash will be fully vested at the
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end of the performance period and paid to the officers in cash during the first fiscal quarter after the end of the performance period.
(5)
Reflects the number of RSUs granted to certain Named Executive Officers on November 16, 2010 pursuant to the retention pool established in connection with the proposed merger with NSTAR. See note 3 to the Summary Compensation Table.
EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2010
The following table sets forth option, RSU and performance share grants outstanding at the end of NU’s fiscal yearended December 31, 2010 for each of the Named Executive Officers. All outstanding options were fully vested as of December 31, 2010.
| Option Awards (1) | Stock Awards (2) | ||||||
Name | Number of | Option | Option | Number of | Market Value of | Equity Incentive | Equity Incentive | |
Charles W. Shivery | 29,024 | $18.90 | 06/11/2012 | 80,206 | 2,556,972 | 82,191 | 2,620,249 | |
David R. McHale | ― | ― | ― | 84,654 | 2,698,765 | 20,846 | 664,570 | |
Leon J. Olivier | ― | ― | ― | 68,496 | 2,183,642 | 21,838 | 696,195 | |
Gregory B. Butler | ― | ― | ― | 63,634 | 2,028,636 | 16,160 | 515,181 | |
James B. Robb | ― | ― | ― | 42,381 | 1,351,092 | 10,589 | 337,577 |
(1)
NU has not granted stock options since 2002.
(2)
Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.
(3)
A total of 2,230 unvested RSUs held by Mr. Robb vested on September 4, 2010 plus 19 associated dividend equivalent units vested on September 30, 2010. An additional 87,294 unvested RSUs will vest on February 25, 2011 (Mr. Shivery: 49,531; Mr. McHale: 11,766; Mr. Olivier: 11,368; Mr. Butler: 8,759 and Mr. Robb: 5,870). An additional 40,929 unvested RSUs will vest on February 25, 2012 (Mr. Shivery: 22,187; Mr. McHale: 5,627; Mr. Olivier: 5,895; Mr. Butler: 4,362; and Mr. Robb: 2,858). An additional 19,222 unvested RSUs will vest on February 25, 2013 (Mr. Shivery: 10,419; Mr. McHale: 2,643; Mr. Olivier: 2,769; Mr. Butler: 2,049; and Mr. Robb: 1,342).
An additional 193,854 unvested RSUs granted pursuant to the retention pool will vest subject to three years of continuous service following completion of the merger with NSTAR (Mr. McHale: 64,618; Mr. Olivier: 48,463; Mr. Butler: 48,463; and Mr. Robb: 32,310). See note 3 to the Summary Compensation Table regarding retention pool grants.
(4)
The market value of RSUs is determined by multiplying the number of RSUs by $31.88, the closing price per share of common shares on December 31, 2010, the last trading day of the fiscal year.
(5)
Reflects the target payout level for 2010 and 2009 performance shares. Payouts for 2010 and 2009 performance shares will be based on actual performance. Performance shares are described in the CD&A and footnote (1) to the Grants of Plan-Based Awards table. Performance shares vest following a three-year performance period to the extent targets are achieved. Performance shares are also discussed in the CD&A under "Performance Units" above. A total of 65,126 unearned performance shares will vest on December 31, 2012 (Mr. Shivery: 35,303; Mr. McHale: 8,954; Mr. Olivier: 9,380; Mr. Butler: 6,941 and Mr. Robb: 4,548). An additional 86,498 unearned performance shares will vest on December 31, 2013 (Mr. Shivery: 46,888; Mr. McHale: 11,892; Mr. Olivier: 12,458; Mr. Butler: 9,219; and Mr. Robb: 6,041).
(6)
The market value is determined by multiplying the number of performance shares in the adjacent column by $31.88, the closing price per share of common shares on December 31, 2010, the last trading day of the fiscal year.
184
OPTIONS EXERCISED AND STOCK VESTED IN 2010
Thefollowing table reports amounts realized on equity compensation during the fiscal year ended December 31, 2010. None of the Named Executive Officers exercised options in 2010. The Stock Awards columns report the vesting of RSU grants to the Named Executive Officers in 2010.
|
| Option Awards |
| Stock Awards | |||||
Name |
|
| Number of |
| Value Realized |
| Number of |
| Value Realized |
Charles W. Shivery |
| ― |
| ― |
| 70,957 |
| 1,863,346 | |
David R. McHale |
| ― |
| ― |
| 15,568 |
| 408,816 | |
Leon J. Olivier |
| ― |
| ― |
| 14,248 |
| 374,188 | |
Gregory J. Butler |
| ― |
| ― |
| 11,526 |
| 302,672 | |
James J. Robb |
| ― |
| ― |
| 6,618 |
| 181,049 |
(1)
Represents the amounts realized upon option exercises, which is the difference between the option exercise price and the market price at the time of exercise.
(2)
Includes RSUs granted to our Named Executive Officers under NU’s long-term incentive programs, including dividend reinvestments, as follows:
Name |
|
| 2007 |
| 2008 |
| 2009 |
Charles W. Shivery |
| 35,087 |
| 24,517 |
| 11,353 | |
David R. McHale |
| 6,767 |
| 5,922 |
| 2,879 | |
Leon J. Olivier |
| 5,952 |
| 5,280 |
| 3,016 | |
Gregory B. Butler |
| 5,052 |
| 4,242 |
| 2,232 | |
James B. Robb |
| 2,249 |
| 2,906 |
| 1,463 |
In all cases, NU reduces the distribution of common shares by that number of shares valued in an amount sufficient to satisfy tax withholding obligations, which amount NU distributes in cash. Included in the value realized are values associated with deferred RSUs, which are also reported in the Registrant Contributions in Last Fiscal Year column of the Non-Qualified Deferred Compensation Table.
(3)
Value realized on vesting of Mr. Robb’s 2007 RSU grant is based on $29.48 per share, the closing price of common shares on September 3, 2010 and the associated third-quarter 2010 dividend equivalent units at $29.87 per share, the closing price of common shares on September 29, 2010. Value realized on vesting for all other amounts is based on $26.26 per share, the closing price of common shares on February 24, 2010. This value includes the value of vested RSUs for which the distribution of common shares is currently deferred.
PENSION BENEFITS IN 2010
The Pension Benefits Table sets forth the estimated present value of accumulated retirement benefits that would be payable to each Named Executive Officer upon his retirement as of the first date upon which he is eligible to receive an unreduced pension benefit (see below). The table distinguishes the benefits among those available through the Retirement Plan, the Supplemental Plan and any additional benefits available under the respective officer’s employment agreement. The Supplemental Plan provides a make whole benefit that is based in part on compensation that is not permitted to be recognized under a tax-qualified plan and provides a target benefit if the eligible officer continues his or her employment until age 60. Benefits under the Supplemental Plan are also based on elements of compensation that are not included under the Retirement Plan. This includes compensation equal to: (i) deferred compen sation; (ii) the value of awards under the Annual Incentive Program for officers; and (iii) long-term incentive awards only for Messrs. McHale and Butler (as to each of their respective make whole benefits), the values of which are frozen at the 2001 target levels.
The present value of accumulated benefits shown in the Pension Benefits Table was calculated as of December 31, 2010 assuming benefits would be paid in the form of a one-half spousal contingent annuitant option (the typical form of payment for the target benefit). For Mr. Olivier, who has a special retirement arrangement, NU assumed that his special retirement benefit would be paid as a lump sum, and his Retirement Plan benefit would be paid in the form of a life annuity with a one-third spousal contingent annuitant option (the typical form of payment under the Retirement Plan). None of Mr. Olivier’s benefits will be provided under the Supplemental Plan. In addition, the present value of accrued benefits for any Named Executive Officer assumes that benefits commence at the earliest age at which the participant would be eligible to retire and receive unreduced benefits. Named Executive Officers are eligible to receive unreduced benefits upon the earlier of (a) attainment of age 65 or (b) attainment of at least age 55 when age plus service equals 85 or more years, except for Mr. Olivier. Mr. Olivier’s unreduced benefit is available at age 60 pursuant to his employment agreement. The target benefit is available for Messrs. Butler and McHale only after age 60. Accordingly, Mr. Shivery is eligible to receive unreduced benefits at age 65, Messrs. McHale and Olivier are eligible to receive unreduced benefits at age 60, and Mr. Butler is eligible to receive unreduced benefits at age 62. Mr. Robb does not participate in the Retirement Plan or the Supplemental Plan.
185
The limitations applicable to the Retirement Plan under the Internal Revenue Code as of December 31, 2010 were used to determine the benefits under each plan. The accrued benefits reflect actual compensation (both salary and incentives) earned during 2010. Under the terms of the Supplemental Plan, annual incentives earned for services provided in a plan year are deemed to have been paid ratably over that plan year. For example, the March 2011 payment pursuant to the 2010 Annual Incentive Program was reflected in the 2010 plan compensation. NU determined the present value of the benefit at retirement age by using the discount rate of 5.57 percent under Statement of Financial Accounting Standards No. 87 for the 2010 fiscal year end measurement (as of December 31, 2010). This present value assumes no pre-retirement mortality, turnover or disability. However, for the postretirement period beginning at the retirement age, NU used the RP2000 Combined Healthy mortality table as published by the Society of Actuaries projected to 2011 with projection scale AA (same table used for financial reporting under FAS 87). Additional assumptions appear in Item 7Management’s Discussion and Analysis and Results of Operations in this Annual Report on Form 10-K.
Pension Benefits
Name | Plan Name | Number of Years | Present Value of | Payments |
Charles W. Shivery (1) | Retirement Plan | 8.6 | 327,627 | ― |
Supplemental Plan | 8.6 | 6,553,108 | ― | |
Other Special Benefit | 11.6 | 2,405,851 | ― | |
David R. McHale | Retirement Plan | 29.3 | 732,032 | ― |
Supplemental Plan | 29.3 | 3,541,066 | ― | |
Leon J. Olivier (2) | Retirement Plan | 11.8 | 439,960 | ― |
Supplemental Plan | 9.3 | — | ― | |
Other Special Benefit | 9.3 | 2,481,374 | ― | |
Other Special Benefit | 31.3 | 1,253,081 | 105,966 | |
Gregory B. Butler | Retirement Plan | 14.0 | 344,191 | ― |
Supplemental Plan | 14.0 | 1,832,152 | ― | |
James B. Robb | Retirement Plan | ― | ― | ― |
Supplemental Plan | ― | ― | ― |
(1)
Mr. Shivery’s actual service with NU totaled 8.6 years at December 31, 2010. However, Mr. Shivery’s employment agreement provides for a special retirement benefit consisting of an amount equal to the difference between: (i) the equivalent of fully-vested benefits under the Retirement Plan and the Supplemental Plan calculated by adding three years to his actual service and using an early retirement commencement reduction factor of two percent per year for each year Mr. Shivery’s age upon retirement is under age 65, if that factor yields a more favorable result to Mr. Shivery than the factors then in use under the Retirement Plan, and (ii) benefits otherwise payable from the Retirement Plan and the Suppleme ntal Plan. The value of the additional three years of service on December 31, 2010 was approximately $2,405,851.
(2)
Mr. Olivier was employed with Northeast Nuclear Energy Company, one of NU’s subsidiaries, from October of 1998 through March of 2001. In connection with this employment, he received a special retirement benefit that provided credit for service with his previous employer, Boston Edison Company (BECO), when calculating the value of his defined benefit pension, offset by the pension benefit provided by BECO. The benefit, which commenced upon Mr. Olivier’s 55th birthday, provides an annuity of $105,966 per year in a form that provides no contingent annuitant benefit. The present value of future payments under this benefit was calculated using the actuarial assumptions currently used by the Retirement Plan. Mr. Olivier was rehired by NU from Entergy in September 2001. Mr. Olivier’s current employment agreement provides for certain supplementa l pension benefits in lieu of benefits under the Supplemental Plan, in order to provide a benefit similar to that provided by Entergy. Under this arrangement, if Mr. Olivier remains continuously employed by NU until September 10, 2011 (or terminates his employment earlier with NU’s consent), he will be eligible to receive a special benefit, subject to reduction for termination prior to age 65, consisting of three percent of final average compensation for each of his first 15 years of service since September 10, 2001, plus one percent of final average compensation for each of the second 15 years of service. Alternatively, if Mr. Olivier voluntarily terminates his employment with NU after his 60th birthday, or NU terminates his employment earlier for any reason other than "cause" (as defined in his employment agreement, generally meaning willful and continued failure to perform his duties after written notice, a violation of NU’s Standards of Business Conduct or conviction of a felony) he is eligible to receive upon retirement a lump sum payment of $2,050,000 in lieu of benefits under the Supplemental Plan and the benefit described in the preceding sentence. These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan. Because Mr. Olivier attained age 60 during 2008, amounts reported in the table assume the termination of his employment on December 31, 2010, and payment of the lump sum benefit of $2,921,334, offset by Retirement Plan benefits.
186
NONQUALIFIED DEFERRED COMPENSATION IN 2010
Name | Executive | Registrant | Aggregate | Aggregate | Aggregate |
Charles W. Shivery | 1,894,394 | 23,700 | 2,298,819 | (83,334) | 10,824,523 |
David R. McHale | 8,400 | 8,400 | 76,104 | (36,732) | 354,500 |
Leon J. Olivier | 110,000 | 9,150 | 214,768 | (92,678) | 1,902,186 |
Gregory B. Butler | ― | ― | 114,262 | (98,805) | 521,013 |
James B. Robb | 46,408 | 25,868 | 25,159 | ― | 170,409 |
(1)
Includes deferrals by the Named Executive Officers under the 2010 Deferral Plan (Mr. Shivery: $31,050; Mr. McHale: $8,400; Mr. Olivier: 110,000; and Mr. Robb: $8,000). Named Executive Officers who participate in the Deferral Plan are provided with a variety of investment opportunities, which the individual can modify and reallocate at any time. Fund gains and losses are updated daily by NU’s recordkeeper, Fidelity Investments. Contributions by the Named Executive Officer are vested at all times; however, the employer matching contribution vests after three years and will be forfeited if the executive’s employment terminates, other than for retirement, prior to vesting.
