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
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
-------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
- ----------- ----------------------------------- ------------------
1-5324 NORTHEAST UTILITIES 04-2147929
-------------------
(a Massachusetts voluntary association)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone: (413) 785-5871
0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850
---------------------------------------
(a Connecticut corporation)
107 Selden Street
Berlin, Connecticut 06037-1616
Telephone: (860) 665-5000
1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050
---------------------------------------
(a New Hampshire corporation)
Energy Park
780 North Commercial Street
Manchester, New Hampshire 03101-1134
Telephone: (603) 669-4000
0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130
--------------------------------------
(a Massachusetts corporation)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone: (413) 785-5871
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 X No
--- ---
Indicate by check mark whether the following registrants are accelerated
filers (as defined in Rule 12b-2 of the Exchange Act):
Northeast Utilities Yes X No
--- ---
The Connecticut Light and Power Company Yes No X
--- ---
Public Service Company of New Hampshire Yes No X
--- ---
Western Massachusetts Electric Company Yes No X
--- ---
Indicate the number of shares outstanding of each of the issuers' classes
of common stock, as of the latest practicable date:
Company - Class of Stock Outstanding at July 31, 2004
- ------------------------ ----------------------------
Northeast Utilities
Common shares, $5.00 par value 128,232,433 shares
The Connecticut Light and Power Company
Common stock, $10.00 par value 6,035,205 shares
Public Service Company of New Hampshire
Common stock, $1.00 par value 301 shares
Western Massachusetts Electric Company
Common stock, $25.00 par value 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 OR SEGMENTS
BMC....................... BMC Energy LLC
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, Inc.
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
CYAPC..................... Connecticut Yankee Atomic Power Company
NRG....................... NRG Energy, Inc.
REGULATORS
CSC....................... Connecticut Siting Council
DPUC...................... Connecticut Department of
Public Utility Control
DTE....................... Massachusetts Department of
Telecommunications and Energy
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
FIN....................... FASB Interpretation
FMCC...................... Federally Mandated Congestion Costs
FSP....................... FASB Staff Position
FTR....................... Financial Transmission Rights
GSC....................... Generation Service Charge
IERM...................... Infrastructure Expansion Rate Mechanism
Incentive Plan............ Northeast Utilities Incentive Plan
ISO-NE.................... New England Independent System Operator
kWh....................... Kilowatt-hour
LMP....................... Locational Marginal Pricing
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
Restructuring
Settlement.............. "Agreement to Settle PSNH Restructuring"
ROE....................... Return on Equity
RTO....................... Regional Transmission Organization
S&P....................... Standard & Poor's
SBC....................... System Benefits Charge
SCRC...................... Stranded Cost Recovery Charge
SFAS...................... Statement of Financial Accounting Standards
SMD....................... Standard Market Design
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
-----------------
Page
----
Part I. Financial Information
Item 1. Consolidated Financial Statements
and
Item 2. Management's Discussion and
Analysis of Financial Condition
and Results of Operations
For the following companies:
Northeast Utilities and Subsidiaries
Consolidated Balance Sheets (Unaudited) -
June 30, 2004 and December 31, 2003...................... 2
Consolidated Statements of Income (Unaudited) -
Three and Six Months Ended June 30, 2004 and 2003........ 4
Consolidated Statements of Cash Flows (Unaudited) -
Six Months Ended June 30, 2004 and 2003.................. 5
Management's Discussion and Analysis of
Financial Condition and Results of Operations............ 6
Report of Independent Registered Public Accounting Firm....... 30
Notes to Consolidated Financial Statements
(unaudited - all companies).................................... 31
The Connecticut Light and Power Company
and Subsidiaries
Consolidated Balance Sheets (Unaudited) -
June 30, 2004 and December 31, 2003...................... 62
Consolidated Statements of Income (Unaudited) -
Three and Six Months Ended June 30, 2004 and 2003........ 64
Consolidated Statements of Cash Flows (Unaudited) -
Six Months Ended June 30, 2004 and 2003.................. 65
Management's Discussion and Analysis of
Financial Condition and Results of Operations............ 66
Public Service Company of New Hampshire
and Subsidiaries
Consolidated Balance Sheets (Unaudited) -
June 30, 2004 and December 31, 2003...................... 72
Consolidated Statements of Income (Unaudited) -
Three and Six Months Ended June 30, 2004 and 2003........ 74
Consolidated Statements of Cash Flows (Unaudited) -
Six Months Ended June 30, 2004 and 2003.................. 75
Management's Discussion and Analysis of
Financial Condition and Results of Operations............ 76
Western Massachusetts Electric Company
and Subsidiary
Consolidated Balance Sheets (Unaudited) -
June 30, 2004 and December 31, 2003...................... 80
Consolidated Statements of Income (Unaudited) -
Three and Six Months Ended June 30, 2004 and 2003........ 82
Consolidated Statements of Cash Flows (Unaudited) -
Six Months Ended June 30, 2004 and 2003.................. 83
Management's Discussion and Analysis of
Financial Condition and Results of Operations............ 84
Item 3. Quantitative and Qualitative
Disclosures About Market Risk............................ 87
Item 4. Controls and Procedures.................................. 89
Part II. Other Information
Item 1. Legal Proceedings........................................ 90
Item 2. Changes in Securities, Use of Proceeds
and Issuer Purchases of Equity Securities................ 91
Item 4. Submission of Matters to a Vote of Security Holders...... 91
Item 6. Exhibits and Reports on Form 8-K......................... 92
Signatures.............................................................. 94
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
-------------- --------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 75,265 $ 37,196
Unrestricted cash from counterparties 104,976 46,496
Restricted cash - LMP costs 123,887 93,630
Special deposits 28,147 79,120
Investments in securitizable assets 190,388 166,465
Receivables, net 648,659 704,893
Unbilled revenues 102,597 125,881
Fuel, materials and supplies, at average cost 154,459 154,076
Derivative assets 365,991 249,117
Prepayments and other 69,106 63,780
--------------- ---------------
1,863,475 1,720,654
--------------- ---------------
Property, Plant and Equipment:
Electric utility 5,702,856 5,465,854
Gas utility 763,605 743,990
Competitive energy 902,871 885,953
Other 238,402 221,986
--------------- ---------------
7,607,734 7,317,783
Less: Accumulated depreciation 2,320,807 2,244,263
--------------- ---------------
5,286,927 5,073,520
Construction work in progress 354,823 356,396
--------------- ---------------
5,641,750 5,429,916
--------------- ---------------
Deferred Debits and Other Assets:
Regulatory assets 2,854,344 2,974,022
Goodwill 319,986 319,986
Purchased intangible assets, net 21,153 22,956
Prepaid pension 358,250 360,706
Other 454,831 428,567
--------------- ---------------
4,008,564 4,106,237
--------------- ---------------
Total Assets $ 11,513,789 $ 11,256,807
=============== ===============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
-------------- --------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ 5,807 $ 105,000
Long-term debt - current portion 89,114 64,936
Accounts payable 903,122 768,783
Accrued taxes 27,148 51,598
Accrued interest 43,310 41,653
Derivative liabilities 163,050 112,612
Counterparty deposits 104,976 46,496
Other 214,378 203,080
--------------- ---------------
1,550,905 1,394,158
--------------- ---------------
Rate Reduction Bonds 1,639,344 1,729,960
--------------- ---------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,346,602 1,287,354
Accumulated deferred investment tax credits 101,000 102,652
Deferred contractual obligations 436,837 469,218
Regulatory liabilities 1,239,698 1,164,288
Other 248,818 247,526
--------------- ---------------
3,372,955 3,271,038
--------------- ---------------
Capitalization:
Long-Term Debt 2,510,927 2,481,331
--------------- ---------------
Preferred Stock of Subsidiaries - Non-Redeemable 116,200 116,200
--------------- ---------------
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 150,578,806 shares issued
and 128,098,320 shares outstanding in 2004 and
150,398,403 shares issued and 127,695,999 shares
outstanding in 2003 752,894 751,992
Capital surplus, paid in 1,110,135 1,108,924
