____________________________________________________________________________________
![[september10q001.jpg]](https://capedge.com/proxy/10-Q/0000072741-04-000155/september10q001.jpg)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
|
|
| For the Quarterly Period EndedSeptember 30, 2004 |
| OR |
[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
|
|
| For the transition period from ____________ to ____________ |
Commission | Registrant; State of Incorporation; | I.R.S. Employer |
1-5324 | NORTHEAST UTILITIES | 04-2147929 |
1-11419 | THE CONNECTICUT LIGHT AND POWER COMPANY | 06-0303850 |
1-6392 | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE | 02-0181050 |
0-7624 | WESTERN MASSACHUSETTS ELECTRIC COMPANY | 04-1961130 |
____________________________________________________________________________________
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:
Yes | No | |
Ö |
Indicate by check mark whether the registrant are accelerated filers (as defined in Rule 12b-2 of the Exchange Act):
Yes | No | |
Northeast Utilities | Ö | |
The Connecticut Light and Power Company | Ö | |
Public Service Company of New Hampshire | Ö | |
Western Massachusetts Electric Company | Ö |
Indicate the number of share outstanding of each of the issuers’ classes of common stock, as of the latest practicable date:
Company – Class of Stock | Outstanding at October 31, 2004 |
Northeast Utilities | 128,384,407 shares |
The Connecticut Light and Power Company | 6,035,205 shares |
Public Service Company of New Hampshire | 301 shares |
Western Massachusetts Electric Company | 434,653 shares |
GLOSSARY OF TERMS | |
The following is a glossary of frequently used abbreviations or acronyms that are found in this report. | |
NU COMPANIES, SEGMENTS OR INVESTMENTS: | |
CL&P | The Connecticut Light and Power Company |
CRC | CL&P Receivables Corporation |
HWP | Holyoke Water Power Company |
NGC | Northeast Generation Company |
NGS | Northeast Generation Services Company |
NU or the company | Northeast Utilities |
NU Enterprises | NU’s competitive subsidiaries comprised of HWP, NGC, NGS, Select Energy, SESI, and Woods Network. For further information, see Note 8, "Segment Information," to the consolidated financial statements. |
PSNH | Public Service Company of New Hampshire |
RMS | R. M. Services |
Select Energy | Select Energy, Inc. (including its wholly owned subsidiary SENY) |
SENY | Select Energy New York, Inc. |
SESI | Select Energy Services, Inc. |
Utility Group | NU’s regulated utilities comprised of CL&P, PSNH, WMECO, and Yankee Gas. For further information, see Note 8, "Segment Information," to the consolidated financial statements. |
WMECO | Western Massachusetts Electric Company |
Woods Network | Woods Network Services, Inc. |
Yankee | Yankee Energy System, Inc. |
Yankee Gas | Yankee Gas Services Company |
THIRD PARTIES: | |
Bechtel | Bechtel Power Corporation |
CY | Connecticut Yankee |
NRG | NRG Energy, Inc. |
REGULATORS: | |
CSC | Connecticut Siting Council |
DPUC | Connecticut Department of Public Utility Control |
FERC | Federal Energy Regulatory Commission |
NHPUC | New Hampshire Public Utilities Commission |
SEC | Securities and Exchange Commission |
OTHER: | |
Act, the | Public Act No. 03-135 |
CTA | Competitive Transition Assessment |
EPS | Earnings Per Share |
FASB | Financial Accounting Standards Board |
FMCC | Federally Mandated Congestion Costs |
GSC | Generation Service Charge |
ISO-NE | New England Independent System Operator |
kWh | Kilowatt-Hour |
LMP | Locational Marginal Pricing |
LNG | Liquefied Natural Gas |
LOCs | Letters of Credit |
MW | Megawatts |
NU 2003 Form 10-K | The Northeast Utilities and Subsidiaries combined 2003 |
Form 10-K as filed with the SEC | NYMEX |
New York Mercantile Exchange | OCA |
Office of Consumer Advocate | OCC |
Office of Consumer Counsel | Restructuring Settlement |
"Agreement to Settle PSNH Restructuring" | ROE |
Return on Equity | RTO |
Regional Transmission Organization | SBC |
System Benefits Charge | SCRC |
Stranded Cost Recovery Charge | SFAS |
Statement of Financial Accounting Standards | SMD |
Standard Market Design | TS |
Transition Energy Service | TSO |
Transitional Standard Offer |
NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
TABLE OF CONTENTS
PART II — OTHER INFORMATION | |
ITEM 1 —Legal Proceedings | 78 |
ITEM 2 —Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities | 79 |
ITEM 6 —Exhibits and Reports on Form 8-K | 79 |
82 | |
NORTHEAST UTILITIES AND SUBSIDIARIES
NORTHEAST UTILITIES AND SUBSIDIARIES | |||||
CONSOLIDATED BALANCE SHEETS | |||||
(Unaudited) | |||||
September 30, | December 31, | ||||
2004 | 2003 | ||||
(Thousands of Dollars) | |||||
LIABILITIES AND CAPITALIZATION | |||||
Current Liabilities: | |||||
Notes payable to banks | $ 1,043 | $ 105,000 | |||
Long-term debt - current portion | 88,963 | 64,936 | |||
Accounts payable | 704,559 | 729,328 | |||
Accrued taxes | 3,111 | 50,134 | |||
Accrued interest | 58,560 | 41,653 | |||
Derivative liabilities | 207,656 | 112,612 | |||
Counterparty deposits | 67,356 | 46,496 | |||
Other | 207,878 | 203,080 | |||
1,339,126 | 1,353,239 | ||||
Rate Reduction Bonds | 1,591,944 | 1,729,960 | |||
Deferred Credits and Other Liabilities: | |||||
Accumulated deferred income taxes | 1,403,816 | 1,287,354 | |||
Accumulated deferred investment tax credits | 100,062 | 102,652 | |||
Deferred contractual obligations | 423,236 | 469,218 | |||
Regulatory liabilities | 1,163,773 | 1,164,288 | |||
Other | 244,692 | 247,526 | |||
3,335,579 | 3,271,038 | ||||
Capitalization: | |||||
Long-Term Debt | 2,839,694 | 2,481,331 | |||
Preferred Stock of Subsidiary - Non-Redeemable | 116,200 | 116,200 | |||
Common Shareholders' Equity: | |||||
Common shares, $5 par value - authorized | |||||
225,000,000 shares; 150,683,698 shares issued | |||||
and 128,349,411 shares outstanding in 2004 and | |||||
150,398,403 shares issued and 127,695,999 shares | |||||
outstanding in 2003 | 753,418 | 751,992 | |||
Capital surplus, paid in | 1,111,152 | 1,108,924 | |||
Deferred contribution plan - employee stock |
| ||||
ownership plan | (63,831) | (73,694) | |||
Retained earnings | 879,153 | 808,932 | |||
Accumulated other comprehensive (loss)/income | (1,923) | 25,991 | |||
Treasury stock, 19,575,940 shares in 2004 | |||||
and 19,518,023 shares in 2003 | (359,060) | (358,025) | |||
Common Shareholders' Equity | 2,318,909 | 2,264,120 | |||
Total Capitalization | 5,274,803 | 4,861,651 | |||
Commitments and Contingencies (Note 4) | |||||
Total Liabilities and Capitalization | $ 11,541,452 | $ 11,215,888 | |||
The accompanying notes are an integral part of these consolidated financial statements. | |||||
NORTHEAST UTILITIES AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
This discussion should be read in conjunction with the consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2004 reports on Form 10-Q, the NU 2003 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q. All per share amounts are reported on a fully diluted basis.
FINANCIAL CONDITION AND BUSINESS ANALYSIS
Executive Summary
The following items in this executive summary are explained in more detail in this report on Form 10-Q:
Results and Outlook:
·
Earnings at Northeast Utilities (NU or the company) decreased by $0.1 million in the third quarter of 2004 compared with the same period of 2003, and increased by $3.1 million for the first nine months of 2004 compared with the first nine months of 2003. Results in the third quarter of 2003 included a negative cumulative effect of an accounting change of $4.7 million associated with NU's former investment in a bill collection company.
·
Retail electric sales decreased 4.9 percent in the third quarter of 2004 compared with the third quarter of 2003 primarily as a result of the 2003 positive unbilled revenue adjustments. Absent these adjustments, revenues were virtually unchanged in the third quarter of 2004, compared with 2003. On a weather-adjusted basis, sales increased 2.8 percent as a result of improved economic conditions.
·
NU has narrowed its projected 2004 earnings range to between $1.25 per share and $1.35 per share. NU also established a 2005 earnings range of between $1.35 per share and $1.45 per share.
Regulatory Items:
·
On August 4, 2004, the Connecticut Department of Public Utility Control (DPUC) issued a final decision on The Connecticut Light and Power Company's (CL&P) petition for reconsideration of the DPUC's December 2003 rate order in CL&P's distribution rate case. This decision had a $6 million positive impact on CL&P's earnings in the third quarter of 2004.
·
The City of Norwalk, Connecticut appealed the July 14, 2003 Connecticut Citing Council approval of the construction of a 345,000-volt transmission line from Bethel, Connecticut to Norwalk, Connecticut. On August 19, 2004, a Connecticut Superior Court judge dismissed the City of Norwalk's appeal.
·
A settlement agreement was approved on September 2, 2004 by the New Hampshire Public Utilities Commission (NHPUC) to raise Public Service Company of New Hampshire's (PSNH) retail distribution rates by $3.5 million annually, effective on October 1, 2004 and $10 million annually, effective on June 1, 2005.
·
On September 3, 2004, the DPUC approved the application of Yankee Gas Services Company (Yankee Gas) to construct a liquefied natural gas (LNG) storage facility in Waterbury, Connecticut, capable of storing the equivalent of 1.2 billion cubic feet of natural gas, with an estimated cost of approximately $100 million.
·
On September 15, 2004, the Federal Energy Regulatory Commission (FERC) approved a settlement agreement allowing the transmission business to implement a formula rate with an 11.0 percent return on equity (ROE). This ROE will remain in effect until the FERC establishes an ROE for a New England regional transmission organization (RTO).
·
On October 14, 2004, Yankee Gas filed a settlement agreement between Yankee Gas, the Office of Consumer Counsel (OCC) and the Prosecutorial Division of the DPUC in its rate case proceeding.
Liquidity:
·
On July 22, 2004, PSNH issued $50 million of 10-year first mortgage bonds at a fixed interest rate of 5.25 percent.
·
On September 17, 2004, CL&P issued $280 million of 10-year and 30-year first mortgage bonds at fixed interest rates of 4.8 percent and 5.75 percent, respectively.
·
On September 23, 2004, Western Massachusetts Electric Company (WMECO) issued $50 million of 30-year senior unsecured notes at a fixed interest rate of 5.9 percent.
·
NU’s capital expenditures continue to be lower than initially projected for 2004. NU’s capital expenditures totaled $463.7 million for the first nine months of 2004, compared with $381.9 million for the first nine months of 2003. NU’s 2004 capital spending is now projected to total $638.4 million compared with the 2004 budget amount of $738 million. The lower projected capital spending amount is due primarily to delays in approvals of major transmission capital projects.
·
CL&P is required to return to customers past overcollections, including $88.5 million of Competitive Transition Assessment (CTA) and System Benefits Charge (SBC) amounts to be returned from October 2004 through April 2005, and $75 million of previously collected Standard Market Design (SMD) costs to be returned from September 2004 through December 2004. Also, $30 million of previous Generation Service Charge (GSC) overrecoveries each year will be used to recover costs in the years 2004 through 2007.
Overview
Consolidated: NU earned $39.1 million, or $0.30 per share, in the third quarter of 2004, compared with earnings of $39.2 million, or $0.31 per share, in the third quarter of 2003. For the first nine months of 2004, NU earned $129.4 million, or $1.01 per share, compared with $126.3 million, or $0.99 per share in the same period of 2003. Earnings in 2003 included a cumulative effect of an accounting change of $4.7 million, or $0.04 per share, associated with NU's former investment in a bill collection company.
A summary of NU's earnings/(losses) by major business for the third quarter and first nine months of 2004 and 2003 is as follows:
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||
(Millions of Dollars) | 2004 | 2003 | 2004 | 2003 | ||
Utility Group | $37.8 | $37.2 |
| $118.3 | $110.8 |
|
NU Enterprises | 4.0 | 6.9 |
| 25.7 | 24.0 |
|
Parent and other | (2.7) | (4.9) |
| (14.6) | (8.5) |
|
Net income | $39.1 | $39.2 |
| $129.4 | $126.3 |
|
NU’s revenues during the first nine months of 2004 increased to $5 billion from $4.5 billion in the same period of 2003. The increase in revenues was primarily due to an increase of $377 million in revenues at NU Enterprises. This increase is the result of $171 million in higher revenues due to higher electric and gas prices and more of NU Enterprises' revenues coming from companies that are not NU subsidiaries. An increase in volumes accounted for the remainder of that increase.
Utility Group: The Utility Group is comprised of CL&P, PSNH, WMECO, and Yankee Gas. Earnings at the Utility Group increased by $0.6 million in the third quarter of 2004 compared with the same period of 2003, and increased by $7.5 million for the first nine months of 2004 compared with the first nine months of 2003. The increase in earnings for the first nine months of 2004 was primarily due to increases in CL&P’sretail rates and an overall lower Utility Group effective tax rate due to adjustments to tax reserves totaling $2.8 million as a result of the actual 2003 tax return amounts being compared to the 2003 year end tax provision estimates in the third quarter of 2004. The CL&P rate case reconsideration decision also had a positive impact on third quarter and year-to-date earnings. Those improvements were partially offset by lower pension income and higher interest and depreciation expense. &nbs p;A summary of Utility Group earnings/ (losses) by company for the third quarter and first nine months of 2004 and 2003 is as follows:
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||
(Millions of Dollars) | 2004 | 2003 | 2004 | 2003 | ||
CL&P * | $21.7 | $29.0 |
| $ 65.1 | $ 59.0 |
|
PSNH | 18.2 | 12.6 |
| 36.0 | 34.5 |
|
WMECO | 1.5 | 5.2 |
| 8.7 | 13.9 |
|
Yankee Gas | (3.6) | (9.6) |
| 8.5 | 3.4 |
|
Net income | $37.8 | $37.2 |
| $118.3 | $110.8 |
|
*After preferred dividends.
CL&P's third quarter 2004 earnings were lower than the same period of 2003 primarily due to the absence of the positive 2003 adjustment to the estimate of unbilled revenues and milder weather in the third quarter of 2004. CL&P’s higher year-to-date earnings resulted from distribution and transmission rate increases that took effect January 1, 2004. These higher retail rates were offset by higher depreciation expense and lower pension income. CL&P also benefited from the final decision on the reconsideration of CL&P’s rate case, which had a third quarter 2004 positive pre-tax impact of approximately $10.2 million (approximately $6 million after-tax). The positive earnings impact included the recovery of $9.4 million in pension assets that were written off in the fourth quarter of 2003.
PSNH earnings were higher for the third quarter and year-to-date 2004, compared with the same period of 2003, primarily as a result of a lower effective tax rate. The lower effective tax rate is due to adjustments to tax reserves totaling a positive $5.4 million recorded in the third quarter of 2004 as a result of the actual 2003 tax return amounts being compared to the 2003 year end tax provision estimates. The lower effective tax rate is also due to the allocation of certain parent company tax benefits to PSNH in accordance with the NU tax allocation agreement. Under its tax allocation agreement, more tax benefits were allocated from NU parent to the Utility Group, including PSNH, in 2004 than in 2003.
WMECO's third quarter and year-to-date earnings were lower due to lower pension income and higher interest and depreciation expense, offset by a lower effective tax rate.
Yankee Gas' third quarter and year-to-date 2004 results benefited from the absence of a negative $5.1 million adjustment to the estimate of unbilled revenues in the third quarter of 2003 and the reduction in income tax expense due to changes in estimates of deferred taxes associated with Yankee Gas' plant assets that were recorded in the second quarter of 2004. Year-to-date results were also positively impacted by a change in rate design implemented in August 2003. Yankee Gas' current rate design is intended to recover more costs based on stable, fixed monthly charges rather than based on variable, usage-based charges as was the rate design in place earlier in 2003. That shift from more variable to more fixed charges has reduced quarterly earnings in the higher-use first and fourth quarters and improved quarterly results in the lower-use second and third quarters compared to Yankee Gas' previous rate design.
Included in Utility Group earnings are earnings related to the transmission business. Transmission business earnings were $11 million in the third quarter of 2004 and $23.6 million for the first nine months of the year compared with earnings of $9.8 million in the third quarter of 2003 and $21.6 million for the first nine months of 2003. Transmission business earnings for the periods in 2004 are higher than the same periods in 2003 primarily due to higher revenues. Transmission revenues are higher in 2004 due to the implementation of a FERC approved formula rate resulting in increased rates. In the first nine months of 2004, $85 million of transmission projects were placed in service. The formula rate allows immediate recovery of these costs. During the first nine months of 2003, revenues were not subject to this formula rate.
NU Enterprises: NU Enterprises, Inc. is the parent company of Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI) and their respective subsidiaries, and Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as "NU Enterprises." The generation operations of Holyoke Water Power Company (HWP) are also included in the results of NU Enterprises. The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy segment and the energy services business segment. The merchant energy business segment is comprised of Select Energy’s wholesale business, which includes approximately 1,293 megawatts (MW) of pumped storage and hydroelectric generation assets owned by NGC, 147 MW of coal-fired generation assets owned by HWP, and Select Energy's retail business. The energy services business consists of the operations of NGS, SESI and Woods Network.
NU Enterprises earnings decreased by $2.9 million in the third quarter of 2004 compared with the third quarter of 2003. The decrease in third quarter profitability was due primarily to lower volumes and margins on wholesale contracts from seasonal pricing, offset by positive adjustments to income tax expense totaling $1.8 million and to a reduction in contract reserves totaling $1.1 million (after-tax). The seasonal pricing produced high margins in the first quarter of 2004 and lower margins in the remaining quarters. Cooler summer weather in 2004 contributed to the lower earnings in 2004 by reducing the sales
volume during the quarter. The decrease in third quarter profitability was also due to net changes to the fair values of natural gas inventory and related hedges. This decrease amounted to $2.5 million (after-tax).
NU Enterprises earnings increased by $1.7 million for the first nine months of 2004 compared with the first nine months of 2003. The improved nine-month earnings compared to last year are a result of improved margins on energy contracts and higher retail volumes.
A summary of NU Enterprises’ earnings/(losses) by business for the third quarter and first nine months of 2004 and 2003 is as follows:
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||
(Millions of Dollars) | 2004 | 2003 | 2004 | 2003 | ||
Merchant energy | $3.3 | $6.9 |
| $27.0 | $22.3 |
|
Energy services and other | 0.7 | - |
| (1.3) | 1.7 |
|
Net income | $4.0 | $6.9 |
| $25.7 | $24.0 |
|
The decreases in year-to-date earnings at the energy services business are due in part to a $1.8 million after-tax loss recorded in the second quarter on a construction contract and a reduced level of work for the United States government. For the period of September 30, 2003 to October 28, 2004, the United States government was precluded by statute from awarding certain energy savings contracts.
Parent and Other: For the three and nine months ended September 30, 2003, parent and other includes the $4.7 million negative cumulative effect of an accounting change associated with NU's former investment in a bill collection company. Absent that amount, parent and other resulted in decreases to NU's earnings of $2.5 million for the third quarter of 2004 compared to 2003, and $10.8 million for the first nine months of 2004 compared to 2003, primarily due to the allocation of income tax benefits from NU parent to subsidiaries.
Future Outlook
Consolidated: NU has narrowed the 2004 earnings projection from between $1.20 per share and $1.40 per share to between $1.25 per share and $1.35 per share.
NU has also established an earnings range of between $1.35 per share and $1.45 per share in 2005.
Utility Group: The narrower NU consolidated earnings estimate for 2004 includes Utility Group earnings of between $1.13 per share and $1.19 per share, which has been narrowed from an earlier earnings range for the Utility Group of between $1.08 per share and $1.20 per share. The Utility Group earnings range includes earnings of between $0.91 per share and $0.95 per share at its distribution and generation businesses and between $0.22 per share and $0.24 per share at its transmission business.
The NU consolidated earnings estimate for 2005 includes Utility Group earnings of between $0.96 per share and $1.00 per share at its distribution and generation businesses and between $0.26 per share and $0.30 per share at its transmission business.
NU Enterprises: The narrower NU consolidated earnings estimate for 2004 includes NU Enterprises earnings of between $0.23 per share and $0.25 per share which has been narrowed from an earlier earnings range for NU Enterprises of between $0.22 per share and $0.30 per share.
The NU consolidated earnings estimate for 2005 includes earnings at NU Enterprises of between $0.26 per share and $0.30 per share.
Parent Company: NU parent is expected to have debt and other expenses of between $0.09 per share and $0.11 per share in 2004, which has been revised from an estimate of $0.10 per share, and between $0.13 per share and $0.15 per share in 2005.
Strategic Overview
In September 2004, management completed its comprehensive review of all its business lines and five-year business plans. The review was performed to identify the best opportunities in each business and determine how to allocate capital to those opportunities. This review resulted in a validation of key elements of the company's existing strategy and increased clarity in how the company expects to invest capital over the next five years. The company has identified significant investment
requirements in the Utility Group transmission and distribution businesses and expects to invest more than $3.7 billion in regulated electric and natural gas infrastructure from 2005 through 2009.
Based on current projections, management expects that the need to invest heavily in regulated infrastructure to meet reliability requirements and customer growth will cause NU’s Utility Group distribution and generation rate base to rise from $2.5 billion in 2004 to nearly $3.9 billion by the end of 2009. Based on currently projected expenditures and capital project completion dates, management expects that the same factors will increase NU’s Utility Group transmission rate base from approximately $500 million in 2004 to approximately $1.7 billion in 2009. Management believes that such investment, assuming it is authorized to earn a appropriate return by regulators on the higher rate base, should allow the company to achieve earnings and dividend growth that will exceed the currently expected average electric utility growth rates in the United States over the next five years. Management believes those industry growth rates to be a pproximately 4 percent. Management expects NU Enterprises to continue to operate in the three power pools of New England, New York and PJM, but does not forecast a need for significant new capital investments in NU Enterprises’ businesses at this time. In fact, management believes that NU Enterprises, if it modestly improves its current profitability, will become a source of cash to fund parent company needs with dividends to NU parent totaling more than $200 million from 2005 through 2009.
Management believes the company's Utility Group capital investments as currently scheduled, when added to projected dividend requirements, will result in net cash needs of approximately $4.4 billion from 2005 through 2009. Management believes that approximately $2.6 billion of that sum will be raised through internal sources with the remaining $1.8 billion coming from external sources. Management expects most of the external funding to be in the form of new debt issues and a substantially lesser amount to be in the form of new equity issues. Management does not have a firm schedule for the issuance of those securities, and the schedule is highly dependent on the timing of capital additions, among other things.