All other amounts relate to the value of common shares, the distribution of which was either automatically deferred upon vesting of underlying RSUs pursuant to the terms of the respective Long-Term Incentive Programs, or pursuant to the Named Executive Officer’s deferral election, calculated using $26.26 per share, the closing price of the common shares on February 24, 2010, the last trading day preceding the vesting date of February 25, 2010. For more information, see the footnotes to the Options Exercised and Stock Vested Table.
(2)
Includes employer matching contributions made to the Deferral Plan as of December 31, 2010 and posted on January 31, 2011, as reported in the All Other Compensation column of the Summary Compensation Table (Mr. Shivery: $23,700; Mr. McHale: $8,400; Mr. Olivier: $9,150; and Mr. Robb: $25,868). The employer matching contribution is deemed to be invested in common shares but is paid in cash at the time of distribution. Also includes nonqualified K-Vantage employer contributions made to the Deferral Plan during fiscal year 2010 (Mr. Robb: $21,218).
(3)
Includes distributions to Named Executive Officers under the Deferral Plan during fiscal year 2010 pursuant to their deferral elections (Mr. Olivier: $17,437); plus the value of previously vested deferred RSUs distributed in 2010, pursuant to the Named Executive Officer’s deferral election, valued at distribution at $26.26 per share, the closing price of NU common shares on February 24, 2010.
(4)
Includes the total market value of Deferral Plan balances at December 31, 2010, plus the value of vested RSUs for which the distribution of common shares is currently deferred, based on $31.88 per share, the closing price of NU common shares on December 31, 2010.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
Generally, a "change of control" means a change in ownership or control of NU effected through (i) the acquisition of 20 percent or more of the combined voting power of common shares or other voting securities, (ii) a change in the majority of NU’s Board of Trustees over a 24-month period, unless approved by a majority of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding NU common shares immediately prior to such business combination do not beneficially own more than 50 percent (75 percent for Messrs. Olivier and Robb) of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than to an entity with respect to which following completion of the transaction more than 50 percent (75 percent for Messrs. Olivier and Robb) of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.
In the event of a change of control, the NEO’s are each entitled to receive compensation and benefits following either termination of employment without "cause" or upon termination of employment by the executive for "good reason," within 24 months following the change of control. The Compensation Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. Termination for "cause" generally means termination due to a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to company property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement. Termination f or "good reason" generally is deemed to occur following an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement, a reduction in the compensation or benefits of the executive officer (a material reduction in compensation or benefits for Messrs. Olivier and Robb, or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control.
187
With respect to the proposed merger with NSTAR, none of the Named Executive Officers will be entitled to receive any additional compensation and benefits in the absence of a termination of employment for cause or for good reason within two years after shareholder approval of the merger.
The discussion and tables below reflect the amount of compensation that would be payable to each of the Named Executive Officers in the event of: (i) termination of employment for cause; (ii) voluntary termination; (iii) involuntary not-for-cause termination (or voluntary termination for good reason); (iv) termination in the event of disability; (v) death; and (vi) termination following a change of control. The amounts shown assume that each termination was effective as of December 31, 2010, the last business day of the fiscal year as required under Securities and Exchange Commission reporting requirements.
Payments Upon Termination
Regardless of the manner in which the employment of a Named Executive Officer terminates, he is entitled to receive certain amounts earned during his term of employment. Such amounts include:
·
Vested RSUs;
·
Amounts contributed under the Deferral Plan;
·
Vested matching contributions under the Deferral Plan;
·
Pay for unused vacation; and
·
Amounts accrued and vested through the Retirement Plan and the 401k Plan.
I.
Post-Employment Compensation: Termination for Cause
Type of Payment |
| Shivery ($) |
| McHale ($) |
| Olivier ($) |
| Butler ($) |
| Robb ($) |
Incentive Programs |
|
|
|
|
|
|
|
|
|
|
Annual Incentives |
| ― |
| ― |
| ― |
| ― |
| ― |
Performance Cash
|
| ― |
| ― |
| ― |
| ― |
| ― |
Performance Shares |
| ― |
| ― |
| ― |
| ― |
| ― |
RSUs (1) |
| 10,288,685 |
| 336,021 |
| 425,570 |
| 496,668 |
| 48,330 |
Pension and Deferred Compensation |
|
|
|
|
|
|
|
|
|
|
Supplemental Plan (2) |
| 3,730,602 |
| ― |
| ― |
| ― |
| ― |
Special Retirement Benefit (3) |
| ― |
| ― |
| 1,610,040 |
| ― |
| ― |
Deferral Plan (4) |
| 535,838 |
| 9,462 |
| 1,476,616 |
| 24,345 |
| 102,906 |
Other Benefits |
|
|
|
|
|
|
|
|
|
|
Health and Welfare Cash Value |
| ― |
| ― |
| ― |
| ― |
| ― |
Perquisites |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payments |
|
|
|
|
|
|
|
|
|
|
Excise Tax & Gross-Up |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payment for Non-Compete |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payment for Liquidated Damages |
| ― |
| ― |
| ― |
| ― |
| ― |
Total |
| 14,555,125 |
| 345,483 |
| 3,512,226 |
| 521,013 |
| 151,236 |
(1)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs that, as of the end of 2010, had been deferred upon vesting and remained deferred. Excludes retention pool RSU grants.
(2)
Represents the actuarial present value at the end of 2010 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in Notes 1 and 2 to the Pension Benefits Table appearing above.
(3)
Represents the actuarial present values at the end of 2010 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000 offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon termination. Pension amounts reflected in the table are present values at the end of 2010 of benefits payable to each NEO upon termination.
(4)
Represents the vested Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2010.
188
II.
Post-Employment Compensation: Voluntary Termination
Type of Payment |
| Shivery ($) |
| McHale ($) |
| Olivier ($) |
| Butler ($) |
| Robb ($) |
Incentive Programs |
|
|
|
|
|
|
|
|
|
|
Annual Incentives |
| 1,987,200 |
| 608,517 |
| 601,494 |
| 458,320 |
| 339,000 |
Performance Cash (1)
|
| 4,486,734 |
| 427,500 |
| 759,313 |
| 347,975 |
| 228,000 |
Performance Shares (2) |
| 2,620,237 |
| ― |
| 331,742 |
| ― |
| ― |
Performance Shares (3) |
| 12,845,657 |
| 336,021 |
| 733,385 |
| 496,668 |
| 48,330 |
RSUs (4) |
|
|
|
|
|
|
|
|
|
|
Pension and Deferred Compensation |
|
|
|
|
|
|
|
|
|
|
Supplemental Plan (5) |
| 6,553,109 |
| ― |
| ― |
| ― |
| ― |
Special Retirement Benefit (6) |
| 2,405,851 |
| �� |
| 1,610,040 |
| ― |
| ― |
Deferral Plan (7) |
| 533,244 |
| 9,462 |
| 1,477,901 |
| 24,345 |
| 102,906 |
Other Benefits |
|
|
|
|
|
|
|
|
|
|
Health and Welfare Benefits (8) |
| 101,181 |
| ― |
| ― |
| ― |
| ― |
Perquisites |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payments |
|
|
|
|
|
|
|
|
|
|
Excise Tax & Gross-Up |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payment for Non-Compete |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payment for Liquidated Damages |
| ― |
| ― |
| ― |
| ― |
| ― |
Total |
| 31,533,213 |
| 1,381,500 |
| 5,513,875 |
| 1,327,308 |
| 718,236 |
(1)
Represents the actual 20109 annual incentive award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" above.
(2)
Represents the actual performance cash award under the 2008 – 2010 Long-Term Incentive Program for each Named Executive Officer. Also includes, for Messrs. Shivery and Olivier, prorated performance cash awards under the 2009 – 2011 and 2010 – 2012 Long-Term Incentive Programs, because each of them would be considered to be a "retiree" under those programs. Amounts are prorated for time worked in each three-year performance period, determined as described in the "Compensation Discussion and Analysis" above.
(3)
Includes, for Messrs. Shivery and Olivier, the prorated performance share award under the 2009 – 2011 and 2010 – 2012 Long-Term Incentive Programs, because each of them would be considered to be a "retiree" under those programs. Amounts are prorated for time worked in the three-year performance period, determined as described in the "Compensation Discussion and Analysis" above.
(4)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs that, as of the end of 2010, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of each RSU grant, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination, and time worked during the vesting period. The values were calculated by multiplying the number of RSUs by $31.88, the closing price of NU common shares on December 31, 2010. Excludes retention pool RSU grants.
(5)
Represents the actuarial present value at the end of 2010 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in Notes 1 and 2 to the Pension Benefits Table above.
(6)
Represents the actuarial present values at the end of 2010 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon voluntary termination were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,748,997 offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon voluntary termination. Pension amounts reflected in the table are present values at the end of 2010 of benefits payable to each Named Executive Officer upon termination. Mr. Shivery’s benefit would be paid as an annuity calculated as described in Notes 1 and 2 to the Pension Benefits Table above.
(7)
Represents the vested Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2010.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2010 of providing post-employment welfare benefits to Mr. Shivery beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. To the extent these benefits are provided in excess of those provided to employees in general, Mr. Shivery would receive payments to offset the taxes incurred on such benefits.
189
III.
Post-Employment Compensation: Involuntary Termination, Not for Cause
Type of Payment |
| Shivery ($) |
| McHale ($) |
| Olivier ($) |
| Butler ($) |
| Robb ($) |
Incentive Programs |
|
|
|
|
|
|
|
|
|
|
Annual Incentives (1) |
| 1,987,200 |
| 608,517 |
| 601,494 |
| 458,320 |
| 339,000 |
Performance Cash (2)
|
| 4,486,734 |
| 788,433 |
| 759,313 |
| 627,782 |
| 228,000 |
Performance Shares (3) |
| 2,620,237 |
| 316,666 |
| 331,742 |
| 245,492 |
| ― |
RSUs (4) |
| 12,845,657 |
| 965,689 |
| 2,266,080 |
| 923,469 |
| 470,148 |
Pension and Deferred Compensation |
|
|
|
|
|
|
|
|
|
|
Supplemental Plan (5) |
| 6,553,109 |
| 2,979,143 |
| ― |
| 1,312,808 |
| ― |
Special Retirement Benefit (6) |
| 2,405,851 |
| 2,147,572 |
| 2,481,374 |
| 1,741,608 |
| ― |
Deferral Plan (7) |
| 533,244 |
| 17,862 |
| 1,477,901 |
| 24,345 |
| 121,891 |
Other Benefits |
|
|
|
|
|
|
|
|
|
|
Health and Welfare Benefits (8) |
| 101,181 |
| 65,269 |
| ― |
| 65,923 |
| ― |
Perquisites (9) |
| ― |
| 7,000 |
| ― |
| 7,000 |
| ― |
Separation Payments |
|
|
|
|
|
|
|
|
|
|
Excise Tax & Gross-Up |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payment for Non-Compete |
| ― |
| 866,251 |
| ― |
| 671,531 |
| 300,000 |
Separation Payment for Liquidated |
| ― |
| 866,251 |
| ― |
| 671,531 |
| 300,000 |
Total |
| 31,533,213 |
| 9,628,653 |
| 7,917,904 |
| 6,749,809 |
| 1,759,039 |
(1)
Represents the actual 2010 annual incentive award for each Named Executive Officer, determined as described in the "Compensation Discussion and Analysis" above.
(2)
Represents the actual performance cash award under the 2008 – 2010 Long-Term Incentive Program for each Named Executive Officer. Also includes, for Messrs. Shivery, McHale, Olivier and Butler, prorated performance cash awards under the 2009 – 2011 and 2010 – 2012 Long-Term Incentive Programs. Amounts are prorated for time worked in each three-year performance period, because each of them would be considered to be a "retiree" under those programs, determined as described in the "Compensation Discussion and Analysis" above.
(3)
Includes, for Messrs. Shivery, McHale, Olivier and Butler, a prorated performance share award under the 2009 – 2011 and 2010 – 2012 Long-Term Incentive Programs. Amounts are prorated for time worked in the three-year performance period, because each of them would be considered to be a "retiree" under those programs, determined as described in the "Compensation Discussion and Analysis" above.
(4)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs and NU’s retention program that, as of the end of 2010, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination, and time worked during the vesting period. Under NU’s retention program, RSUs vest fully upon termination without cause of the Named Executive Officers and the value is reduced by any separation payments as described in footnotes 10 and 11.The values were calculated by multiplying the number of RSUs by $31.88, the closing price of NU common shares on December 31, 2 010.
(5)
Represents the actuarial present value at the end of 2010 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.
(6)
Represents the actuarial present values at the end of 2010 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreements with Messrs. McHale and Butler, pension benefits available upon an involuntary termination other than for cause were calculated with the addition of two years of age and service. Pursuant to the employment agreement with Mr. Shivery, pension benefits were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,921,334, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon an involuntary termination other than for cause. Pension amounts reflected in the table are present values at the end of 2010 of benefits payable to each Named Executive Officer upon termination. Except for the benefit payable to Mr. Olivier, all benefits are annuities calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.
(7)
Represents the vested Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2010.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2010 of providing post-employment welfare benefits to the Named Executive Officers beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Each of Messrs. McHale and Butler is entitled to receive active health and welfare
190
benefits and the cash value of company-paid active long-term disability and life insurance benefits for two years under the terms of his respective employment agreement, plus tax gross-up with respect to such taxable subsidized coverage and are eligible to receive qualified benefits under NU’s retiree health plan. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. Therefore, the amount reported in the table for Messrs. McHale and Butler represents (a) the value of 24 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) tax gross-up payments thereon. The amount reported in the table for Mr. Shivery represents (a) the value of lifetime retiree health coverage, plus (b) tax gross-up payments thereon.