Deferred contribution plan - employee stock
ownership plan (67,274) (73,694)
Retained earnings 840,082 808,932
Accumulated other comprehensive income 46,645 25,991
Treasury stock, 19,573,433 shares in 2004
and 19,518,023 shares in 2003 (359,024) (358,025)
--------------- ---------------
Common Shareholders' Equity 2,323,458 2,264,120
--------------- ---------------
Total Capitalization 4,950,585 4,861,651
--------------- ---------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 11,513,789 $ 11,256,807
=============== ===============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------ -----------------------------
2004 2003 2004 2003
-------------- -------------- -------------- -------------
Operating Revenues $ 1,524,666 $ 1,330,038 $ 3,362,953 $ 2,914,221
-------------- -------------- -------------- --------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 914,200 767,002 2,091,511 1,732,605
Other 270,737 230,708 497,262 419,418
Maintenance 67,673 68,280 124,884 114,172
Depreciation 55,561 50,692 110,134 100,165
Amortization 28,087 22,890 57,378 83,303
Amortization of rate reduction bonds 38,294 35,303 81,293 74,503
Taxes other than income taxes 55,695 51,460 133,284 125,434
-------------- -------------- -------------- --------------
Total operating expenses 1,430,247 1,226,335 3,095,746 2,649,600
-------------- -------------- -------------- --------------
Operating Income 94,419 103,703 267,207 264,621
Interest Expense:
Interest on long-term debt 33,998 28,546 66,736 61,486
Interest on rate reduction bonds 25,043 27,364 50,738 55,225
Other interest 4,097 3,617 8,444 6,361
-------------- -------------- -------------- --------------
Interest expense, net 63,138 59,527 125,918 123,072
-------------- -------------- -------------- --------------
Other Income, Net 2,862 754 4,549 1,330
-------------- -------------- -------------- --------------
Income Before Income Tax Expense 34,143 44,930 145,838 142,879
Income Tax Expense 9,871 16,672 52,734 53,027
-------------- -------------- -------------- --------------
Income Before Preferred Dividends of Subsidiary 24,272 28,258 93,104 89,852
Preferred Dividends of Subsidiary 1,389 1,389 2,779 2,779
-------------- -------------- -------------- --------------
Net Income $ 22,883 $ 26,869 $ 90,325 $ 87,073
=============== ============== ============== ==============
Basic and Fully Diluted Earnings Per Common Share $ 0.18 $ 0.21 $ 0.71 $ 0.69
============== ============== ============== ==============
Basic Common Shares Outstanding (average) 128,033,513 126,747,117 127,956,640 126,880,397
============== ============== ============== ==============
Fully Diluted Common Shares Outstanding (average) 128,182,645 126,860,208 128,121,751 126,982,903
============== ============== ============== ==============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<Table>
<Caption>
Six Months Ended
June 30,
-------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating Activities:
Income before preferred dividends of subsidiary $ 93,104 $ 89,852
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 110,134 100,165
Deferred income taxes and investment tax credits, net 34,478 (10,383)
Amortization 57,378 83,303
Amortization of rate reduction bonds 81,293 74,503
Amortization/(deferral) of recoverable energy costs 24,193 (9,441)
Increase/(decrease) in prepaid pension 2,456 (15,606)
Regulatory overrecoveries 8,753 49,183
Other sources of cash 19,270 15,256
Other uses of cash (66,519) (70,895)
Changes in current assets and liabilities:
Restricted cash - LMP costs (30,257) -
Receivables and unbilled revenues, net 79,518 173,596
Fuel, materials and supplies 51 (4,208)
Investments in securitizable assets (23,923) 32,376
Other current assets (26,433) (63,608)
Accounts payable 134,339 (123,235)
Accrued taxes (24,450) (109,987)
Other current liabilities 34,661 786
---------- ----------
Net cash flows provided by operating activities 508,046 211,657
---------- ----------
Investing Activities:
Investments in plant:
Electric, gas and other utility plant (300,248) (226,515)
Competitive energy assets (11,329) (7,534)
---------- ----------
Cash flows used for investments in plant (311,577) (234,049)
Buyout/buydown of IPP contracts - (20,437)
Other investment activities 11,450 12,084
---------- ----------
Net cash flows used in investing activities (300,127) (242,402)
---------- ----------
Financing Activities:
Issuance of common shares 2,786 7,463
Repurchase of common shares - (23,209)
Issuance of long-term debt 82,438 194,851
Retirement of rate reduction bonds (90,616) (82,314)
(Decrease)/increase in short-term debt (99,193) 7,000
Reacquisitions and retirements of long-term debt (23,621) (28,688)
Cash dividends on preferred stock of subsidiaries (2,779) (2,779)
Cash dividends on common shares (38,379) (34,886)
Other financing activities (486) (4,343)
---------- ----------
Net cash flows (used in)/provided by financing activities (169,850) 33,095
---------- ----------
Net increase in cash and cash equivalents 38,069 2,350
Cash and cash equivalents - beginning of period 37,196 54,678
---------- ----------
Cash and cash equivalents - end of period $ 75,265 $ 57,028
========== ==========
</Table>
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 Quarter 2004 Form 10-Q,
the NU 2003 Form 10-K, and the current reports on Form 8-K dated May 19, 2004
and July 14, 2004. 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:
o Earnings at Northeast Utilities (NU or the company) decreased by $4
million in the second quarter of 2004 compared with the same period of
2003, and increased by $3.2 million for the first six months of 2004
compared with the first six months of 2003.
o Results for the second quarter and first half of 2004 include the
write-down of half of NU's $7.5 million investment in a developer of fuel
cell and power quality equipment. That write-down reduced earnings by
$0.02 per share.
o Regulated retail electric sales increased 4.6 percent in the first
half of 2004, compared with the first half of 2003, on a weather adjusted
basis. Second quarter retail electric sales increased 5.7 percent in 2004
compared with the same period of 2003, on a weather adjusted basis.
o NU continues to project earnings of between $1.20 per share and $1.40
per share in 2004.
Regulatory Items:
o On June 14, 2004, the transmission segment of NU's regulated companies
reached a settlement agreement with parties to its rate case in the
transmission rate case that allows transmission to implement formula-based
rates as proposed with an 11.0 percent return on equity (ROE) until the
Federal Energy Regulatory Commission (FERC) establishes an ROE for the
regional transmission organization (RTO). The FERC is expected to issue a
decision on the settlement agreement in the second half of 2004.
o A settlement agreement reached to settle the dispute over standard
market design (SMD) locational marginal pricing (LMP) costs, which was
filed with the FERC on March 3, 2004, was approved on June 28, 2004. The
settlement agreement had no impact on 2004 earnings.
o The Connecticut Department of Public Utility Control (DPUC) issued a
final decision on August 4, 2004, on reconsideration of items in the
December 2003 Connecticut Light and Power Company (CL&P) distribution rate
case decision. The final decision was generally favorable, and
reconsideration was granted on all issues raised by CL&P.
o On July 2, 2004, Yankee Gas Services Company (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.
o On August 4, 2004, the DPUC issued a final decision accepting the
settlement filed in April 2004 by Yankee Gas, which provided for the
termination of Yankee Gas' Infrastructure Expansion Rate Mechanism (IERM).
o A settlement agreement was filed for approval in July 2004 with the
New Hampshire Public Utilities Commission (NHPUC) to raise Public Service
Company of New Hampshire (PSNH) retail distribution rates by $3.5 million
on October 1, 2004 and $10 million on June 1, 2005.
o On July 19, 2004, the Massachusetts Department of Telecommunications
and Energy (DTE) issued an order approving Western Massachusetts Electric
Company's (WMECO) financing of its prior spent nuclear fuel liability
through the issuance of up to $52 million in debt. WMECO plans to issue
this debt by the end of 2004.
o In June 2004, the FERC approved a 40-year license extension for
Northeast Generation Company's (NGC) Housatonic hydroelectric generation
units in Connecticut. That license covers 115 megawatts (MW) of capacity.
Liquidity:
o At June 30, 2004, NU had $180.2 million of cash, including cash and
cash equivalents and unrestricted cash from counterparties compared with
$83.7 million at December 31, 2003.
o On May 11, 2004, NU announced an 8.3 percent increase in its quarterly
dividend. On September 30, 2004, NU will pay a dividend of $0.1625 per
share to shareholders of record as of September 1, 2004.
o NU's capital expenditures have been lower than projected at the
beginning of 2004. NU's capital expenditures totaled $311.6 million for
the first six months of 2004, compared with $234 million for the first six
months of 2003. NU's 2004 capital spending was originally budgeted to total
$738 million, but is now projected to total $674.2 million due to delays in
certain transmission projects.