Labor Relations
On October 22, 2004, contracts offered by CL&P to employees represented by Locals 420 and 457 of the International Brotherhood of Electrical Workers were rejected by the unions. These two contracts cover approximately 1,200 CL&P employees, primarily physical workers including electricians, line workers, meter readers and installers, cable splicers, and warehouse personnel. Management cannot predict the outcome of contract negotiations or the ultimate impact, if any, of a possible strike.
Liquidity
Consolidated: NU continues to maintain an adequate level of liquidity. At September 30, 2004, NU had $97.9 million of cash and cash equivalents on hand compared with $36.7 million at December 31, 2003. The cash position of NU at September 30, 2004 includes $41 million of previously restricted cash collected for SMD costs that will be refunded to CL&P's customers.
NU’s net cash flows provided by operating activities increased to $532.1 million in the first nine months of 2004 from $460.8 million in the first nine months of 2003 due to changes in working capital items and to changes in regulatory (refunds)/overrecoveries.
The release of restricted cash collected in 2003 associated with locational marginal pricing (LMP) costs but not yet paid to suppliers or refunded to customers, increased cash from operations in the first nine months of 2004. CL&P paid $83 million to its standard offer suppliers in accordance with the FERC-approved SMD settlement agreement, which decreased accounts payable. Another approximately $56 million will be refunded to customers related to the SMD settlement agreement in the fourth quarter of 2004 and will negatively impact cash flows from operations. An increase in counterparty deposits, which fluctuate based on changes in the fair value of certain energy contracts, resulted in an increase in other current liabilities and had a positive impact on cash flows from operations in the first nine months of 2004 compared to the same period in 2003.
The decrease in regulatory (refunds)/overrecoveries is primarily due to lower CTA and GSC collections in the first nine months of 2004 as NU refunds amounts to its ratepayers for past over collections or uses those amounts to recover current costs. These refunds are also the primary reason for the positive change in deferred income taxes for the first nine months of 2004 as compared to the first nine months of 2003, which has increased operating cash flows. The change in deferred income taxes is expected to continue to benefit cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets.
On September 30, 2004, NU paid a dividend of $0.1625 per share. On October 12, 2004, the NU Board of Trustees approved a common dividend of $0.1625 per share, payable on December 30, 2004, to shareholders of record at December 1, 2004.
NU’s capital expenditures have been lower than what had been expected at the beginning of 2004. NU’s capital expenditures totaled $463.7 million for the first nine months of 2004, compared with $381.9 million for the first nine months of 2003. NU currently projects capital expenditures of $638.4 million in 2004 compared with the 2004 budgeted amount of $738 million. The revised 2004 projection includes $355.1 by CL&P, $148.2 million by PSNH, $38.4 million by WMECO, $62.4 million by Yankee Gas, and $34.3 million by other NU subsidiaries. The lower level of capital spending compared to the budget was primarily related to delays in approvals of certain major transmission projects as a result of an appeal of a Connecticut Siting Council (CSC) decision and other legal and regulatory delays.
Utility Group: At September 30, 2004, the Utility Group had no borrowings outstanding on its $300 million revolving credit line. This revolving credit line is scheduled to mature on November 8, 2004 and will be replaced on that date by a $400 million, five-year facility. Under this new credit line, CL&P will be able to borrow up to $200 million and PSNH, WMECO, and Yankee Gas will be able to borrow up to $100 million, each on a short-term basis.
In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At September 30, 2004, CL&P had sold accounts receivable totaling $40 million to that financial institution. For more information regarding the sale of receivables, see Note 1G, "Summary of Significant Accounting Policies - Sale of Customer Receivables" to the consolidated financial statements.
On September 17, 2004, CL&P issued $150 million of 10-year first mortgage bonds at a fixed interest rate of 4.8 percent and also issued $130 million of 30-year first mortgage bonds at a fixed interest rate of 5.75 percent. CL&P used the proceeds from these issuances to repay short-term debt.
As part of the approved SMD settlement agreement, CL&P paid $83 million to its suppliers on July 8, 2004. Under the settlement agreement, CL&P also agreed to refund $75 million to its customers. The $83 million supplier payment was made from an escrow fund that was established during 2003 as these costs were being collected from customers. Of the combined payment and refund amount totaling $158 million, $31 million was not funded from the escrow account. CL&P began returning the $75 million to customers over a four-month period on September 1, 2004. Additionally, the DPUC ordered a refund of $88.5 million in CTA/SBC overcollections over a seven-month period beginning with October 2004 consumption. The combination of the SMD and CTA/SBC refunds, when combined with CL&P’s proposed capital expenditures, will negatively impact CL&P’s liquidity. CL&P is also refunding GSC overrecover ies of $120 million over a four-year period beginning in 2004. However, CL&P expects no difficulty in meeting these additional cash requirements.
On July 22, 2004, PSNH issued $50 million of 10-year first mortgage bonds at a fixed interest rate of 5.25 percent. Proceeds were used to repay short-term debt and fund PSNH’s capital expenditure program. In October 2004, PSNH received sufficient approvals to begin the construction related to the conversion of one of the coal-fired units at Schiller Station to burn wood. The NHPUC has approved the project but the NHPUC's approval is subject to an appeal to the New Hampshire Supreme Court. This project is expected to cost $75 million.
On September 23, 2004, WMECO issued $50 million of 30-year senior unsecured notes at a fixed interest rate of 5.9 percent. Proceeds were used to finance a trust fund which will be used to meet WMECO's prior spent nuclear fuel liability.
Yankee Gas plans to issue up to $50 million in 15-year first mortgage bonds in the fourth quarter of 2004, pursuant to existing DPUC approvals. The proceeds will be used primarily to repay short-term debt, approximately $35 million of which was incurred to redeem two series of high coupon rate first mortgage bonds in the fourth quarter of 2004. On September 3, 2004, the DPUC approved the application by Yankee Gas to construct a LNG storage facility with an estimated cost of approximately $100 million that is capable of storing the equivalent of 1.2 billion cubic feet of natural gas.
NU Enterprises: At September 30, 2004, NU Enterprises had $113.6 million in letters of credit (LOCs) outstanding on NU parent’s $350 million revolving credit line. This revolving credit line is scheduled to mature on November 8, 2004 and will be replaced on that date by a $500 million five-year facility under which borrowings will be made on a short-term basis. NU is seeking to increase its short-term borrowing authorization from the Securities and Exchange Commission (SEC) to $500 million from $450 million. A total of $350 million of the $500 million under the credit line can be in the form of LOCs which can be used to provide support for Select Energy’s activities.
NU Enterprises' liquidity is significantly impacted by both the amount of collateral from other counterparties it holds and the amount of collateral it is required to deposit with counterparties.
On September 17, 2004, Moody’s Investors Service lowered NGC’s bond rating to Baa3 from Baa2 and changed the outlook to "stable." The change is not expected to have any negative impact on NGC.
SESI borrowed a net total of $8.1 million during 2004 to finance the implementation of energy saving improvements at
customer facilities. Cash to repay these borrowings is funded by SESI's energy savings contracts. No additional non-contract related borrowings were made in the third quarter of 2004.
Nuclear Decommissioning and Plant Closure Costs
NU has significant decommissioning and plant closure cost obligations to the companies that own the Yankee Atomic (YA), Connecticut Yankee (CY) and Maine Yankee (MY) nuclear power plants (collectively, the Yankee Companies). Each plant has been shut down and is undergoing decommissioning. 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 pass these costs on to their customers through state regulatory commission-approved retail rates. YA has received FERC approval to collect all presently estimated decommissioning costs. MY and various other parties filed a settlement agreement with the FERC, which provides for the collection of approximately $27 million annually through October 31, 2008 for all presently est imated decommissioning and long-term spent fuel storage costs. The MY settlement was approved by the FERC on September 16, 2004.
CY's estimated decommissioning and plant closure costs for the period 2000 through 2023 have increased by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the fact that CY is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July 2003, due to the increases in the projected costs of spent fuel storage, and increased security and liability and property insurance costs. NU's share of CY's increase in decommissioning and plant closure costs is approximately $194 million. On July 1, 2004, CY filed with the FERC for recovery of these increased costs. In the filing, CY sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund, and scheduled hearings for May 2005. In total, NU's estimated remaining decommissioning and plant closure obligation for CY is $310.2 million at September 30, 2004.
On June 10, 2004, the DPUC and OCC filed a petition seeking declaratory order that CY be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred. On August 30, 2004, the FERC denied this petition. On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition. On October 29, 2004, the FERC issued an order granting further consideration regarding the DPUC's and OCC's petition for reconsideration. No hearing date has been established.
CY is currently in litigation with Bechtel over the termination of its decommissioning contract. On June 13, 2003, CY gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant. CY terminated the contract due to Bechtel's history of incomplete and untimely performance and refusal to perform the remaining decommissioning work. Bechtel has departed the site, and the decommissioning responsibility has been transitioned to CY, which has recommenced the decommissioning process.
On June 23, 2003, Bechtel filed a complaint against CY asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and rescission of the contract. Bechtel has since amended its complaint to add claims for wrongful termination. On August 22, 2003, CY filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing. Discovery is currently underway, and a trial has been scheduled for May 2006.
On July 20, 2004, the Connecticut Superior Court (the Court) allowed the DPUC to intervene in the prejudgment remedy (PJR) proceeding filed in June 2004 for the limited purpose of objecting to Bechtel’s requested garnishment of the decommissioning trust and related payments. On October 27, 2004, Bechtel and CY entered into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY's real property in Connecticut with a book value of $7.9 million and the escrowing of $41.7 million the sponsors are scheduled to pay to CY through June 30, 2007. This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CY intends to contest the attachability of such assets.
NU cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased decommissioning costs. Management believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO. However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings. NU also cannot predict the
timing and outcome of the litigation with Bechtel or its impact on NU. For additional current information regarding these issues and litigation with Bechtel, see Part II, Item 1, "Legal Proceedings," in this report on Form 10-Q.
The Yankee Companies are seeking recovery of damages from the United States Department of Energy (DOE) for the cost of storing spent nuclear fuel that the DOE has failed to remove. The DOE trial ended on August 30, 2004, and a verdict has not yet been reached. The related claim for damages from the DOE incurred through 2010 is approximately $500 million. The current rates of the Yankee Companies do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on NU.
Utility Group Business Development and Capital Expenditures
Connecticut - CL&P: On August 19, 2004 a Connecticut Superior Court judge dismissed an appeal by the City of Norwalk concerning construction of a 345,000 volt transmission project from Bethel, Connecticut to Norwalk, Connecticut. Based upon a recently completed estimate, the project is currently projected to cost between $300 million and $350 million, depending upon resolution of technical and siting issues. The project is expected to help alleviate identified reliability issues in southwest Connecticut and to help reduce congestion costs for all of Connecticut. This current cost estimate has increased from a previous estimate of $200 million due to a number of factors, including higher bids, especially for underground construction in southwest Connecticut, and additional requirements that were added during the extensive permitting and technical design process. While work on the related substations has begun, work on the transmission lines has not yet begun and is pending final reviews involving the CSC, the New England Independent System Operator (ISO-NE), and the Connecticut Department of Transportation. Management estimates a project completion date of December 2006, which is one year later than the previous estimate due to the Norwalk court appeal. At September 30, 2004, CL&P has capitalized $56.6 million associated with this project.
On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of a separate 345,000 volt transmission line from Norwalk, Connecticut to Middletown, Connecticut. The CSC has requested, and CL&P and UI have granted, a six-month extension of the date for final decision to April 2005. Construction is expected to commence shortly after the final route and configuration are determined by CSC. Some of the alternatives being considered by CL&P and evaluated by ISO-NE and CSC are significantly more costly than CL&P's previous estimate of $620 million for the total project. For forecasting purposes, CL&P is using an estimated total project cost of $700 million with a 2009 in service date, both of which recognize the complexity of the issues surrounding the siting and construction of the project, as well as the potential for court appeals of the CSC decision. The current estimated construction cost of this pr oject continues to be evaluated as the project scope and portions of the transmission line to be built overhead and underground are under review. CL&P will jointly site this project with UI, and CL&P will own 80 percent of the project. At September 30, 2004, CL&P has capitalized $15.8 million related to this project.
In September 2002, the CSC approved a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York. This project is estimated to cost in the range of $100 million, and CL&P and the Long Island Power Authority (LIPA) will each own approximately 50 percent of the line. CL&P has not yet signed a contract with a vendor to complete this work; therefore, the cost estimate could increase. The project has received CSC approval but still requires federal and New York state approvals. On October 1, 2004, consistent with a comprehensive settlement agreement reached on June 24, 2004, CL&P and LIPA jointly filed an implementation plan for the cable replacement with the Connecticut Department of Environmental Protection. Pending final approval, construction activities are scheduled to begin in the fall of 2006. Management expects the cable to be in service by the m iddle of 2008. At September 30, 2004, CL&P has capitalized $6.3 million related to this project.
In May 2004, CL&P applied to the CSC to construct two 115,000-volt underground transmission lines between Norwalk, Connecticut and Stamford, Connecticut. The project is expected to cost approximately $120 million and will help meet the growing electric demands in the area. Management expects the lines to be in service by 2008. At September 30, 2004, CL&P has capitalized $2.5 million related to this project.
In the first nine months of 2004, NU placed in service $85 million of electric transmission projects. These projects included CL&P's $37 million upgrade of a transmission substation in Stamford, Connecticut that will allow more than 100 additional MW to be imported into southwest Connecticut.
Connecticut - Yankee Gas: On September 3, 2004, the DPUC approved the application by Yankee Gas to construct a LNG storage facility in Waterbury, Connecticut, at an expected cost of approximately $100 million, that is capable of storing the equivalent of 1.2 billion cubic feet of natural gas. On October 18, 2004, Yankee Gas signed a contract with a vendor that will build the facility, which will be filled through both liquification of natural gas on-site and the transportation of LNG from off-site locations. Yankee Gas anticipates beginning construction late in 2004 and for the facility to become operational in late 2007 in time for the 2007/2008 heating season. At September 30, 2004, Yankee Gas has capitalized $5.4 million related to this project.
On November 1, 2004, Yankee Gas placed in service a new nine-mile gas line to connect its system in southeast Connecticut to the New England Gas Company (NEGASCO) system in Rhode Island. The construction project and a 20-year contract between Yankee Gas and NEGASCO were previously approved by the DPUC and the FERC. The NEGASCO project will provide Yankee Gas with additional revenue, improve service reliability in the Stonington, Connecticut area, and expand natural gas delivery into additional areas of southeastern Connecticut.
New Hampshire: In October 2004, PSNH received sufficient approvals to begin the construction related to the conversion of one of three 50 megawatt units at the coal-fired Schiller Station to burn wood (Northern Wood Project). The $75 million Northern Wood Project is expected to be completed by late 2006. The NHPUC’s approval of the project is subject to an appeal to the New Hampshire Supreme Court brought by some of New Hampshire’s existing wood-fired generating plant owners. Management does not believe that the appeal will negatively affect PSNH’s ability to complete the Northern Wood Project.
For further information regarding rate matters associated with business development and capital expenditures, see "Regulatory Issues and Rate Matters," in this Management's Discussion and Analysis.
Regional Transmission Organization
On October 31, 2003, the ISO-NE, along with NU and six other New England transmission owning companies, filed a proposal with the FERC to create an RTO for New England. On March 24, 2004, the FERC issued an order conditionally accepting the New England RTO proposal. The RTO is intended to strengthen the independent and efficient management of the region’s power system while ensuring that customers in New England continue to have highly reliable service and also realize the benefits of a competitive wholesale energy market.
In a separate filing made on November 4, 2003, NU along with six other New England transmission owners requested, consistent with the FERC’s pricing policy for RTOs and Order-2000-compliant independent system operators, that the FERC approve a single ROE for regional and local rates that would consist of a proposed 12.8 percent base ROE as well as incentive adders of 0.5 percent for joining a RTO and 1.0 percent for constructing new transmission facilities approved by the RTO.
In its March 24, 2004 order, the FERC accepted the proposal for the 0.5 percent incentive adder, but set for hearing the issues of the appropriate base ROE and the clarification as to which facilities the 1.0 percent incentive adder applies.
On October 29, 2004, NU along with the other New England transmission owners, filed rebuttal testimony with the FERC in preparation for December 2004 ROE hearings. The revised testimony, among other items, updated the required FERC discounted cash flow methodology calculations used to support the requested base ROE. This update to the calculations produced an 11.1 percent base ROE, which is 1.7 percent lower than the ROE originally proposed in November 2003 of 12.8 percent. The reduction in the ROE is due to changes in some of the inputs used in the discounted cash flow analysis. The incentive adders would still apply to the revised base ROE.
On November 3, 2004, the FERC issued an order that 1) determined that the New England transmission owners' methodology used to calculate the proposed ROE is appropriate, 2) provided guidance related to the incentive adders and 3) approved certain compliance items that were required by the FERC's March 24, 2004 order.
The order approved the methodology that had been proposed by the transmission owners for calculating the base ROE, which is based on the use of the mid-point of a proxy group of companies. The FERC found in its order that the proxy group proposed by the transmission owners was appropriate. The actual base ROE will be determined utilizing this methodology following the hearings, which are scheduled to commence in December 2004. Management cannot at this time predict the ultimate ROE that will be determined following the hearings, and cannot predict whether the hearings regarding the ROE will be contentious.
The order also clarified the application of the 0.5 percent incentive adder for joining a RTO and reaffirmed the appropriateness of the 1.0 percent incentive adder for new investments. However, still unresolved is the type of investments to which the FERC believes that the 1.0 percent incentive adder should apply.
A final ruling regarding these issues is expected in the second quarter of 2005.
Utility Group Regulatory Issues and Rate Matters
Transmission: On August 26, 2003, the transmission segment of NU's regulated companies filed a transmission rate case at the FERC. In the filing, the companies requested implementation of a formula rate that would allow recovery of increasing transmission expenditures on a timelier basis and that the changes, including a $23.7 million annual rate increase through 2004, take effect on October 27, 2003. The companies requested that the FERC maintain their existing 11.75 percent ROE until a ROE for the New England RTO is established by the FERC. On October 22, 2003, the FERC accepted this filing implementing the proposed rates subject to refund effective on October 28, 2003 and set several issues for hearing.
On June 14, 2004, the transmission segment of NU’s regulated companies reached a settlement agreement with the parties to its rate case which allows NU to implement formula-based rates as proposed, with an allowed ROE of 11.0 percent. This ROE will be superceded by the ROE determined as part of the ongoing RTO proceedings. On September 15, 2004, the FERC approved the settlement agreement. The impact of the change in ROE from 11.75 percent to 11.0 percent was recognized in the second quarter and reduced earnings by $1.1 million.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and NU’s Local Network Service (LNS) tariff. The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities. This regional rate is reset on June 1st of each year. The LNS tariff provides for the recovery of NU’s total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates. NU’s LNS tariff is also reset on June 1st of each year to coincide with the change in RNS rates. Additionally, NU’s LNS tariff provides for a true-up to actual costs which ensures that NU recovers its total transmis sion revenue requirements, including the allowed ROE. Through September 30, 2004, this true-up has resulted in the recognition of a $4 million regulatory liability.
A significant portion of NU's transmission businesses' revenue is from charges to NU's distribution businesses. These distribution businesses recover these charges through rates charged to their retail customers. WMECO has a rate tracking mechanism to track transmission costs charged in distribution rates to the actual amount of transmission charges incurred. The 2004 rates set in the CL&P distribution rate case contained a level of transmission revenue sufficient to recover CL&P's anticipated 2004 transmission costs. CL&P continues to evaluate whether or not it will seek a new retail transmission rate in 2005. The June 1, 2005 PSNH rate increase includes revenues to recover expected transmission costs. Neither CL&P nor PSNH have transmission tracking mechanisms.
Connecticut - CL&P:
Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor of Connecticut signed into law Public Act No. 03-135 (the Act) which amended Connecticut's 1998 electric utility industry legislation. The Act required CL&P to file a four-year transmission and distribution plan with the DPUC. On December 17, 2003, the DPUC issued its final decision in the rate case.
CL&P filed a petition for reconsideration of certain items in the final decision on December 31, 2003. Other parties also filed petitions for reconsideration. The DPUC issued a final decision on the petitions on August 4, 2004. The final decision allows CL&P to recover an additional $32 million beginning August 1, 2004. The DPUC also authorized using existing CTA overrecoveries in lieu of an increase in rates to recover approximately $24 million, which is the net present value of the $32 million.
The final decision had a third quarter positive pre-tax impact of $10.2 million (approximately $6 million after-tax) on CL&P. The remaining amount will be amortized over four years as an increase to revenues as the related costs to be recovered are incurred. The DPUC's conclusion on streetlighting refund periods and methodologies was also included in the final decision, and management has determined that the streetlighting refund period and methodology included in the final decision did not have an impact on CL&P's net income or financial position at September 30, 2004.
Under the Act, CL&P is allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (kWh) from customers who purchase transitional standard offer service (TSO). That fee can increase to 0.75 mills if CL&P beats certain regional benchmarks. The fixed portion of the procurement fee amounted to approximately $9 million for the nine months ended September 30, 2004, and is expected to total approximately $12 million (approximately $7 million after-tax) for 2004. CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee. A decision is expected in the first quarter of 2005. The variable portion of the procurement fee has not been recorded in 2004 and could total approximately $6 million if CL&P's proposed methodology is approved by the DPUC.
CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and independent power producer (IPP) over market costs, while the 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 worker protection costs.
On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the DPUC, which compares CTA and SBC revenues to revenue requirements. A final decision in the 2003 CTA and SBC docket was issued on August 4, 2004 and ordered a refund to customers of $88.5 million over a seven-month period beginning with October 2004 consumption.
The DPUC also directed CL&P to impute revenues of $2.7 million during 2004 payable to customers associated with a previously renegotiated IPP contract. On September 15, 2004, CL&P filed an appeal and a motion for partial stay with the Connecticut Superior Court challenging the DPUC’s August 4, 2004 decision regarding this contract. The motion for partial stay was granted. On October 15, 2004, CL&P entered into a settlement agreement involving the counterparties to this contract and various other parties. If approved by the DPUC and by the bankruptcy court of one of the counterparties, the DPUC will rescind the imputed revenues order and CL&P would withdraw its appeal. CL&P is awaiting approvals of the settlement agreement.
In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued a final decision denying CL&P's request, and on October 24, 2003, CL&P appealed the DPUC's final decision to the Connecticut Superior Court. The appeal has been fully briefed and is in the argument phase, and a decision from the Connecticut Superior Court could be rendered by the end of 2004. If CL&P's request is granted through these court proceedings, then there could be additional amounts due to CL&P from its customers. The 2004 impact of including the deferred intercompany liability in CTA revenue requirements has been a reduction of approximately $19.3 million in revenue.