(9)
Represents the cost to NU of reimbursing fees for financial planning and tax preparation services to Messrs. McHale, and Butler for two years.
(10)
Represents payments made as consideration for agreements by each of Messrs. McHale, Butler, and Robb not to compete with the company following termination. Employment or other agreements with Messrs. McHale and Butler provide for a lump-sum payment in an amount equal to the sum of their 2010 annual salary plus annual incentive award at target, and one-half of the sum of 2009 annual salary plus annual incentive award at target (for Mr. Robb). These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
(11)
Represents severance payments to Messrs. McHale, Butler and Robb paid in addition to the non-compete agreement payments described in note 10. This payment is an amount equal to the sum (one-half of the sum for Mr. Robb) of their actual base salary paid in 2010 (2009 for Mr. Robb) plus 2010 annual incentive award at target (2009 for Mr. Robb). These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
IV.
Post-Employment Compensation: Termination Upon Disability
Type of Payment |
| Shivery ($) |
| McHale ($) |
| Olivier ($) |
| Butler ($) |
| Robb ($) | |
Incentive Programs |
|
|
|
|
|
|
|
|
|
| |
Annual Incentives (1) |
| 1,987,200 |
| 608,517 |
| 601,494 |
| 458,320 |
| 339,000 | |
Performance Cash (2)
|
| 4,486,734 |
| 788,433 |
| 759,313 |
| 627,782 |
| 411,329 | |
Performance Shares (3) |
| 2,620,237 |
| 316,666 |
| 331,742 |
| 245,492 |
| 160,855 | |
RSUs (4) |
| 12,845,657 |
| 2,698,191 |
| 2,266,080 |
| 2,266,531 |
| 1,229,085 | |
Pension and Deferred Compensation |
|
|
|
|
|
|
|
|
|
| |
Supplemental Plan (5) |
| 6,553,109 |
| 4,950,069 |
| ― |
| 1,832,154 |
| ― | |
Special Retirement Benefit (6) |
| 2,405,851 |
| ― |
| 2,481,374 |
| ― |
| ― | |
Deferral Plan (7) |
| 533,244 |
| 17,862 |
| 1,477,901 |
| 24,345 |
| 121,891 | |
Other Benefits |
|
|
|
|
|
|
|
|
|
| |
Health and Welfare Benefits (8) |
| 101,181 |
| ― |
| ― |
| ― |
| ― | |
Perquisites |
| ― |
| ― |
| ― |
| ― |
| ― | |
Separation Payments |
|
|
|
|
|
|
|
|
|
| |
Excise Tax & Gross-Up |
| ― |
| ― |
| ― |
| ― |
| ― | |
Separation Payment for Non-Compete |
| ― |
| ― |
| ― |
| ― |
| ― | |
Separation Payment for Liquidated |
| ― |
| ― |
| ― |
| ― |
| ― | |
Total |
| 31,533,213 |
| 9,379,738 |
| 7,917,904 |
| 5,454,624 |
| 2,262,160 |
(1)
Represents the actual 2010 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis above.
(2)
Represents the actual performance cash award under the 2008 – 2010 Long-Term Incentive Program determined as described in the Compensation Discussion and Analysis above, plus performance cash awards at target under each of the 2009 – 2011 Long-Term Incentive Program and 2010 – 2012 Long-Term Incentive Program prorated for time worked in each three-year performance period.
(3)
Represents the performance share award at target under the 2009 – 2011 and 2010 – 2012 Long-Term Incentive Programs prorated for time worked in the three-year performance period, as described in the Compensation Discussion and Analysis above.
(4)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs and NU’s retention program that, as of the end of 2010, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination, and time worked during the vesting period. Under NU’s retention program, RSUs vest fully upon termination on account of disability of the Named Executive Officer. The values were calculated by multiplying the number of RSUs by $31.88, the closing price of NU common shares on December 31, 2010.
(5)
Represents the actuarial present value at the end of 2010 of the benefit payable from the Supplemental Plan to each NEO other than Mr. Olivier. For purposes of valuing the pension benefits, NU has assumed that each Named Executive Officer
191
would remain on NU’s Long Term Disability plan until the executive’s first unreduced combined pension benefit age. Therefore, the numbers shown represent the actuarial present values at the end of 2010 of nonqualified pension benefits payable to each Named Executive Officer, assuming termination of employment at the earliest unreduced benefit age. The earliest unreduced benefit ages are different for each NEO based on employment agreement provisions and years of service, as follows: Mr. Shivery: immediately; Mr. McHale: age 55; Mr. Olivier: immediately; and Mr. Butler: age 62. The benefit is payable as an annuity, and the present value was calculated as described in Notes 1 and 2 to the Pension Benefits Table appearing above.
(6)
Represents the actuarial present values at the end of 2010 of the amounts payable to the Named Executive Officers under the assumptions discussed in note 5, solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon disability termination were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,921,334, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon disability termination. Mr. Shivery’s benefit would be paid as an annuity calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.
(7)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2010.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2010 of providing post-employment welfare benefits to Mr. Shivery beyond those benefits that would be provided to a nonexecutive employee upon disability termination. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. To the extent these benefits are provided in excess of those provided to employees in general, Mr. Shivery would receive payments to offset the taxes incurred on such benefits.
V.
Post-Employment Compensation: Death
Type of Payment |
| Shivery ($) |
| McHale ($) |
| Olivier ($) |
| Butler ($) |
| Robb ($) |
Incentive Programs |
|
|
|
|
|
|
|
|
|
|
Annual Incentives (1) |
| 1,987,200 |
| 608,517 |
| 601,494 |
| 458,320 |
| 339,000 |
Performance Cash (2)
|
| 4,486,734 |
| 788,433 |
| 759,313 |
| 627,782 |
| 411,329 |
Performance Shares (3) |
| 2,620,237 |
| 316,666 |
| 331,742 |
| 245,492 |
| 160,855 |
RSUs (4) |
| 12,845,657 |
| 2,698,191 |
| 2,266,080 |
| 2,266,531 |
| 1,229,085 |
Pension and Deferred Compensation |
|
|
|
|
|
|
|
|
|
|
Supplemental Plan (5) |
| 3,313,827 |
| 5,407,021 |
| ― |
| 738,452 |
| ― |
Special Retirement Benefit (6) |
| 1,216,610 |
| ― |
| 2,571,862 |
| ― |
| ― |
Deferral Plan (7) |
| 533,244 |
| 17,862 |
| 1,477,901 |
| 24,345 |
| 121,891 |
Other Benefits |
|
|
|
|
|
|
|
|
|
|
Health and Welfare Benefits (8) |
| 60,235 |
| ― |
| ― |
| ― |
| ― |
Perquisites |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payments |
|
|
|
|
|
|
|
|
|
|
Excise Tax & Gross-Up |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payment for Non-Compete |
| ― |
| ― |
| ― |
| ― |
| ― |
Separation Payment for Liquidated |
| ― |
| ― |
| ― |
| ― |
| ― |
Total |
| 27,063,744 |
| 9,836,690 |
| 8,008,392 |
| 4,360,922 |
| 2,262,160 |
(1)
Represents the actual 2010 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis above.
(2)
Represents the actual performance cash award under the 2008– 2010 Long-Term Incentive Program determined as described in the Compensation Discussion and Analysis above, plus performance cash awards at target under each of the 2009 – 2011 Long-Term Incentive Program and the 2010 – 2012 Long-Term Incentive Program prorated for time worked in each three-year performance period.
(3)
Represents the performance share award at target under the 2009 – 2011 and 2010 – 2012 Long-Term Incentive Programs prorated for time worked in the three-year performance period, as described in the Compensation Discussion and Analysis above.
(4)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs and NU’s retention program that, as of the end of 2010, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination upon death, and time worked during the vesting period. Under NU’s retention program, RSUs vest fully upon termination on account of death of the Named Executive Officer. The values were calculated by multiplying the number of RSUs by $31.88, the closing price of NU common shares on December 31, 2010.
192
(5)
Represents the lump sum present value of pension payments from the Supplemental Plan to the surviving spouse of each Named Executive Officer. The benefits are payable as annuities, and the present values are calculated as described in Notes 1 and 2 to the Pension Benefits Table appearing above.
(6)
Represents the actuarial present values at the end of 2010 of the amounts payable to the surviving spouses of the Named Executive Officers, solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon death were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,921,334, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier’s spouse upon death. Pension amounts reflected in the table are present values at the end of 2010 of benefits payable immediately to each Named Executive Officer’s surviving spouse. Mr. Shivery’s benefit would be paid as an annuity calculated as descr ibed in Notes 1 and 2 to the Pension Benefits Table appearing above.
(7)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2010.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2010 of providing post-employment welfare benefits to the Mr. Shivery’s surviving spouse beyond those benefits that would be provided to a nonexecutive employee’s spouse upon the employee’s death. Mr. Shivery’s surviving spouse is entitled to receive retiree health benefits under Mr. Shivery’s employment agreement. To the extent these benefits are taxable to Mr. Shivery’s surviving spouse, she would receive payments to offset the taxes incurred on such benefits.
Payments Made Upon a Change of Control
The employment or other agreements with Messrs. McHale, Olivier, Butler, and Robb include change of control benefits. Mr. Olivier participates in the SSP, which provides benefits upon termination of employment in connection with a change of control. The employment agreements and the SSP are binding on NU and on certain of NU’s majority-owned subsidiaries, including CL&P. The terms of the various employment agreements are substantially similar, except for the agreement with Mr. Olivier, which refers instead to the change of control provisions of the SSP, and the agreement with Mr. Robb.
Pursuant to the employment or other agreements and under the terms of the SSP, if an executive officer’s employment terminates following a change of control, other than termination of employment for "cause" (as defined in the employment agreements, generally meaning willful and continued failure to perform his duties after written notice, a violation of NU’s Standards of Business Conduct or conviction of a felony), or by reason of death or disability), or if the executive officer terminates his or her employment for "good reason" (as defined in the employment agreements, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control), then the executive officer will receive the benefits listed below, which receipt is conditioned upon delivery of a binding release of all legal claims against the NU and its subsidiaries:
·
A lump sum severance payment of two-times (one-times for Mr. Olivier and one-half times for Mr. Robb) the sum of the executive’s base salary plus all annual awards that would be payable for the relevant year determined at target (Base Compensation);
·
As consideration for a non-competition and non-solicitation covenant, a lump sum payment in an amount equal to the Base Compensation (one-half times Base Compensation for Mr. Robb);
·
Active health benefits continuation, provided for three years (two years for Mr. Olivier, none for Mr. Robb);
·
Benefits as if provided under the Supplemental Plan, notwithstanding eligibility requirements for the Target Benefit, including favorable actuarial reductions and the addition of three years to the executive’s age and years of service as compared to benefits available upon voluntary termination of employment (except for Mr. Olivier, whose benefits are described below, and Mr. Robb, who does not participate in the Supplemental Plan);
·
Automatic vesting and distribution in respect of all unvested RSUs and all performance units at target; and
·
A lump sum payment in an amount equal to the excise tax charged to the executive under the Internal Revenue Code as a result of the receipt of any change of control payments, plus tax gross-up (except for Mr. Olivier and Mr. Robb).
The summaries of the employment agreements above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the employment agreements, copies of which have been filed as exhibits to this Annual Report on Form 10-K .
193
VI.
Post-Employment Compensation: Termination Following a Change of Control
Type of Payment |
| Shivery ($) |
| McHale ($) |
| Olivier ($) |
| Butler ($) |
| Robb ($) |
Incentive Programs |
|
|
|
|
|
|
|
|
|
|
Annual Incentives (1) |
| 1,987,200 |
| 608,517 |
| 601,494 |
| 458,320 |
| 339,000 |
Performance Cash (2)
|
| 4,486,734 |
| 1,116,550 |
| 1,103,064 |
| 882,154 |
| 577,987 |
Performance Shares (3) |
| 2,620,237 |
| 664,557 |
| 696,193 |
| 515,186 |
| 337,573 |
RSUs (4) |
| 12,845,657 |
| 974,757 |
| 1,064,198 |
| 980,290 |
| 791,210 |
Pension and Deferred Compensation |
|
|
|
|
|
|
|
|
|
|
Supplemental Plan (5) |
| 6,553,109 |
| 1,355,288 |
| ― |
| 611,833 |
| ― |
Special Retirement Benefit (6) |
| 2,405,851 |
| 3,831,993 |
| 2,481,374 |
| 3,043,307 |
| ― |
Deferral Plan (7) |
| 533,244 |
| 17,862 |
| 1,477,901 |
| 24,345 |
| 121,891 |
Other Benefits |
|
|
|
|
|
|
|
|
|
|
Health and Welfare Benefits (8) |
| 101,181 |
| 98,890 |
| 20,053 |
| 86,064 |
| ― |
Perquisites (9) |
| ― |
| 8,500 |
| ― |
| 8,500 |
| ― |
Separation Payments |
|
|
|
|
|
|
|
|
|
|
Excise Tax & Gross-Up (10) |
| ― |
| 4,001,955 |
| ― |
| 2,767,501 |
| ― |
Separation Payment for Non-Compete |
| ― |
| 866,251 |
| 907,501 |
| 671,531 |
| 300,000 |
Separation Payment for Liquidated |
| ― |
| 1,732,501 |
| 907,501 |
| 1,343,062 |
| 300,000 |
Total |
| 31,533,213 |
| 15,277,621 |
| 9,259,279 |
| 11,392,093 |
| 2,767,661 |
(1)
Represents the actual 2010 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis above.