Overview
- --------
Consolidated: NU earned $22.9 million, or $0.18 per share, in the second
quarter of 2004, compared with earnings of $26.9 million, or $0.21 per
share in the second quarter of 2003. For the first six months of 2004, NU
earned $90.3 million or $0.71 per share, compared with earnings of $87.1
million, or $0.69 per share, in the first six months of 2003. The results
for the second quarter and first six months of 2004 include an after-tax
write-down of $2.4 million, or $0.02 per share, of NU's investment in a
developer of fuel cell and power quality equipment. NU's remaining
investment in that company is $3.8 million.
A summary of NU's earnings/(losses) by business segment for the second
quarter and first six months of 2004 and 2003 is as follows:
- -------------------------------------------------------------------------------
For the Three Months For the Six Months
Ended June 30, Ended June 30,
- -------------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Utility Group $27.1 $15.5 $80.5 $73.6
NU Enterprises 2.9 11.9 21.7 17.1
Other (7.1) (0.5) (11.9) (3.6)
- -------------------------------------------------------------------------------
Net income $22.9 $26.9 $90.3 $87.1
- -------------------------------------------------------------------------------
NU's revenues during the first six months of 2004 increased to $3.4 billion
from $2.9 billion in the same period of 2003. The increase in revenues was
primarily due to an increase of approximately $230 million in revenues at
NU Enterprises' merchant energy business segment as a result of $192
million in higher revenues from higher electric and gas prices and an
increase in volumes that accounted for the remainder of that increase.
NU's revenue increase is also the result of a $183 million increase in
Utility Group revenues due to an increase in retail electric sales volume
that accounted for $133 million of that increase and an increase in retail
electric prices that 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 $11.6 million in the
second quarter of 2004 compared with the same period of 2003, and increased
by $6.9 million for the first six months of 2004 compared with the first
six months of 2003. The increase in earnings for the first six months of
the year was primarily due to an increase in retail electric sales of 3.7
percent. A summary of Utility Group earnings/(losses) by company for the
second quarter and first six months of 2004 and 2003 is as follows:
- -------------------------------------------------------------------------------
For the Three Months For the Six Months
Ended June 30, Ended June 30,
- -------------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
CL&P * $17.3 $ 4.7 $43.5 $30.0
PSNH 6.0 11.1 17.8 21.9
WMECO 3.6 2.6 7.1 8.7
Yankee Gas 0.2 (2.9) 12.1 13.0
- -------------------------------------------------------------------------------
Net income $27.1 $15.5 $80.5 $73.6
- -------------------------------------------------------------------------------
*After preferred dividends
CL&P's higher earnings resulted from distribution and transmission rate
increases that took effect January 1, 2004. These higher retail rates
offset higher depreciation expense and higher pension expense.
Additionally, CL&P also benefited from a 3.3 percent increase in retail
electric sales.
PSNH's lower earnings were due primarily to higher pension expense and
lower unbilled revenues.
The lower year-to-date earnings at WMECO were due to lower pension income
and higher interest expense.
Yankee Gas' second quarter results benefited from a change in rate design
implemented in August 2003 and lower income tax expense. 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 will reduce quarterly earnings in the higher-
use first and fourth quarters and improve quarterly results in the lower-
use second and third quarters compared to Yankee Gas' previous rate design.
Yankee Gas' results for the first six months of 2004 compared to 2003
continue to reflect the impact of the change in rate design. The reduction
in income tax expense was a result of revisions to estimates of deferred
taxes associated with Yankee Gas' plant assets.
Included in Utility Group earnings are earnings related to the regulated
transmission business. Transmission business earnings were $5.3 million in
the second quarter of 2004 and $12.5 million for the first six months of
the year compared with earnings of $3.8 million in the second quarter of
2003 and $11.8 million for the first six 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 a revenue tracking mechanism that was put in place in 2004
to match revenues and costs of providing transmission service. In the
first six months of 2004, $70.2 million of transmission projects were
placed in service. The revenue tracking mechanism allows immediate
recovery of these costs. During the first six months of 2003, revenues
were not subject to such a tracking mechanism.
NU Enterprises: NU Enterprises, Inc. is the parent company of 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
business segment and the energy services business segment. The merchant
energy business segment is comprised of Select Energy's wholesale business,
which includes approximately 1,440 MW of primarily pumped storage and
hydroelectric generation assets owned by NGC 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 $9 million in the second quarter of
2004 compared with the second quarter of 2003, but increased by $4.6
million for the first six months of 2004 compared with the first six months
of 2003. The improved six-month earnings are a result of improved margins
and higher retail volumes on merchant energy contracts. A summary of NU
Enterprises' earnings/(losses) by business for the second quarter and first
six months of 2004 and 2003 is as follows:
- -------------------------------------------------------------------------------
For the Three Months For the Six Months
Ended June 30, Ended June 30,
- -------------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Merchant energy $ 4.5 $10.6 $23.6 $15.5
Energy services (1.4) 1.4 (1.6) 1.8
Parent company (0.2) (0.1) (0.3) (0.2)
- -------------------------------------------------------------------------------
Net income $ 2.9 $11.9 $21.7 $17.1
- -------------------------------------------------------------------------------
A $6.1 million decrease in quarterly profitability was largely anticipated
at the merchant energy business and was due primarily to the structuring of
some of Select Energy's full requirements wholesale power contracts, which
produced higher per megawatt-hour revenues in the first quarter of 2004 and
lower revenues in the second quarter of 2004. Select Energy's cost per
kilowatt-hour (kWh) for procuring electricity is relatively flat throughout
2004. However, contracted sales prices to some of Select Energy's
wholesale customers were relatively high in the first quarter and were
lower in the second quarter, creating better wholesale margins in the first
quarter of 2004 and lower margins in the second quarter. This decrease was
offset by the retail business' improved volumes and improved margins on
those volumes. However, earnings were higher in the first half of 2004
compared with the first half of 2003 as a result of improved margins.
Merchant energy business earnings are expected to be more evenly distributed
between the third and fourth quarters of 2004 than between the first and
second quarters of 2004.
The decreases in second quarter and 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.
Future Outlook
- --------------
Consolidated: NU continues to project earnings of between $1.20 per share
and $1.40 per share in 2004.
Utility Group: The NU consolidated earnings estimate for 2004 includes
Utility Group earnings of between $1.08 per share and $1.20 per share.
NU Enterprises: The NU consolidated earnings estimate for 2004 continues
to reflect earnings of between $0.22 per share and $0.30 per share or
earnings of between $28 million and $38 million at NU Enterprises. The
merchant energy business earned $23.6 million through June 30, 2004, and NU
now projects that 2004 merchant energy business segment earnings will be
near the upper end of the $24 million to $31 million earnings range. The
energy services business segment, comprised of NGS, SESI and Woods Network
may fall below the low end of its previous earnings range of $4 million.
Parent Company: NU parent is expected to have debt and other expenses of
approximately $0.10 per share.
Strategic Overview
- ------------------
As part of its strategic planning process, management is performing a
comprehensive review of all of its business lines and developing five-year
business plans. While this review has not been completed, it is not
expected that the results will significantly adjust the business and
operating strategy of the company.
Liquidity
- ---------
Consolidated: NU continues to maintain an adequate level of liquidity. At
June 30, 2004, NU had $180.2 million of cash, including cash and cash
equivalents and unrestricted cash from counterparties compared with $83.7
million at December 31, 2003.
NU's net cash flows provided by operating activities increased to $508
million in the first six months of 2004 from $211.7 million in the first
six months of 2003. The increase is due to changes in working capital
items, primarily accounts payable and accrued taxes. Accounts payable
increased in the first six months of 2004 due primarily to an increase in
CL&P accounts payable resulting from transitional standard offers (TSO)
supply purchases at higher prices and an increased percentage of TSO
purchases from unaffiliated suppliers. In the first six months of 2003,
accounts payable decreased due to lower Select Energy wholesale electricity
purchases. Accrued taxes decreased by $110 million in 2003 due primarily
to the payment of taxes on the gain on the sale of Seabrook compared to a
decrease of $24.5 million in 2004. These 2003 changes were partially
offset by a decrease in accounts receivable related to a lower level of
Select Energy sales in the first six months of 2003 compared to the last
quarter of 2002 and a decrease in investments in securitizable assets and
regulatory overrecoveries. The decrease in regulatory overrecoveries is
primarily due to lower Competitive Transition Assessment (CTA) and
Generation Service Charge (GSC) collections in the first six months of
2004, which is also the primary reason for the change in deferred income
taxes from the first six months of 2003 to the first six months of 2004.