Impacts of Standard Market Design: On March 1, 2003, ISO-NE implemented SMD. As part of SMD, LMP is utilized to assign value and causation to transmission congestion and line losses. Transmission congestion costs represent the additional costs incurred due to the need to run uneconomic generating units in certain areas that have transmission constraints, which prevent these areas from obtaining alternative lower-cost generation. Line losses represent losses of electricity as it is sent over transmission lines.
CL&P was billed $186 million of incremental LMP costs in 2003 by its standard offer service suppliers, including affiliate Select Energy, or by ISO-NE and collected $158 million from its customers. CL&P and its suppliers disputed the responsibility for the $186 million of incremental LMP costs incurred. An agreement was reached settling the dispute among all the parties involved and was filed with the FERC on March 3, 2004. NU recorded a pre-tax loss in 2003 of approximately $60 million (approximately $37 million after-tax) related to this settlement agreement. The settlement agreement was approved by the FERC on June 28, 2004.
On July 8, 2004, CL&P paid the standard offer service suppliers $83 million as part of the approved settlement agreement. On August 25, 2004, the DPUC approved a joint proposal for refunding the remaining $75 million to customers. The approved refund was included in customer bills beginning with September 2004 billings and will continue through December 2004 billings. The refund will total $83.5 million, consisting of the remaining $75 million of SMD amounts and an additional $8.5 million associated with previous replacement power costs collected from customers but later recouped from a supplier.
Application for Issuance of Long-Term Debt: On September 9, 2004, CL&P filed an application with the DPUC requesting approval to issue long-term debt in the amount of $600 million during the period February 1, 2005 to December 31, 2007. Additionally, CL&P is requesting approval to enter into hedging transactions, from time to time ending on December 31, 2007, in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associated with the debt or debt issuances. The DPUC has not yet issued a schedule for review of this application.
Connecticut - Yankee Gas:
Rate Case Filing: On July 2, 2004, Yankee Gas filed a rate case with the DPUC to increase retail rates by $26.5 million, or 7.2 percent, effective January 1, 2005. Yankee Gas also requested an authorized ROE of 10.75 percent in the rate case filing. The requested increase in rates results from increased costs of distribution delivery services such as pension and healthcare, as well as additional investments needed to maintain a safe and reliable gas distribution system.
On October 14, 2004, Yankee Gas filed a settlement agreement with the DPUC. Parties to the agreement included the OCC and the Prosecutorial Division of the DPUC. The settlement agreement increases customer rates by $14 million annually, allows an ROE of 9.9 percent and reduces Yankee Gas' annual expense for plant taken out of service by approximately $5 million. As part of the settlement agreement, Yankee Gas has generally agreed not to file a new rate increase application prior to the earlier of the in-service date of its new LNG facility or July 1, 2007. The DPUC has suspended the rate case hearing schedule and held a hearing on October 28, 2004 to review the settlement agreement. A decision is expected during the fourth quarter of 2004.
New Hampshire:
Delivery Rate Case: PSNH's delivery rates were fixed, effective May 1, 2001, by the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) until February 1, 2004. Consistent with the requirements of the Restructuring Settlement and state law, PSNH filed a delivery service rate case and tariffs with the NHPUC on December 29, 2003 to increase electricity delivery rates by approximately $21 million, or 2.6 percent, effective February 1, 2004.
On July 14, 2004, PSNH filed with the NHPUC a revenue requirements settlement agreement among several parties, including the NHPUC staff and the Office of Consumer Advocate (OCA). The terms of the proposed settlement agreement allowed for increases in PSNH's delivery rates totaling $3.5 million annually, effective prospectively on October 1, 2004, and an incremental $10 million annual increase effective prospectively on June 1, 2005, for a total rate increase of $13.5 million. On July 29, 2004, PSNH filed with the NHPUC a rate design settlement agreement among several parties, including the NHPUC staff. These proposed revenue requirements and rate design settlement agreements together resolve all delivery service rate case issues. On September 2, 2004, the NHPUC issued an order approving both settlement agreements, and new delivery service rates went into effect on October 1, 2004.
Transition Energy Service: In accordance with the Restructuring Settlement and state law, PSNH files for updated transition energy service (TS) rates annually. Presently, TS rates for all customers may change annually effective February 1st. The TS rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation investment. PSNH defers any difference between its TS revenues and the actual costs incurred.
On September 24, 2004, PSNH filed a petition with the NHPUC requesting a change in the TS rate for the period February 1, 2005 through January 31, 2006. In its filing, PSNH did not request a specific TS rate; rather, given the current price volatility in the energy markets, PSNH requested that the NHPUC review and approve its underlying operational data within the September 24, 2004 filing. In December 2004, PSNH expects to petition for a specific TS rate based on updated market information. Management expects the NHPUC to issue an order prior to February 1, 2005.
SCRC Reconciliation Filing: The stranded cost recovery charge (SCRC) allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues billed with stranded costs, and TS revenues billed with TS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $200.6 million at September 30, 2004. This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $422.6 million to $222 million.
The 2003 SCRC reconciliation filing was filed with the NHPUC on April 30, 2004, and a proposed stipulation and settlement agreement between PSNH, the OCA and NHPUC staff was filed with the NHPUC on October 4, 2004. Under the terms of the settlement agreement, no costs related to the recovery of stranded costs or the cost of providing TS were disallowed, and the NHPUC staff agreed to accept the 2003 SCRC filing without change. On October 29, 2004, the NHPUC issued an order accepting the settlement agreement as filed.
Estimated unbilled revenues are not included in the reconciliation of billed revenues to incurred costs through rate mechanisms for the SCRC and the TS. At September 30, 2004, the unbilled balance related to SCRC and TS was $11.7 million and $16.7 million, respectively. The level of the TS rate will vary from time to time and will continue until it is replaced with "Default Energy Service," or some equivalent, which will then continue indefinitely. The SCRC rate is expected to begin decreasing in late 2006. Management will seek from regulators a determination as to the ultimate inclusion of any of this unbilled revenue into billed rates.
Massachusetts:
Transition Cost Reconciliation: On March 31, 2004, WMECO filed its 2003 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy. This filing reconciled the recovery of generation-related stranded costs for calendar year 2003. The timing of a final decision is uncertain, but management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or financial position.
NU Enterprises
Business Segments:NU Enterprises aligns its businesses into two business segments, the merchant energy business segment and the energy services business segment. The merchant energy business segment includes Select Energy's wholesale and retail marketing businesses. Also included in this segment are 1,440 MW of generation assets, including 1,293 MW of pumped storage and hydroelectric generation assets at NGC and 147 MW of coal-fired generation assets at HWP. The wholesale business primarily services firm requirements sales to local distribution companies and bilateral sales to other counterparties. To serve these customers, Select Energy relies on its own generation and inventory of energy products procured in the market.
The energy services business segment includes the operations of SESI, NGS, and Woods Network. SESI performs energy management services for large commercial customers, institutional facilities and the United States government and energy-related construction services. NGS operates and maintains NGC's and HWP's generation assets and provides third-party electrical services. Woods Network is a network design, products and services company.
Outlook: During 2004, NU expects that NU Enterprises will earn in the range of $30 million to $33 million, with the merchant energy business segment expected to earn in the range of between $29 million and $31 million and the energy services business segment expected to earn in the range of between $1 million and $2 million. Those ranges are dependent on NU Enterprises' ability to achieve targeted origination margins, successfully manage its contract portfolios and improve the financial performance of the energy services business segment.
Intercompany Transactions: CL&P's standard offer purchases from Select Energy represented $134.8 million for the three months ended September 30, 2004, compared with $184.9 million during the same period in 2003. Other energy purchases between CL&P and Select Energy totaled $25.7 million for the three months ended September 30, 2004 and $32.2 million during the same period in 2003. Additionally, WMECO's purchases from Select Energy represented $28 million for the three months ended September 30, 2004, compared with $42.1 million during the same period in 2003.
CL&P's standard offer purchases from Select Energy represented $391.5 million for the first nine months of 2004, compared with $464.8 million during the same period in 2003. Other energy purchases between CL&P and Select Energy totaled $83.4 million for the first nine months of 2004 and $101.4 million during the same period in 2003. Additionally, WMECO's purchases from Select Energy represented $81.5 million for the first nine months of 2004, compared with $110.3 million during the same period in 2003. These amounts are eliminated in consolidation.
NU Enterprises' Market and Other Risks
Overview: For further information on risk management activities, see "Competitive Energy Subsidiaries' Market and Other Risks" in NU's combined report on Form 10-K.
Risk management within Select Energy is organized to address the market, credit and operational exposures arising from the merchant energy business segment, which include: wholesale marketing activities (including limited energy trading for market and price discovery purposes as well as asset optimization) and retail marketing activities. The framework for managing these risks is set forth in NU's risk management policies and procedures, which are reviewed by the NU Board of Trustees on an as needed basis.
Merchant Energy Marketing Activities: Select Energy manages its portfolio of wholesale and retail marketing contracts and assets to maximize value while maintaining an acceptable level of risk. At forward market prices in effect at September 30, 2004, the wholesale marketing portfolio had a positive fair value. This positive fair value indicates a likely positive impact on Select Energy's gross margin in the future. However, there could be significant volatility in the energy commodities markets that may affect this position between now and when the contracts are settled. Accordingly, there can be no assurances that Select Energy will realize the gross margin corresponding to the present positive fair value of its wholesale marketing portfolio.
Hedging and Non-Trading: For information on derivatives used for hedging purposes and non-trading derivatives, see Note 2, "Derivative Instruments," to the consolidated financial statements.
Wholesale Contracts Defined as "Energy Trading": Energy trading transactions at Select Energy include financial transactions and physical delivery transactions for electricity, natural gas and oil in which Select Energy is attempting to profit from changes in market prices. Energy trading contracts are recorded at fair value, and changes in fair value affect net income.
At September 30, 2004, Select Energy had trading derivative assets of $94 million and trading derivative liabilities of $71 million, for a net positive position of $23 million for the entire trading portfolio. These amounts are combined with other derivatives and are included in derivative assets and derivative liabilities on the accompanying consolidated balance sheets. The decrease in both derivative asset and liability amounts from June 30, 2004, relates primarily to contracts realized or otherwise settled during the period. Information regarding non-trading and other derivatives is included in Note 2, "Derivative Instruments," to the consolidated financial statements.
There can be no assurances that Select Energy will realize cash corresponding to the present positive net fair value of its trading positions. Numerous factors could either positively or negatively affect the realization of the net fair value amount in cash. These include the volatility of commodity prices, changes in market design or settlement mechanisms, the outcome of future transactions, the performance of counterparties, and other factors.
Select Energy has policies and procedures requiring all trading positions to be marked-to-market at the end of each business day and segregating responsibilities between the individuals actually trading (front office) and those confirming the trades (middle office). The determination of the portfolio's fair value is the responsibility of the middle office independent from the front office.
The methods used to determine the fair value of energy trading contracts are identified and segregated in the table of fair value of contracts at September 30, 2004. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures and options 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 or natural gas, and are marked to the mid-point of bid and ask market prices. Currently, Select Energy has no contracts for which fair value is determined based on a model or other valuation method. Broker quotes for electricity at locations that Select Energy has entered into deals are available through the year 2006. Broker quotes for natural gas are available through 2013.
Generally, valuations of short-term 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 contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded. However, Select Energy has obtained corresponding purchase or sale contracts for substantially all of the trading contracts that have maturities in excess of one year. Because these contracts are sourced, changes in the value of these contracts due to fluctuations in commodity prices are not expected to affect Select Energy's earnings.
As of and for the nine months ended September 30, 2004, the sources of the fair value of trading contracts and the changes in fair value of these trading contracts are included in the following tables. Intercompany transactions are eliminated and not reflected in the amounts below.
(Millions of Dollars) | Fair Value of Trading Contracts at September 30, 2004 | |||
Sources of Fair Value | Maturity Less | Maturity of One | Maturity in Excess | Total Fair |
Prices actively quoted | $0.7 | $0.2 | $ - | $ 0.9 |
Prices provided by external sources | 1.1 | 7.7 | 13.3 | 22.1 |
Totals | $1.8 | $7.9 | $13.3 | $23.0 |
The fair value of energy trading contracts decreased $5.3 million from $28.3 million at June 30, 2004 to $23 million at September 30, 2004. The change in the fair value of the trading portfolio is primarily attributable to contracts realized or otherwise settled during the period. There were no changes in valuation techniques or assumptions in the third quarter of 2004.
Total Portfolio Fair Value | ||
(Millions of Dollars) | Three Months Ended | Nine Months Ended |
Fair value of trading contracts outstanding | $28.3 | $32.5 |
Contracts realized or otherwise settled during the period | (5.4) | (11.5) |
Changes in fair value of contracts | 0.1 | 2.0 |
Fair value of trading contracts outstanding | $23.0 | $23.0 |
Changing Market: The breadth and depth of the market for energy marketing products in Select Energy's areas of business have been adversely affected by the withdrawal or financial weakening of a number of companies, particularly power marketers, who have historically done significant amounts of business with Select Energy. In general, the market for such products is shorter term in nature with less liquidity, market pricing information is less readily available and participants are sometimes unable to meet Select Energy's credit standards without providing cash or LOC support. Select Energy is being adversely affected by these factors, and there could be a continuing adverse impact on Select Energy's business lines due to its increasing reliance on business arrangements with a more limited number of counterparties, primarily power generators.
Changes are occurring in the administration of transmission systems in territories in which Select Energy does business. RTOs are being proposed and approved, and other changes in market design are occurring within transmission regions. As the market continues to evolve, there could be additional challenges or opportunities that management cannot determine at this time.
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 written 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, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy's entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may affect Select Energy's over all exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At September 30, 2004, approximately 74 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was cash collateralized or rated BBB- or better. Select Energy held $67.4 million and $46.5 million of counterparty cash advances at September 30, 2004 and December 31, 2003, respectively. For further information, see Note 1I, "Cash and Cash Equivalents," to the consolidated financial statements.
Select Energy's Credit: A number of Select Energy's contracts require the posting of additional collateral in the form of cash or LOCs in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline. At NU's present investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline two to three levels to sub-investment grade, Select Energy could, under its present contracts, be asked to provide approximately $384 million of collateral or LOCs to various unaffiliated counterparties and approximately $136 million to several independent system operators and unaffiliated local distribution companies, which management believes NU would currently be able to provide, subject to the SEC limits described below. NU's credit ratings outlooks are currently stable or negative, but management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.
On June 30, 2004, the SEC issued an order allowing NU to significantly expand its financial support of NU Enterprises. The new order allows NU through June 30, 2007 to 1) increase its allowable investments in certain of its unregulated businesses, presently 15 percent of its consolidated capitalization as permitted by SEC regulation, by an additional $500 million, 2) increase the limit for its guarantees of all of its competitive affiliates from $500 million to $750 million, and 3) increase its allowable investments in exempt wholesale generators (EWGs) from $481 million to $1 billion. The order will permit NU to fully support the planned level of business activities of Select Energy and its other unregulated businesses. NU has no present plans to significantly expand its EWG portfolio. However, if an investment opportunity becomes available, NU will be able to pursue it within the new allowable EWG investment level.
For further information regarding Select Energy's activities and risks, see Note 2, "Derivative Instruments," and Note 5, "Comprehensive Income," to the consolidated financial statements.
Critical Accounting Policies and Estimates Update
Income Taxes:Income tax expense is calculated in each reporting period in each of the jurisdictions in which NU operates. This process involves estimating actual current tax expense or benefit as well as the income tax impact of temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses, for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. The income tax estimation process impacts all of NU's segments. Adjustments made to income tax estimates can significantly affect NU's consolidated financial statements.
The estimates that are made by management in order to record income tax expense are compared each year to the actual tax amounts included on NU's income tax returns as filed. The income tax returns were filed in the fall of 2004 for the 2003 tax year. Management adjusted NU's tax reserves to reflect the difference in the actual 2003 tax return amounts being compared to the 2003 year end estimated tax expense. Recording these tax reserve adjustments resulted in a positive impact in the third quarter on NU's earnings of approximately $3.7 million, including a PSNH adjustment of a positive $5.4 million, a CL&P adjustment of a negative $3.2 million, a WMECO adjustment of a positive $0.6 million, and a NU Enterprises adjustment of a positive $1.8 million. Adjustments for other NU subsidiaries amounted to a negative $0.9 million. The process of truing up the income tax differences between the consolidated financial statements and the income tax returns is an annual procedure.
Goodwill Impairment Testing: NU conducts annual goodwill impairment testing as of October 1st. Testing of current goodwill balances commenced in October of 2004.
Derivative Accounting and the Election of Normal: Most of the contracts comprising Select Energy's wholesale and retail marketing activities are derivatives. The application of derivative accounting under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, is complex and requires management's judgment. Judgment is applied in the election and designation of the normal purchases and sale exception (and resulting accrual accounting), which includes the conclusions 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. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting would be term inated and fair value accounting would be applied.
Adjustments to the Impact of the Medicare Subsidy: On December 8, 2003, the President signed into law a bill that expanded Medicare, primarily by adding a prescription drug benefit and by adding a federal subsidy to qualifying plan sponsors of retiree health care benefit plans. Management believes that NU currently qualifies for the subsidy.
The actuarial gain resulting from the expansion of the Medicare program decreases the postretirement benefits other than pensions (PBOP) accumulated plan benefit obligation. Based on the most recent actuarial valuation as of January 1, 2004, the impact of the Medicare program has been revised from a $20 million decrease in the PBOP benefit obligation at December 31, 2003 to $27 million at September 30, 2004. The total $27 million decrease consists of $20 million as a direct result of the subsidy for certain non-capped retirees and $7 million related to changes in participation assumptions for capped retirees and future retirees as a result of the subsidy. The total $27 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years. For the nine months ended September 30, 2004, this reduction in PBOP expense totaled approximately $2.8 million, including amortization of the actuarial gain of $1. 5 million and a reduction in interest cost based on a lower PBOP benefit obligation of $1.3 million.
Utility Group Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not been billed. Unbilled revenues are assets on the balance sheet that become 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 Utility Group estimates unbilled revenues monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less the total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales. The estimated DE factor can have a significant impact on estimated unbilled revenue amounts.
In accordance with management's policy of testing the estimate of unbilled revenues twice each year using the cycle method of estimating unbilled revenues, testing was performed in the second quarter of 2004. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is more accurate than the requirements method when used in a mostly weather-neutral month.
The cycle method testing resulted in adjustments to the estimate of unbilled revenues that had a net positive after-tax earnings impact of $1.5 million in the second quarter of 2004. There were positive after-tax impacts on CL&P, WMECO and Yankee Gas of $1.8 million, $0.9 million, and $0.5 million, respectively, while there was a negative after-tax impact on PSNH of $1.7 million.
Testing using the cycle method will be performed again in the fourth quarter of 2004, and any adjustment will be recorded in the fourth quarter of 2004.
Other Matters
Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 4, "Commitments and Contingencies," to the consolidated financial statements.
The following are material updates to the table of contractual obligations and commercial commitments disclosed in NU's 2003 report on Form 10-K:
(Millions of Dollars) | 2004 | 2005 | 2006 | 2007 | 2008 | Thereafter |
Contracted expenditures for construction of Yankee Gas LNG facility | $ 7.5 | $ 30.6 | $ 39.3 | $ 3.4 | $ - | $ - |
Northern Wood Project | 21.6 | 36.5 | 5.6 | - | - | - |
FERC-approved billings from the Yankee Companies | 40.8 | 92.5 | 74.4 | 68.6 | 60.9 | 113.5 |
$69.9 | $159.6 | $119.3 | $72.0 | $60.9 | $113.5 |
Certain other estimated construction expenditures totaling $19.2 million related to the Yankee Gas LNG facility and $11.3 million related to the Northern Wood Project are not included in the contracts signed to build these facilities and are not included in the table above. NU's other long-term contractual arrangements have not changed materially from the amounts reported at December 31, 2003.
Forward Looking Statements: This discussion and analysis includes statements concerning NU's expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward looking statements” within the meaning of the Private Litigation Reform Act of 1995. In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and 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 looking statements. Factors that may cause actual results to differ materially from those included in the forward looking statements include, but a re not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, expiration or initiation of significant energy supply contracts, regulations or regulatory policy, levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC. Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.
Website: Additional financial information is available through NU’s website at www.nu.com.
RESULTS OF OPERATIONS - NU CONSOLIDATED
The following table provides the variances in income statement line items for the consolidated statements of income for NU included in this report on Form 10-Q for the third quarter of 2004 and the first nine months of 2004:
Income Statement Variances | ||||||||||||
Third | Percent | Nine | Percent | |||||||||
Operating Revenues: | $ | 28 | 2 | % | $ | 476 | 10 | % | ||||
Operating Expenses: | ||||||||||||
Fuel, purchased and net interchange power | (2) | - | 357 | 13 | ||||||||
Other operation | 41 | 18 | 126 | 19 | ||||||||
Maintenance | 8 | 17 | 12 | 14 | ||||||||
Depreciation | 6 | 12 | 16 | 11 | ||||||||
Amortization | (14) | (24) | (40) | (28) | ||||||||
Amortization of rate reduction bonds | 3 | 6 | 9 | 8 | ||||||||
Taxes other than income taxes | 2 | 4 | 10 | 6 | ||||||||
Total operating expenses | 44 | 3 | 490 | 12 | ||||||||
Operating income | (16) | (13) | (14) | (3) | ||||||||
Interest expense, net | - | - | 3 | 2 | ||||||||
Other income, net | 3 | 75 | 7 | (a) | ||||||||
Income before income tax expense | (13) | (19) | (10) | (5) | ||||||||
Income tax expense | (8) | (34) | 8 | (11) | ||||||||
Preferred dividends of subsidiary | - | - | - | - | ||||||||
Income before cumulative effect of accounting change | (5) | (11) | (2) | (1) | ||||||||
Cumulative effect of accounting change, net of tax benefit | 5 | 100 | 5 | 100 | ||||||||
Net Income |
| $ | - |
| - | % | $ | 3 | 2 | % | ||
(a) Percent greater than 100.
Comparison of the Third Quarter of 2004 to the Third Quarter of 2003
Operating Revenues
Total revenues increased $28 million in the third quarter of 2004, compared with the same period in 2003, due to higher revenues from NU Enterprises ($78 million after intercompany eliminations), higher gas distribution revenues ($17 million) and higher regulated transmission revenues ($5 million after intercompany eliminations), partially offset by lower electric distribution revenues ($72 million).
NU Enterprises' contribution to consolidated NU revenues increased primarily due to more of its revenues coming from companies that are not other subsidiaries of NU ($71 million), and due to higher revenues for the merchant energy segment resulting from higher gas prices and volumes ($10 million). Total NU Enterprises third quarter revenues before eliminations were flat in 2004 compared to 2003.