(2)
Represents the actual performance cash award under the 2008 – 2010 Long-Term Incentive Program for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis above, plus performance cash awards at target for each Named Executive Officer under each of the 2009 – 2011 Long-Term Incentive Program and the 2010 – 2012 Long-Term Incentive Program.
(3)
Represents the performance share award at target for each Named Executive Officer under the 2009 – 2011 and 2010 – 2012 Long-Term Incentive Programs, determined as described in the Compensation Discussion and Analysis above.
(4)
Represents values of all RSUs granted to the Named Executive Officers under NU’s long-term incentive programs and NU’s retention program that, as of the end of 2010, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest fully on termination following a change of control. Under NU’s retention program, RSUs vest fully upon termination without cause of the Named Executive Officers and the value is reduced by any separation payments as described in footnotes 11 and 12. For Messrs. McHale, Olivier, and Butler, retention pool RSU grants are fully eliminated when offset by separation payments. The values were calculated by multiplying the number of RSUs by $31.88, the closing price of NU common shares on December 31, 2010.
(5)
Represents the actuarial present value at the end of 2010 of the benefit payable from the Supplemental Plan to Messrs. Shivery, McHale, and Butler upon termination. The benefit is payable as an annuity, and the present value was calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.
(6)
Represents the actuarial present values at the end of 2010 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreements with Messrs. McHale and Butler, pension benefits available upon termination following a Change of Control were calculated with the addition of three years of age and service. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon retirement were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Butler, the value of the Supplemental Plan and Special Retirement Benefits will be paid as a single lump sum rather than as an annuity if his termination date occurs within two years following a change in control that qualifies under Section 1.409A of the Treasury Regulations. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,921,334, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon termination following a Change in Control. Pension amounts reflected in the table are present values at the end of 2010 of benefits payable to each Named Executive Officer upon termination Except for the benefits payable to Messrs. Butler and Olivier, all benefits are annuities calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.
(7)
Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2010.
(8)
Represents the costs to the company estimated by NU’s benefits consultants as of the end of 2010 of providing post-employment welfare benefits to the Named Executive Officers beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Each of Messrs. McHale and Butler is entitled to receive active health and welfare
194
benefits and the cash value of company-paid active long-term disability and life insurance benefits for three years under the terms of his respective employment agreement, plus tax gross-up with respect to such taxable subsidized coverage and are eligible for qualified benefits under NU’s retiree health plan. Mr. Olivier participates in the SSP and is eligible for two years of active health benefits continuation and is eligible for qualified benefits under NU’s retiree health plan. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. Therefore, the amount reported in the table for Mr. McHale represents (a) the value of 36 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) tax gross-up payments thereon. The amount reported in the table for Mr. Butler represents (a) the value of 36 month s of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) tax gross-up payments thereon, less (c) the value of 12 months of retiree health coverage at retiree rates. The amount reported in the table for Mr. Olivier represents (a) the value of 24 months of employer contributions toward active health benefits, plus (b) tax gross-up payments thereon, less (c) the value of 24 months of retiree health coverage at retiree rates. The amount reported in the table for Mr. Shivery represents (a) the value of lifetime retiree health coverage, plus (b) tax gross-up payments thereon.
(9)
Represents the cost of reimbursing fees for financial planning and tax preparation services to Messrs. McHale and Butler for three years.
(10)
Represents payments made to offset costs to Messrs. McHale and Butler associated with certain excise taxes under Section 280G of the Internal Revenue Code. Employees may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a termination following a Change of Control that exceed specified Internal Revenue Service limits. Employment agreements with each Named Executive Officer except Mr. Olivier and Mr. Robb provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on the Section 280G excise tax rate of 20 percent, the statutory federal income tax withholding rate of 35 percent, the Connecticut state income tax rate of 6.5 percent, and the Medicare tax rate of 1.45 percent.
(11)
Represents payments made as consideration for each Named Executive Officer’s agreement not to compete with the company following termination of employment. This payment equals the sum (one-half of the sum for Mr. Robb) of the actual base salary paid in 2010 (2009 for Mr. Robb) plus annual incentive award at target. Agreements with each Named Executive Officer provide for a lump-sum payment equal to their annual salary plus their annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
(12)
Represents severance payments to each Named Executive Officer paid in addition to the non-compete agreement payments described in note (11). For Messrs. McHale, and Butler, this payment equals two-times the sum of the actual base salary paid in 2010 plus annual incentive award at target. For Mr. Olivier, this payment equals the sum of the actual base salary paid in 2010 plus annual incentive award at target. For Mr. Robb this payment equals one-half of the sums of his actual base salary paid in 2009 plus annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
NU
In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Common Share Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 30, 2011.
PSNH and WMECO
Certain information required by this Item 12 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
195
CL&P
NU owns 100 percent of the outstanding common stock of CL&P. The following table sets forth, as of February 22, 2011, the beneficial ownership of the equity securities of NU by (i) the Chief Executive Officer of CL&P and the executive officers of CL&P listed on the Summary Compensation Table in Item 11 and (ii) all of the current executive officers and directors of CL&P, as a group. No equity securities of CL&P are owned by any of the directors or executive officers of CL&P.
|
| Amount and Nature of Beneficial Ownership(1) | ||||||||
|
| NU |
| Options(2) |
| Total |
| Percent |
| Restricted |
Leon J. Olivier, CEO, Director(5) |
| 32,895 |
| - |
| 32,895 |
| * |
| 91,120 |
David R. McHale, CFO, Director(5)(7) |
| 35,790 |
| - |
| 35,790 |
| * |
| 101,674 |
Gregory B. Butler, Senior Vice President and General |
| 47,955 |
| - |
|
|
| * |
| 84,399 |
James B. Robb, Director(5) |
| 8,668 |
| - |
| 8,668 |
| * |
| 47,774 |
Charles W. Shivery, Chairman, Director(5)(8) |
| 54,350 |
| 29,024 |
| 83,374 |
| * |
| 512,518 |
All directors and Executive Officers as a Group (7 persons) |
| 199,800 |
| 29,024 |
| 227,007 |
| * |
| 859,267 |
*Less than 1 percent of common shares outstanding.
(1)
The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as note below.
(2)
Reflects common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 22, 2011.
(3)
Includes unissued common shares consisting of performance shares restricted share units, deferred restricted share units and/or deferred shares, including dividend equivalents, as to which none of the individuals has voting or investment power. Also includes phantom common shares, representing employer matching contributions distributable only in cash, held by executive officers who participate in our Deferred Compensation Plan for Executives. Accordingly, these securities have been excluded from the "Total" column.
(4)
Includes 44,251 shares owned jointly by Mr. Butler and his spouse with whom he shares voting and investment power.
(5)
Includes common shares held in the 401(k) Plan in the employer stock ownership plan account over which the holder has sole voting and investment power (Mr. Butler: 3,264 shares; Mr. McHale: 3,967 shares; Mr. Olivier: 1,887 shares; Mr. Robb: 649 shares; and Mr. Shivery: 2,021 shares).
(6)
Includes common shares held as units in the 401(k) Plan invested in the NU Common Shares Fund over which the holder has sole voting and investment power (Mr. Butler: 439 shares; and Mr. McHale: 1,817 shares).
(7)
Includes 112 shares held by Mr. McHale in the 401(k) Plan TRAESOP/PAYSOP account over which Mr. McHale has sole voting and investment power.
(8)
Includes 1,500 shares owned jointly by Mr. Shivery and his spouse with whom he shares voting and investment power.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth the number of NU common shares issuable under NU equity compensation plans, as well as their weighted exercise price, as of December 31, 2010, in accordance with the rules of the SEC:
Plan Category |
| Number of |
| Weighted-average |
| Number of securities |
Equity compensation plans approved by |
| 1,375,637 |
| $ 18.80 |
| 4,001,028 |
Equity compensation plans not approved by |
| - |
| - |
| - |
Total |
| 1,375,637 |
| $ 18.80 |
| 4,001,028 |
(a)
Includes 112,599 common shares to be issued upon exercise of options, 1,014,479 common shares for distribution of restricted share units, and 248,559 performance shares issuable at target, all pursuant to the terms of our Incentive Plan.
(b)
The weighted-average exercise price in Column (b) does not take into account restricted share units or performance shares, which have no exercise price.
(c)
Includes 932,178 common shares issuable under our Employee Share Purchase Plan II.
(d)
All of our current compensation plans under which equity securities of NU are authorized for issuance have been approved by NU’s shareholders.
196
Item 13.
Certain Relationships and Related Transactions, and Director Independence
NU
Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Certain Relationships and Related Transactions" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 30, 2011.
PSNH and WMECO
Certain information required by this Item 13 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
CL&P
NU’s Code of Ethics for Senior Financial Officers applies to the Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) of CL&P and certain other NU subsidiaries. Under the Code, one’s position as a Senior Financial Officer in the company may not be used to improperly benefit such officer or his or her family or friends. Under the Code, specific activities that may be considered conflicts of interest include, but are not limited to, directly or indirectly acquiring or retaining a significant financial interest in an organization that is a customer, vendor or competitor, or that seeks to do business with the company; serving, without proper safeguards, as an officer or director of, or working or rendering services for an organization that is a customer, vendor or competitor, or that seeks to do business with the company. Waivers of the provisions of the Code of Ethics for Trus tees, executive officers or directors must be approved by NU’s Board of Trustees. Any such Waivers will be disclosed pursuant to legal requirements.
NU’s Standards of Business Conduct, which applies to all Trustees, directors, officers and employees of NU and its subsidiaries, including CL&P, contains a Conflict of Interest Policy that requires all such individuals to disclose any potential conflicts of interest. Such individuals are expected to discuss their particular situations with management to ensure appropriate steps are in place to avoid a conflict of interest. All disclosures must be reviewed and approved by management to ensure a particular situation does not adversely impact the individual’s primary job and role.
NU’s Related Party Transactions Policy is administered by the Corporate Governance Committee of NU’s Board of Trustees. The Policy generally defines a "Related Party Transaction" as any transaction or series of transactions in which (i) NU or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any "Related Party" has a direct or indirect material interest. A "Related Party" is defined as any Trustee or nominee for Trustee, any executive officer, any shareholder owning more than 5 percent of NU's total outstanding shares, and any immediate family member of any such person. Management submits to the Corporate Governance Committee for consideration any Related Party Transaction into which NU or a subsidiary proposes to enter. The Corporate Governance Committee recommends to the NU Board of Trustees for approval only those transactions th at are in NU’s best interests. If management causes the company to enter into a Related Party Transaction prior to approval by the Corporate Governance Committee, the transaction will be subject to ratification by the NU Board of Trustees. If the NU Board of Trustees determines not to ratify the transaction, then management will make all reasonable efforts to cancel or annul such transaction.
The directors of CL&P are employees of CL&P and/or other subsidiaries of NU and thus are not considered independent.
Item 14.
Principal Accountant Fees and Services
NU
Incorporated herein by reference is the information contained in the section "Relationship with Independent Auditors" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 30, 2011.
CL&P, PSNH and WMECO
Pre-Approval of Services Provided by Principal Auditors
None of CL&P, PSNH or WMECO is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit Committee of NU’s Board of Trustees. NU’s Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the NU Audit Committee Chair and/or Vice Chair provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the NU Audit Committee at the next regularly scheduled meeting of the Committee.
The following relates to fees and services for the entire NU system, including NU, CL&P, PSNH and WMECO.
197
Fees Paid to Principal Auditor
NU and its subsidiaries paid Deloitte & Touche LLP fees aggregating $3,697,371 and $2,727,410 for the years ended December 31, 2010 and 2009, respectively, comprised of the following:
1.
Audit Fees
The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the Deloitte Entities), for audit services rendered for the years ended December 31, 2010 and 2009 totaled $2,713,150 and $2,636,775, respectively. The audit fees were incurred for audits of NU’s annual consolidated financial statements and those of its subsidiaries, reviews of financial statements included in NU’s Quarterly Reports on Form 10-Q and those of its subsidiaries, comfort letters, consents and other costs related to registration statements and financings. Audit fees in 2010 also included consents and other procedures related to a well-known seasoned issuer registration statement on Form S-3 and NU’s registration statement on Form S-4 filed to registered common shares to be issued in the proposed merger with NSTAR. The fees also included audits of internal controls over financial reporting as of December 31, 2010 and 2009, as well as auditing the implementation of new accounting standards and the accounting for new contracts and proposed transactions.
2.
Audit Related Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2010 and 2009 totaled $480,186 and $66,000, respectively. Audit related fees in 2010 related to advisory services in connection with the preliminary readiness assessment for IFRS ($40,000) and accounting and tax due diligence procedures related to the proposed merger with NSTAR ($396,186). Audit related fees in 2010 and 2009 were also related to the examination of management’s assertions about the securitization subsidiaries of CL&P, PSNH and WMECO.
3.
Tax Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2010 and 2009 totaled $52,535 and $23,135, respectively. These services related primarily to the reviews of tax returns and reviewing the tax impacts of proposed transactions in 2010 and 2009, plus tax advice on the partnership agreement for NPT, the related TSA and certain transmission asset sales agreements in 2010.
4.
All Other Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for services other than the services described above for the years ended December 31, 2010 and 2009 totaled $451,500 and $1,500, respectively. All other fees in 2010 consisted primarily of advisory services related to the Company's consideration of a business for enterprise resource planning. All other fees in 2010 and 2009 also included a license fee for access to an accounting research tool.
The Audit Committee of NU’s Board of Trustees pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for NU and its subsidiaries by the independent auditors, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit. The Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. During 2010, all services described above were pre-approved by the Audit Committee.
The Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining auditor independence and has concluded that the Deloitte Entities were and are independent of NU and its subsidiaries in all respects.
198
PART IV
Item 15.