The change in deferred income taxes is expected to continue to benefit cash
flows from operations due to bonus tax depreciation on newly completed
plant assets. Cash flows from operations, which have been significantly
affected by changes in working capital items, are not necessarily
indicative of the cash flows for the second half of 2004.
On June 30, 2004, NU paid a dividend of $0.15 per share. On May 11, 2004,
the NU Board of Trustees approved a common dividend of $0.1625 per share,
payable September 30, 2004, to shareholders of record at September 1, 2004.
The dividend declared on May 11, 2004 represents an 8.3 percent increase in
the common dividend. This increase is consistent with management's
intention of recommending increases in the common dividend at a rate that
is higher than the expected industry average.
NU's capital expenditures have been lower than projected at the beginning
of 2004. NU's capital expenditures totaled $311.6 million for the first
six months of 2004, compared with $234 million for the first six months of
2003. NU's 2004 capital spending was budgeted to total $738 million, but
is now projected to total $674.2 million, including $383.7 million by CL&P,
$152.4 million by PSNH, $39.4 million by WMECO, $60 million by Yankee Gas,
and $38.7 million by other NU subsidiaries. The lower level of capital
expenditures was primarily related to delays in certain transmission
projects as a result of appeals of decisions by the Connecticut Siting
Council (CSC) and other legal and regulatory delays. Further delays in
certain major projects could cause NU's actual capital spending to be below
this projection.
In June 2004, Standard & Poor's (S&P) announced a new method of calculating
the capital adequacy of companies engaged in the competitive marketing and
trading of electricity and natural gas. S&P stated that companies rated
investment grade, such as NU and all of its regulated operating companies,
should have the liquidity to meet whatever collateral requirements are
necessitated by a simultaneous downgrade of NU's ratings to below
investment grade and a significant movement in forward energy prices. NU
continues to evaluate the future impact of the new S&P standard and may
need to increase its credit lines to meet S&P's capital adequacy standards.
At this time, management does not believe that the cost of any additional
liquidity which may be required will have a material impact on future
earnings.
Utility Group: At June 30, 2004, the Utility Group had $5 million in
borrowings outstanding on its $300 million revolving credit line. This
credit line is scheduled to mature in November 2004 and is expected to be
renewed for at least one year.
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 June 30, 2004, CL&P had sold
accounts receivable totaling $80 million to that financial institution.
For more information regarding the sale of receivables, see Note 1H,
"Summary of Significant Accounting Policies - Sale of Customer Receivables"
to the consolidated financial statements.
On June 23, 2004, the DPUC approved CL&P's request to issue up to $280
million of debt securities. CL&P expects to issue the debt later in 2004.
Proceeds will be used to repay short-term debt and to refinance a $59
million, 8.5 percent bond issuance that will be redeemed on August 10, 2004
at a call premium of 3.87 percent. At June 30, 2004, CL&P had $196.2
million in short-term debt outstanding from the NU Money Pool.
As part of the approved SMD settlement agreement, CL&P paid $83 million to
suppliers on July 8, 2004, and agreed to refund $75 million to its
customers. Of the combined payment and refund amount totaling $158
million, $31 million has not been funded into the restricted cash - LMP
costs account. Additionally, as part of the DPUC's final decision
regarding CL&P's CTA and System Benefits Charge (SBC) docket, the DPUC
ordered a refund to CL&P's customers of $88.5 million over a seven-month
period beginning with October 2004 consumption. These refunds, when
combined with CL&P's proposed capital projects and previously ordered
refunds of CTA and SBC amounts, will negatively impact CL&P's liquidity.
However, CL&P expects no difficulty funding these additional requirements.
On July 22, 2004, PSNH issued $50 million of first mortgage bonds at a
fixed interest rate of 5.25 percent. Proceeds were used to pay down short-
term debt and fund PSNH's capital expenditure program. At June 30, 2004,
PSNH had $62.1 million in short-term debt outstanding from the NU Money
Pool.
On July 19, 2004, the DTE issued an order approving WMECO's financing of
its prior spent nuclear fuel liability through the issuance of up to $52
million in debt. WMECO plans to issue this debt by the end of 2004.
NU Enterprises: At June 30, 2004, NU Enterprises had $53 million in
letters of credit (LOCs) outstanding on NU parent's $350 million revolving
credit line. This credit line is scheduled to mature in November 2004 and
is expected to be renewed for at least one year.
SESI borrowed $7.4 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.
Nuclear Decommissioning and Plant Closure Costs
- -----------------------------------------------
The purchasers of NU's ownership shares of the Millstone, Seabrook and
Vermont Yankee nuclear power plants assumed the obligation of
decommissioning those plants, but NU still 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 to 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 if
approved, provides for the collection of approximately $27 million annually
for decommissioning and long-term storage of spent fuel through October 31,
2008. Approval of the MY settlement agreement by the FERC is anticipated
in the fall of 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 termination of the
decommissioning contract with Bechtel Power Corporation in July 2003, the
fact that CY is now self-performing all work to complete the
decommissioning of the plant, 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 the increased costs. In the filing CY seeks to
increase its annual decommissioning collections from $16.7 million to $93
million for a six-year period beginning January 1, 2005. FERC proceedings
have not yet been scheduled. In total, NU's estimated remaining
decommissioning and plant closure obligation to CY is $315.5 million at
June 30, 2004.
Previously, on June 10, 2004, the DPUC and the Office of Consumer Counsel
filed a petition with the FERC seeking a declaratory order that CY can
recover all decommissioning costs from its wholesale purchasers, including
CL&P, PSNH and WMECO, but such purchasers may not recover in their retail
rates any costs which FERC might determine to have been imprudently
incurred. CY and the wholesale purchasers have objected and the matter is
pending.
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 these 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. For further information regarding these issues, see Part
II, Item 1, "Legal Proceedings," in this report on Form 10-Q.
Utility Group Business Development and Capital Expenditures
- -----------------------------------------------------------
Connecticut - CL&P: On July 14, 2003, the CSC approved a 345,000 volt
transmission project from Bethel, Connecticut to Norwalk, Connecticut. The
project is estimated to cost approximately $200 million and will help
alleviate identified reliability issues in southwest Connecticut and help
reduce congestion costs for all of Connecticut. An appeal of the CSC
decision by the City of Norwalk is pending. Hearings on the merits of the
appeal were held in early July 2004 and a decision on the appeal is
expected this summer. Management is currently reassessing the project's
expected cost and completion date. This project is exempt from the State
of Connecticut's moratorium on the approval of new electric and natural gas
transmission projects. At June 30, 2004, CL&P has capitalized $41.5 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 estimated construction costs of this project
are approximately $620 million. CL&P will jointly site this project with
UI and CL&P will own 80 percent, or approximately $496 million, of the
project. This project is also exempt from the State of Connecticut's
moratorium on the approval of new electric and natural gas transmission
projects. Hearings before the CSC began in February 2004 and are scheduled
to continue through the third quarter of 2004, with a final CSC decision
scheduled for December 2004. Construction is expected to commence shortly
after the final decision. At June 30, 2004, CL&P has capitalized $13.2
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. The project is expected to cost approximately $100 million and
CL&P and the Long Island Power Authority (LIPA) each own approximately 50
percent of the line. The project still requires federal and New York State
approvals, but is exempt from the State of Connecticut's moratorium on the
approval of new electric and natural gas transmission projects. On June
24, 2004, representatives from CL&P, the state of Connecticut, LIPA, and
the Cross Sound Cable Company reached a comprehensive settlement of issues
surrounding the activation of the separate Cross Sound Cable, in which NU
has no investment. Among other items, the settlement agreement calls for
the replacement of the existing Norwalk to Northport transmission line. A
timetable for replacement of the line is due to be filed with the
Connecticut Department of Environmental Protection by October 1, 2004.
Management now expects the replacement cable to be operational by 2008. At
June 30, 2004, CL&P has capitalized $6.5 million related to this project.