The electric distribution revenue decrease is primarily due to lower SMD revenue for CL&P ($91 million), lower sales volume for distribution revenues ($14 million) which includes the absence of the 2003 positive unbilled revenue estimate change, lower CL&P Energy Adjustment Clause (EAC) revenue as a result of the end of EAC billings in December 2003 ($12 million), lower revenues for CL&P and WMECO transition charges ($17 million), partially offset by increases in the standard offer, TS, and default service revenues for CL&P, PSNH and WMECO ($41 million) due mainly to rate increases and Federally Mandated Congestion Cost (FMCC) revenues for CL&P ($40 million). Electric retail kWh sales decreased by 4.9 percent in the third quarter of 2004 primarily due to the 2003 unbilled revenue estimate change. In addition, electric wholesale revenues decreased by $27 million primarily due to lower short-term transactions ($21 million) and t he expiration of long-term contracts ($6 million).
The higher gas distribution revenues are primarily due to the absence of the 2003 negative adjustment to the estimate of unbilled revenues ($19 million).
Transmission revenues were higher due to the October 2003 implementation of the transmission rate case filed at the FERC.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $2 million in the third quarter of 2004, primarily due to lower wholesale costs at NU Enterprises ($14 million after intercompany eliminations) partially offset by higher purchased power costs for the Utility Group ($11 million after intercompany eliminations). The increase for the Utility Group is primarily due to more of its standard offer service being provided by companies that are not other subsidiaries of NU ($71 million) as a result of the change in the amount of standard offer service provided by Select Energy, partially offset by the decrease in the CL&P fuel expense amortization resulting from the rate adjustment clauses ($62 million).
Other Operation
Other operation expenses increased $41 million in the third quarter of 2004, primarily due to higher competitive business expenses resulting from business growth ($19 million) and higher CL&P reliability must run costs ($22 million) and other power pool related expenses ($6 million), higher regulated business administrative and general expenses ($13 million) primarily due to higher pension costs and higher distribution expenses ($2 million), partially offset by lower C&LM spending ($13 million).
Maintenance
Maintenance expenses increased $8 million in the third quarter of 2004, primarily due to higher distribution maintenance expense ($3 million) and higher fossil production expense ($3 million).
Depreciation
Depreciation increased $6 million in the third quarter of 2004 due to higher Utility Group plant balances and higher depreciation rates at CL&P resulting from the distribution rate case decision effective in January 2004.
Amortization
Amortization decreased $14 million in the third quarter of 2004 primarily due to lower Utility Group recovery of stranded costs ($7 million) and a decrease in CL&P amortization expense resulting from the distribution rate case decision effective in January 2004 ($7 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $3 million in the third quarter of 2004 due to the repayment of additional principal as compared to 2003.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $2 million in the third quarter of 2004 primarily due to higher local property taxes, higher payroll taxes and higher sales tax.
Other Income, Net
Other income, net increased $3 million in the third quarter of 2004 primarily due to the recognition beginning in 2004 of a CL&P procurement fee approved in the December 2003 TSO docket decision ($3 million).
Income Tax Expense
Income tax expense decreased $8 million in the third quarter of 2004 due to lower income before tax expense along with a lower effective tax rate due to adjustments to tax reserves as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates.
Comparison of the First Nine Months of 2004 to the First Nine Months of 2003
Operating Revenues
Total revenues increased $476 million in the first nine months of 2004, compared with the same period in 2003, due to higher revenues from NU Enterprises ($377 million after intercompany eliminations), higher electric distribution revenues ($53 million), higher gas distribution revenues ($38 million) and higher regulated transmission revenues ($8 million after intercompany eliminations).
The NU Enterprises’ revenue increase is primarily due to higher revenues for the merchant energy segment resulting from higher electric prices ($146 million), higher gas volumes ($54 million) and higher gas prices ($25 million), partially offset by lower electric volumes ($7 million). The NU Enterprises' contribution to consolidated NU revenues increased due to more of its revenues coming from companies that are not other subsidiaries of NU ($122 million).
The electric distribution revenue increase is primarily due to increases in the standard offer, TS, and default service revenues for CL&P, PSNH and WMECO ($192 million) due mainly to rate increases, FMCC revenues for CL&P ($115 million) and higher CL&P retail transmission rates ($20 million), partially offset by lower SMD revenue for CL&P ($120 million), lower CL&P EAC revenue as a result of the end of EAC billings in December 2003 ($33 million) and lower revenues for CL&P and WMECO transition revenues ($34 million). In addition, electric wholesale revenues decreased by $74 million primarily due to lower short-term transactions ($56 million) and the expiration of long-term contracts ($18 million).
The higher gas distribution revenue is primarily due to the increased recovery of gas costs and the absence of the 2003 unbilled revenue estimate change ($28 million).
Transmission revenues were higher due to the October 2003 implementation of the transmission rate case filed at the FERC.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $357 million in the first nine months of 2004, primarily due to higher wholesale costs at NU Enterprises ($184 million after intercompany eliminations) and higher purchased power costs for the Utility Group ($170 million after intercompany eliminations). The increase for the Utility Group is primarily due to more of its standard offer service being provided by companies that are not other subsidiaries of NU ($122 million) as a result of the change in the amount of standard offer service provided by Select Energy,an increase in the standard offer service requirements rates for CL&P ($66 million) and WMECO ($15 million), higher Yankee Gas expenses due to increased gas prices ($28 million), partially offset by the 2003 recovery of certain fuel costs ($33 million), lower wholesale purchases for CL&P ($17 million) and WMECO ($5 million), and lower expenses for PS NH due to lower regulated energy and capacity purchases ($7 million).
Other Operation
Other operation expenses increased $126 million in the first nine months of 2004, primarily due to higher competitive business expenses resulting from business growth ($57 million), higher CL&P reliability must run costs ($42 million) and other power pool related expenses ($8 million), higher regulated business administrative and general expenses ($18 million) primarily due to higher pension costs, higher fossil production expense ($4 million), higher distribution expenses ($4 million), and higher nuclear related expenses as a result of the absence of the 2003 CL&P Millstone use of proceeds docket ($2million), partially offset by lower C&LM spending ($11 million). That docket resulted in the recovery of certain other operation costs and maintenance costs that were expensed in periods prior to 2003. The recovery of these costs through the use of proceeds docket resulted in credits to these accounts in the fi rst quarter of 2003.
Maintenance
Maintenance expenses increased $12 million in the first nine months of 2004, primarily due to higher distribution maintenance expense ($6 million) and the absence of the 2003 positive resolution of the CL&P Millstone use of proceeds docket ($5 million).
Depreciation
Depreciation increased $16 million in the first nine months of 2004 due to higher Utility Group plant balances and higher depreciation rates at CL&P resulting from the distribution rate case decision effective in January 2004.
Amortization
Amortization decreased $40 million in the first nine months of 2004 primarily due to lower Utility Group recovery of stranded costs and a decrease in amortization expense resulting from the implementation of the CL&P distribution rate case decision effective in January 2004 ($22 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $9 million in the first nine months of 2004 due to the repayment of additional principal as compared to 2003.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $10 million in the first nine months of 2004 primarily due to higher Connecticut gross earnings tax as a result of an increase in revenues for NU Enterprises, CL&P and Yankee Gas, higher local property taxes, higher payroll taxes and higher sales tax.
Interest Expense, Net
Interest expense, net increased $3 million in the first nine months of 2004 primarily due to the issuance of $75 million of ten-year notes at Yankee Gas in January 2004.
Other Income, Net
Other income, net increased $7 million in the first nine months of 2004 primarily due to the recognition beginning in 2004 of a CL&P procurement fee approved in the TSO docket decision ($9million).
Income Tax Expense
Income tax expense decreased $8 million in the first nine months of 2004 due to lower income before tax expense along with a lower effective tax rate due to adjustments to tax reserves as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and Shareholders of Northeast Utilities
We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries ("the Company") as of September 30, 2004, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2004 and 2003, and of cash flows for the nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
We conducted our reviews in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, shareholders’ equity, cash flows and income taxes for each of the three years in the period ended December 31, 2003 (not presented herein); and in our report dated February 23, 2004, we expressed an unqualified opinion (which includes an explanatory paragraph with respect to the Company’s adoption in 2001 of Statement of Financial Accounting Standards (SFAS) No. 133,Accounting for Derivative Instruments and Hedging Activitiesas amended, its adoption in 2003 of Emerging Issues Task Force No. 03-11,Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and not “He ld for Trading Purposes” as Defined in Issue No. 02-3and FASB Interpretation No. 46,Consolidation of Variable Interest Entities,and its adoption in 2002 of SFAS No. 142,Goodwill and Other Intangible Assets) on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/
Deloitte & Touche LLP
Deloitte & Touche LLP
Hartford, Connecticut
November 5, 2004
NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)
A.
Presentation
The accompanying unaudited financial statements should be read in conjunction with this complete report on Form 10-Q, the First and Second Quarter 2004 reports on Form 10-Q, and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed as part of the NU 2003 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q. The accompanying financial statements contain, in the opinion of management, all adjustments necessary to present fairly NU's and the above companies' financial position at September 30, 2004, the results of operations for the three-month and nine-month periods ended September 30, 2004 and 2003, and statements of cash flows for the nine-mon th periods ended September 30, 2004 and 2003. All adjustments are of a normal, recurring nature except those described in Note 1B. Due primarily to the seasonality of NU’s business and to the quarterly earnings profile of NU Enterprises’ merchant energy business segment in 2004, the results of operations and statements of cash flows for the nine-month periods ended September 30, 2004 and 2003, are not indicative of the results expected for a full year.
The consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.
The preparation of financial statements 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 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 in the accompanying financial statements have been made to conform with the current period presentation.
B.
New Accounting Standards
Other-Than-Temporary Impairments: The Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) issued and later deferred the effective date of accounting guidance included in EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments." EITF Issue No. 03-1 provides guidance on how to evaluate and recognize an impairment loss that is other-than-temporary and could impact NU's investments in Acumentrics Corporation (Acumentrics) and NEON Communications, Inc. (NEON) upon its effective date. Certain accounting guidance included in EITF Issue No. 03-1 is not effective until the FASB issues additional guidance on this issue. EITF Issue No. 03-1 also requires certain annual disclosures that are effective for NU's December 31, 2004 annual report on Form 10-K.
For further information regarding NU's investments in Acumentrics and NEON, see Note 1H, "Summary of Significant Accounting Policies - Other Investments," to the consolidated financial statements.
C.
Guarantees
NU provides credit assurance in the form of guarantees and letters of credit (LOCs) in the normal course of business, primarily for the financial performance obligations of NU Enterprises. NU would be required to perform under these guarantees in the event of non-performance by NU Enterprises, primarily Select Energy, Inc. (Select Energy). At September 30, 2004, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU, primarily on behalf of NU Enterprises, totaled $990.8 million. Additionally, NU had $113.6 million of LOCs issued for the benefit of NU Enterprises outstanding at September 30, 2004.
At September 30, 2004, NU had outstanding guarantees on behalf of the Utility Group of $11.2 million. This amount is included in the total outstanding NU guarantee exposure amount of $990.8 million.
Several underlying contracts that NU guarantees and certain surety bonds contain credit ratings triggers that would require NU to post collateral in the event that NU’s credit ratings are downgraded below investment grade.
NU currently has authorization from the Securities and Exchange Commission (SEC) to provide up to $750 million of guarantees for NU Enterprises through June 30, 2007. The $11.2 million in guarantees to the Utility Group are subject to a separate $50 million SEC limitation apart from the current $750 million guarantee limit. The amount of guarantees outstanding for compliance with the SEC limit for NU Enterprises at September 30, 2004 is $422 million, which is calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45. FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU.
On October 19, 2004, the SEC authorized NU to issue guarantees of up to an aggregate $100 million through June 30, 2007 of the debt or other obligations of two of its subsidiaries, Northeast Utilities Service Company and Rocky River Realty Company. These companies provide certain specialized support and real estate services to the entire NU system and occasionally enter into transactions that require financial backing from NU parent.
D.
Regulatory Accounting
The accounting policies of NU's Utility Group 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 Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation."
The transmission and distribution businesses of CL&P, WMECO and PSNH, along with PSNH's generation business and Yankee Gas’ distribution business, continue to be cost-of-service rate regulated, and management believes that the application of SFAS No. 71 to those portions of the aforementioned companies continues to be appropriate. Management also believes that it is probable that NU's Utility Group companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.
Regulatory Assets: The components of regulatory assets are as follows:
At September 30, 2004 | ||||||||
(Millions of Dollars) | NU Consolidated | CL&P | PSNH | WMECO | ||||
Recoverable nuclear costs | $ 54.0 | $ - |
| $ 30.6 |
| $ 23.4 |
| |
Securitized assets | 1,526.0 | 1,025.4 |
| 432.7 |
| 67.9 |
| |
Income taxes, net | 317.3 | 208.1 |
| 39.3 |
| 56.8 |
| |
Unrecovered contractual obligations | 352.2 | 208.3 |
| 65.1 |
| 78.8 |
| |
Recoverable energy costs | 268.8 | 61.7 |
| 200.7 |
| 3.2 |
| |
Other | 284.6 | 64.7 |
| 156.8 |
| 10.6 |
| |
Totals | $2,802.9 | $1,568.2 |
| $925.2 |
| $240.7 |
| |
At December 31, 2003 | ||||||||
(Millions of Dollars) | NU Consolidated | CL&P | PSNH | WMECO | ||||
Recoverable nuclear costs | $ 82.4 | $ 16.4 |
| $ 33.3 |
| $ 32.7 |
| |
Securitized assets | 1,664.0 | 1,123.7 |
| 465.3 |
| 75.0 |
| |
Income taxes, net | 253.8 | 140.9 |
| 44.2 |
| 60.1 |
| |
Unrecovered contractual obligations | 378.6 | 221.8 |
| 69.9 |
| 86.9 |
| |
Recoverable energy costs | 255.7 | 30.1 |
| 218.3 |
| 3.7 |
| |
Other | 339.5 | 140.1 |
| 138.4 |
| 9.8 |
| |
Totals | $2,974.0 | $1,673.0 |
| $969.4 |
| $268.2 |
| |
At September 30, 2004 and December 31, 2003, NU maintained $68.8 million and $63.4 million, respectively, of additional other regulatory assets, primarily associated with Yankee Gas' income taxes, net and other regulatory assets related to environmental clean-up costs and hardship receivables.
Additionally, NU had approximately $11.6 million and approximately $12 million of regulatory assets at September 30, 2004 and December 31, 2003, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets. These amounts represent regulatory assets that have not yet been approved by the applicable regulatory agency. Management believes these assets are recoverable in future rates.
As discussed in Note 4D, "Commitments and Contingencies - Deferred Contractual Obligations," a substantial portion of the unrecovered contractual obligations regulatory asset has not yet been approved for recovery. At this time management believes that these regulatory assets are probable of recovery.
Regulatory Liabilities: The Utility Group maintained $1.2 billion of regulatory liabilities at both September 30, 2004 and December 31, 2003. These amounts are comprised of the following:
At September 30, 2004 | ||||||||
(Millions of Dollars) | NU Consolidated | CL&P | PSNH | WMECO | ||||
Cost of removal | $ 331.8 | $146.7 |
| $ 88.2 |
| $24.6 |
| |
CTA, GSC and SBC overcollections | 235.4 | 235.4 |
| - |
| - |
| |
Cumulative deferral – SCRC | 200.6 | - |
| 200.6 |
| - |
| |
Regulatory liabilities offsetting |
186.4 |
186.4 |
|
- |
|
- |
| |
LMP overcollections | 61.6 | 61.6 |
| - |
| - |
| |
Other | 148.0 | 81.3 |
| 24.4 |
| 6.8 |
| |
Totals | $1,163.8 | $711.4 |
| $313.2 |
| $31.4 |
| |
At December 31, 2003 | ||||||||
(Millions of Dollars) | NU Consolidated | CL&P | PSNH | WMECO | ||||
Cost of removal | $ 334.0 | $150.0 |
| $ 88.0 |
| $ 25.0 |
| |
CTA, GSC and SBC overcollections | 333.7 | 333.7 |
| - |
| - |
| |
Cumulative deferral – SCRC | 160.4 | - |
| 160.4 |
| - |
| |
Regulatory liabilities offsetting |
116.9 |
115.4 |
|
1.5 |
|
- |
| |
LMP overcollections | 83.6 | 83.6 |
| - |
| - |
| |
Other | 135.7 | 70.3 |
| 22.2 |
| 2.8 |
| |
Totals | $1,164.3 | $753.0 |
| $272.1 |
| $27.8 |
| |
At September 30, 2004 and December 31, 2003, NU maintained $107.8 million and $111.4 million, respectively, of additional other regulatory liabilities, associated with Yankee Gas' cost of removal, deferred gas costs, pension and other regulatory liabilities.
E.
Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of Utility Group 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 in other interest expense and the cost of equity funds is recorded as other income on the consolidated statements of income:
For the Nine Months Ended | ||
(Millions of Dollars) | September 30, 2004 | September 30, 2003 |
Borrowed funds | $3.1 | $4.1 |
Equity funds | 2.2 | 5.1 |
Totals | $5.3 | $9.2 |
Average AFUDC rates | 3.8% | 4.2% |
F.
Equity-Based Compensation
NU maintains an Employee Stock Purchase Plan and other long-term, equity-based incentive plans under the Northeast Utilities Incentive Plan. NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," and related interpretations. No equity-based employee compensation cost for stock options is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to equity-based employee compensation:
For the Nine Months Ended | ||
(Millions of Dollars, except per share amounts) | September 30, 2004 | September 30, 2003 |
Net income, as reported | $129.4 | $126.3 |
Total equity-based employee compensation expense | 1.5 | 1.4 |
Pro forma net income | $127.9 | $124.9 |
EPS: | ||
Basic and fully diluted – as reported | $1.01 | $0.99 |
Basic and fully diluted – pro forma | $1.00 | $0.98 |
Net income as reported includes $2.8 million and $1.2 million expensed for restricted stock and restricted stock units for the nine months ended September 30, 2004 and 2003, respectively. NU accounts for restricted stock in accordance with APB No. 25 and amortizes the intrinsic value of the award over the related service period.
NU assumes an income tax rate of 40 percent to estimate the tax effect on total equity-based employee compensation expense determined under the fair value-based method for all awards.
During the nine-month period ended September 30, 2004, no stock options were awarded.
On March 31, 2004, the FASB issued an exposure draft that, if finalized as proposed, would require NU to expense equity-based employee compensation under the fair value-based method. The FASB continues to redeliberate this exposure draft and has deferred the effective date of a final statement to July 1, 2005 from January 1, 2005. A final standard could be issued in the fourth quarter of 2004.
G.
Sale of Customer Receivables
CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At September 30, 2004 and December 31, 2003, CL&P had sold accounts receivable of $40 million and $80 million, respectively, to the financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. At September 30, 2004, the reserve requirements calculated in accordance with the related Receivables Purchase and Sale Agreement were $8.7 million. This reserve amount is deducted from the amount of receivables eligible for sale at the time. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. At September 30, 2004, the amount of customer receivables sold to CRC by CL&P but not sol d to the financial institution totaling $212.5 million are included in investments in securitizable assets on the accompanying consolidated balance sheets. This amount would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy. On July 7, 2004, CL&P renewed the arrangement with the financial institution through July 6, 2005.
The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."
H.
Other Investments
Yankee Energy System, Inc. (Yankee) maintains a long-term note receivable from BMC Energy LLC (BMC), an operator of renewable energy projects. In late-March 2004, based on revised information that impacts undiscounted cash flow projections and fair value estimates, management determined that the fair value of the note receivable from BMC had declined and that the note was impaired. As a result, management recorded an after-tax investment write-down of $1.5 million ($2.5 million on a pre-tax basis) in the first quarter of 2004.
NU has an investment in the common stock of Acumentrics, a developer of fuel cell and power quality equipment. Based on revised information that affected the fair value of NU’s investment, management determined that at June 30, 2004, the value of NU’s investment declined and that the decline was other-than-temporary in nature. An after-tax investment write-down of $2.4 million ($3.8 million on a pre-tax basis) was recorded to reduce the carrying value of the investment to $3.8 million. NU also has an investment in Acumentrics debt securities totaling $2.2 million at September 30, 2004.
On June 30, 2004, Yankee sold virtually all of the assets and liabilities of R.M. Services, Inc. (RMS), a provider of consumer collection services, for $3 million. In conjunction with the sale in the second quarter of 2004, an estimated gain totaling $0.6 million was included as a gain from sale of RMS. As a result of adjustments to estimates recorded in conjunction with the sale during the third quarter of 2004, this gain was increased by $0.2 million and totals $0.8 million at September 30, 2004. For the three and six months ended June 30, 2004, RMS was consolidated into NU's financial statements and had pre-tax losses totaling $0.7 million and $1.7 million, respectively. These amounts are recorded in other income - other, net on the accompanying consolidated statements of income. For the three and six months ended June 30, 2003, which is before RMS was consolidated, Yankee recorded pre-tax investment write-down s totaling $1.1 million and $1.4 million, respectively, related to its investment in RMS.
These charges are included in Note 1L, "Summary of Significant Accounting Policies – Other Income," and in the Eliminations and Other segment in Note 8, "Segment Information," to the consolidated financial statements.
NU has an investment in the common stock of NEON, a provider of optical networking services. On July 19, 2004, NEON and Globix Corporation (Globix) announced a definitive merger agreement in which Globix, an unaffiliated publicly-owned entity would acquire NEON for shares of Globix common stock. If the merger is consummated, then NU would receive 1.2748 shares of Globix common stock for each of the 1.8 million shares of NEON stock it owns. Management continues to evaluate the potential impact of the proposed merger on NU's investment in NEON, which had a carrying value of $9.9 million at September 30, 2004.
NU owns 49 percent of the common stock of Connecticut Yankee (CY) with a carrying value of $21 million at September 30, 2004. CY is involved in litigation over the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel). Management believes that this litigation has not impaired the value of its investment in CY at September 30, 2004 but will continue to evaluate the impact of the litigation on NU's investment. For further information regarding the Bechtel litigation, see Note 4D, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.
I.
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, overdraft amounts are reclassified from cash and cash equivalents to accounts payable.
Also included in cash and cash equivalents, until these amounts are utilized in NU's overall cash management process, are balances collected from counterparties resulting from Select Energy's credit management activities totaling $67.4 million at September 31, 2004 and $46.5 million at December 31, 2003. An offsetting liability has been recorded in other current liabilities for the amounts collected. To the extent Select Energy requires collateral from counterparties, cash is held as a part of the total collateral required. The right to hold such cash collateral in an unrestricted manner is determined by the terms of Select Energy’s 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.
J.