Exhibits and Financial Statement Schedules
(a) | 1. | Financial Statements: | ||
The financial statements filed as part of this Annual Report on Form 10-K are set forth under Item 8, "Financial Statements and Supplementary Data." Reference is made to the index on page 72. | ||||
2. | Schedules | |||
I. | Financial Information of Registrant: | S-1 | ||
Northeast Utilities (Parent) Statements of Income for the Years Ended | S-2 | |||
Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended | S-3 | |||
II. | Valuation and Qualifying Accounts and Reserves for NU, CL&P, PSNH and WMECO for 2010, 2009 and 2008 | S-4 | ||
All other schedules of the companies for which inclusion is required in the applicable regulations of the SEC are permitted to be omitted under the related instructions or are not applicable, and therefore have been omitted. | ||||
3. | Exhibit Index | E-1 |
199
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS AT DECEMBER 31, 2008 AND 2007 (Thousands of Dollars) | ||||
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
| 2008 |
| 2007 |
ASSETS |
|
|
|
|
Current Assets: |
|
|
|
|
Cash |
| $ 1,294 |
| $ 294 |
Notes receivable from affiliated companies |
| 304,704 |
| 115,600 |
Accounts receivable |
| 2,757 |
| 452 |
Accounts receivable from affiliated companies |
| 1,221 |
| 4,690 |
Taxes receivable |
| 4,932 |
| 6,971 |
Derivative assets - current |
| - |
| 5,133 |
Prepayments and other |
| 378 |
| 119 |
|
| 315,286 |
| 133,259 |
Deferred Debits and Other Assets: |
|
|
|
|
Investments in subsidiary companies, at equity |
| 3,551,308 |
| 3,235,694 |
Accumulated deferred income taxes |
| 25,425 |
| 21,058 |
Derivative assets - long-term |
| 20,827 |
| - |
Other |
| 18,676 |
| 18,153 |
|
| 3,616,236 |
| 3,274,905 |
Total Assets |
| $ 3,931,522 |
| $ 3,408,164 |
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
Current Liabilities: |
|
|
|
|
Notes payable to banks |
| $ 303,519 |
| $ 42,000 |
Long-term debt - current portion |
| - |
| 150,000 |
Accounts payable |
| 7 |
| 27 |
Accounts payable to affiliated companies |
| 35,515 |
| 1,743 |
Accrued interest |
| 5,972 |
| 5,180 |
Other |
| 422 |
| 425 |
|
| 345,435 |
| 199,375 |
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
Other |
| 32,031 |
| 27,811 |
|
| 32,031 |
| 27,811 |
Capitalization: |
|
|
|
|
Long-Term Debt |
| 533,744 |
| 267,143 |
Common shares, $5 par value - authorized |
|
|
|
|
225,000,000 shares; 176,212,275 shares issued |
|
|
|
|
and 155,834,361 shares outstanding in 2008 and |
|
|
|
|
175,924,694 shares issued and 155,079,770 shares |
|
|
|
|
outstanding in 2007 |
| 881,061 |
| 879,623 |
Capital surplus, paid in |
| 1,475,006 |
| 1,465,946 |
Deferred contribution plan - employee stock |
|
|
|
|
ownership plan |
| (15,481) |
| (26,352) |
Retained earnings |
| 1,078,594 |
| 946,792 |
Accumulated other comprehensive (loss)/income |
| (37,265) |
| 9,359 |
Treasury stock, 19,708,136 shares in 2008 |
|
|
|
|
and 19,705,545 shares in 2007 |
| (361,603) |
| (361,533) |
Common Shareholders' Equity |
| 3,020,312 |
| 2,913,835 |
Total Capitalization |
| 3,554,056 |
| 3,180,978 |
Total Liabilities and Capitalization |
| $ 3,931,522 |
| $ 3,408,164 |
|
|
|
|
|
|
|
|
|
|
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTHEAST UTILITIES |
(Registrant) |
By | /s/ Charles W. Shivery | Date | |
Charles W. Shivery | |||
Chairman of the Board, | February 25, 2011 | ||
President and Chief Executive Officer | |||
(Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Charles W. Shivery | Chairman of the Board, President and Chief | February 25, 2011 | ||
Charles W. Shivery | Executive Officer, and a Trustee | |||
(Principal Executive Officer) | ||||
/s/ David R. McHale | Executive Vice President and | February 25, 2011 | ||
David R. McHale | ||||
/s/ Jay S. Buth | Vice President - Accounting and Controller | February 25, 2011 | ||
Jay S. Buth | ||||
/s/ Richard H. Booth | Trustee | February 25, 2011 | ||
Richard H. Booth | ||||
/s/ John S. Clarkeson | Trustee | February 25, 2011 | ||
John S. Clarkeson | ||||
/s/ Cotton M. Cleveland | Trustee | February 25, 2011 | ||
Cotton M. Cleveland | ||||
/s/ Sanford Cloud, Jr. | Trustee | February 25, 2011 | ||
Sanford Cloud, Jr. | ||||
/s/ John F. Swope | Trustee | February 25, 2011 | ||
John F. Swope | ||||
/s/ Robert E. Patricelli | Trustee | February 25, 2011 | ||
Robert E. Patricelli | ||||
/s/ John G. Graham | Trustee | February 25, 2011 | ||
John G. Graham | ||||
/s/ Elizabeth T. Kennan | Trustee | February 25, 2011 | ||
Elizabeth T. Kennan | ||||
200
/s/ Kenneth R. Leibler | Trustee | February 25, 2011 | ||
Kenneth R. Leibler | ||||
/s/ Dennis R. Wraase | Trustee | February 25, 2011 | ||
Dennis R. Wraase |
201
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY |
(Registrant) |
By | /s/ Leon J. Olivier | Date | |
Leon J. Olivier | |||
Chief Executive Officer | February 25, 2011 | ||
(Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Charles W. Shivery | Chairman and a Director | February 25, 2011 | ||
Charles W. Shivery | ||||
/s/ Leon J. Olivier | Chief Executive Officer and a Director | February 25, 2011 | ||
Leon J. Olivier | (Principal Executive Officer) | |||
/s/ Jeffrey D. Butler | President and Chief Operating Officer | February 25, 2011 | ||
Jeffrey D. Butler | and a Director | |||
/s/ David R. McHale | Executive Vice President and Chief Financial | February 25, 2011 | ||
David R. McHale | Officer and a Director | |||
(Principal Financial Officer) | ||||
/s/ Gregory B. Butler | Director | February 25, 2011 | ||
Gregory B. Butler | ||||
/s/ Jean M. LaVechhia | Director | February 25, 2011 | ||
Jean M. LaVecchia | ||||
/s/ James B. Robb | Director | February 25, 2011 | ||
James B. Robb | ||||
/s/ Jay S. Buth | Vice President - Accounting and Controller | February 25, 2011 | ||
Jay S. Buth | ||||
202
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE |
(Registrant) |
By | /s/ Leon J. Olivier | Date | |
Leon J. Olivier | |||
Chief Executive Officer | February 25, 2011 | ||
(Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Charles W. Shivery | Chairman and a Director | February 25, 2011 | ||
Charles W. Shivery | ||||
/s/ Leon J. Olivier | Chief Executive Officer and a Director | February 25, 2011 | ||
Leon J. Olivier | (Principal Executive Officer) | |||
/s/ Gary A. Long | President and Chief Operating Officer | February 25, 2011 | ||
Gary A. Long | and a Director | |||
/s/ David R. McHale | Executive Vice President and Chief Financial | February 25, 2011 | ||
David R. McHale | Officer and a Director | |||
(Principal Financial Officer) | ||||
/s/ Gregory B. Butler | Director | February 25, 2011 | ||
Gregory B. Butler | ||||
/s/ Jean M. LaVecchia | Director | February 25, 2011 | ||
Jean M. LaVecchia | ||||
/s/ James B. Robb | Director | February 25, 2011 | ||
James B. Robb | ||||
/s/ Jay S. Buth | Vice President - Accounting and Controller | February 25, 2011 | ||
Jay S. Buth |
203
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
(Registrant) |
By | /s/ Leon J. Olivier | Date | |
Leon J. Olivier | |||
Chief Executive Officer | February 25, 2011 | ||
(Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Charles W. Shivery | Chairman and a Director | February 25, 2011 | ||
Charles W. Shivery | ||||
/s/ Leon J. Olivier | Chief Executive Officer and a Director | February 25, 2011 | ||
Leon J. Olivier | (Principal Executive Officer) | |||
/s/ Peter J. Clarke | President and Chief Operating Officer | February 25, 2011 | ||
Peter J. Clarke | and a Director | |||
/s/ David R. McHale | Executive Vice President and Chief Financial | February 25, 2011 | ||
David R. McHale | Officer and a Director | |||
(Principal Financial Officer) | ||||
/s/ Gregory B. Butler | Director | February 25, 2011 | ||
Gregory B. Butler | ||||
/s/ Jean M. LaVecchia | Director | February 25, 2011 | ||
Jean M. LaVecchia | ||||
/s/ James B. Robb | Director | February 25, 2011 | ||
James B. Robb | ||||
/s/ Jay S. Buth | Vice President - Accounting and Controller | February 25, 2011 | ||
Jay S. Buth |
204
SCHEDULE I | ||||
NORTHEAST UTILITIES (PARENT) | ||||
FINANCIAL INFORMATION OF REGISTRANT | ||||
BALANCE SHEETS | ||||
AS OF DECEMBER 31, 2010 AND 2009 | ||||
(Thousands of Dollars) | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2010 |
| 2009 |
ASSETS |
|
|
|
|
Current Assets: |
|
|
|
|
Cash |
| $ 268 |
| $ 1,222 |
Notes Receivable from Affiliated Companies |
| 132,600 |
| 186,213 |
Accounts Receivable |
| 2,885 |
| 3,150 |
Accounts Receivable from Affiliated Companies |
| 1,163 |
| 1,689 |
Taxes Receivable |
| 18,139 |
| 2,838 |
Prepayments and Other Current Assets |
| 18,021 |
| 6,837 |
Total Current Assets |
| 173,076 |
| 201,949 |
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
Investments in Subsidiary Companies, at Equity |
| 4,323,455 |
| 3,928,090 |
Notes Receivable from Affiliated Companies |
| 62,500 |
| 62,500 |
Accumulated Deferred Income Taxes |
| 23,288 |
| 31,503 |
Derivative Assets |
| 4,099 |
| 6,520 |
Other Long-Term Assets |
| 8,179 |
| 16,971 |
Total Deferred Debits and Other Assets |
| 4,421,521 |
| 4,045,584 |
|
|
|
|
|
Total Assets |
| $ 4,594,597 |
| $ 4,247,533 |
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
Current Liabilities: |
|
|
|
|
Notes Payable to Banks |
| $ 237,000 |
| $ 100,313 |
Accounts Payable |
| 179 |
| - |
Accounts Payable to Affiliated Companies |
| 411 |
| - |
Accrued Taxes |
| 3,616 |
| 1,162 |
Accrued Interest |
| 8,024 |
| 6,112 |
Other |
| 1,145 |
| 408 |
Total Current Liabilities |
| 250,375 |
| 107,995 |
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
Other |
| 6,776 |
| 35,442 |
Total Deferred Credits and Other Liabilities |
| 6,776 |
| 35,442 |
|
|
|
|
|
Capitalization: |
|
|
|
|
Long-Term Debt |
| 524,813 |
| 526,194 |
|
|
|
|
|
Equity: |
|
|
|
|
Common Shareholders' Equity: |
|
|
|
|
Common Shares |
| 978,909 |
| 977,276 |
Capital Surplus, Paid in |
| 1,777,592 |
| 1,762,097 |
Deferred Contribution Plan |
| - |
| (2,944) |
Retained Earnings |
| 1,452,777 |
| 1,246,543 |
Accumulated Other Comprehensive Loss |
| (43,370) |
| (43,467) |
Treasury Stock |
| (354,732) |
| (361,603) |
Common Shareholders' Equity |
| 3,811,176 |
| 3,577,902 |
Noncontrolling Interests |
| 1,457 |
| - |
Total Equity |
| 3,812,633 |
| 3,577,902 |
Total Capitalization |
| 4,337,446 |
| 4,104,096 |
|
|
|
|
|
Total Liabilities and Capitalization |
| $ 4,594,597 |
| $ 4,247,533 |
|
|
|
|
|
|
|
|
|
|
|
S-1
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006 (Thousands of Dollars, Except Share Information) | |||||||
|
| ||||||
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
|
| 2008 |
| 2007 |
| 2006 | |
|
|
|
|
|
|
| |
Operating Revenues |
| $ - |
| $ - |
| $ - | |
|
|
|
|
|
|
| |
Operating Expenses: |
|
|
|
|
|
| |
Other |
| 53,484 |
| 3,786 |
| 4,063 | |
Operating Loss |
| (53,484) |
| (3,786) |
| (4,063) | |
Interest Expense |
| 30,893 |
| 27,993 |
| 32,945 | |
Other Income: |
|
|
|
|
|
| |
Equity in earnings of subsidiaries |
| 307,908 |
| 247,786 |
| 473,279 | |
Other, net |
| 6,956 |
| 30,516 |
| 29,493 | |
Other Income, Net |
| 314,864 |
| 278,302 |
| 502,772 | |
Income Before Income Tax (Benefit)/Expense |
| 230,487 |
| 246,523 |
| 465,764 | |
Income Tax (Benefit)/Expense |
| (30,341) |
| 40 |
| (4,814) | |
Net Income |
| $ 260,828 |
| $ 246,483 |
| $ 470,578 | |
|
|
|
|
|
|
| |
Basic Earnings Per Common Share |
| $ 1.68 |
| $ 1.59 |
| $ 3.06 | |
|
|
|
|
|
|
| |
Fully Diluted Earnings Per Common Share |
| $ 1.67 |
| $ 1.59 |
| $ 3.05 | |
|
|
|
|
|
|
| |
Basic Common Shares Outstanding (weighted average) |
| 155,531,846 |
| 154,759,727 |
| 153,767,527 | |
Fully Diluted Common Shares Outstanding (weighted average) |
| 155,999,240 |
| 155,304,361 |
| 154,146,669 | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
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| |
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|
SCHEDULE I | ||||
NORTHEAST UTILITIES (PARENT) | ||||
FINANCIAL INFORMATION OF REGISTRANT | ||||
STATEMENTS OF INCOME | ||||
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008 | ||||