In the first six months of 2004, NU placed in service $70.2 million of
electric transmission projects. These projects included CL&P's $36 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 June 10, 2004, Yankee Gas submitted a
compliance filing with the DPUC concerning the construction of a 1.2
billion cubic foot liquefied natural gas storage facility in Waterbury,
Connecticut. A final DPUC decision is anticipated in the third quarter of
2004. If that decision is acceptable to Yankee Gas, it is expected that
Yankee Gas will enter into a final contract for the construction of the LNG
facility, which is now expected to cost $108 million. Yankee Gas would
anticipate beginning construction later in 2004 and for the facility to
become operational in 2007 in time for the 2007/2008 heating season. This
project is also exempt from the State of Connecticut's moratorium on the
approval of new electric and natural gas transmission projects. At June 30,
2004, Yankee Gas has capitalized $4.1 million related to this project.
New Hampshire: In May 2004, PSNH received final approval from the NHPUC to
convert one of three 50 megawatt units at the coal-fired Schiller Station
to burn wood. In its final decision, the NHPUC approved a joint motion for
reconsideration with the Office of Consumer Advocate (OCA), the state
Office of Energy and Planning and the New Hampshire Timberland Owners'
Association that modified a risk and reward sharing mechanism approved in
an order on February 6, 2004, by the NHPUC. PSNH still is required to
obtain various environmental permits, but expects to begin construction
later in 2004 following the receipt of those permits. The $75 million
project, which will reduce air emissions, will take approximately two years
to complete.
The NHPUC's decision approving PSNH's proposal regarding Schiller Station
is the subject of an appeal to the New Hampshire Supreme Court by the
state's existing wood-fired generating plant owners. Management believes
that the appeal will not impair PSNH's ability to proceed with the Schiller
Station project.
For further information regarding rate matters associated with business
development and capital expenditures, see "Restructuring and Rate Matters,"
in this Management's Discussion and Analysis.
Regional Transmission Organization
- ----------------------------------
In Order 2000, the FERC required all transmission owning utilities to
voluntarily form RTOs or to state why this process has not begun.
On October 31, 2003, the New England Independent System Operator (ISO-NE),
along with NU and six other New England transmission 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 the most reliable system possible to
facilitate 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 to hearing the issues of the appropriate
base ROE and the clarification as to which facilities the 1.0 percent
incentive adder applies. A final ruling regarding these issues is expected
in 2005.
Restructuring and Rate Matters
- ------------------------------
Utility Group: On August 26, 2003, the transmission segment of NU's
regulated companies filed its first transmission rate case at the FERC
since 1995. 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 that
allows transmission to implement formula-based rates as proposed with an
11.0 percent ROE until the FERC establishes an ROE for the RTO. The FERC
is expected to issue a decision on the settlement agreement in the second
half of 2004.
Revenues billed through June 2004 were based on the original proposed ROE
of 11.75 percent. The settlement agreement resulted in the recognition of
a $1.8 million regulatory liability for the reduction in ROE from 11.75
percent to 11.0 percent and reduced second quarter 2004 earnings by $1.1
million. In addition, a regulatory liability for the collection of costs
not yet incurred has also been recognized but had no impact on earnings.
This total regulatory liability at June 30, 2004 was approximately $4
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
Pool Transmission Facilities. This regional rate is reset on June 1st of
each year. The LNS tariff which was accepted by the FERC on October 22,
2003, provides for the recovery of NU's total transmission revenue
requirements, net of revenues received from other sources, including
revenues received under the RNS rates. NU's LNS rate is a formula rate
which is also reset on June 1st of each year. Additionally, NU's LNS
tariff provides for a true-up to actual costs which ensures that NU
recovers its total annual transmission revenue requirements, including the
allowed ROE. The calculation of new rates under the LNS tariff, as well as
the true-up calculation, are filed with FERC.
Connecticut - CL&P:
Impacts of Standard Market Design: On March 1, 2003, the 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. A settlement agreement was reached to settle 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, and the remaining $75 million
became available to be refunded to CL&P's customers. The method in which
the $75 million will be refunded to customers is currently under review by
the DPUC with a decision expected in the third quarter of 2004.
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) that 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 rate case
on December 31, 2003. Other parties also filed petitions for
reconsideration. On January 21, 2004, the DPUC agreed to reconsider CL&P's
items and issued a final decision on the reconsideration on August 4, 2004.
The final decision allows CL&P to recover approximately $32 million related
to these items beginning August 1, 2004. The DPUC has authorized using the
existing CTA overrecoveries to recover the approximately $24 million net
present value of these additional amounts in lieu of an increase in rates.
The final decision could have a positive pre-tax impact of up to
approximately $12 million in 2004. The DPUC's conclusion on streetlighting
refund periods and methodologies was also included in the final decision
and could significantly reduce the $12 million pre-tax impact. In addition,
the impact could also be offset by CL&P's earnings sharing mechanism.
Management has not determined the amount of these potential offsets.
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
workers protection costs. The GSC allows CL&P to recover the costs of the
procurement of energy for standard offer service.
On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the
DPUC. For the year ended December 31, 2003, total CTA revenues and excess
GSC revenues as filed exceeded the CTA revenue requirement by $148.3
million. For the same period, SBC revenues as filed exceeded the SBC
revenue requirement by $25.5 million. These amounts were recorded as
regulatory liabilities on the accompanying consolidated balance sheets.
A final decision in the 2003 CTA and SBC docket was issued on August 4,
2004. In the final decision, the DPUC ordered a refund to customers of
$88.5 million over a seven-month period beginning with October 2004
consumption. The DPUC ordered that the SBC rate be reduced to zero
effective January 1, 2005. The DPUC also directed CL&P to impute revenue
of $2.7 million to customers associated with a previously renegotiated IPP
contract. CL&P will likely seek rehearing on this issue, and management
cannot predict the outcome of this issue at this time.
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 income taxes 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 the company's request is
ultimately granted through 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.
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. Yankee Gas expects a decision from the
DPUC on the rate case by the end of 2004 and anticipates that it will
underearn its currently authorized 11.0 percent ROE in 2004.
IERM Settlement: On April 29, 2004, Yankee Gas and the OCC filed a
settlement agreement that provides for the termination of Yankee Gas' IERM,
which tracked the revenue and expenses associated with its system expansion
program. The settlement finalizes ratemaking treatment for all Yankee Gas
IERM projects and returns Yankee Gas to a traditional capital investment
test. A final decision approving the settlement was issued on August 4,
2004. The settlement agreement temporarily lowers the ROE on certain IERM
assets to Yankee Gas' debt rate and will not have a material adverse impact
on Yankee Gas' net income or financial position.
New Hampshire:
Delivery Rate Case: PSNH's delivery rates were fixed 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 OCA. If approved by the NHPUC, the settlement would allow increases in
PSNH's delivery rates totaling $3.5 million annually, effective
prospectively on October 1, 2004, and an incremental $10 million increase
annually 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. If approved by the NHPUC, these two settlement agreements would
resolve all delivery service rate case issues. A hearing took place on
August 3, 2004, and a decision is expected by the end of the third quarter
of 2004.
Transition Energy Service: In accordance with the Restructuring Settlement
and state law, PSNH files for updated transition energy service (TS) rates
annually. 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
December 19, 2003, the NHPUC issued an order approving a $0.0536 per kWh TS
rate effective February 1, 2004 through January 31, 2005.
The December 2003 order also addressed the issue of cost deferrals by
requiring a review of TS costs in July 2004 for a possible TS rate change
effective August 1, 2004. Accordingly, PSNH filed a petition with the
NHPUC on July 1, 2004 requesting a change in the TS rate from the current
$0.0536 per kWh to $0.0594 per kWh based on actual costs and underrecoveries
incurred to date and updated cost projections. A hearing took place on
July 26, 2004, and an order changing the TS rate to $0.0579 per kWh, effective
August 1, 2004 was issued by the NHPUC on August 2,
2004.
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 $175.8 million at June 30, 2004. The 2003 SCRC filing was made on
April 30, 2004. Management does not expect the review of the 2003 SCRC
filing to have a material effect on PSNH's net income or financial
position. Hearings are currently scheduled for October 2004.