Special Deposits
Special deposits represents amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amount of $80.2 million and amounts included in escrow for Select Energy Services, Inc. (SESI) that have not been spent on construction projects of $21.5 million at September 30, 2004. Similar amounts totaled $24.5 million and $32 million, respectively, at December 31, 2003. Special deposits at December 31, 2003 also included $30.1 million in escrow that PSNH funded to acquire Connecticut Valley Electric Company, Inc. on January 1, 2004.
K.
Restricted Cash – LMP Costs
Restricted cash - LMP costs represented incremental locational marginal pricing (LMP) cost amounts that were collected by CL&P and deposited into an escrow account. At December 31, 2003, restricted cash - LMP costs totaled $93.6 million, and an additional $30 million was deposited in 2004. During the third quarter of 2004, $83 million of the account was paid to CL&P’s standard offer suppliers in accordance with the Federal Energy Regulatory Commission (FERC) approved Standard Market Design (SMD) settlement. The remaining $41 million was released from the escrow account in the third quarter and will be refunded to CL&P's customers as a credit on bills from September to December of 2004.
L.
Other Income
The pre-tax components of NU’s other income items are as follows:
For the Three Months Ended | ||
(Millions of Dollars) | September 30, 2004 | September 30, 2003 |
Investment income | $6.3 | $5.5 |
CL&P procurement fee | 3.0 | - |
AFUDC – equity funds | 0.3 | 1.8 |
Gain on sale of RMS | 0.2 | - |
Charitable donations | (0.4) | (0.4) |
Other, net | (1.2) | (2.2) |
Totals | $8.2 | $4.7 |
For the Nine Months Ended | ||
(Millions of Dollars) | September 30, 2004 | September 30, 2003 |
Investment write-downs | $ (6.3) | $ - |
Investment income | 13.4 | 13.5 |
CL&P procurement fee | 8.8 | - |
AFUDC – equity funds | 2.2 | 5.1 |
Gain on sale of RMS | 0.8 | - |
Charitable donations | (1.7) | (3.1) |
Other, net | (4.5) | (9.5) |
Totals | $12.7 | $ 6.0 |
2.
DERIVATIVE INSTRUMENTS (NU, CL&P, Select Energy, Yankee Gas)
Derivatives that are utilized for trading purposes are recorded at fair value with changes in fair value included in earnings. Other contracts that are derivatives but do not meet the definition of a cash flow or fair value hedge and cannot be designated as normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income until the underlying transactions occur. For contracts that meet the definition of a derivative but do not meet the hedging requirements, and for the ineffective portion of contracts that meet the cash flow hedge requirements, the changes in fair value of those contracts are recognized currently in earnings. Derivative contracts designated as fair value hedges and the item they are hedging are both recorded at fair value on the consolidated balance sheets. Derivative contracts that are entered into as a normal purchase or sale and are probable of resulting in physical delivery, and are documented as such, are recorded under accrual accounting.
For the nine months ended September 30, 2004, a negative $42.7 million, net of tax, was reclassified as an expense from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings. Also during the third quarter of 2004, new cash flow hedge transactions were entered into that hedge cash flows through 2006. As a result of these new transactions and market value changes since January 1, 2004, accumulated other comprehensive income decreased by $27.3 million, net of tax. Accumulated other comprehensive income at September 30, 2004, was a negative $2.5 million, net of tax (decrease to equity), relating to hedged transactions, and it is estimated that a positive $1.5 million included in this net of tax balance will be reclassified as an increase to earnings within the next twelve months. Cash flows from hedge contracts are reported in the same category as cash flows fr om the underlying hedged transaction.
There was no material impact recognized in earnings for the ineffective portion of cash flow hedges. A pre-tax negative $4.2 million was recognized in earnings for the ineffective portion of fair value hedges. The changes in the fair value of both the fair value hedges and the natural gas inventory being hedged are recorded in fuel, purchased, and net interchange power on the accompanying consolidated statements of income.
The tables below summarize the derivative assets and liabilities at September 30, 2004 and December 31, 2003. The business activities of NU Enterprises that result in the recognition of derivative assets include concentrations of credit risk to energy marketing and trading counterparties. At September 30, 2004, Select Energy has $178.2 million of derivative assets from trading, non-trading, and hedging activities. These assets are exposed to counterparty credit risk. However, a significant portion of these assets is contracted with investment grade rated counterparties or collateralized with cash. The amounts below do not include option premiums paid, which are recorded as prepayments and amounted to $4.4 million and $9.1 million related to energy trading activities and $9 million and $7.6 million related to marketing activities at September 30, 2004 and December 31, 2003, respectively. These amounts also do not inclu de option premiums received, which are recorded as other current liabilities and amounted to $7 million and $12.2 million related to energy trading activities at September 30, 2004 and December 31, 2003, respectively, and $1.9 million related to marketing activities at September 30, 2004.
At September 30, 2004 | ||||||
(Millions of Dollars) | Assets | Liabilities | Total | |||
NU Enterprises: |
|
|
|
| ||
Trading | $ 94.0 | $ (71.0) |
| $ 23.0 |
| |
Non-trading | 3.3 | (2.3) |
| 1.0 |
| |
Hedging | 80.9 | (84.9) |
| (4.0) |
| |
Utility Group - Gas: |
|
|
|
|
| |
Non-trading | 0.3 | (0.1) |
| 0.2 |
| |
Hedging | 3.0 | - |
| 3.0 |
| |
Utility Group - Electric: |
|
|
|
|
| |
Non-trading | 186.3 | (49.4) |
| 136.9 |
| |
NU Parent: |
|
|
|
|
| |
Hedging | 0.7 | - |
| 0.7 |
| |
Total | $368.5 | $(207.7) |
| $160.8 |
| |
At December 31, 2003 | ||||||
(Millions of Dollars) | Assets | Liabilities | Total | |||
NU Enterprises: |
|
|
|
| ||
Trading | $ 71.8 | $(39.3) |
| $ 32.5 |
| |
Non-trading | 1.6 | (0.8) |
| 0.8 |
| |
Hedging | 55.8 | (12.7) |
| 43.1 |
| |
Utility Group - Gas: |
|
|
|
|
| |
Non-trading | 0.2 | (0.2) |
| - |
| |
Hedging | 2.8 | - |
| 2.8 |
| |
Utility Group - Electric: |
|
|
|
|
| |
Non-trading | 116.9 | (56.0) |
| 60.9 |
| |
NU Parent: |
|
|
|
|
| |
Hedging | - | (3.6) |
| (3.6) |
| |
Total | $249.1 | $(112.6) |
| $136.5 |
| |
NU Enterprises - Trading: To gather market intelligence and utilize this information in risk management activities for the wholesale marketing activities, Select Energy conducts limited energy trading activities in electricity, natural gas, and oil, and therefore, experiences net open positions. Select Energy manages these open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures.
Derivatives used in trading activities are recorded at fair value and included in the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues in the consolidated statements of income in the period of change. The net fair value positions of the trading portfolio at September 30, 2004 and at December 31, 2003 were assets of $23 million and $32.5 million, respectively.
Select Energy's trading portfolio includes New York Mercantile Exchange (NYMEX) futures, financial swaps, and options, the fair value of which is based on closing exchange prices; over-the-counter forwards, financial swaps, and options, the fair value of which is based on the mid-point of bid and ask market prices; and bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources. Select Energy's trading portfolio also includes transmission congestion contracts (TCC). The fair value of the TCCs included in the trading portfolio is based on published market data.
NU Enterprises - Non-Trading: Non-trading derivative contracts are used for delivery of energy related to Select Energy's wholesale and retail marketing activities. These contracts are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, as defined. These contracts cannot be designated as normal purchases or sales either because they are included in the New York energy market that settles financially or because management did not elect the normal purchases and sales designation. Changes in fair value of a positive $0.2 million of non-trading derivative contracts were recorded in revenues in the first nine months of 2004.
Market information for the TCCs classified as non-trading is not available, and those contracts cannot be reliably valued. Management believes the amounts paid for these contracts, which total $5.4 million at September 30, 2004, and $4.3 million at December 31, 2003 and are included in premiums paid, are equal to their fair value.
NU Enterprises - Hedging: Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales and purchase commitments to certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts to manage the market risk associated with a portion of its anticipated supply and delivery requirements. These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity or natural gas. A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in accumulated other co mprehensive income. Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.
Select Energy maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2006. Select Energy has hedged its gas supply risk under these agreements through NYMEX futures contracts. Under these contracts, which also extend through 2006, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At September 30, 2004 the NYMEX futures contracts had notional values of $88.3 million and were recorded at fair value as derivative assets of $18.9 million.
Select Energy also maintains various physical and financial instruments to hedge its electric and gas purchases and sales through 2006. These instruments include forwards, futures, options, financial collars, swaps and financial transmission rights (FTRs). These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $62 million and derivative liabilities of $84.5 million at September 30, 2004.
Select Energy hedges certain amounts of natural gas inventory with gas futures, options and swaps, some of which are accounted for as fair value hedges. The changes in fair value of the futures, options and swaps were recorded as derivative liabilities of $0.4 million at September 30, 2004. During the third quarter, a change in the fair value of hedged natural gas inventory of a negative $4.3 million was recorded along with the change in the fair value of the hedge of a positive $0.1 million. In September 2004, certain of these fair value hedges were redesignated as cash flow hedges, and future changes in fair value will be included in other comprehensive income (equity), unless ineffective.
Utility Group - Gas - Non-Trading: Yankee Gas' non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm sales contracts with options to curtail delivery. These contracts are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, as defined, because of the optionality in the contract terms. Non-trading derivatives at September 30, 2004 included assets of $0.3 million and liabilities of $0.1 million.
Utility Group - Gas - Hedging: Yankee Gas maintains a master swap agreement with a financial counterparty to purchase gas at fixed prices. Under this master swap agreement, the purchase price of a specified quantity of gas for an unaffiliated customer is effectively fixed over the term of the gas service agreements with that customer for a period not extending beyond 2005. At September 30, 2004 the commodity swap agreement had a notional value of $3.3 million and was recorded at fair value as a derivative asset of $3 million. The firm commitment contract that is hedged is also recorded as a liability on the accompanying consolidated balance sheets, and changes in fair values of the hedge and firm commitment have offsetting impacts in earnings.
Utility Group - Electric - Non-Trading: CL&P has two independent power producer (IPP) contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception to SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. The fair values of these IPP non-trading derivatives at September 30, 2004 include a derivative asset with a fair value of $186.3 million and a derivative liability with a fair value of $49.4 million. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.
NU Parent - Hedging: In March of 2003, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate note that matures on April 1, 2012. As a matched-terms fair value hedge, the changes in fair value of the swap and the hedged debt instrument are recorded on the consolidated balance sheets but are equal and offsetting in the consolidated statements of income. The cumulative change in the fair value of the hedged debt of $0.7 million is included an increase to long-term debt on the consolidated balance sheets. The hedge is recorded as a derivative asset of $0.7 million. The resulting changes in interest payments made are recorded as adjustments to interest expense.
3.
GOODWILL AND OTHER INTANGIBLE ASSETS (Yankee Gas, NU Enterprises)
SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment at least annually by applying a fair value-based test. NU uses October 1st as the annual goodwill impairment testing date. 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. There were no impairments or adjustments to the goodwill balances during the nine-month periods ended September 30, 2004 and 2003.
NU's reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 8, "Segment Information," to the consolidated financial statements. Consistent with the way management reviews the operating results of its reporting units, NU's reporting units under the NU Enterprises reportable segment include: 1) the merchant energy reporting unit and 2) the energy services reporting unit. The merchant energy reporting unit is comprised of the operations of Select Energy, Northeast Generation Company (NGC) and the generation operations of Holyoke Water Power Company (HWP), while the energy services reporting unit is comprised of the operations of SESI, Northeast Generation Services Company (NGS) and Woods Network Services, Inc. (Woods Network). As a result, NU's reporting units that maintain goodwill are as follows: the Yankee Gas reporting unit, whic h is classified under the Utility Group - gas reportable segment; the merchant energy reporting unit, which is classified under the NU Enterprises - merchant energy reportable segment; and the energy services reporting unit, which is classified under NU Enterprises - eliminations and other. The goodwill balances of these reporting units are included in the table herein.
At September 30, 2004, NU maintained $319.9 million of goodwill that is no longer being amortized, $11.7 million of identifiable intangible assets subject to amortization and $8.5 million of intangible assets not subject to amortization. At December 31, 2003, NU maintained $319.9 million of goodwill that is no longer being amortized, $14.4 million of identifiable intangible assets subject to amortization and $8.5 million of intangible assets not subject to amortization. A summary of NU's goodwill balances at September 30, 2004 and December 31, 2003, by reportable segment and reporting unit is as follows:
(Millions of Dollars) | At September 30, 2004 | At December 31, 2003 |
Utility Group – Gas: | ||
Yankee Gas | $287.6 | $287.6 |
NU Enterprises: | ||
Merchant Energy | 3.2 | 3.2 |
Energy Services | 29.1 | 29.1 |
Totals | $319.9 | $319.9 |
The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas.
At September 30, 2004 and December 31, 2003, NU's intangible assets and related accumulated amortization, all of which related to NU Enterprises, consisted of the following:
At September 30, 2004 | |||
(Millions of Dollars) | Gross Balance | Accumulated Amortization | Net Balance |
Intangible assets subject to amortization: | |||
Exclusivity agreement | $17.7 | $ 9.2 | $ 8.5 |
Customer list | 6.6 | 3.4 | 3.2 |
Totals | $24.3 | $12.6 | $11.7 |
Intangible assets not subject to amortization: | |||
Customer relationships | $5.2 | ||
Tradenames | 3.3 | ||
Totals | $8.5 | ||
At December 31, 2003 | |||
(Millions of Dollars) | Gross Balance | Accumulated Amortization | Net Balance |
Intangible assets subject to amortization: | |||
Exclusivity agreement | $17.7 | $ 7.2 | $10.5 |
Customer list | 6.6 | 2.7 | 3.9 |
Totals | $24.3 | $ 9.9 | $14.4 |
Intangible assets not subject to amortization: | |||
Customer relationships | $ 5.2 | ||
Tradenames | 3.3 | ||
Totals | $ 8.5 | ||
NU recorded amortization expense of $2.7 million and $2.6 million for the nine months ended September 30, 2004 and 2003, respectively, related to intangible assets. Based on the current amount of intangible assets subject to amortization, the estimated annual amortization expense for 2004 and for each of the succeeding 5 years from 2005 through 2009 is $3.6 million in 2004 through 2007 and no amortization expense in 2008 or 2009. These amounts may vary as acquisitions and dispositions occur in the future.
4.
COMMITMENTS AND CONTINGENCIES
A.
Regulatory Issues and Rate Matters (CL&P, PSNH, WMECO)
Connecticut:
CTA and SBC Reconciliation: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while 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 worker protection costs.
On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the Connecticut Department of Public Utility Control (DPUC), which compares CTA and SBC revenues to revenue requirements. A final decision in the 2003 CTA and SBC docket was issued on August 4, 2004 and ordered a refund to customers of $88.5 million over a seven-month period beginning with October 2004 consumption.
The DPUC also directed CL&P to impute revenues of $2.7 million during 2004 payable to customers associated with a previously renegotiated IPP contract. On September 15, 2004, CL&P filed an appeal and a motion for partial stay with the Connecticut Superior Court challenging the DPUC’s August 4, 2004 decision regarding this contract. The motion for partial stay was granted. On October 15, 2004, CL&P entered into a settlement involving the counterparties to this contract and various other parties. If approved by the DPUC and by the bankruptcy court of one of the counterparties, the DPUC will rescind the imputed revenues order, and CL&P would withdraw its appeal. CL&P is awaiting approvals of the settlement.
In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued a final decision denying CL&P's request, and on October 24, 2003, CL&P appealed the DPUC's final decision to the Connecticut Superior Court. The appeal has been fully briefed and is in the argument phase, and a decision from the Connecticut Superior Court could be rendered by the end of 2004. If CL&P's request is granted through these court proceedings, then there could be additional amounts due to CL&P from its customers. The 2004 impact of including the deferred intercompany liability in CTA revenue requirements has been a reduction of approximately $19.3 million in revenue.
New Hampshire:
SCRC Reconciliation Filing: The stranded cost recovery charge (SCRC) allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues billed with stranded costs, and transition energy service (TS) revenues billed with TS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $200.6 million at September 30, 2004. This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $422.6 million to $222 million.
The 2003 SCRC reconciliation filing was filed with the NHPUC on April 30, 2004, and a proposed stipulation and settlement agreement between PSNH, the Office of Consumer Advocate and NHPUC staff was filed with the NHPUC on October 4, 2004. Under the terms of the settlement agreement, no costs related to the recovery of stranded costs or the cost of providing TS were disallowed, and the NHPUC staff agreed to accept the 2003 SCRC filing without change. On October 29, 2004, the NHPUC issued an order accepting the settlement agreement as filed.
Estimated unbilled revenues are not included in the reconciliation of billed revenues to incurred costs through rate mechanisms for the SCRC and the TS. At September 30, 2004, the unbilled balance related to SCRC and TS was $11.7 million and $16.7 million, respectively. The level of the TS rate will vary from time to time and will continue until it is replaced with “Default Energy Service,” or some equivalent, which will then continue indefinitely. The SCRC rate is expected to begin decreasing in late 2006. Management will seek from regulators a determination as to the ultimate inclusion of any of this unbilled revenue into billed rates.
Massachusetts:
Transition Cost Reconciliation: On March 31, 2004, WMECO filed its 2003 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy. This filing reconciled the recovery of generation-related stranded costs for calendar year 2003. The timing of a final decision is uncertain, but management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or financial position.
B.
NRG Energy, Inc. Exposures (CL&P, Yankee Gas)
Certain subsidiaries of NU, including CL&P and Yankee Gas, entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions. On December 5, 2003, NRG emerged from bankruptcy. NU's NRG-related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of SMD on March 1, 2003, 2) the recovery of CL&P's station service billings from NRG, and 3) the recovery of Yankee Gas' and CL&P's expenditures that were incurred related to an NRG subsidiary's generating plant construction project that is now abandoned. While it is unable to determine the ultimate outcome of these issues, management does not expect that their resolution will have a material adverse effect on NU's consolidated financial condition or results of operations.
C.
Long-Term Contractual Arrangements (CL&P, PSNH, WMECO, Yankee Gas, and Select Energy)
Select Energy maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $5.4 billion at September 30, 2004, as follows (millions of dollars):
Year | |
2004 | $1,460.9 |
2005 | 2,914.6 |
2006 | 452.7 |
2007 | 125.7 |
2008 | 89.0 |
Thereafter | 312.5 |
Total | $5,355.4 |
Select Energy's purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power as energy trading purchases are classified net with the corresponding revenues.
The following are material updates to the table of contractual obligations and commercial commitments discussed in NU's 2003 report on Form 10-K:
(Millions of Dollars) | 2004 | 2005 | 2006 | 2007 | 2008 | Thereafter |
Contracted expenditures for construction of Yankee Gas LNG facility | $ 7.5 | $ 30.6 | $ 39.3 | $ 3.4 | $ - | $ - |
Northern Wood Project | 21.6 | 36.5 | 5.6 | - | - | - |
FERC-approved billings from the Yankee Companies | 40.8 | 92.5 | 74.4 | 68.6 | 60.9 | 113.5 |
$69.9 | $159.6 | $119.3 | $72.0 | $60.9 | $113.5 |
Certain other estimated construction expenditures totaling $19.2 million related to the Yankee Gas liquefied natural gas (LNG) facility and $11.3 million related to the Northern Wood Project are not included in the contracts signed to build these facilities and are not included in the table above. NU's other long-term contractual arrangements have not changed materially from the amounts reported at December 31, 2003.
D.
Deferred Contractual Obligations (NU, CL&P, PSNH, WMECO)
NU still has significant decommissioning and plant closure cost obligations to the companies that own the Yankee Atomic (YA), CY and Maine Yankee (MY) nuclear power plants (collectively, the Yankee Companies). Each plant has been shut down and is undergoing decommissioning. 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 pass these costs on to their customers through state regulatory commission-approved retail rates. YA has received FERC approval to collect all presently estimated decommissioning costs. MY and various other parties filed a settlement agreement with the FERC, which provides for the collection of approximately $27 million annually through October 31, 2008 for all presently estimated decommis sioning and long-term spent fuel storage costs. The MY settlement was approved by the FERC on September 16, 2004.
CY's estimated decommissioning and plant closure costs for the period 2000 through 2023 have increased by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the fact that CY is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel in July 2003, the increases in the projected costs of spent fuel storage, and increased security and liability and property insurance costs. NU's share of CY's increase in decommissioning and plant closure costs is approximately $194 million. On July 1, 2004, CY filed with the FERC for recovery of these increased costs. In the filing, CY sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC i ssued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund, and scheduled hearings for May 2005. In total, NU's estimated remaining decommissioning and plant closure obligation for CY is $310.2 million at September 30, 2004.
On June 10, 2004, the DPUC and Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CY be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred. On August 30, 2004, the FERC denied this petition. On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition. On October 29, 2004, the FERC issued an order granting further consideration regarding the DPUC's and OCC's petition for reconsideration. No hearing date has been established.
CY is currently in litigation with Bechtel over the termination of its decommissioning contract. On June 13, 2003, CY gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant. CY terminated the contract due to Bechtel's history of incomplete and untimely performance and refusal to perform the remaining decommissioning work. Bechtel has departed the site and the decommissioning responsibility has been transitioned to CY, which has recommenced the decommissioning process.
On June 23, 2003, Bechtel filed a complaint against CY asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and rescission of the contract. Bechtel has since amended its complaint to add claims for wrongful termination. On August 22, 2003, CY filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing. Discovery is currently underway and a trial has been scheduled for May 2006.
On July 20, 2004, the Connecticut Superior Court (the Court) allowed the DPUC to intervene in the prejudgment remedy (PJR) proceeding filed in June 2004 for the limited purpose of objecting to Bechtel’s requested garnishment of the decommissioning trust and related payments. On October 27, 2004, Bechtel and CY entered into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY's real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CY through June 30, 2007. This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CY intends to contest the attachability of such assets. Management cannot predict the outcome of this litigation or its impact on NU.
NU cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased decommissioning costs. Management believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO. However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings. NU also cannot predict the timing and the outcome of the litigation with Bechtel.
The Yankee Companies also are seeking recovery of damages from the United States Department of Energy (DOE) for the cost of storing spent nuclear fuel that the DOE has failed to remove. The DOE trial ended on August 30, 2004 and a verdict has not been reached. The related claim for damages from the DOE incurred through 2010 is approximately $500 million. The current Yankee Companies' rates do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on NU.
For additional current information regarding these issues and litigation with Bechtel, see Part II, Item 1, "Legal Proceedings," in this report on Form 10-Q.
E.