(Thousands of Dollars, Except Share Information) | ||||
|
| 2010 |
| 2009 |
| 2008 |
|
|
|
|
|
|
|
Operating Revenues |
| $ - |
| $ - |
| $ - |
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
Other |
| 21,081 |
| 3,251 |
| 53,484 |
Operating Loss |
| (21,081) |
| (3,251) |
| (53,484) |
Interest Expense |
| 12,058 |
| 29,678 |
| 30,893 |
|
|
|
|
|
|
|
Other Income, Net: |
|
|
|
|
|
|
Equity in Earnings of Subsidiaries |
| 396,333 |
| 346,137 |
| 307,908 |
Other, Net |
| 4,536 |
| 6,511 |
| 6,956 |
Other Income, Net |
| 400,869 |
| 352,648 |
| 314,864 |
Income Before Income Tax Benefit |
| 367,730 |
| 319,719 |
| 230,487 |
Income Tax Benefit |
| (20,276) |
| (10,314) |
| (30,341) |
Net Income |
| 388,006 |
| 330,033 |
| 260,828 |
Net Income Attributable to Noncontrolling Interest |
| 57 |
| - |
| - |
Net Income Attributable to Controlling Interest |
| $ 387,949 |
| $ 330,033 |
| $ 260,828 |
|
|
|
|
|
|
|
Basic Earnings per Common Share |
| $ 2.20 |
| $ 1.91 |
| $ 1.68 |
|
|
|
|
|
|
|
Diluted Earnings per Common Share |
| $ 2.19 |
| $ 1.91 |
| $ 1.67 |
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
Basic |
| 176,636,086 |
| 172,567,928 |
| 155,531,846 |
Diluted |
| 176,885,387 |
| 172,717,246 |
| 155,999,240 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
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|
|
|
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|
|
|
|
|
|
|
S-2
`
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006 (Thousands of Dollars) | |||||
| 2008 |
| 2007 |
| 2006 |
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
|
Net income | $ 260,828 |
| $ 246,483 |
| $ 470,578 |
Adjustments to reconcile to net cash flows |
|
|
|
|
|
provided by/(used in) operating activities: |
|
|
|
|
|
Equity in earnings of subsidiaries | (307,908) |
| (247,786) |
| (473,279) |
Cash dividends received from subsidiaries | 215,162 |
| 141,891 |
| 190,759 |
Deferred income taxes | (3,164) |
| (14,324) |
| 11,582 |
Stock-based compensation expense | 13,518 |
| 13,855 |
| 14,718 |
Decrease/(increase) in other deferred debits | 108 |
| 106 |
| (9,170) |
Increase in other deferred credits | 340 |
| 1,725 |
| 1,064 |
Other adjustments | (1,390) |
| (849) |
| (815) |
Changes in current assets and liabilities: |
|
|
|
|
|
Receivables, including affiliate receivables | 883 |
| (906) |
| 4,285 |
Prepayments and other current assets | (256) |
| 3 |
| 14 |
Accounts payable, including affiliate payables | 33,752 |
| 1,446 |
| (448) |
Taxes receivable/accrued | 3,580 |
| (244,675) |
| 228,363 |
Accrued interest and other current liabilities | 2,707 |
| (444) |
| 214 |
Net cash flows provided by/(used in) operating activities | 218,160 |
| (103,475) |
| 437,865 |
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
Capital contributions to subsidiaries | (323,164) |
| (683,427) |
| (156,577) |
Return of investment in subsidiaries | 30,000 |
| 19,869 |
| 435,000 |
(Increase)/decrease in NU Money Pool lending | (84,600) |
| 871,800 |
| (595,200) |
(Increase)/decrease in notes receivable from affiliated companies | (79,504) |
| (42,000) |
| 32,000 |
Other investing activities | 1,557 |
| 1,462 |
| 2,185 |
Net cash flows (used in)/provided by investing activities | (455,711) |
| 167,704 |
| (282,592) |
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
Issuance of common shares related to shared-based compensation | 5,524 |
| 9,056 |
| 9,494 |
Cash dividends on common shares | (129,077) |
| (120,988) |
| (112,745) |
Increase/(decrease) in short-term debt | 261,519 |
| 42,000 |
| (32,000) |
Issuance of long-term debt | 250,000 |
| - |
| - |
Retirements of long-term debt | (150,000) |
| - |
| (21,000) |
Other financing activities | 585 |
| 4,206 |
| 2,379 |
Net cash flows provided by/(used in) financing activities | 238,551 |
| (65,726) |
| (153,872) |
Net increase/(decrease) in cash | 1,000 |
| (1,497) |
| 1,401 |
Cash - beginning of year | 294 |
| 1,791 |
| 390 |
Cash - end of year | $ 1,294 |
| $ 294 |
| $ 1,791 |
|
|
|
|
|
|
Supplemental Cash Flow Information: |
|
|
|
|
|
Cash paid/(received) during the year for: |
|
|
|
|
|
Interest, net of amounts capitalized | $ 27,522 |
| $ 25,580 |
| $ 32,498 |
Income taxes | $ (37,063) |
| $ 259,707 |
| $ (651) |
SCHEDULE I | |||||
NORTHEAST UTILITIES (PARENT) | |||||
FINANCIAL INFORMATION OF REGISTRANT | |||||
STATEMENTS OF CASH FLOWS | |||||
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008 | |||||
(Thousands of Dollars) | |||||
|
|
|
|
|
|
| 2010 |
| 2009 |
| 2008 |
Operating Activities: |
|
|
|
|
|
Net Income | $ 388,006 |
| $ 330,033 |
| $ 260,828 |
Adjustments to Reconcile Net Income to Net Cash |
|
|
|
|
|
Flows Provided by Operating Activities: |
|
|
|
|
|
Equity in Earnings of Subsidiaries | (396,333) |
| (346,137) |
| (307,908) |
Cash Dividends Received from Subsidiaries | 309,669 |
| 207,877 |
| 215,162 |
Deferred Income Taxes | 8,398 |
| (6,658) |
| (3,164) |
Other | 23,675 |
| 15,525 |
| 12,576 |
Changes in Current Assets and Liabilities: |
|
|
|
|
|
Receivables, Including Affiliate Receivables | 791 |
| (861) |
| 883 |
Accounts Payable, Including Affiliate Payables | 590 |
| (35,522) |
| 33,752 |
Taxes Receivable/Accrued | (28,394) |
| 5,591 |
| 3,580 |
Other Current Assets and Liabilities | (12,656) |
| 2,369 |
| 2,451 |
Net Cash Flows Provided by Operating Activities | 293,746 |
| 172,217 |
| 218,160 |
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
|
Capital Contributions to Subsidiaries | (313,560) |
| (243,688) |
| (323,164) |
Return of Investment in Subsidiaries | 5,000 |
| - |
| 30,000 |
Decrease/(Increase) in NU Money Pool Lending | 83,300 |
| 128,700 |
| (84,600) |
Increase in Notes Receivable from Affiliated Companies | (29,687) |
| (72,709) |
| (79,504) |
Other Investing Activities | 1,703 |
| 2,283 |
| 1,557 |
Net Cash Flows Used in Investing Activities | (253,244) |
| (185,414) |
| (455,711) |
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
Issuance of Common Shares | - |
| 383,295 |
| - |
Cash Dividends on Common Shares | (180,542) |
| (162,381) |
| (129,077) |
Increase/(Decrease) in Short-Term Debt | 136,687 |
| (203,206) |
| 261,519 |
Issuance of Long-Term Debt | - |
| - |
| 250,000 |
Retirements of Long-Term Debt | - |
| - |
| (150,000) |
Financing Fees | - |
| (12,457) |
| - |
Other Financing Activities | 2,399 |
| 7,874 |
| 6,109 |
Net Cash Flows (Used in)/Provided by Financing Activities | (41,456) |
| 13,125 |
| 238,551 |
Net (Decrease)/Increase in Cash | (954) |
| (72) |
| 1,000 |
Cash - Beginning of Year | 1,222 |
| 1,294 |
| 294 |
Cash - End of Year | $ 268 |
| $ 1,222 |
| $ 1,294 |
|
|
|
|
|
|
Supplemental Cash Flow Information: |
|
|
|
|
|
Cash Paid/(Received) During the Year for: |
|
|
|
|
|
Interest, Net of Amounts Capitalized | $ 22,886 |
| $ 26,744 |
| $ 27,522 |
Income Taxes | $ 1,291 |
| $ (12,848) |
| $ (37,063) |
S-3
ScheduleSCHEDULE II
NORTHEAST UTILITIES AND SUBSIDIARIES
Northeast Utilities and SubsidiariesVALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Valuation and Qualifying Accounts and Reserves
For the Years Ended DecemberFOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008 2007 and 2006
(Thousands of Dollars)
Column A |
| Column B |
| Column C |
| Column D |
| Column E | ||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||
|
|
|
| Additions |
|
|
|
| ||||||||||||||||
|
|
|
| (1) |
| (2) |
|
|
|
| ||||||||||||||
|
|
|
| Charged |
| Charged to |
|
|
|
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
NU Consolidated: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Reserves deducted from assets - reserves for uncollectible accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
2008 |
| $ | 25,529 |
| $ | 28,573 |
| $ | 81,991 |
| $ | 92,818 |
| $ | 43,275 | |||||||||
2007 |
|
| 22,369 |
|
| 29,140 |
|
| (7,106) |
|
| 18,874 |
|
| 25,529 | |||||||||
2006 (c) |
|
| 25,044 |
|
| 29,366 |
|
| 1,922 |
|
| 33,963 |
|
| 22,369 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
CL&P: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Reserves deducted from assets - reserves for uncollectible accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
2008 |
| $ | 7,874 |
| $ | 5,951 |
| $ | 81,129 |
| $ | 70,998 |
| $ | 23,956 | |||||||||
2007 |
|
| 1,679 |
|
| 18,121 |
|
| (8,243) |
|
| 3,683 |
|
| 7,874 | |||||||||
2006 |
|
| 1,982 |
|
| 13,582 |
|
| 6,470 |
|
| 20,355 |
|
| 1,679 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
PSNH: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Reserves deducted from assets - reserves for uncollectible accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
2008 |
| $ | 2,675 |
| $ | 5,661 |
| $ | 483 |
| $ | 4,654 |
| $ | 4,165 | |||||||||
2007 |
|
| 2,626 |
|
| 3,433 |
|
| 324 |
|
| 3,708 |
|
| 2,675 | |||||||||
2006 |
|
| 2,362 |
|
| 4,208 |
|
| 316 |
|
| 4,260 |
|
| 2,626 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
WMECO: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Reserves deducted from assets - reserves for uncollectible accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
2008 |
| $ | 5,699 |
| $ | 8,185 |
| $ | 234 |
| $ | 7,547 |
| $ | 6,571 | |||||||||
2007 |
|
| 5,073 |
|
| 6,922 |
|
| 155 |
|
| 6,451 |
|
| 5,699 | |||||||||
2006 |
|
| 3,653 |
|
| 5,503 |
|
| 194 |
|
| 4,277 |
|
| 5,073 |
Column A |
| Column B |
| Column C |
| Column D |
| Column E | ||||||||
|
|
|
|
|
|
|
|
| ||||||||
|
|
|
| Additions |
|
|
|
| ||||||||
|
|
|
| (1) |
| (2) |
|
|
|
| ||||||
|
|
|
| Charged |
| Charged to |
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
NU: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Reserves Deducted from Assets - Reserves for Uncollectible Accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
2010 |
| $ | 55,300 |
| $ | 31,352 |
| $ | 10,714 |
| $ | 57,569 |
| $ | 39,797 | |
2009 |
|
| 43,275 |
|
| 53,947 |
|
| 24,136 |
|
| 66,058 |
|
| 55,300 | |
2008 |
|
| 25,529 |
|
| 28,573 |
|
| 81,991 |
|
| 92,818 |
|
| 43,275 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
CL&P: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Reserves Deducted from Assets - Reserves for Uncollectible Accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
2010 |
| $ | 26,057 |
| $ | 7,484 |
| $ | 9,919 |
| $ | 26,286 |
| $ | 17,174 | |
2009 |
|
| 23,956 |
|
| 15,276 |
|
| 20,115 |
|
| 33,290 |
|
| 26,057 | |
2008 |
|
| 7,874 |
|
| 5,951 |
|
| 81,129 |
|
| 70,998 |
|
| 23,956 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
PSNH: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Reserves Deducted from Assets - Reserves for Uncollectible Accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
2010 |
| $ | 5,086 |
| $ | 8,858 |
| $ | 1,017 |
| $ | 8,137 |
| $ | 6,824 | |
2009 |
|
| 4,165 |
|
| 10,084 |
|
| 652 |
|
| 9,815 |
|
| 5,086 | |
2008 |
|
| 2,675 |
|
| 5,661 |
|
| 483 |
|
| 4,654 |
|
| 4,165 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
WMECO: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Reserves Deducted from Assets - Reserves for Uncollectible Accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
2010 |
| $ | 7,217 |
| $ | 9,747 |
| $ | 243 |
| $ | 11,232 |
| $ | 5,975 | |
2009 |
|
| 6,571 |
|
| 7,590 |
|
| 103 |
|
| 7,047 |
|
| 7,217 | |
2008 |
|
| 5,699 |
|
| 8,185 |
|
| 234 |
|
| 7,547 |
|
| 6,571 |
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b)
Amounts written off, net of recoveries. In November 2006, theThe DPUC issued an order allowing CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. AtAs of December 31, 2010, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $65 million, $6.9 million and $7.5 million, respectively. As of December 31, 2009, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $54.5 million, $9.1 million and $8.6 million, respectively. As of December 31, 2008, CL&P and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $41 million and $10 million, respectively. At December 31, 2007, CL&P and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $24 million and $8 million, respectively. At December 31, 2006, CL&P and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $17 million and $8 million, respectively.