Estimated unbilled revenues for PSNH are not considered in the reconciliation
of certain billed revenues to incurred costs through rate mechanisms such as
the SCRC and the SBC. Accordingly, changes in estimated unbilled revenues due
to changes in these charges impact PSNH's earnings in the period of change.
Massachusetts:
Transition Cost Reconciliation: On March 31, 2004, WMECO filed its 2003
transition cost reconciliation with the DTE. This filing reconciled the
recovery of generation-related stranded costs for calendar year 2003. The
timing of a final decision is uncertain. 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, consisting of 1,293 MW of
primarily pumped storage and hydroelectric generation assets at NGC and 147
MW of coal-fired generation at HWP.
In June 2004, the FERC approved a 40-year license extension for NGC's
Housatonic hydroelectric generation units in Connecticut. That license
covers four conventional stations and one pumped storage station, which
together account for approximately 115 MW of capacity.
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
service company.
Outlook: During 2004, NU expects that NU Enterprises will earn in the
range of $28 million to $38 million, with the merchant energy business
segment expected to earn near the upper end of its range of between $24
million and $31 million and the energy services business segment may fall
below the low end of its previous earnings range of $4 million. Those
ranges are heavily dependent on NU Enterprises' ability to achieve targeted
wholesale and retail origination margins, successfully manage its contract
portfolios and improve the financial performance of the energy services
business segment.
In the second quarter of 2004, Select Energy won 12-month contracts to
serve various NSTAR subsidiaries. Under these contracts, Select Energy
will serve approximately 1,100 MW and will earn more than $225 million of
revenues over the contract term of July 1, 2004 through June 30, 2005.
Select Energy will continue to bid on contracts in 2004 that will take
effect in 2004 and beyond. Select Energy's ability to secure a significant
amount of wholesale load is a critical factor in NU Enterprises' ongoing
profitability. Based upon June 30, 2004 market information, Select
Energy's wholesale electric and gas business has already contracted
approximately 80 percent of the sales needed to reach its 2004 gross margin
targets, assuming satisfactory portfolio management for the remainder of
the year.
The retail marketing portion of NU Enterprises' merchant energy business
segment has already contracted for more than 75 percent of the business
needed to achieve 2004 gross margin targets.
Intercompany Transactions: CL&P's standard offer purchases from Select
Energy represented $108.3 million for the three months ended June 30, 2004,
compared with $138.9 million during the same period in 2003. Other energy
purchases between CL&P and Select Energy totaled $27.7 million for the
three months ended June 30, 2004 and $33.2 million during the same period
in 2003. Additionally, WMECO's purchases from Select Energy represented
$21 million for the three months ended June 30, 2004, compared with $29.2
million during the same period in 2003. These amounts are eliminated in
consolidation.
CL&P's standard offer purchases from Select Energy represented $256.8
million for the first six months of 2004, compared with $279.9 million
during the same period in 2003. Other energy purchases between CL&P and
Select Energy totaled $57.7 million for the first six months of 2004 and
$69.2 million during the same period in 2003. Additionally, WMECO's
purchases from Select Energy represented $53 million for the first six
months of 2004, compared with $68.2 million during the same period in 2003.
These amounts are eliminated in consolidation.
At June 30, 2004, CL&P and WMECO held $22 million and $10.8 million,
respectively, of unrestricted cash from Select Energy, who is a
counterparty to energy contracts with CL&P and WMECO. These amounts
eliminate 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 periodically reviewed by the NU Board of Trustees.
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 June 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 June 30, 2004, Select Energy had trading derivative assets of $111.2
million and trading derivative liabilities of $82.9 million, for a net
positive position of $28.3 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 increase in both derivative asset and liability amounts from
March 31, 2004, relates primarily to price increases. 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
June 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; 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; and 3) prices based on models or other valuation methods
primarily include transactions for which specific quotes are not available.
Currently, Select Energy has no contracts for which fair value is
determined based on a model or other valuation method. Broker quotes for
electricity 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 six months ended June 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 June 30, 2004
- -------------------------------------------------------------------------------
Maturity Maturity of Maturity in Total
Less than One to Four Excess of Fair
Sources of Fair Value One Year Years Four Years Value
- -------------------------------------------------------------------------------
Prices actively quoted $0.3 $0.1 $ - $ 0.4
Prices provided by
external sources 6.3 7.5 14.1 27.9
- -------------------------------------------------------------------------------
Totals $6.6 $7.6 $14.1 $28.3
- -------------------------------------------------------------------------------
The fair value of energy trading contracts increased $0.9 million from
$27.4 million at March 31, 2004 to $28.3 million at June 30, 2004. The
change in the fair value of the trading portfolio is primarily attributable
to changes in energy commodity prices during the period. There were no
changes in valuation techniques or assumptions in the second quarter of
2004.
- -------------------------------------------------------------------------------
Total Portfolio Fair Value
- -------------------------------------------------------------------------------
Three Months Ended Six Months Ended
(Millions of Dollars) June 30, 2004 June 30, 2004
- -------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the beginning
of the period $27.4 $32.5
Contracts realized or otherwise
settled during the period (0.4) (6.1)
Changes in fair value of
contracts 1.3 1.9
- -------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the end
of the period $28.3 $28.3
- -------------------------------------------------------------------------------
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. For example, SMD was implemented in New England on
March 1, 2003 and has created both challenges and opportunities for Select
Energy. For information regarding the effects of SMD on Select Energy and
RTOs, see "Restructuring and Rate Matters," and "Regional Transmission
Organization," in this Management's Discussion and Analysis. As the market
continues to evolve, there could be additional adverse effects 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 conditions (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 overall 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 June 30, 2004, approximately
79 percent of Select Energy's counterparty credit exposure to wholesale and
trading counterparties was cash collateralized or rated BBB- or better.
Select Energy held $105 million and $46.5 million of counterparty cash
advances at June 30, 2004 and December 31, 2003, respectively. For further
information, see Note 1K, "Unrestricted Cash from Counterparties," 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 $310 million of collateral or LOCs to various
unaffiliated counterparties and approximately $97 million to several
independent system operators and unaffiliated local distribution companies,
which management believes NU would currently be able to provide, subject to
the Securities and Exchange Commission (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
- -------------------------------------------------
Accounting for Transmission Revenues Subject to Refund: The $23.7 million
transmission rate increase that NU's electric operating companies requested
began being billed subject to refund on October 28, 2003. The rate
increase was based on a proposed ROE of 11.75 percent, which is unchanged
from the ROE included in previous transmission rates and is currently being
billed.
Since October 27, 2003, management has evaluated the increase in
transmission revenues that has been collected to determine if any amounts
are probable of refund to customers in the future.
On June 14, 2004, the transmission segment of NU's regulated companies
reached a settlement agreement with the parties to its rate case that
allows transmission to implement formula-based rates as proposed with an
11.0 percent ROE until the FERC establishes an ROE for the RTO. The FERC
is expected to issue a decision on the settlement agreement in the second
half of 2004.
Revenues billed through June 2004 were based on the original proposed ROE
of 11.75 percent. The settlement agreement resulted in the recognition of
a $1.8 million regulatory liability for the reduction in ROE from 11.75
percent to 11.0 percent and reduced second quarter 2004 earnings by $1.1
million. In addition, a regulatory liability for the collection of costs
not yet incurred has also been recognized but had no impact on earnings.
This total regulatory liability at June 30, 2004 was approximately $4
million.
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 expenses 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 expense sufficient to cover CL&P's anticipated 2004
transmission costs. The June 1, 2005 PSNH rate increase includes revenues
in recognition of the transfer of certain assets from transmission rates to
distribution rates. Neither CL&P nor PSNH have transmission tracking
mechanisms.
Accounting for PSNH Rate Case: PSNH requested that an increase in rates be
included in bills starting on February 1, 2004 subject to refund. The
NHPUC denied that request but indicated that any rate changes from the rate
case would be effective from February 1, 2004 forward.
On July 14, 2004, PSNH filed with the NHPUC a settlement agreement among
several parties including the NHPUC staff and the OCA. If approved by the
NHPUC, the settlement would result in increases in PSNH's delivery rates
effective prospectively on October 1, 2004 and effective prospectively on
June 1, 2005.
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 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.