Consolidated Edison, Inc. Merger Litigation
Certain gain and loss contingencies continue to exist with regard to the 1999 merger agreement between NU and Consolidated Edison, Inc. (Con Edison) and the related litigation. Interrogatory appeals in the case are now pending, and no trial date has been set. At this stage of the litigation, management can predict neither the outcome of this matter nor its ultimate effect on NU. For additional information on this litigation, see Part II, Item 1, "Legal Proceedings" in this report on Form 10-Q.
5.
COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises)
Total comprehensive income, which includes all comprehensive income/(loss) items by category, for the nine months ended September 30, 2004 and 2003 is as follows:
Nine Months Ended September 30, 2004 | |||||||||||
NU | CL&P | PSNH | WMECO | NU | Other | ||||||
Net income* | $129.4 | $65.1 | $36.0 | $8.7 | $25.7 | $(6.1) | |||||
Comprehensive income/(loss) items: | |||||||||||
Qualified cash flow hedging instruments | (30.4) | - | - | - | (30.5) | 0.1 | |||||
Unrealized losses on securities | (0.6) | - | - | - | - | (0.6) | |||||
Net change in comprehensive | (31.0) | - | - | - | (30.5) | (0.5) | |||||
Total comprehensive income/(loss) | $ 98.4 | $65.1 | $36.0 | $8.7 | $(4.8) | $(6.6) | |||||
Nine Months Ended September 30, 2003 | ||||||||||||
NU | CL&P | PSNH | WMECO | NU | Other | |||||||
Net income* | $126.3 | $59.0 | $34.5 | $13.9 | $24.0 | $(5.1) | ||||||
Comprehensive income/(loss) items: | ||||||||||||
Qualified cash flow hedging instruments | (18.7) | - | - | - | (14.7) | (4.0) | ||||||
Unrealized losses on securities | 1.0 | 0.1 | 0.1 | - | - | 0.8 | ||||||
Net change in comprehensive | (17.7) | 0.1 | 0.1 | - | (14.7) | (3.2) | ||||||
Total comprehensive income/(loss) | $108.6 | $59.1 | $34.6 | $13.9 | $ 9.3 | $(8.3) | ||||||
*After preferred dividends of subsidiary.
NU's total comprehensive income for the three months ended September 30, 2004 and 2003 totaled $9.4 million in losses and $34.6 million in income, respectively.
Amounts included in the Other column primarily relate to NU parent and Northeast Utilities Service Company.
Accumulated other comprehensive income fair value adjustments in NU’s qualified cash flow hedging instruments for the three and nine months ended September 30, 2004 and the twelve months ended December 31, 2003 are as follows:
(Millions of Dollars, Net of Tax) | Three Months | Nine Months | Twelve Months |
Balance at beginning of period | $45.7 | $24.8 | $15.5 |
Hedged transactions recognized into earnings | (15.5) | (42.7) | (5.3) |
Change in fair value | (7.3) | 25.8 | 5.0 |
Cash flow transactions entered into for the period | (25.4) | (10.4) | 9.6 |
Net change associated with the current | (48.2) | (27.3) | 9.3 |
Total fair value adjustments included | $(2.5) | $(2.5) | $24.8 |
Accumulated other comprehensive income items unrelated to NU's qualified cash flow hedging instruments totaled $0.6 million and $1.2 million in gains at September 30, 2004 and December 31, 2003, respectively. These amounts primarily relate to unrealized gains on investments in marketable debt and equity securities, net of related income taxes.
6.
EARNINGS PER SHARE (NU)
EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. At September 30, 2004 and 2003, 647,856 options and 2,004,224 options, respectively, were excluded from the following table as these options were antidilutive. The following table sets forth the components of basic and fully diluted EPS:
| Nine Months Ended September 30, | |
(Millions of Dollars, Except for Share Information) | 2004 | 2003 |
Income before preferred dividends of subsidiaries | $133.6 | $135.2 |
Preferred dividends of subsidiaries | 4.2 | 4.2 |
Income before cumulative effect of accounting change | $129.4 | $131.0 |
Cumulative effect of accounting change, net of tax benefit | - | (4.7 ) |
Net income | $129.4 | $126.3 |
Basic EPS common shares outstanding (average) | 128,064,364 | 126,976,161 |
Dilutive effects of employee stock options | 166,903 | 110,256 |
Fully diluted EPS common shares outstanding (average) | 128,231,267 | 127,086,417 |
Basic and fully diluted EPS: | ||
Income before cumulative effect of accounting change | $1.01 | $1.03 |
Cumulative effect of accounting change net of tax benefit | - | (0.04 ) |
Net income | $1.01 | $0.99 |
7.
PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All Companies)
NU’s subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering the majority of regular NU employees and also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). The components of net periodic benefit expense/(income) for the Pension Plan and the PBOP Plan for the nine months ended September 30, 2004 and 2003 are estimated as follows:
For the Nine Months Ended September 30, | ||||||
Pension Benefits | Postretirement Benefits | |||||
(Millions of Dollars) | 2004 | 2003 | 2004 | 2003 | ||
Service cost | $30.5 | $26.3 |
| $4.5 | $4.0 |
|
Interest cost | 89.2 | 87.7 |
| 19.0 | 20.1 |
|
Expected return on plan assets | (131.3) | (136.9) |
| (9.4) | (11.2) |
|
Amortization of unrecognized net |
(1.1) |
(1.1) |
|
8.9 |
8.9 |
|
Amortization of prior service cost | 5.4 | 5.4 |
| (0.3) | (0.3) |
|
Amortization of actuarial loss/(gain) | 11.5 | (5.3) |
| - | - |
|
Other amortization, net | - | - |
| 8.6 | 4.8 |
|
Total - net periodic expense/(income) | $ 4.2 | $(23.9) |
| $31.3 | $26.3 |
|
A portion of these expenses/(income) is capitalized related to employees working on capital projects.
NU does not expect to make any contributions to the Pension Plan in 2004. NU anticipates contributing approximately $10.4 million quarterly totaling $41.7 million in 2004 to fund its PBOP Plan.
Based on the most recent actuarial valuation as of January 1, 2004, the impact of the Medicare program has been revised from a $20 million decrease in the PBOP benefit obligation at December 31, 2003 to $27 million at September 30, 2004. The total $27 million decrease consists of $20 million as a direct result of the subsidy for certain non-capped retirees and $7 million related to changes in participation assumptions for capped retirees and future retirees as a result of the subsidy. The total $27 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years. For the nine months ended September 30, 2004, this reduction in PBOP expense totaled approximately $2.8 million, including amortization of the actuarial gain of $1.5 million and a reduction in interest cost based on a lower PBOP benefit obligation of $1.3 million.
As a result of litigation with nineteen former employees, in April 2004, NU was ordered by the court to modify its retirement plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and increased future monthly benefit payments. In the third quarter, NU withdrew its appeal of the court's ruling. As a consequence, benefits with an estimated cost of $2.1 million will be provided to these fifteen former employees. This amount will be recorded as a plan amendment, which will be amortized as a prior service cost and will increase pension expense over approximately 13 years.
8.
SEGMENT INFORMATION (All Companies)
NU is organized between the Utility Group and NU Enterprises businesses 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 they operate. Based on enhanced information that is reviewed by NU's chief operating decision maker, separate detailed information regarding the Utility Group's transmission businesses and NU Enterprises' merchant energy business is now included in the following segment information. Segment information for all periods has been restated to conform to the current presentation except for total asset information for the transmission business segment.
The Utility Group segment, including both the regulated electric distribution and transmission businesses, as well as the gas distribution business comprised of Yankee Gas, represents approximately 69 percent and 73 percent of NU's total revenues for the nine months ended September 30, 2004 and 2003, respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose complete financial statements are included in NU's combined report on Form 10-Q. PSNH's distribution segment includes generation activities. Also included in this combined report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission businesses. Utility Group 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.
The NU Enterprises merchant energy business segment includes Select Energy, NGC, the generation operations of HWP, and their respective subsidiaries, while the NU Enterprises eliminations and other business segment includes SESI, NGS, Woods Network, and their respective subsidiaries and intercompany eliminations. The results of NU Enterprises parent are also included within eliminations and other.
Effective January 1, 2004, Select Energy began serving a portion of CL&P's transitional standard offer (TSO) load for 2004. Total Select Energy revenues from CL&P for CL&P's standard offer load, TSO load and for other transactions with CL&P, represented approximately $474.9 million or 22 percent for the nine months ended September 30, 2004 and approximately $566.2 million or 30 percent for the nine months ended September 30, 2003, of total NU Enterprises' revenues. Total CL&P purchases from Select Energy are eliminated in consolidation.
Additionally, WMECO's purchases from Select Energy for standard offer and default service and for other transactions with Select Energy represented approximately $81.5 million and $110.3 million of total NU Enterprises' revenues for the nine months ended September 30, 2004 and 2003, respectively. Total WMECO purchases from Select Energy are eliminated in consolidation. Select Energy revenues related to contracts with NSTAR companies represented $251.6 million or 12 percent of total NU Enterprises' revenues for the nine months ended September 30, 2004. Select Energy also provides BGS in the New Jersey market. Select Energy revenues related to these contracts represented $238.5 million or 11 percent of total NU Enterprises' revenues for the nine months ended September 30, 2004 and $323.6 million or 17 percent for the nine months ended September 30, 2003. No other individual customer represented in excess of 10 percent of NU E nterprises' revenues for the nine months ended September 30, 2004 or 2003.
Eliminations and other in the NU consolidated tables includes the results for Mode 1 Communications, Inc., an investor in NEON, the results of the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, RMS, Yankee Energy Financial Services, and NorConn Properties, Inc.), the non-energy operations of HWP, the results of NU's parent and service companies, and write-downs of certain of the company's investments. Interest expense included in eliminations and other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in eliminations and other. Eliminations and other includes NU's investment in RMS. Virtually all of the assets and liabilities of RMS were sold on June 30, 2004.
NU's segment information for the three months and nine months ended September 30, 2004 and 2003 is as follows (some amounts between segment schedules may not agree due to rounding):
For the Nine Months Ended September 30, 2004 | ||||||
Utility Group | ||||||
Distribution | NU | Eliminations | ||||
(Millions of Dollars) | Electric | Gas | Transmission | Enterprises | and Other | Totals |
Operating revenues | $3,061.4 | $ 291.4 | $105.4 | $2,156.4 | $(583.7) | $5,030.9 |
Depreciation and amortization | (340.2) | (19.4) | (16.2) | (14.5) | (1.7) | (392.0) |
Other operating expenses | (2,474.5) | (250.9) | (48.6) | (2,067.5) | 580.9 | (4,260.6) |
Operating income/(loss) | 246.7 | 21.1 | 40.6 | 74.4 | (4.5) | 378.3 |
Interest expense, net | (118.4) | (12.7) | (8.7) | (39.4) | (10.2) | (189.4) |
Other income/(loss), net | 10.9 | (0.8) | (0.3) | 5.3 | (2.4) | 12.7 |
Income tax (expense)/benefit | (48.8) | 0.9 | (8.0) | (14.6) | 2.5 | (68.0) |
Preferred dividends | (4.2) | - | - | - | - | (4.2) |
Net income/(loss) | $ 86.2 | $ 8.5 | $ 23.6 | $ 25.7 | $ (14.6) | $ 129.4 |
Total assets (1) | $8,359.6 | $1,072.8 | $ - | $2,113.7 | $ (4.7) | $11,541.4 |
Total investments in plant | $ 281.3 | $ 37.1 | $120.9 | $ 13.9 | $ 10.5 | $ 463.7 |
(1)
Information for segmenting total assets between electric distribution and transmission is not available at September 30, 2004. On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution column above.
For the Three Months Ended September 30, 2004 | ||||||
Utility Group | ||||||
Distribution | NU | Eliminations | ||||
(Millions of Dollars) | Electric | Gas | Transmission | Enterprises | and Other | Totals |
Operating revenues | $1,037.7 | $48.2 | $40.8 | $739.0 | $(197.7) | $1,668.0 |
Depreciation and amortization | (124.9) | (6.6) | (6.1) | (4.9) | (0.7) | (143.2) |
Other operating expenses | (827.8) | (45.7) | (18.3) | (719.8) | 197.9 | (1,413.7) |
Operating income/(loss) | 85.0 | (4.1) | 16.4 | 14.3 | (0.5) | 111.1 |
Interest expense, net | (39.2) | (4.3) | (3.0) | (13.5) | (3.5) | (63.5) |
Other income/(loss), net | 3.9 | (0.2) | (0.2) | 2.4 | 2.3 | 8.2 |
Income tax (expense)/benefit | (17.9) | 5.0 | (2.2) | 0.8 | (1.0) | (15.3) |
Preferred dividends | (1.4) | - | - | - | - | (1.4) |
Net income/(loss) | $ 30.4 | $(3.6) | $11.0 | $ 4.0 | $ (2.7) | $ 39.1 |
For the Nine Months Ended September 30, 2003 | ||||||
Utility Group | ||||||
Distribution | NU | Eliminations | ||||
(Millions of Dollars) | Electric | Gas | Transmission | Enterprises | and Other | Totals |
Operating revenues | $2,998.5 | $253.7 | $88.5 | $1,903.4 | $(689.8) | $4,554.3 |
Depreciation and amortization | (358.4) | (17.2) | (13.9) | (14.8) | (1.7) | (406.0) |
Other operating expenses | (2,372.0) | (219.1) | (39.4) | (1,814.3) | 688.4 | (3,756.4) |
Operating income/(loss) | 268.1 | 17.4 | 35.2 | 74.3 | (3.1) | 391.9 |
Interest expense, net | (125.5) | (9.9) | (3.9) | (36.6) | (10.5) | (186.4) |
Other income/(loss), net | 2.2 | (1.4) | (0.1) | 4.2 | 1.1 | 6.0 |
Income tax (expense)/benefit | (54.8) | (2.7) | (9.6) | (17.9) | 8.7 | (76.3) |
Preferred dividends | (4.2) | - | - | - | - | (4.2) |
Income/(loss) before cumulative | 85.8 | 3.4 | 21.6 | 24.0 | (3.8) | 131.0 |
Cumulative effect of accounting | - | - | - | - | (4.7) | (4.7) |
Net income/(loss) | $ 85.8 | $ 3.4 | $21.6 | $ 24.0 | $ (8.5) | $ 126.3 |
Total investments in plant | $ 255.3 | $ 37.4 | $ 64.5 | $ 12.2 | $ 12.5 | $ 381.9 |
For the Three Months Ended September 30, 2003 | ||||||
Utility Group | ||||||
Distribution | NU | Eliminations | ||||
(Millions of Dollars) | Electric | Gas | Transmission | Enterprises | and Other | Totals |
Operating revenues | $1,104.5 | $30.6 | $32.7 | $735.3 | $(263.1) | $1,640.0 |
Depreciation and amortization | (132.3) | (5.8) | (4.7) | (4.6) | (0.6) | (148.0) |
Other operating expenses | (871.5) | (19.5) | (11.6) | (707.2) | 245.1 | (1,364.7) |
Operating income/(loss) | 100.7 | 5.3 | 16.4 | 23.5 | (18.6) | 127.3 |
Interest expense, net | (41.7) | (3.4) | (1.1) | (13.5) | (3.7) | (63.4) |
Other income/(loss), net | 2.7 | (0.4) | - | 1.3 | 1.1 | 4.7 |
Income tax (expense)/benefit | (23.3) | (11.1) | (5.5) | (4.4) | 21.0 | (23.3) |
Preferred dividends | (1.4) | - | - | - | - | (1.4) |
Income/(loss) before cumulative | 37.0 | (9.6) | 9.8 | 6.9 | (0.2) | 43.9 |
Cumulative effect of accounting | - | - | - | - | (4.7) | (4.7) |
Net income/(loss) | $ 37.0 | $(9.6) | $ 9.8 | $ 6.9 | $ (4.9) | $ 39.2 |
Utility Group segment information related to the regulated electric distribution and transmission businesses for CL&P, PSNH and WMECO for the three months and nine months ended September 30, 2004 and 2003 is as follows:
CL&P - For the Nine Months Ended September 30, 2004 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $2,083.4 | $69.9 | $2,153.3 |
Depreciation and amortization | (170.5) | (11.4) | (181.9) |
Other operating expenses | (1,761.0) | (32.0) | (1,793.0) |
Operating income | 151.9 | 26.5 | 178.4 |
Interest expense, net | (75.4) | (6.3) | (81.7) |
Other income, net | 15.3 | (0.2) | 15.1 |
Income tax expense | (38.0) | (4.5) | (42.5) |
Preferred dividends | (4.2) | - | (4.2) |
Net income | $ 49.6 | $15.5 | $ 65.1 |
Total investments in plant | $ 180.1 | $98.9 | $ 279.0 |
CL&P - For the Three Months Ended September 30, 2004 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $699.4 | $26.1 | $725.5 |
Depreciation and amortization | (56.9) | (3.9) | (60.8) |
Other operating expenses | (587.9) | (11.9) | (599.8) |
Operating income | 54.6 | 10.3 | 64.9 |
Interest expense, net | (24.6) | (2.3) | (26.9) |
Other income, net | 5.2 | (0.1) | 5.1 |
Income tax expense | (19.2) | (0.8) | (20.0) |
Preferred dividends | (1.4) | - | (1.4) |
Net income | $ 14.6 | $ 7.1 | $ 21.7 |
CL&P - For the Nine Months Ended September 30, 2003 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $2,061.3 | $57.7 | $2,119.0 |
Depreciation and amortization | (225.6) | (10.4) | (236.0) |
Other operating expenses | (1,681.9) | (26.1) | (1,708.0) |
Operating income | 153.8 | 21.2 | 175.0 |
Interest expense, net | (82.1) | (2.8) | (84.9) |
Other income, net | 4.8 | (0.2) | 4.6 |
Income tax expense | (26.8) | (4.7) | (31.5) |
Preferred dividends | (4.2) | - | (4.2) |
Net income | $ 45.5 | $13.5 | $ 59.0 |
Total investments in plant | $ 176.5 | $45.9 | $ 222.4 |
CL&P - For the Three Months Ended September 30, 2003 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $775.8 | $22.1 | $797.9 |
Depreciation and amortization | (76.6) | (3.5) | (80.1) |
Other operating expenses | (639.1) | (7.5) | (646.6) |
Operating income | 60.1 | 11.1 | 71.2 |
Interest expense, net | (27.4) | (0.8) | (28.2) |
Other income, net | 2.6 | - | 2.6 |
Income tax expense | (11.3) | (3.9) | (15.2) |
Preferred dividends | (1.4) | - | (1.4) |
Net income | $ 22.6 | $ 6.4 | $ 29.0 |
PSNH - For the Nine Months Ended September 30, 2004 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $705.3 | $24.2 | $729.5 |
Depreciation and amortization | (139.6) | (3.4) | (143.0) |
Other operating expenses | (493.0) | (11.4) | (504.4) |
Operating income | 72.7 | 9.4 | 82.1 |
Interest expense, net | (32.6) | (1.3) | (33.9) |
Other income, net | (3.3) | (0.1) | (3.4) |
Income tax expense | (6.7) | (2.1) | (8.8) |
Net income | $ 30.1 | $ 5.9 | $ 36.0 |
Total investments in plant | $ 70.5 | $18.3 | $ 88.8 |
PSNH - For the Three Months Ended September 30, 2004 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $247.7 | $11.2 | $258.9 |
Depreciation and amortization | (58.1) | (1.7) | (59.8) |
Other operating expenses | (164.2) | (4.5) | (168.7) |
Operating income | 25.4 | 5.0 | 30.4 |
Interest expense, net | (11.1) | (0.5) | (11.6) |
Other income, net | (1.2) | - | (1.2) |
Income tax expense | 1.4 | (0.8) | 0.6 |
Net income | $ 14.5 | $ 3.7 | $ 18.2 |
PSNH - For the Nine Months Ended September 30, 2003 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $650.8 | $19.3 | $670.1 |
Depreciation and amortization | (81.9) | (2.2) | (84.1) |
Other operating expenses | (481.5) | (8.7) | (490.2) |
Operating income | 87.4 | 8.4 | 95.8 |
Interest expense, net | (33.8) | (0.7) | (34.5) |
Other income, net | (3.6) | - | (3.6) |
Income tax expense | (20.4) | (2.8) | (23.2) |
Net income | $ 29.6 | $ 4.9 | $ 34.5 |
Total investments in plant | $ 59.6 | $17.3 | $ 76.9 |
PSNH - For the Three Months Ended September 30, 2003 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $229.4 | $6.6 | $236.0 |
Depreciation and amortization | (39.1) | (0.8) | (39.9) |
Other operating expenses | (158.8) | (2.5) | (161.3) |
Operating income | 31.5 | 3.3 | 34.8 |
Interest expense, net | (11.3) | (0.2) | (11.5) |
Other income, net | (1.2) | - | (1.2) |
Income tax expense | (8.5) | (1.0) | (9.5) |
Net income | $ 10.5 | $2.1 | $ 12.6 |
WMECO - For the Nine Months Ended September 30, 2004 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $272.9 | $11.3 | $284.2 |
Depreciation and amortization | (30.1) | (1.4) | (31.5) |
Other operating expenses | (220.7) | (5.2) | (225.9) |
Operating income | 22.1 | 4.7 | 26.8 |
Interest expense, net | (10.3) | (1.0) | (11.3) |
Other income, net | (1.1) | (0.1) | (1.2) |
Income tax expense | (4.1) | (1.5) | (5.6) |
Net income | $ 6.6 | $ 2.1 | 8.7 |
Total investments in plant | $ 21.6 | $ 3.7 | $ 25.3 |
WMECO - For the Three Months Ended September 30, 2004 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $90.7 | $3.5 | $94.2 |
Depreciation and amortization | (10.0) | (0.5) | (10.5) |
Other operating expenses | (75.7) | (1.9) | (77.6) |
Operating income | 5.0 | 1.1 | 6.1 |
Interest expense, net | (3.4) | (0.3) | (3.7) |
Other income, net | (0.2) | (0.1) | (0.3) |
Income tax expense | (0.1) | (0.5) | (0.6) |
Net income | $ 1.3 | $0.2 | $ 1.5 |
WMECO - For the Nine Months Ended September 30, 2003 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $286.3 | $11.5 | $297.8 |
Depreciation and amortization | (50.7) | (1.3) | (52.0) |
Other operating expenses | (208.7) | (4.6) | (213.3) |
Operating income | 26.9 | 5.6 | 32.5 |
Interest expense, net | (9.6) | (0.4) | (10.0) |
Other income, net | 1.0 | - | 1.0 |
Income tax expense | (7.6) | (2.0) | (9.6) |
Net income | $ 10.7 | $ 3.2 | $ 13.9 |
Total investments in plant | $ 19.2 | $ 1.3 | $ 20.5 |
WMECO - For the Three Months Ended September 30, 2003 | |||
(Millions of Dollars) | Distribution | Transmission | Totals |
Operating revenues | $99.3 | $4.1 | $103.4 |
Depreciation and amortization | (16.6) | (0.5) | (17.1) |
Other operating expenses | (73.5) | (1.7) | (75.2) |
Operating income | 9.2 | 1.9 | 11.1 |
Interest expense, net | (3.0) | (0.1) | (3.1) |
Other income, net | 1.2 | - | 1.2 |
Income tax expense | (3.4) | (0.6) | (4.0) |
Net income | $ 4.0 | $1.2 | $ 5.2 |
NU Enterprises' segment information for the three months and nine months ended September 30, 2004 and 2003 is as follows. Eliminations are included in the services and other column:
NU Enterprises - For the Nine Months Ended September 30, 2004 | |||
(Millions of Dollars) | Merchant Energy | Services | Totals |
Operating revenues | $1,949.1 | $207.3 | $2,156.4 |
Depreciation and amortization | (13.0) | (1.5) | (14.5) |
Other operating expenses | (1,860.7) | (206.8) | (2,067.5) |
Operating income | 75.4 | (1.0) | 74.4 |
Interest expense, net | (32.8) | (6.6) | (39.4) |
Other (loss)/income, net | (0.1) | 5.4 | 5.3 |
Income tax (expense)/benefit | (15.5) | 0.9 | (14.6) |
Net income/(loss) | $ 27.0 | $ (1.3) | $ 25.7 |
Total assets | $1,793.3 | $320.4 | $2,113.7 |
Total investments in plant | $ 13.0 | $ 0.9 | $ 13.9 |
NU Enterprises - For the Three Months Ended September 30, 2004 | |||
(Millions of Dollars) | Merchant Energy | Services | Totals |
Operating revenues | $664.1 | $74.9 | $739.0 |
Depreciation and amortization | (4.4) | (0.5) | (4.9) |
Other operating expenses | (646.2) | (73.6) | (719.8) |
Operating income | 13.5 | 0.8 | 14.3 |
Interest expense, net | (11.2) | (2.3) | (13.5) |
Other (loss)/income, net | - | 2.4 | 2.4 |
Income tax (expense)/benefit | 1.0 | (0.2) | 0.8 |
Net income/(loss) | $ 3.3 | $ 0.7 | $ 4.0 |
NU Enterprises - For the Nine Months Ended September 30, 2003 | |||
(Millions of Dollars) | Merchant Energy | Services | Totals |
Operating revenues | $1,731.1 | $172.3 | $1,903.4 |
Depreciation and amortization | (13.2) | (1.6) | (14.8) |
Other operating expenses | (1,646.0) | (168.3) | (1,814.3) |
Operating income | 71.9 | 2.4 | 74.3 |
Interest expense, net | (31.2) | (5.4) | (36.6) |
Other (loss)/income, net | (2.5) | 6.7 | 4.2 |
Income tax (expense)/benefit | (15.9) | (2.0) | (17.9) |
Net income/(loss) | $ 22.3 | $ 1.7 | $ 24.0 |
Total investments in plant | $ 12.2 | $ - | $ 12.2 |
NU Enterprises - For the Three Months Ended September 30, 2003 | |||
(Millions of Dollars) | Merchant Energy | Services | Totals |
Operating revenues | $675.9 | $59.4 | $735.3 |
Depreciation and amortization | (4.5) | (0.1) | (4.6) |
Other operating expenses | (648.6) | (58.6) | (707.2) |
Operating income | 22.8 | 0.7 | 23.5 |
Interest expense, net | (11.2) | (2.3) | (13.5) |
Other (loss)/income, net | (0.3) | 1.6 | 1.3 |
Income tax (expense)/benefit | (4.4) | - | (4.4) |
Net income/(loss) | $ 6.9 | $ - | $ 6.9 |
This Page Intentionally Left Blank
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES | |||||
CONSOLIDATED BALANCE SHEETS | |||||
(Unaudited) | |||||
September 30, | December 31, | ||||
2004 | 2003 | ||||
(Thousands of Dollars) | |||||
LIABILITIES AND CAPITALIZATION | |||||
Current Liabilities: | |||||
Notes payable to affiliated companies | $ 46,225 | $ 91,125 | |||
Accounts payable | 169,645 | 138,155 | |||
Accounts payable to affiliated companies | 100,688 | 176,948 | |||
Accrued taxes | 13,847 | 65,587 | |||
Accrued interest | 9,833 | 10,361 | |||
Derivative liabilities | 49,386 | 54,566 | |||
Other | 48,505 | 49,674 | |||
438,129 | 586,416 | ||||
Rate Reduction Bonds | 1,026,389 | 1,124,779 | |||
Deferred Credits and Other Liabilities: | |||||
Accumulated deferred income taxes | 746,026 | 609,068 | |||
Accumulated deferred investment tax credits | 89,183 | 90,885 | |||
Deferred contractual obligations | 288,046 | 318,043 | |||
Regulatory liabilities | 711,418 | 752,992 | |||
Other | 83,956 | 79,935 | |||
1,918,629 | 1,850,923 | ||||
Capitalization: | |||||
Long-Term Debt | 1,051,922 | 830,149 | |||
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 2004 and 2003 | 60,352 | 60,352 | |||
Capital surplus, paid in | 384,396 | 326,629 | |||
Retained earnings | 341,650 | 311,793 | |||
Accumulated other comprehensive loss | (370) | (347) | |||
Common Stockholder's Equity | 786,028 | 698,427 | |||
Total Capitalization | 1,954,150 | 1,644,776 | |||
Commitments and Contingencies (Note 4) | |||||
Total Liabilities and Capitalization | $ 5,337,297 | $ 5,206,894 | |||
The accompanying notes are an integral part of these consolidated financial statements. | |||||
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
CL&P is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management’s discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2004 reports on Form 10-Q, the NU 2003 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q.