(c)
Amounts include activity related to accounts that are classified as assets held for sale and discontinued operations.
S-4
EXHIBIT INDEX
Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith. Management contracts and compensation plans or arrangements are designated with a (+).
Exhibit
Number
Description
32.
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
(A)
Northeast Utilities
2.1
Agreement and Plan of Merger By and Among Northeast Utilities, NU Holding Energy 1 LLC, NU Holding Energy 2 LLC and NSTAR dated as of October 16, 2010 (Exhibit 2.1 Current Report on Form 8-K filed October 18, 2010, File No. 001-05324)
*2.1.1
Amendment 1 to Agreement and Plan of Merger By and Among Northeast Utilities, NU Holding Energy 1 LLC, NU Holding Energy 2 LLC and NSTAR dated as of November 1, 2010
*2.1.2
Amendment 2 to Agreement and Plan of Merger By and Among Northeast Utilities, NU Holding Energy 1 LLC, NU Holding Energy 2 LLC and NSTAR dated as of December 16, 2010
3.
Articles of Incorporation and By-Laws
(A)
Northeast Utilities
3.1
Declaration of Trust of NU, as amended through May 10, 2005 (Exhibit A.1, NU Form U-1 filed June 23, 2005, File No. 70-10315)
(B)
The Connecticut Light and Power Company
3.1
Certificate of Incorporation of CL&P, restated to March 22, 1994 (Exhibit 3.2.1, 1993 CL&P Form 10-K filed on March 25, 1994, File No. 0-00404)
3.1.1
Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996 (Exhibit 3.2.2, 1996 CL&P Form 10-K filed March 25, 1997, File No. 0-00404)001-11419)
3.1.2
Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998 (Exhibit 3.2.3, 1998 CL&P Form 10-K filed March 23, 1999, File No. 0-00404)000-00404)
3.2
By-laws of CL&P, as amended to January 1, 1997 (Exhibit 3.2.3, 1996 CL&P Form 10-K filed March 25, 1997, File No. 0-00404)001-11419)
(C)
Public Service Company of New Hampshire
3.1
Articles of Incorporation, as amended to May 16, 1991.1991 (Exhibit 3.3.1, 1993 PSNH Form 10-K filed on March 25, 1994, File No. 1-6392)001-06392)
3.2
By-laws of PSNH, as in effect June 27, 2008 (Exhibit 2,3, PSNH Form 10-Q for the Quarter Ended June 30, 2008 filed August 7, 2008, File No. 1-6392)001-06392)
(D)
Western Massachusetts Electric Company
3.1
Articles of Organization of WMECO, restated to February 23, 1995 (Exhibit 3.4.1, 1994 WMECO Form 10-K filed on March 27, 1995, File No. 0-7624)001-07624)
3.2
By-laws of WMECO, as amended to April 1, 1999 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 1999 filed August 13, 1999, File No. 0-7624)000-07624)
3.2.1
By-laws of WMECO, as further amended to May 1, 2000 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 2000 filed August 11, 2000, File No. 0-7624)000-07624)
4
E-1
4.
Instruments defining the rights of security holders, including indentures
(A)
Northeast Utilities
4.1
Indenture between NU and The Bank of New York as Trustee dated as of April 1, 2002 between NU and the Bank of New York as Trustee (Exhibit A-3, NU 35-CERT filed April 9,16, 2002, File No. 70-9535)070-09535)
4.1.1
First Supplemental Indenture between NU and The Bank of New York as Trustee dated as of April 1, 2002, between NU and the Bank of New York as Trustee, relating to $263M$263 million of Senior Notes, Series A, due 2012 (Exhibit A-4, NU 35-CERT filed April 9,16, 2002, File No. 70-9535)070-09535)
4.1.2
Third Supplemental Indenture dated as of June 1, 2008, between NU and theThe Bank of New York Trust Company N.A., as Trustee, dated as of June 1, 2008, relating to $250M$250 million of Senior Notes, Series C, due 2013, (Exhibit 4.1, to NU Current Report on Form 8-K filed June 5,10, 2008, File No. 001-5324)001-05324)
4.2
Amended and Restated Credit Agreement dated December 9, 2005 between NU, the Banks Named Therein, Union Bank, of California, N.A. as Administrative Agent, and Barclays Bank, PLC, Citibank, N.A., JPMorgan Chase Bank, N.A. and Union Bank, of California, N.A., as Fronting Banks dated September 24, 2010 (Exhibit 99.1,10, NU Current Report on Form 8-K10-Q for the Quarter Ended September 30, 2010, filed December 9, 2005,November 8, 2010, File No. 1-5324)
E-1
001-05324)
(B)
The Connecticut Light and Power Company
4.1
Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921 (Composite including all twenty-four amendments to May 1, 1967) (Exhibit 4.1.1, 1989 CL&PNU Form 10-K, File No. 0-00404)001-05324)
4.1.1
Series D Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of October 1, 1994 (Exhibit 4.2.16, 1994 CL&P Form 10-K filed on March 27, 1995, File No. 0-00404)001-11419)
4.1.2
Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee, dated as of September 1, 2004 (Exhibit 99.2, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 0-00404)000-00404)
4.1.3
Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 0-00404)000-00404)
4.2
Composite Indenture of Mortgage and Deed of Trust between CL&P and Deutsche Bank Trust Company Americas f/k/a Bankers Trust Company, dated as of May 1, 1921, as amended and supplemented by seventy-three supplemental mortgages to and including Supplemental Mortgage dated as of April 1, 2005 (Exhibit 99.5, CL&P Current Report on Form 8-K filed April 7,13, 2005, File No. 0-00404)000-00404)
4.2.1
Supplemental Indenture (2005 Series A Bonds and 2005 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 0-00404)000-00404)
4.2.2
Supplemental Indenture (2006 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2006 (Exhibit 99.2, CL&P Current Report on Form 8-K filed June 7, 2006, File No. 0-00404)000-00404)
4.2.3
Supplemental Indenture (2007 Series A Bonds and 2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2007 (Exhibit 99.2, CL&P Current Report on Form 8-K filed March 27,29, 2007, File No. 0-00404)000-00404)
4.2.4
Supplemental Indenture (2007 Series C Bonds and 2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 20062007 (Exhibit 4, CL&P Current Report on Form 8-K filed September 17,19, 2007, File No. 0-00404)000-00404)
4.2.5
Supplemental Indenture (2008 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of May 1, 2008 (Exhibit 4.1 to4, CL&P Current Report on Form 8-K filed May 27,29, 2008, File No. 0-00404)000-00404)
4.2.6
Supplemental Indenture (2009 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of February 1, 2009 (Exhibit 4, CL&P Current Report on Form 8-K filed February 19, 2009, File No. 000-00404)
E-2
4.3
Financing Agreement between The Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986 (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246)030-00246)
4.4
Financing Agreement between The Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Revenue Bonds, 1988 Series) dated as of October 1, 1988 (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246)030-00246)
4.5
Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and BayBank, the Trustee (Pollution Control Refunding Revenue Bonds, 1992 Series A) dated as of December 1, 1992 (Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246)030-00246)
4.6
Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Refunding Bonds - Series A, Tax Exempt Refunding)1993A Series) dated as of September 1, 1993 (Exhibit 4.2.21, 1993 CL&P Form 10-K filed March 25, 1994, File No. 0-00404)000-00404)
4.7
Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Refunding Bonds - Series B, Tax Exempt Refunding)– 1993B Series) dated as of September 1, 1993 (Exhibit 4.2.22, 1993 CL&P Form 10-K,10- K filed March 25, 1994, File No. 0-00404)000-00404)
4.8
Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P (CL&P Pollutiondated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond - 1996A Series) dated as of January 1, 1997 (Exhibit 4.2.24, 1996 CL&P Form 10-K filed March 25, 1997, File No. 0-00404)001-11419)
4.8.1
First Amendment to Amended and Restated Loan Agreement (CL&P Pollution Control Revenue Bond-1996A Series), dated as of October 1, 2008, by and between the Connecticut Development Authority and CL&P dated as of October 1, 2008 (Pollution Control Revenue Bond-1996A Series) (Exhibit 10.1, CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No. 0-00404)
E-2
000-00404)
4.9
Amended and Restated Indenture of Trust between Connecticut Development Authority and Fleet National Bank, the Trustee (CL&P Pollution Control Revenue Bond-1996A Series), dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond-1996A Series) (Exhibit 4.2.24.1, 1996 CL&P Form 10-K, filed March 25, 1997, File No. 0-00404)000-11419)
4.9.1
First Amendment to Amended and Restated Indenture of Trust between Connecticut Development Authority and U.S. Bank National Association, as the Trustee dated as of October 1, 2008 (Exhibit 10.2 CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No.0-00404)No. 000-00404)
4.10
Ambac Municipal Bond Insurance Policy issued by the Connecticut Development Authority (CL&P Pollution Control Revenue Bond-1996A Series), effective January 23, 1997 (Exhibit 4.2.24.3, 1996 CL&P Form 10-K, File No. 1-11419)
4.11
Release Agreement dated as of October 1, 2008, by and among Ambac Assurance Corporation, U.S. Bank National Association, as the Trustee, CL&P, and the Connecticut Development Authority (Exhibit 10, CL&P Form 10-Q for the Quarter Ended September 30, 2008, File No. 0-00404)
4.12
Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc.N.A., as Administrative Agent dated September 24, 2010 (Exhibit 99.2,10, CL&P Current Report on Form 8-K10-Q for the Quarter Ended September 30, 2010 filed December 9, 2005,November 8, 2010, File No. 0-00404)000-00404)
(C)
Public Service Company of New Hampshire
4.1
First Mortgage Indenture dated as of August 15, 1978 between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, dated as of August 15, 1978 (Composite including all amendments to May 16, 1991) (Exhibit 4.4.1, 1992 PSNH Form 10-K, File No. 1-6392)001-05324)
4.1.1
Tenth Supplemental Indenture dated as of May 1, 1991 between PSNH and First Fidelity Bank, National Association, now First Union National Bank dated as of May 1, 1991 (Exhibit 4.1, PSNH Current Report on Form 8-K filed February 10, 1992, File No. 1-6392)001-06392)
4.1.2
Twelfth Supplemental Indenture dated as of December 1, 2001 between PSNH and First Union National Bank dated as of December 1, 2001 (Exhibit 4.3.1.2, 2001 PSNH Form 10-K filed March 22, 2002, File No. 1-6392)001-06392)
4.1.3
Thirteenth Supplemental Indenture dated as of July 1, 2004, between PSNH and Wachovia Bank, National Association, successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of July 1, 2004 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 5, 2004, File No. 1-6392)001-06392)
4.1.4
Fourteenth Supplemental Indenture dated as of October 1, 2005, between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of October 1, 2005 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 6, 2005, File No. 1-6392)001-06392)
4.1.5
Fifteenth Supplemental Indenture dated as of September 17, 2007, between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of September 1, 2007 (Exhibit 4.1, PSNH Current Report on Form 8-K filed September 24, 2007, File No. 1-6392)001-06392)
E-3
4.1.6
Sixteenth Supplemental Indenture dated as of May 1, 2008, between PSNH and U.S. Bank National Association, as Trustee, relating to First Mortgage Bonds, Series O, dueDue 2018, dated as of May 1, 2008 (Exhibit 4.1 to PSNH Current Report on Form 8-K filed May 27,29, 2008 (File No.1-6392)No. 001-06392)
4.1.7
Seventeenth Supplemental Indenture between PSNH and U.S. Bank National Association, as Trustee dated as of December 1, 2009 (Exhibit 4.1, PSNH Current Report on Form 8-K filed December 15, 2009 (File No. 001-06392)
4.2
Series D (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999 (Exhibit 4.3.6, 1999 PSNH Form 10-K filed March 27, 2000, File No. 1-6392)001-06392)
4.3
Series E (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999 (Exhibit 4.3.7, 1999 PSNH Form 10-K filed March 27, 2000, File No. 1-6392)001-06392)
4.4
Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.4, 2001 PSNH Form 10-K filed March 22, 2002, File No. 1-6392)001-06392)
4.5
Series B Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.5, 2001 PSNH Form 10-K filed March 22, 2002, File No. 1-6392)001-06392)
4.6
Series C Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.6, 2001 PSNH Form 10-K filed March 22, 2002, File No. 1-6392)
E-3
001-06392)
4.7
Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp, USA, Inc.N.A., as Administrative Agent dated September 24, 2010 (Exhibit 99.2,10, PSNH Current Report on Form 8-K10-Q for the Quarter Ended September 30, 2010 filed December 9, 2005,November 8, 2010, File No. 1-6392)001-06392)
(D)
Western Massachusetts Electric Company
4.1
Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Revenue Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993 (Exhibit 4.4.13, 1993 WMECO Form 10-K filed March 25,1994, File No. 0-7624)000-07624)
4.2
Indenture between WMECO and theThe Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Current Report on Form 8-K filed October 8, 2003, File No. 0-7624)000-07624)
4.2.1
First Supplemental Indenture between WMECO and theThe Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.3, WMECO Current Report on Form 8-K filed October 8, 2003, File No. 0-7624)000-07624)
4.2.2
Second Supplemental Indenture between WMECO and The Bank of New York, as Trustee, dated as of September 1, 2004 between WMECO and Bank of New York, as Trustee (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 27, 2004, File No. 0-7624)000-07624)
4.2.3
Third Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2005 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 12, 2005, File No. 0-7624)000-07624)
4.2.4
Fourth Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2007 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 17,20, 2007, File No. 0-7624)000-07624)
4.2.5
Fifth Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of March 1, 2010 (Exhibit 4.1, WMECO Current Report on Form 8-K filed March 10, 2010, File No. 000-07624)
4.3
Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp, USA, Inc.N.A., as Administrative Agent dated September 24, 2010 (Exhibit 99.2,10, WMECO Current Report on Form 8-K10-Q for the Quarter Ended September 30, 2010 filed December 9, 2005,November 8, 2010, File No. 0-7624)000-07624)
10
E-4
10.