Other Matters
- -------------
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 4, "Commitments and Contingencies,"
to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes forward
looking statements, which are statements of future expectations and not
facts including, but not limited to, statements regarding future earnings,
refinancings, regulatory proceedings, the use of proceeds from
restructuring, and the recovery of operating costs. Words such as
estimates, expects, anticipates, intends, plans, and similar expressions
identify forward looking statements. Actual results or outcomes could
differ materially as a result of further actions by state and federal
regulatory bodies, competition and industry restructuring, changes in
economic conditions, changes in weather patterns, changes in laws,
developments in legal or public policy doctrines, technological
developments, volatility in electric and natural gas commodity markets, and
other presently unknown or unforeseen factors.
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 second quarter of 2004 and the first six months of 2004:
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Second Six
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues: $195 15% $449 15%
Operating Expenses:
Fuel, purchased and net
interchange power 147 19 359 21
Other operation 40 17 78 19
Maintenance - - 10 9
Depreciation 5 10 10 10
Amortization 5 23 (26) (31)
Amortization of rate
reduction bonds 3 8 7 9
Taxes other than income taxes 4 8 8 6
---- ---- ---- ----
Total operating expenses 204 17 446 17
---- ---- ---- ----
Operating income (9) (9) 3 1
---- ---- ---- ----
Interest expense, net 4 6 3 2
Other income, net 2 (a) 3 (a)
---- ---- ---- ----
Income before income tax expense (11) (24) 3 2
Income tax expense (7) (41) - -
Preferred dividends of
subsidiary - - - -
---- ---- ---- ----
Net Income $ (4) (15)% $ 3 4%
==== ==== ==== ====
(a) Percent greater than 100.
Comparison of the Second Quarter of 2004 to the Second Quarter of 2003
Operating Revenues
Total revenues increased $195 million in the second quarter of 2004,
compared with the same period in 2003, due to higher revenues from NU
Enterprises ($66 million or $111 million after intercompany eliminations)
and higher distribution revenues ($80 million or $77 million after
intercompany eliminations) and higher regulated transmission revenues ($9
million or $5 million after intercompany eliminations).
The NU Enterprises' revenues increase is primarily due to higher revenues
for the merchant energy segment resulting from higher electric prices ($59
million), higher gas volumes ($15 million) and higher gas prices ($2
million), partially offset by lower electric volumes ($18 million).
The electric distribution revenue increase is primarily due to increases in
the standard offer and default service revenues for CL&P, PSNH and WMECO
($74 million) due mainly to rate increases, Federally Mandated Congestion
Cost (FMCC) revenues for CL&P ($35 million), and higher sales volume for
distribution revenues ($12 million), partially offset by lower SMD revenue
for CL&P ($30 million), lower CL&P Energy Adjustment Clause (EAC) revenue
as a result of the end of EAC billings in December 2003 ($9 million) and
lower revenues for CL&P and WMECO transition charges ($6 million).
Electric retail kWh sales increased by 4.8 percent in the second quarter of
2004.
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 $147 million in
the second quarter of 2004, primarily due to higher wholesale costs at NU
Enterprises ($62 million or $59 million after intercompany eliminations)
and higher purchased power costs for the Utility Group ($40 million or $88
million after intercompany eliminations). The increase for the Utility
Group is primarily due to an increase in the standard offer service
requirements rates for CL&P ($51 million) and an increase for WMECO ($5
million), partially offset by the 2003 recovery of certain fuel costs ($9
million).
Other Operation
Other operation expenses increased $40 million in the second quarter of
2004, primarily due to higher competitive business expenses resulting from
business growth ($15 million), higher reliability must run costs ($15
million) and higher regulated business administrative and general expenses
($7 million) due to higher pension costs.
Depreciation
Depreciation increased $5 million in the second 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 increased $5 million in the second quarter of 2004 primarily
due to higher Utility Group recovery of stranded costs offset by a decrease
in amortization expense resulting from the implementation of the CL&P
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 second
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 $4 million in the second quarter of
2004 primarily due to higher Connecticut gross earnings tax as a result of
an increase in revenues for NU Enterprises and CL&P, higher local property
taxes, higher payroll taxes and higher sales tax.
Interest Expense, Net
Interest expense, net increased $4 million in the second quarter of 2004
primarily due to higher interest on long-term debt at NU parent related to
a 2003 settlement payment to NU as a result of the interest rate swap for
the $263 million fixed-rate senior notes and an increase in long-term debt
expense due to the issuance of $150 million of five-year notes at NU parent
in June 2003.
Other Income, Net
Other income, net increased $2 million in the second quarter of 2004
primarily due to the recognition beginning in 2004 of a CL&P procurement
fee approved in the TSO docket decision ($3 million) and a decrease in
charitable contributions ($1 million), partially offset by an investment
impairment ($3 million).
Income Tax Expense
Income tax expense decreased due to lower income before tax expense along
with a lower effective tax rate due to the regulatory treatment of taxes by
certain Utility Group companies.
Comparison of the First Six Months of 2004 to the First Six Months of 2003
Operating Revenues
Total revenues increased $449 million in the first six months of 2004,
compared with the same period in 2003, due to higher revenues from NU
Enterprises ($250 million or $298 million after intercompany eliminations),
higher electric distribution revenues ($130 million or $125 million after
intercompany eliminations), higher gas distribution revenues ($20 million)
and higher regulated transmission revenues ($9 million or $3 million after
intercompany eliminations).
The NU Enterprises' revenues increase is primarily due to higher revenues
for the merchant energy segment resulting from higher electric prices ($180
million), higher gas volumes ($46 million) and higher gas prices ($12
million), partially offset by lower electric volumes ($11 million).
The electric distribution revenue increase is primarily due to increases in
the standard offer and default service revenues for CL&P, PSNH and WMECO
($150 million) due mainly to rate increases, FMCC revenues for CL&P ($75
million), higher sales volume for distribution revenues ($19 million) and
higher CL&P retail transmission rates ($13 million), partially offset by
lower SMD revenue for CL&P ($29 million), lower CL&P EAC revenue as a
result of the end of EAC billings in December 2003 ($21 million) and lower
revenues for CL&P and WMECO transition revenues ($16 million). Electric
retail kWh sales increased by 3.7 percent in the first six months of 2004.
In addition, electric wholesale revenues decreased by $47 million primarily
due to lower short-term transactions ($35 million) and the expiration of
long-term contracts ($12 million).
The higher gas distribution revenue is primarily due to the increased
recovery of gas costs. Firm natural gas sales increased by 3.4 percent in
the first six months of 2004 from the same period of 2003.
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 $359 million in
the first six months of 2004, primarily due to higher wholesale costs at NU
Enterprises ($201 million or $198 million after intercompany eliminations)
and higher purchased power costs for the Utility Group ($108 million or
$161 million after intercompany eliminations). The increase for the
Utility Group is primarily due to an increase in the standard offer service
requirements rates for CL&P ($120 million) and an increase for WMECO ($12
million), higher Yankee Gas expenses due to increased gas prices ($21
million), partially offset by the 2003 recovery of certain fuel costs ($21
million), lower wholesale purchases for CL&P ($12 million) and WMECO ($4
million), and lower expenses for PSNH due to lower regulated energy and
capacity purchases ($9 million).
Other Operation
Other operation expenses increased $78 million in the first six months of
2004, primarily due to higher competitive business expenses resulting from
business growth ($31 million), higher reliability must run costs ($20
million), higher regulated business administrative and general expenses
($15 million) due to higher pension costs, higher fossil production expense
($3 million), and higher nuclear related expenses as a result of the
absence of the 2003 CL&P Millstone use of proceeds docket ($2 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 first quarter of 2003.
Maintenance
Maintenance expenses increased $10 million in the first six months of 2004,
primarily due to higher competitive transmission expense ($6 million), the
absence of the 2003 positive resolution of the CL&P Millstone use of
proceeds docket ($5 million), and higher distribution expense ($3 million),
partially offset by lower fossil production expense ($3 million).
Depreciation
Depreciation increased $10 million in the first six 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 $26 million in the first six 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 ($15
million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $7 million in the first six
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 $8 million in the first six 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 six months of 2004
primarily due to the issuance of $150 million of five-year notes at NU
parent in June 2003.
Other Income, Net
Other income, net increased $3 million in the first six months of 2004
primarily due to the recognition beginning in 2004 of a CL&P procurement
fee approved in the TSO docket decision ($6 million) and a decrease in
charitable contributions ($3 million), partially offset by investment
impairments ($6 million).