RESULTS OF OPERATIONS
The components of significant income statement variances for the third quarter of 2004 and the first nine months of 2004 are provided in the table below.
|
| Income Statement Variances |
| ||||||||
|
| Third |
| Percent |
| Nine |
| Percent |
| ||
Operating Revenues: |
| $ | (72) | (9) | % | $ | 34 | 2 | % | ||
| |||||||||||
Operating Expenses: |
| ||||||||||
Fuel, purchased and net interchange power | (72) | (14) | 16 | 1 | |||||||
Other operation | 20 | 23 | 60 | 23 | |||||||
Maintenance | 3 | 17 | 6 | 12 | |||||||
Depreciation | 4 | 14 | 10 | 13 | |||||||
Amortization of regulatory assets, net | (25) | (96) | (70) | (88) | |||||||
Amortization of rate reduction bonds | 2 | 7 | 6 | 7 | |||||||
Taxes other than income taxes | 2 | 4 | 3 | 2 | |||||||
Total operating expenses | (66) | (9) | 31 | 2 | |||||||
Operating income | (6) | (9) | 3 | 2 | |||||||
Interest expense, net | (1) | (5) | (3) | (4) | |||||||
Other income, net | 3 | 90 | 11 | (a) | |||||||
Income before income tax expense | (2) | (6) | 17 | 18 | |||||||
Income tax expense | 5 | 32 | 11 | 35 | |||||||
Preferred dividends of subsidiary | - | - | - | - | |||||||
Net Income |
| $ | (7) |
| (25) | % | $ | 6 |
| 10 | % |
(a) Percent greater than 100.
Comparison of the Third Quarter of 2004 to the Third Quarter of 2003
Operating Revenues
Operating revenues decreased $72 million in the third quarter of 2004, compared with the same period in 2003, due to lower distribution revenues ($76 million), partially offset by higher transmission revenues ($4 million).
Distribution revenues were lower due to a decrease in revenues associated with the recovery of fuel, RMR and congestion costs and due to the negative 2003 unbilled revenue adjustment ($41 million), lower rates for the recovery of system benefit, C&LM, and transition costs ($30 million), and lower sales volumes for delivery revenues ($13 million), partially offset by higher TSO revenues ($17 million), the final DPUC order in the petition for reconsideration docket ($10 million), and an increase in the retail transmission rate ($8 million). Retail sales in the third quarter of 2004 were 6.6 percent lower than the same period last year primarily due to the 2003 positive unbilled estimate change. Wholesale revenues are lower due to a lower number of wholesale transactions ($23 million).
Transmission revenues were higher due to the October 2003 implementation of the transmission rate case filed at the FERC.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $72 million primarily due to lower amortization of fuel expense as a result of the lower recovery of fuel and congestion costs ($41 million), lower standard offer service supply costs ($15 million) as a result of a 2003 overrecovery, and lower purchased power costs ($16 million).
Other Operation
Other operation expenses increased $20 million primarily due to higher RMR costs ($22 million) and other power pool related expenses recovered through the Federally Mandated Congestion Cost (FMCC) charge ($6 million), and higher distribution operation expenses ($2 million), partially offset by lower C&LM expenses ($12 million).
Maintenance
Maintenance expenses increased $3 million primarily due to higher distribution line maintenance expenses.
Depreciation
Depreciation expense increased $4 million due to higher utility plant balances and higher depreciation rates resulting from the distribution rate case decision effective in January 2004.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $25 million primarily due to lower amortization related to the recovery of system benefit and transition charges ($18 million), and a reduction to amortization expense resulting from the implementation of the distribution rate case decision effective in January 2004 ($7 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $2 million due to the repayment of additional principal.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $2 million primarily due to higher local property taxes.
Interest Expense, Net
Interest expense, net decreased $1 million primarily due to lower rate reduction bond interest resulting from lower principal balances outstanding.
Other Income, Net
Other income, net increased $3 million primarily due to the recognition beginning in 2004 of a procurement fee approved in the TSO docket ($3 million).
Income Tax Expense
Income tax expense increased $5 million primarily due to a higher effective tax rate due to adjustments to tax reserves as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates.
Comparison of the First Nine Months of 2004 to the First Nine Months of 2003
Operating Revenues
Operating revenues increased $34 million in the first nine months of 2004, compared with the same period in 2003, due to higher distribution revenues ($22 million) and higher transmission revenues ($12 million).
Distribution revenues were higher due to an increase in TSO revenues ($120 million), an increase in the retail transmission rate ($20 million), the final DPUC order in the petition for reconsideration docket ($10 million), partially offset by lower rates for the recovery of system benefit, C&LM, and transition costs ($49 million) and lower revenues associated with the recovery of fuel, RMR and congestion costs ($18 million). Retail sales in the first nine months of 2004 were 0.3 percent lower than the same period of 2003 primarily due to the 2003 positive unbilled estimate change. The lower sales volume for delivery revenues was offset by increased rates. Wholesale revenues are lower due to a lower number of wholesale transactions ($51 million).
Transmission revenues were higher due to the October 2003 implementation of the transmission rate case filed at the FERC.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $16 million primarily due to an increase in the standard offer service supply costs ($59 million), partially offset by lower amortization of fuel expense as a result of the lower recovery of fuel and congestion costs ($18 million), lower wholesale purchases ($17 million) and lower purchased power costs ($8 million).
Other Operation
Other operation expenses increased $60 million primarily due to higher RMR costs ($42 million) and other power pool related expenses which are recovered through the Federally Mandated Congestion Costs (FMCC) charge ($8 million), higher administrative and general expenses ($10 million) primarily due to higher pension costs, higher distribution operation expenses ($4 million), and the 2003 positive resolution of the CL&P Millstone use of proceeds docket ($2 million), partially offset by lower C&LM expenses ($10 million).
Maintenance
Maintenance expenses increased $6 million primarily due to the 2003 positive resolution of the CL&P Millstone use of proceeds docket ($4 million), higher distribution maintenance expenses ($3 million), partially offset by lower transmission expenses ($1 million).
Depreciation
Depreciation expense increased $10 million due to higher utility plant balances and higher depreciation rates resulting from the distribution rate case decision effective in January 2004.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $70 million primarily due to lower amortization related to the recovery of system benefit and transition charges ($50 million), and a reduction to amortization expense resulting from the implementation of the distribution rate case decision effective in January 2004 ($22 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $6 million due to the repayment of additional principal.
Interest Expense, Net
Interest expense, net decreased $3 million due to lower rate reduction bond interest resulting from lower principal balances outstanding.
Other Income, Net
Other income, net increased $11 million primarily due to the recognition beginning in 2004 of a procurement fee approved in the TSO docket ($9 million).
Income Tax Expense
Income tax expense increased $11 million due to higher income before tax expense and a higher effective tax rate due to adjustments to tax reserves as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates.
LIQUIDITY
CL&P's net cash flows provided by operating activities decreased to $201.2 million for the nine months ended September 30, 2004 from $383.3 million for the same period in 2003 due to decreases in regulatory (refunds)/overrecoveries, amortization of regulatory assets and decreases in working capital items, primarily accounts payable and accrued taxes. These decreases are offset by changes in deferred income taxes and restricted cash - LMP costs.
The decrease in regulatory (refunds)/overrecoveries is primarily due to lower CTA and Generation Service Charge (GSC) collections in the first nine months of 2004 as CL&P is refunding amounts to its ratepayers for past overcollections or using those amounts to recover current costs. These refunds are also the primary reason for the positive change in deferred income taxes for the first nine months of 2004 as compared to the first nine months of 2003, which has increased operating cash flows. The change in deferred income taxes is expected to continue to benefit cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets. The decrease in amortization of regulatory assets is primarily due to lower amortization related to the recovery of system benefit and transition costs and implementation of the distribution rate case decision.
The release of restricted cash collected in 2003 associated with LMP costs but not yet paid to suppliers or refunded to customers increased cash from operations in the first nine months of 2004. CL&P paid $83 million to its standard offer suppliers in accordance with the FERC-approved SMD settlement agreement, which decreased accounts payable. Another approximately $56 million will be refunded to customers related to the SMD settlement agreement in the fourth quarter of 2004 and will negatively impact cash flows from operations. The timing of standard offer payments negatively impacted operating cash flows in the first nine months of 2004 as compared to the first nine months of 2003 and decreased accounts payable. The decrease in accrued taxes is primarily due to the timing of tax payments in 2004 and lower 2004 accrued taxes as a result of lower taxable income.
CL&P's net cash flows used in investing activities increased to $324.3 million for the first nine months of 2004 from $249.6 million for the same period in 2003. The increase in investing activities is primarily due to higher capital expenditures and lendings to the NU Money Pool during the first nine months of 2004 as compared to the same period in 2003.
CL&P's capital expenditures have been lower than what had been expected at the beginning of 2004. CL&P’s capital expenditures totaled $279 million for the first nine months of 2004, compared with $222.4 million for the first nine months of 2003. CL&P currently projects capital expenditures of $355.1 million in 2004 compared with the 2004 budgeted amount of $440 million. The lower level of capital spending compared to the budget was primarily related to delays in certain major transmission projects as a result of appeals of CSC decisions and other legal and regulatory delays.
The level of financing activities for the nine months ended September 30, 2004 included a capital contribution from NU in the amount of $58 million. CL&P also paid $35.3 million in dividends to NU during the first nine months of 2004 compared to $30 million during the first nine months of 2003.
At September 30, 2004, CL&P had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This revolving credit line is scheduled to mature on November 8, 2004 and will be replaced on that date by a $400 million, five-year facility. Under this new credit line, CL&P will be able to borrow up to $200 million on a short-term basis.
In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At September 30, 2004, CL&P had sold accounts receivable totaling $40 million to that financial institution. For more information regarding the sale of receivables, see Note 1G, "Summary of Significant Accounting Policies - Sale of Customer Receivables" to the consolidated financial statements.
On September 17, 2004, CL&P issued $150 million of 10-year first mortgage bonds at a fixed interest rate of 4.8 percent and also issued $130 million of 30-year first mortgage bonds at a fixed interest rate of 5.75 percent. CL&P used the proceeds from these issuances to repay short-term debt.
As part of the approved SMD settlement agreement, CL&P paid $83 million to its suppliers on July 8, 2004. Under the settlement agreement, CL&P also agreed to refund $75 million to its customers. The $83 million supplier payment was made from an escrow fund that was established during 2003 as these costs were being collected from customers. Of the combined payment and refund amount totaling $158 million, $31 million was not funded from the escrow account. CL&P began returning the $75 million to customers over a four-month period on September 1, 2004. Additionally, the DPUC ordered a refund of $88.5 million in CTA/SBC overcollections over a seven-month period beginning with October 2004 consumption. The combination of the SMD and CTA/SBC refunds, when combined with CL&P’s proposed capital expenditures, will negatively impact CL&P’s liquidity. CL&P is also refunding GSC overrecover ies of $120 million over a four-year period beginning in 2004. However, CL&P expects no difficulty in meeting these additional cash requirements.
This Page Intentionally Left Blank
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES | |||||
CONSOLIDATED BALANCE SHEETS | |||||
(Unaudited) | |||||
September 30, | December 31, | ||||
2004 | 2003 | ||||
(Thousands of Dollars) | |||||
LIABILITIES AND CAPITALIZATION | |||||
Current Liabilities: | |||||
Notes payable to banks | $ - | $ 10,000 | |||
Notes payable to affiliated companies | 22,900 | 48,900 | |||
Accounts payable | 34,152 | 48,408 | |||
Accounts payable to affiliated companies | 13,762 | 13,911 | |||
Accrued taxes | 8,287 | 1,913 | |||
Accrued interest | 14,332 | 10,894 | |||
Unremitted rate reduction bond collections | 9,770 | 11,051 | |||
Derivative liabilities | - | 1,414 | |||
Other | 17,216 | 16,689 | |||
120,419 | 163,180 | ||||
Rate Reduction Bonds | 440,476 | 472,222 | |||
Deferred Credits and Other Liabilities: | |||||
Accumulated deferred income taxes | 318,818 | 338,930 | |||
Accumulated deferred investment tax credits | 1,743 | 2,096 | |||
Deferred contractual obligations | 56,430 | 64,237 | |||
Regulatory liabilities | 313,187 | 272,081 | |||
Accrued pension | 53,938 | 44,766 | |||
Other | 26,631 | 26,124 | |||
770,747 | 748,234 | ||||
Capitalization: | |||||
Long-Term Debt | 457,188 | 407,285 | |||
Common Stockholder's Equity: | |||||
Common stock, $1 par value - authorized | |||||
100,000,000 shares; 301 shares outstanding | |||||
in 2004 and 2003 | - | - | |||
Capital surplus, paid in | 156,389 | 156,555 | |||
Retained earnings | 241,660 | 223,822 | |||
Accumulated other comprehensive loss | (141) | (117) | |||
Common Stockholder's Equity | 397,908 | 380,260 | |||
Total Capitalization | 855,096 | 787,545 | |||
Commitments and Contingencies (Note 4) | |||||
Total Liabilities and Capitalization | $ 2,186,738 | $ 2,171,181 | |||
The accompanying notes are an integral part of these consolidated financial statements. | |||||
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
PSNH is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management’s discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2004 reports on Form 10-Q, the NU 2003 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q.
RESULTS OF OPERATIONS
The components of significant income statement variances for the third quarter of 2004 and for the first nine months of 2004 are provided in the table below.
|
| Income Statement Variances |
| ||||||||
|
| Third |
| Percent |
| Nine |
| Percent |
| ||
Operating Revenues: |
| $ | 23 | 10 | % | $ | 59 | 9 | % | ||
| |||||||||||
Operating Expenses: |
| ||||||||||
Fuel, purchased and net interchange power | 1 | 1 | (7) | (2) | |||||||
Other operation | 7 | 21 | 22 | 22 | |||||||
Maintenance | (1) | (8) | (1) | (2) | |||||||
Depreciation | 1 | 8 | 2 | 7 | |||||||
Amortization of regulatory assets, net | 18 | 100 | 53 | (a) | |||||||
Amortization of rate reduction bonds | 1 | 5 | 3 | 11 | |||||||
Taxes other than income taxes | - | 1 | 1 | 5 | |||||||
Total operating expenses | 27 | 14 | 73 | 13 | |||||||
Operating income | (4) | (13) | (14) | (14) | |||||||
Interest expense, net | - | - | (1) | (2) | |||||||
Other income, net | - | - | - | - | |||||||
Income before income tax expense | (4) | (20) | (13) | (22) | |||||||
Income tax expense | (10) | (a) | (15) | (62) | |||||||
Net Income |
| $ | 6 | 45 | % | $ | 2 |
| 4 | % | |
(a) Percent greater than 100.
Comparison of the Third Quarter of 2004 to the Third Quarter of 2003
Operating Revenues
Operating revenues increased $23 million in the third quarter of 2004, as compared to the same period in 2003, primarily due to an increase in transition service energy rates ($20 million) and higher wholesale transmission revenues ($5 million), partially offset by lower wholesale revenues ($2 million).
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power increased $1 million primarily as a result of higher fossil fuel costs, partially offset by lower energy and capacity purchases.
Other Operation
Other operation expenses increased $7 million primarily due to higher retail transmission expenses which are collected through retail delivery rates ($3 million), higher fossil operation expense ($2 million), and higher administrative expense ($3 million) primarily due to higher pension and medical costs.
Maintenance
Maintenance expense decreased $1 million primarily due to lower fossil maintenance expenses.
Depreciation
Depreciation increased $1 million primarily due to higher plant balances.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $18 million primarily due to an acceleration in the recovery of PSNH’s non-securitized stranded costs. The acceleration of non-securitized stranded cost recovery was due to the positive reconciliation of stranded cost revenues and stranded cost expense, which also includes net TS costs.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $1 million as a result of the repayment of additional principal.
Income Tax Expense
Income tax expense decreased $10 million primarily due to a lower effective tax rate due to adjustments to tax reserves as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates ($5 million) and lower state unitary taxable income which resulted in lower state income taxes.
Comparison of the First Nine Months of 2004 to the First Nine Months of 2003
Operating Revenues
Operating revenues increased $59 million in the first nine months of 2004 compared with the same period of 2003, primarily due to higher distribution retail revenue ($68 million) and higher transmission revenue ($5 million), partially offset by lower wholesale revenue ($15 million). Distribution retail revenue increased primarily due to higher transition service energy revenue ($56 million) as a result of a combination of increased transition service energy rates ($48 million) and higher sales volumes ($8 million), and higher stranded cost revenues ($11 million). Retail kilowatt-hour (kWh) sales increased by 2.8 percent in 2004. Transmission revenues were higher due to the October 2003 implementation of the FERC approved transmission rate increase. The regulated wholesale revenue decrease is primarily due to a lower number of wholesale transactions.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power decreased $7 million primarily as a result of lower regulated energy and capacity purchases, partially offset by higher fossil fuel costs.
Other Operation
Other operation expenses increased $22 million primarily due to higher retail transmission expenses which are collected through retail delivery rates ($7 million), higher fossil generation expense ($5 million), and higher administrative expenses ($9 million) primarily due to higher pension and medical costs.