Material Contracts
(A)
Northeast UtilitiesNU
10.1
Lease dated as of April 14, 1992 between The Rocky River Realty Company and Northeast Utilities Service Company dated as of April 14, 1992 with respect to the Berlin, Connecticut headquarters (Exhibit 10.29,10.29.1, 1992 NU Form 10-K, File No. 1-5324)001-05324)
10.2
Indenture of Mortgage and Deed of Trust dated July 1, 1989 between Yankee Gas Services Company and the Connecticut National Bank, as Trustee, dated July 1, 1989 (Exhibit 4.7, Yankee Energy System, Inc. Form 10-K for the fiscal year ended September 30, 1990, File No. 0-10721)001-10721)
10.2.1
First Supplemental Indenture of Mortgage and Deed of Trust dated April 1, 1992 between Yankee Gas Services Company and The Connecticut National Bank, as Trustee, Yankeedated April 1, 1992 (Yankee Energy System, Inc. (RegistrationRegistration Statement on Form S-3, fileddated October 2, 1992, File No. 33-52750)
10.2.2
Fourth Supplemental Indenture of Mortgage and Deed of Trust dated April 1, 1997 between Yankee Gas Services Company and Fleet National Bank (formerly The Connecticut National Bank), as Trustee dated April 1, 1997 (Exhibit 4.15, Yankee Energy System, Inc. Form 10-K for the fiscal year ended September 30, 1997 filed December 10, 1997, File No. 001-10721)
10.2.3
Fifth Supplemental Indenture of Mortgage and Deed of Trust dated January 1, 1999 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated January 1, 1999 (Exhibit 4.2, Yankee Energy System, Inc. Form 10-Q for the fiscal quarterQuarter ended March 31, 1999 filed May 13, 1999, File No. 001-10721)
10.2.4
Sixth Supplemental Indenture of Mortgage and Deed of Trust dated January 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated January 1, 2004 (Exhibit 10.5.6, 2004 NU Form 10-K filed March 17, 2005, File No. 1-5324)001-05324)
10.2.5
Seventh Supplemental Indenture of Mortgage and Deed of Trust dated November 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated November 1, 2005 (Exhibit 10.5.7, 2004 NU Form 10-K filed March 17, 2005, File No. 1-5324)001-05324)
10.2.6
Eighth Supplemental Indenture of Mortgage and Deed of Trust dated July 1, 2005 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank) dated July 1, 2005 (Exhibit 10.5.8, NU Form 10-Q for the Quarter Ended June 30, 2005 filed August 8, 2005, File No. 1-5324)
E-4
001-05324)
10.2.7
Ninth Supplemental Indenture of Mortgage dated asand Deed of October 1, 2008Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as trusteeTrustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank), dated as Trusteeof October 1, 2008 (Exhibit 10-1,10.1, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 1-5324)001-05324)
10.2.8
+
*10.3
SummaryTenth Supplemental Indenture of Mortgage between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee Compensation Arrangementto The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank), dated as of April 1, 2010 (Exhibit 10, NU Form 10-Q for the Quarter Ended March 31, 2010 filed May 7, 2010, File No. 001-05324)
+* +10.3
Northeast Utilities Board of Trustees' Compensation Arrangement Summary
+10.4
Amended and Restated Northeast Utilities Deferred Compensation Plan for Trustees, effective January 1, 2009 (Exhibit 10.6, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 1-5324)001-05324)
*10.5
Purchase and SaleLimited Liability Company Agreement of Northern Pass Transmission LLC dated as of April 6, 2010
*10.5.1
Amendment No. 1 to Limited Liability Company Agreement of Northern Pass Transmission LLC, dated as of May 1, 2006 between Select Energy, Inc. and Amerada Hess Corporation (Exhibit 10.32, NU Form 10-Q for the Quarter Ended March 31, 2006, File No. 1-5324)14, 2010
10.6*10.5.2
Purchase and SaleAmendment No. 2 to Limited Liability Company Agreement dated July 24, 2006 between HWP and Mt. Tom Generating Companyof Northern Pass Transmission LLC, (Exhibit 10.33, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.6.1
Guaranty dated July 24, 2006 of NU for the benefit of Mt. Tom Generating Company LLC (Exhibit 10.33.2, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.7
Stock Purchase Agreement dated July 24, 2006 between NU Enterprises and NE Energy, Inc. (Exhibit 10.34, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.7.1
Guaranty dated July 24, 2006 of NU for the benefit of NE Energy, Inc. (Exhibit 10.34.2, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.8
Purchase and Sale Agreement dated July 24, 2006 by and among NGS, Select Energy, Northeast Utilities Service Company on the one hand, and NE Energy, Inc. on the other hand (Exhibit 10.35, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.8.1
Guaranty dated July 24, 2006 of NU for the benefit of NE Energy, Inc. (Exhibit 10.35.2, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.9
Stock Purchase Agreement dated as of February 1, 2006November 18, 2010
*10.6
Transmission Service Agreement by and among Ameresco, Inc. ("Ameresco"), NU Enterprisesbetween Northern Pass Transmission LLC, as Owner and NU (Exhibit 10.36, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)H.Q. Hydro Renewable Energy, as Purchaser dated October 4, 2010
10.9.1
Stock Purchase Agreement Amendment and Waiver dated as of May 5, 2006 among NU Enterprises, NU and Ameresco (Exhibit 10.36.3, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)E-5
10.9.2
NU Indemnification Agreement dated as of May 5, 2006 (Exhibit 10.36.4, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.9.3
Agreement to Purchase Contract Payments dated as of May 5, 2006 among NU, Ameresco and General Electric Capital Corporation (Exhibit 10.36.5, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
(B)
NU, CL&P, PSNH and WMECO
10.1
Form of Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO) dated as of July 1, 1966 (Exhibit 10.20, 1993 NU Form 10-K filed March 25, 1994, File No. 1-5324)001-05324)
10.1.1
Form of Renewal of Service Contract (Exhibit 10.1.2,10.2, 2006 NU Form 10-K filed March 1, 2007, File No. 1-5324)001-05324)
10.2
Agreements among New England Utilities with respect to the Hydro-QuébecHydro-Quebec interconnection projects (Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 1-3446.)001-03446)
10.3
Transmission Operating Agreement dated as of February 1, 2005 between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. dated as of February 1, 2005 (Exhibit 10.29, 2004 NU Form 10-K filed March 17, 2005, File No. 1-5324)001-05324)
10.3.1
Rate Design and Funds Disbursement Agreement effective June 30, 2006 among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc., effective June 30, 2006 (Exhibit 10.22.1, 2006 NU Form 10-K filed March 1, 2007, File No. 1-5324)
E-5
001-05324)
10.4
Northeast Utilities Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology dated as of January 1, 2008 among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company Trustee dated as of January 1, 2008 (Exhibit 10.1, NU Form 10-Q for the Quarter Ended March 31, 2008 filed May 9, 2008, File No. 1-5324)001-05324)
+
10.5
Separation Agreement with Cheryl W. Grisé, dated June 22, 2007 (Exhibit 10.20.2, 2008 NU Form 10-K, File No. 1-5324)
+ *
10.6
Amended and Restated Employment Agreement with Charles W. Shivery, effective January 1, 2009 (Exhibit 10.6, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+ *
10.710.6
Amended and Restated Employment Agreement with Gregory B. Butler, effective January 1, 2009 (Exhibit 10.7, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+ *
10.810.7
Amended and Restated Employment Agreement with David R. McHale, effective January 1, 2009 (Exhibit 10.8, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+ *
10.910.8
Amended and Restated Memorandum Agreement between Northeast Utilities and Leon J. Olivier, effective January 1, 2009 (Exhibit 10.9, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+
10.1010.9
Amended and Restated Incentive Plan Effective January 1, 2009 (Exhibit 10.3, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 1-5324)001-05324)
+
10.1110.10
Amended and Restated Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Company effective January 1, 2009 (Exhibit 10.5, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 1-5324)001-05324)
+
10.1210.11
Trust Agreement under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, 2002 NU Form 10-K filed March 21, 2003, File No. 1-5324)001-05324)
+
10.12.110.11.1
First Amendment to Trust Agreement,Under Supplemental Executive Retirement Plan, effective as of December 10, 2002 (Exhibit 10 (B)10(B) 10.19.1, 2003 NU Form 10-K filed March 12, 2004, File No. 1-5324)001-05324)
+ *
10.12.210.11.2
Second Amendment to Trust Agreement,Under Supplemental Executive Retirement, effective as of November 12, 2008 (Exhibit 10.12.2, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+
10.1310.12
Special Severance Program for Officers of NU System Companies as of January 1, 2009, (Exhibit 10.2, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 1-5324)001-05324)
+
10.1410.13
Amended and Restated Northeast Utilities Deferred Compensation Plan for Executives as of January 1, 2009 (Exhibit 10.4 NU Form 10-Q for Quarter Ended September 30, 2008 filed November 10, 2008, File No. 1-5324)001-05324)
+10.14
Agreement with James B. Robb effective October 15, 2009 (Exhibit 10.14 2009 NU Form 10-K filed February 26, 2010, File No. 001-05324)
+10.15
Northeast Utilities Retention Agreement (Exhibit 10.1, NU Registration Statement on Form S-4, filed November 22, 2010, File No. 333-170754)
E-6
10.16
Northeast Utilities System's Second Amended and Restated Tax Allocation Agreement dated as of September 21, 2005 (Exhibit D.4 to Amendment No. 1 to U5S Annual Report for the year ended December 31, 2004, filed September 30, 2005, File No. 1-5324)001-05324)
(C)
NU and CL&P
10.1
CL&P Transition Property Purchase and Sale Agreement between CL&P Funding LLC and CL&P, dated as of March 30, 2001 (Exhibit 10.55, 2001 CL&P Form 10-K filed March 22 2002, File No. 0-11419)000-00404)
10.2
CL&P Transition Property Servicing Agreement between CL&P Funding LLC and CL&P, dated as of March 30, 2001 (Exhibit 10.56, 2001 CL&P Form 10-K filed March 22, 2002, File No. 0-11419)000-00404)
10.3
CL&P Agreement Re: Connecticut NEEWS Projects by and between CL&P and The United Illuminating Company dated July 14, 2010 (Exhibit 10, CL&P Form 10-Q, for the Quarter Ended June 30, 2010 filed on August 6, 2010, File No. 000-00404)
*10.4
Purchase and Sale Agreement by and between The Connecticut Light & Power Company, as Seller and Connecticut Transmission Municipal Electric Energy Cooperative, as Buyer dated December 16, 2010
(D)
NU and PSNH
10.1
PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.57, 2001 PSNH Form 10-K filed March 22, 2002, File No. 1-6392)001-06392)
10.2
PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.58, 2001 PSNH Form 10-K filed March 22, 2002, File No. 1-6392)001-06392)
(E)
NU and WMECO
10.1
Lease and Agreement dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina dated as of December 15, 1988 (Exhibit 10.63, 1988 WMECONU Form 10-K, File No. 0-7624)001-05324)
10.2
WMECO Transition Property Purchase and Sale Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001 (Exhibit 10.61, 2001 WMECO Form 10-K filed March 22, 2002, File No. 0-7624)000-07624)
10.3
WMECO Transition Property Servicing Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001 (Exhibit 10.62, 2001 WMECO Form 10-K filed March 22, 2002, File No. 0-7624)
E-6
000-07624)
*12
Ratio of Earnings to Fixed Charges
(A)
Northeast Utilities
12
Ratio of Earnings to Fixed Charges
(B)
The Connecticut Light and Power Company
12
Ratio of Earnings to Fixed Charges
(C)
Public Service Company of New Hampshire
12
Ratio of Earnings to Fixed Charges
(D)
Western Massachusetts Electric Company
12
Ratio of Earnings to Fixed Charges
*21
Subsidiaries of the Registrant
*23
Consent of Independent Registered Public Accounting Firm
23.1
Deloitte & Touche LLP
23.2
PricewaterhouseCoopers LLP
*31
Rule 13a -– 14(a)/15d -15 d – 14(a) Certifications
E-7
(A)
Northeast Utilities
31
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast UtilitiesNU required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Northeast UtilitiesNU required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
(B)
The Connecticut Light and Power Company
3131.
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power CompanyCL&P required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power CompanyCL&P required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
(C)
Public Service Company of New Hampshire
3131.
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New HampshirePSNH required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New HampshirePSNH required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
(D)
Western Massachusetts Electric Company
31
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric CompanyWMECO required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric CompanyWMECO required by Rule 13a -– 14(a)/15d -– 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2009
E-7
25, 2011
*32
18 U.S.C. Section 1350 Certifications
(A)
Northeast Utilities
32
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
(B)
The Connecticut Light and Power Company
32
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
(C)
Public Service Company of New Hampshire
32
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
E-8
(D)
Western Massachusetts Electric Company
32
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 200925, 2011
*101.INS
XBRL Instance Document
*101.SCH
XBRL Taxonomy Extension Schema
*101.CAL
XBRL Taxonomy Extension Calculation
*101.DEF
XBRL Taxonomy Extension Definition
*101.LAB
XBRL Taxonomy Extension Labels
*101.PRE
XBRL Taxonomy Extension Presentation
E-8E-9