Maintenance
Maintenance expense decreased $1 million primarily due to lower fossil maintenance expenses ($4 million), mainly due to a higher level of fossil production maintenance overhaul expenses in 2003, partially offset by higher tree trimming, substation and overhead line maintenance ($2 million).
Depreciation
Depreciation increased $2 million primarily due to higher plant balances.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $53 million primarily due to an acceleration in the recovery of PSNH’s non-securitized stranded costs. The acceleration of non-securitized stranded cost recovery was possible due to the positive reconciliation of stranded cost revenues and stranded cost expense, which also includes net TS costs.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $3 million as a result of the repayment of additional principal.
Income Tax Expense
Income tax expense decreased $15 million primarily due to a lower effective tax rate due to adjustments to tax reserves as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates ($5 million), lower unitary taxable income which resulted in lower state income taxes, and lower book taxable income.
LIQUIDITY
PSNH's net cash flows provided by operating activities increased to $123.4 million for the nine months ended September 30, 2004 from $49.8 million for the same period in 2003. Cash flows provided by operating activities increased due to changes in working capital items, primarily accrued taxes, and due to higher amortization of regulatory assets. Accrued taxes decreased in 2003 due to the payment of taxes on the gain of the sale of Seabrook. Amortization of regulatory assets increased in the first nine months of 2004 primarily due to higher recovery of stranded and transition service energy costs.
At September 30, 2004, PSNH had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This revolving credit line is scheduled to mature on November 8, 2004 and will be replaced on that date by a $400 million, five-year facility. Under this new credit line PSNH will be able to borrow up to $100 million on a short-term basis.
There was a higher level of investing activities in the first nine months of 2004 compared to the same period of 2003 primarily due to lendings to the NU Money Pool and an increase in capital expenditures.
PSNH’s capital expenditures have been lower than what had been expected at the beginning of 2004. PSNH’s capital expenditures totaled $88.8 million for the first nine months of 2004, compared with $76.9 million for the first nine months of 2003. PSNH currently projects capital expenditures of $148.2 million in 2004 compared with the 2004 budgeted amount of $160 million.
PSNH paid $18.2 million in dividends to NU during the first nine months of 2004 compared to $11.2 million during the first nine months of 2003. There were no capital contributions made to PSNH from NU during the nine months ended 2004 or 2003.
On July 22, 2004, PSNH issued $50 million of 10-year first mortgage bonds at a fixed interest rate of 5.25 percent. Proceeds were used to repay short-term debt and fund PSNH’s capital expenditure program. In October 2004, PSNH received sufficient approvals to begin the construction related to the conversion of one of the coal-fired units at Schiller Station to burn wood. The NHPUC has approved the project but the NHPUC's approval is subject to an appeal to the New Hampshire Supreme Court. This project is expected to cost $75 million.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY | |||||
CONSOLIDATED BALANCE SHEETS | |||||
(Unaudited) | |||||
September 30, | December 31, | ||||
2004 | 2003 | ||||
(Thousands of Dollars) | |||||
LIABILITIES AND CAPITALIZATION | |||||
Current Liabilities: | |||||
Notes payable to banks | $ - | $ 10,000 | |||
Notes payable to affiliated companies | 34,200 | 31,400 | |||
Accounts payable | 16,927 | 10,173 | |||
Accounts payable to affiliated companies | 18,067 | 22,302 | |||
Accrued taxes | 567 | 765 | |||
Accrued interest | 1,287 | 2,544 | |||
Other | 11,073 | 9,785 | |||
82,121 | 86,969 | ||||
Rate Reduction Bonds | 125,078 | 132,960 | |||
Deferred Credits and Other Liabilities: | |||||
Accumulated deferred income taxes | 217,970 | 216,547 | |||
Accumulated deferred investment tax credits | 3,075 | 3,326 | |||
Deferred contractual obligations | 78,759 | 86,937 | |||
Regulatory liabilities | 31,360 | 27,776 | |||
Other | 7,701 | 8,357 | |||
338,865 | 342,943 | ||||
Capitalization: | |||||
Long-Term Debt | 207,451 | 157,202 | |||
Common Stockholder's Equity: | |||||
Common stock, $25 par value - authorized | |||||
1,072,471 shares; 434,653 shares outstanding | |||||
in 2004 and 2003 | 10,866 | 10,866 | |||
Capital surplus, paid in | 75,972 | 69,544 | |||
Retained earnings | 75,476 | 71,677 | |||
Accumulated other comprehensive loss | (89) | (84) | |||
Common Stockholder's Equity | 162,225 | 152,003 | |||
Total Capitalization | 369,676 | 309,205 | |||
Commitments and Contingencies (Note 4) | |||||
Total Liabilities and Capitalization | $ 915,740 | $ 872,077 | |||
| |||||
|
| ||||
The accompanying notes are an integral part of these consolidated financial statements. | |||||
The accompanying notes are an integral part of these consolidated financial statements. |
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
Management's Discussion and Analysis of
Financial Condition and Results of Operations
WMECO is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management’s discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2004 reports on Form 10-Q, the NU 2003 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q.
RESULTS OF OPERATIONS
The components of significant income statement variances for the third quarter of 2004 and the first nine months of 2004 are provided in the table below.
|
| Income Statement Variances |
| ||||||||
|
| Third |
| Percent |
| Nine |
| Percent |
| ||
Operating Revenues: |
| $ | (9) | (9) | % | $ | (14) | (5) | % | ||
| |||||||||||
Operating Expenses: |
| ||||||||||
Fuel, purchased and net interchange power | 3 | 5 | 11 | 7 | |||||||
Other operation | - | - | 1 | 2 | |||||||
Maintenance | - | - | 1 | 8 | |||||||
Depreciation | - | - | 1 | 7 | |||||||
Amortization of regulatory assets, net | (7) | (63) | (22) | (64) | |||||||
Amortization of rate reduction bonds | - | - | - | - | |||||||
Taxes other than income taxes | - | - | - | - | |||||||
Total operating expenses | (4) | (5) | (8) | (3) | |||||||
Operating income | (5) | (45) | (6) | (18) | |||||||
Interest expense, net | 1 | 19 | 1 | 14 | |||||||
Other income, net | (1) | (a) | (2) | (a) | |||||||
Income before income tax expense | (7) | (76) | (9) | (39) | |||||||
Income tax expense | (3) | (84) | (4) | (42) | |||||||
Net Income |
| $ | (4) | (70) | % | $ | (5) |
| (37) | % | |
(a) Percent greater than 100.
Comparison of the Third Quarter of 2004 to the Third Quarter of 2003
Operating Revenues
Operating revenues decreased $9 million in the third quarter of 2004, as compared to the same period in 2003, primarily due to lower transition charge revenues ($7 million), lower delivery revenues due primarily to lower sales volumes ($2 million) and lower wholesale revenue ($2 million) partially offset by higher standard offer service revenues ($3 million). Retail sales were 1.5 percent lower due to the change in unbilled revenue estimates recognized in 2003. The regulated wholesale revenue decrease is primarily due to a lower number of wholesale transactions.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $3 million primarily due to higher standard offer supply costs.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $7 million primarily due to the lower recovery of stranded costs as a result of the decrease in the transition component of retail rates.
Interest Expense, Net
Interest expense, net increased $1 million primarily due to higher long-term debt levels.
Other Income, Net
Other income, net decreased $1 million primarily due to the absence of the 2003 benefit of a transition charge settlement.
Income Tax Expense
Income tax expense decreased $3 million primarily due to lower book taxable income.
Comparison of the First Nine Months of 2004 to the First Nine Months of 2003
Operating Revenues
Operating revenues decreased $14 million in the first nine months of 2004 compared with the same period of 2003, primarily due to lower retail ($5 million) and wholesale revenue ($7 million). Retail revenues were lower primarily due to a decrease in the transition charge and retail transmission rates ($20 million) which was partially offset by an increase in standard offer service revenues ($15 million). Wholesale revenues were lower primarily due to a lower number of wholesale transactions. Retail kWh sales increased by 1.6 percent in 2004.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $11 million primarily due to higher standard offer supply costs.
Other Operation
Other operation increased $1 million primarily due to higher pension costs ($2 million), offset by lower retail transmission expenses which are collected through retail transmission rates ($1 million).
Maintenance
Maintenance expense increased $1 million primarily due to higher tree trimming expenses.
Depreciation
Depreciation expense increased $1 million primarily due to higher utility plant balances.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $22 million primarily due to the lower recovery of stranded costs as a result of the decrease in the transition component of retail rates.
Interest Expense, Net
Interest expense, net increased $1 million primarily due to higher long-term debt levels.
Other Income, Net
Other income, net decreased $2 million primarily due to the absence of the 2003 benefit of a transition charge settlement.
Income Tax Expense
Income tax expense decreased $4 million primarily due to lower book taxable income.
LIQUIDITY
WMECO's net cash flows provided by operating activities decreased to $37.3 million for the first nine months of 2004 from $52.2 million for the same period of 2003. Net cash flows provided by operating activities decreased primarily due to a decrease in amortization of regulatory assets. Amortization of regulatory assets decreased in the first nine months of 2004 primarily due to the lower recovery of stranded costs as a result of a decrease in the transition component of retail rates.
At September 30, 2004, WMECO had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This revolving credit line is scheduled to mature on November 8, 2004 and will be replaced on that date by a $400 million, five-year facility. Under this new credit line WMECO will be able to borrow up to $100 million on a short-term basis.
WMECO's net cash flows used in investing activities were $71 million for the nine months ended September 30, 2004, compared with $74.9 million for the same period of 2003. Investing activities for the nine months 2004 are made up of borrowings from the NU Money Pool and an investment in a trust fund that will be used to meet WMECO's prior spent nuclear fuel liability.
WMECO’s capital expenditures totaled $25.3 million for the first nine months of 2004, compared with $20.5 million for the first nine months of 2003.
WMECO paid $4.9 million in dividends to NU in the first nine months of 2004 compared to $18 million in the first nine months of 2003. There were no capital contributions made to WMECO from NU during the nine months ended 2004 or 2003.
On September 23, 2004, WMECO issued $50 million of 30-year senior unsecured notes at a fixed interest rate of 5.9 percent. Proceeds were used to finance a trust fund which will be used to meet WMECO's prior spent nuclear fuel liability.
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk Information
Select Energy utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, fair value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices.
NU Enterprises - Wholesale and Retail Marketing Portfolio: When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil on the wholesale and retail marketing portfolio, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, natural gas and oil, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange.
Select Energy has determined a hypothetical change in the fair value for its wholesale and retail marketing portfolio, which includes cash flow hedges and electricity, natural gas and oil contracts, assuming a 10 percent change in forward market prices. At September 30, 2004, a 10 percent change in market price would have resulted in an increase in fair value of $47.4 million or a decrease in fair value of $45.1 million.
The impact of a change in electricity, natural gas and oil prices on Select Energy's wholesale and retail marketing portfolio at September 30, 2004, is not necessarily representative of the results that will be realized when these contracts are physically delivered.
NU Enterprises - Trading Contracts: At September 30, 2004, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices. That 10 percent change would result in approximately a $1.1 million increase or decrease in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either non-financial or non-quantifiable. These risks principally include credit risk, which is not reflected in this sensitivity analysis.
Other Risk Management Activities
Interest Rate Risk Management: NU manages its interest rate risk exposure in accordance with its written policies and procedures by maintaining a mix of fixed and variable rate debt. At September 30, 2004, approximately 86 percent (77 percent including the debt subject to the fixed-to-floating interest rate swap in variable rate debt) of NU’s long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate. The remaining long-term debt is variable-rate and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in NU’s variable interest rates, including the rate on debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.9 million. At September 30, 2004, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associa ted with its $263 million of fixed-rate debt.
Credit Risk Management: Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of its contractual obligations. NU serves 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 NU realizes 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 which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU’s risk management process.
Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council operating outside of the business lines that create or actively manage these risk exposures to ensure compliance with NU’s stated risk management policies.
NU tracks and re-balances the risk in its portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.
NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy. Select Energy has 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. 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 overall exposure to credit risk, either pos itively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.
At September 30, 2004 and December 31, 2003, Select Energy maintained collateral balances from counterparties of $67.4 million and $46.5 million, respectively. These amounts are included in both cash and cash equivalents and other current liabilities on the accompanying consolidated balance sheets. Select Energy also has collateral balances deposited with counterparties of $80.2 million and $24.5 million at September 30, 2004 and December 31, 2003, respectively.
The Utility Group has a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises. However, the Utility Group companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. The Utility Group manages the credit risk with these counterparties in accordance with established credit risk practices and maintains an oversight group that monitors contracting risks, including credit risk.
Additional quantitative and qualitative disclosures about market risk are set forth in "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations," to the consolidated financial statements herein.
ITEM 4.
NU, CL&P, PSNH and WMECO (collectively, the companies) evaluated the design and operation of their 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 the supervision and with the participation of management, including the companies’ principal executive officer and principal financial officer, as of the end of the period covered by this Quarterly Report on Form 10-Q. The principal executive officer and principal financial officer have concluded, based on their review, that the companies’ disclosure controls and procedures are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act 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 officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
There have been no significant changes in the companies’ internal controls over financial reporting during the quarter ended September 30, 2004 that have materially affected, or are reasonably likely to materially affect the companies’ internal control over financial reporting.
Management is conducting testing in connection with its assessment of internal controls over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002. Management anticipates completing its assessment as of December 31, 2004 on a timely basis for inclusion in NU's annual report on Form 10-K.
PART II. OTHER INFORMATION
ITEM 1.
1.
Consolidated Edison, Inc. v. NU – Merger Appeals and Related Litigation
This litigation consists of the consolidated civil lawsuits filed in the United States District Court for the Southern District of New York (District Court) by Con Edison and NU regarding the parties’ October 19, 1999 Agreement and Plan of Merger, as amended and restated as of January 11, 2000 (Merger Agreement). In its amended complaint, Con Edison alleges that NU failed to perform material obligations under the Merger Agreement, that there was a "Material Adverse Change" with respect to NU and that certain conditions precedent to Con Edison’s obligation to merge with NU was not and could not be satisfied. (Con Edison’s amended complaint further asserted claims for fraud and negligent misrepresentation which were dismissed on summary judgment on March 15, 2003.) In its counterclaim, NU seeks damages in excess of $1 billion alleging that Con Edison is in material breach of the Merger Agreement based on its repudiati on thereof and its refusal to proceed with the merger.
The companies have completed discovery in the litigation and submitted cross motions for summary judgment. The District Court has denied Con Edison’s motion in its entirety, thus eliminating Con Edison’s claims against NU for fraud and negligent misrepresentation.
On December 24, 2003, the District Court granted Robert Rimkoski’s July 24, 2003 motion to intervene as the representative of the March 5, 2001 class of NU shareholders, who he asserts are entitled to any damages which may be payable by Con Edison. NU filed a cross-claim against Rimkoski seeking a declaratory ruling that NU’s current shareholders are the proper third-party beneficiaries under the Merger Agreement, rather than the March 5, 2001 class of shareholders. By order dated May 15, 2004, the District Court issued its opinion that the March 5, 2001 class of shareholders are the proper beneficiaries under the Merger Agreement. Citing "substantial grounds for difference of opinion" and the potential impact of this decision beyond the issues in this case, the court certified the decision for appeal to the Second Circuit Court of Appeals. In addition, the court included in its certification the previous determina tion that the NU shareholders are the intended third-party beneficiaries under the Merger Agreement.
NU and Con Edison filed separate petitions for appeal on June 1, 2004 with the Second Circuit Court of Appeals. By order dated October 20, 2004, the Second Circuit granted the parties’ petitions for appeal.
No trial date has been set. At this stage of the litigation, management can predict neither the outcome of this matter nor its ultimate effect on NU.
2.
Connecticut Yankee Decommissioning Dispute
CY continues to prosecute its counterclaims for excess completion costs and other damages against Bechtel in the Court. Discovery is underway and a trial has been scheduled for May 2006. On July 20, 2004, the Court allowed the DPUC to intervene in the PJR proceeding filed in June 2004 for the limited purpose of objecting to Bechtel’s requested garnishment of the decommissioning trust and related payments. Oral argument was held on August 26, 2004 on the legal availability of the remedies requested by Bechtel but no decision has been issued. On October 27, 2004, Bechtel and CY entered into a Stipulation Regarding Prejudgment Remedy under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY's real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CY through June 30, 2007. This stipul ation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CY intends to contest the attachability of such assets. Management cannot predict the outcome of this litigation or its impact on NU.
For further information relating to the dispute with Bechtel, see Part I, Item 3, "Legal Proceedings" in NU’s 2003 Form 10-K and Part II, "Other Information – Legal Proceedings" in NU’s Form 10-Q for the quarter ended June 30, 2004. For further information relating to decommissioning collections, see Part I, Item 1, "Business – Nuclear Generation – Decommissioning" in NU’s 2003 Form 10-K.
3.
NRG/Yankee Gas
On October 9, 2002, NRG informed Yankee Gas that its affiliate, Meriden Gas Turbines, LLC (MGT), was permanently shutting down or abandoning its Meriden power plant project, and requested that Yankee Gas cease its construction activities and begin an orderly wind down of its work relating to the project. In November 2002, MGT filed suit against Yankee Gas in Meriden Superior Court, claiming that Yankee Gas breached the agreement with MGT (MGT Agreement) and seeking a declaratory ruling from the court that Yankee Gas wrongfully drew down a $16 million letter of credit. Yankee Gas has filed an amended answer and counterclaim and an application for PJR seeking to attach sufficient assets to secure a judgment on Yankee Gas’ counterclaims and a preliminary injunction seeking to enjoin a sale of MGT’s assets, including the MGT project itself. Hearings were held on Yankee Gas’ applications and the court ordered the parties to partic ipate in mediation, which was held on September 21, 2004. The mediation was unsuccessfuland on October 7, 2004, the court denied Yankee Gas' application for a PJR and preliminary injunction. Expert witness discovery is ongoing.
For additional information on NRG-related matters, including this litigation, see Item 1, "Business - Rates and Electric Industry Restructuring - Connecticut Rates and Restructuring" in NU’s 2003 Form 10-K and Part II, "Other Information - Legal Proceedings" in NU’s Forms 10-Q for the quarters ended March 31, 2004 and June 30, 2004.
ITEM 2.
CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES
There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the quarter ended September 30, 2004.
ITEM 6.
EXHIBITS AND REPORTS ON FORM 8-K
(a)
Listing of Exhibits (NU)
Exhibit No.
Description
10.1
Letter Agreement relating to employment of Lawrence E. De Simone dated September 27, 2004
15
Deloitte & Touche LLP Letter Regarding Unaudited Financial Information
31
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
31.1
Certification of John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
32
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and John H. Forsgren, Vice Chairman, 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 November 5, 2004
(a)
Listing of Exhibits (CL&P)
4.15
Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.2 to CL&P Form 8-K filed September 22, 2004)
4.16
Form of Composite Indenture of Mortgage, as proposed to be amended and restated (included as Schedule C to the Series A Supplemental Indenture) dated as of May 1, 1921, as amended and supplemented (Exhibit 99.4 to CL&P Form 8-K filed September 22, 2004)
4.17
Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5 to CL&P Form 8-K filed September 22, 2004)
31
Certification of Cheryl W. Grisé, Chief Executive Officer of The Connecticut Light and Power Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
31.1
Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
32
Certification of Cheryl W. Grisé, Chief Executive Officer of The Connecticut Light and Power Company and John H. Forsgren, 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 November 5, 2004
(a)
Listing of Exhibits (PSNH)
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 (Exhibit 99.2 to PSNH Form 8-K filed October 5, 2004)
31
Certification of Cheryl W. Grisé, Chief Executive Officer of Public Service Company of New Hampshire, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
31.1
Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
32
Certification of Cheryl W. Grisé, Chief Executive Officer of Public Service Company of New Hampshire and John H. Forsgren, 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 November 5, 2004
(a)
Listing of Exhibits (WMECO)
4.1.3
Second Supplemental Indenture dated as of September 1, 2004, between WMECO and Morgan Stanley & Co. (Exhibit 4.1 to WMECO Form 8-K filed September 27, 2004)
31
Certification of Cheryl W. Grisé, Chief Executive Officer of Western Massachusetts Electric Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
31.1
Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2004
32
Certification of Cheryl W. Grisé, Chief Executive Officer of Western Massachusetts Electric Company and John H. Forsgren, 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 November 5, 2004
(b)
Reports on Form 8-K:
NU and PSNH filed current reports on Form 8-K dated July 14, 2004 disclosing:
·
The filing with the NHPUC of a settlement among several parties with regards to its delivery service rate case.
PSNH filed a current report on Form 8-K dated July 22, 2004 disclosing:
·
The completion of the issuance and sale to the public of $50 million of 5.25 percent first mortgage bonds due in 2014.
NU and CL&P filed current reports on Form 8-K dated August 19, 2004 disclosing:
·
The dismissal of the appeal by the City of Norwalk concerning the Bethel, Connecticut to Norwalk, Connecticut transmission project.
NU filed a current report on Form 8-K dated September 15, 2004 disclosing:
·
The announcement that John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer, will retire effective January 1, 2005 and at that time, David R. McHale, NU Vice President and Treasurer, will be promoted to senior vice president and chief financial officer.
CL&P filed a current report on Form 8-K dated September 17, 2004 disclosing:
·
The completion of the issuance and sale to the public of $150 million of 4.8 percent first mortgage bonds due in 2014 and $130 million of 5.75 percent first mortgage bonds due in 2034.
WMECO filed a current report on Form 8-K dated September 23, 2004 disclosing:
·
The completion of the issuance and sale to the public of $50 million of 5.9 percent senior notes due in 2034.
NU filed a current report on Form 8-K dated October 25, 2004 disclosing:
·
NU's financial results for the third quarter and nine months ended September 30, 2004.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
NORTHEAST UTILITIES | ||
Registrant | ||
Date: November 5, 2004 | By | /s/ John H. Forsgren |
John H. Forsgren | ||
Vice Chairman, | ||
Executive Vice President and Chief Financial Officer | ||
| (for the Registrant and as Principal Financial Officer) | |
____________________________________________________________________________________
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY | ||
Registrant | ||
Date: November 5, 2004 | By | /s/ John H. Forsgren |
John H. Forsgren | ||
Executive Vice President and Chief Financial Officer | ||
| (for the Registrant and as Principal Financial Officer) | |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE | ||
Registrant | ||
Date: November 5, 2004 | By | /s/ John H. Forsgren |
John H. Forsgren | ||
Executive Vice President and Chief Financial Officer | ||
| (for the Registrant and as Principal Financial Officer) | |
____________________________________________________________________________________
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY | ||
Registrant | ||
Date: November 5, 2004 | By | /s/ John H. Forsgren |
John H. Forsgren | ||
Executive Vice President and Chief Financial Officer | ||
| (for the Registrant and as Principal Financial Officer) | |