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 June 30, 2004,
and the related condensed consolidated statements of income for the three-
month and six-month periods ended June 30, 2004 and 2003 and of cash flows
for the six-month periods ended June 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 Activities as amended, its adoption in 2003 of
Emerging Issues Task Force Issue No. 03-11, Reporting Realized Gains and
Losses on Derivative Instruments that are Subject to FASB Statement No. 133
and not "Held for Trading Purposes" as Defined in Issue No. 02-3 and 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
August 6, 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
Quarter 2004 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 dated May 19, 2004 and July 14, 2004. 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 June 30, 2004, the
results of operations for the three-month and six-month periods
ended June 30, 2004 and 2003, and statements of cash flows for
the six-month periods ended June 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 six-month periods
ended June 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
Accounting for the Effect of Medicare Changes on Postretirement
Benefits Other Than Pension (PBOP): On December 8, 2003, the
President of the United States signed into law a bill that
expands 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 for certain retiree groups.
Financial Accounting Standards Board (FASB) Staff Position (FSP)
No. FAS 106-1, "Accounting and Disclosure Requirements Related to
the Medicare Prescription Drug, Improvement and Modernization Act
of 2003," required NU to make an election whether to either defer
the impact of the subsidy until the FASB issues guidance or to
reflect the impact of the subsidy on December 31, 2003 reported
amounts. NU chose to reflect the impact on December 31, 2003
reported amounts with no impact on 2003 expenses, assets, or
liabilities. The estimate of the actuarial gain, which decreased
the PBOP benefit obligation, was refined in the first quarter of
2004 to $20 million and is currently being amortized as a
reduction to PBOP expense over 13 years.
The estimated reduction in PBOP expense could change as a result
of the completion of an actuarial estimate of the subsidy based
on recent prescription drug claim experience. The subsidy
estimate could also change as regulations are promulgated by the
federal agencies responsible for administration of the Medicare
program.
On May 19, 2004, the FASB issued FSP No. FAS 106-2, "Accounting
and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003," to provide
guidance on accounting for the effects of the aforementioned Medicare
expansion. This FSP supersedes FSP No. FAS 106-1 and concludes
that the effects of the federal subsidy should be considered an
actuarial gain and treated like similar gains and losses and
requires certain disclosures for employers that sponsor
postretirement health care plans that provide prescription drug
benefits which are included in this report on Form 10-Q. The
accounting treatment under FSP No. FAS 106-2 is consistent with
FSP No. FAS 106-1 and with NU's accounting treatment at
December 31, 2003.
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 June 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 $897.7 million.
Additionally, NU had $53 million of LOCs issued for the benefit
of NU Enterprises outstanding at June 30, 2004.
CL&P had obtained surety bonds in the amount of $31.1 million
related to the collection of March 2003 and April 2003
incremental locational marginal pricing (LMP) costs in compliance
with a Connecticut Department of Public Utility Control (DPUC)
order. Effective April 30, 2004, the DPUC approved CL&P's
request to remove this surety bond requirement, and the surety
bonds were cancelled. At June 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 $897.7 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 to below investment grade.
On June 30, 2004, the Securities and Exchange Commission (SEC)
issued an order allowing NU to expand its financial support of NU
Enterprises. Under the order, NU has authorization from the SEC
to provide up to $750 million of guarantees for NU Enterprises
through June 30, 2007. The 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 June 30, 2004 is $329.8 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.
D. Unbilled Revenues
Unbilled revenues represent an estimate of electricity or gas
delivered to customers that has not been billed. Unbilled
revenues represent 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 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.
E. 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, PSNH and
WMECO, 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 business portions of the aforementioned companies
continues to be appropriate. Management also believes that it is
probable that NU's operating 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 June 30, 2004
---------------------------------------------------------------------------
NU
(Millions of Dollars) Consolidated CL&P PSNH WMECO
---------------------------------------------------------------------------
Recoverable nuclear costs $ 62.7 $ 1.2 $ 31.5 $ 30.0
Securitized assets 1,570.5 1,059.9 443.9 66.7
Income taxes, net 264.0 151.4 42.2 59.5
Unrecovered contractual
obligations 359.1 211.6 66.3 81.2
Recoverable energy costs 246.6 36.6 206.6 3.4
Other 351.4 138.4 151.5 9.3
--------------------------------------------------------------------------
Totals $2,854.3 $1,599.1 $942.0 $250.1
--------------------------------------------------------------------------
--------------------------------------------------------------------------
At December 31, 2003
--------------------------------------------------------------------------
NU
(Millions of Dollars) 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 June 30, 2004 and December 31, 2003, NU maintained $63.1 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 $12.6 million and approximately
$12 million of regulatory assets at June 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.
Regulatory Liabilities: The Utility Group maintained $1.2 billion
of regulatory liabilities at both June 30, 2004 and December 31,
2003. These amounts are comprised of the following:
-----------------------------------------------------------------------
At June 30, 2004
-----------------------------------------------------------------------
NU
(Millions of Dollars) Consolidated CL&P PSNH WMECO
-----------------------------------------------------------------------
Cost of removal $ 333.2 $147.6 $ 88.8 $24.7
CTA, GSC and SBC
overcollections 327.6 327.6 - -
Cumulative deferral - SCRC 175.8 - 175.8 -
Regulatory liabilities
offsetting Utility
Group derivative assets 160.0 159.6 0.4 -
LMP overcollections 83.8 83.8 - -
Other 159.3 78.6 22.9 6.8
-----------------------------------------------------------------------
Totals $1,239.7 $797.2 $287.9 $31.5
-----------------------------------------------------------------------
-----------------------------------------------------------------------
At December 31, 2003
-----------------------------------------------------------------------
NU
(Millions of Dollars) 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 Utility
Group derivative assets 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 June 30, 2004 and December 31, 2003, NU maintained $123.1 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.
Estimated unbilled revenues for PSNH are not considered in the
reconciliation of certain billed revenues to incurred costs
through such rate mechanisms as the Stranded Cost Recovery Charge
(SCRC) and the System Benefits Charge (SBC). Accordingly,
changes in estimated unbilled revenues due to changes in these
charges impact PSNH's earnings in the period of change.
F. 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 Six Months Ended
-----------------------------------------------------------------
(Millions of Dollars) June 30, 2004 June 30, 2003
-----------------------------------------------------------------
Borrowed funds $2.2 $2.7
Equity funds 1.9 3.3
-----------------------------------------------------------------
Totals $4.1 $6.0
-----------------------------------------------------------------
Average AFUDC rates 3.7% 4.5%
-----------------------------------------------------------------
G. 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 Six Months Ended
---------------------------------------------------------------------
(Millions of Dollars, June 30, June 30,
except per share amounts) 2004 2003
---------------------------------------------------------------------
Net income, as reported $90.3 $87.1
Total equity-based employee
compensation expense
determined under fair
value-based method for all
awards, net of related
tax effects 1.0 1.0
---------------------------------------------------------------------
Pro forma net income $89.3 $86.1
---------------------------------------------------------------------
EPS:
Basic and fully diluted -
as reported $0.71 $0.69
Basic and fully diluted -
pro forma $0.70 $0.68
---------------------------------------------------------------------
Net income as reported includes $1.6 million and $0.8 million
expensed for restricted stock and restricted stock units for the
six months ended June 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 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 six-month period ended June 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 beginning
on January 1, 2005.
H. 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 both June 30, 2004 and December 31, 2003,
CL&P had sold accounts receivable of $80 million to the financial
institution with limited recourse through CL&P Receivables
Corporation (CRC), a wholly owned subsidiary of CL&P. At June 30,
2004, the reserve requirements calculated in accordance with
the Receivables Purchase and Sale Agreement were $19.5 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 June 30, 2004, amounts sold to
CRC by CL&P but not sold to the financial institution totaling
$190.4 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."
I. Other Investments
NU has an investment in the common stock of 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.
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.
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, a gain totaling $0.6 million was included as a gain from the
sale of RMS. 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-downs
totaling $1.1 million and $1.4 million, respectively, related to
its investment in RMS.
These charges are disclosed in Note 1N, "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 Communications,
Inc. (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.
J. 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.
K. Unrestricted Cash From Counterparties
Unrestricted cash on deposit from counterparties represents
balances collected from counterparties resulting from Select
Energy's credit management activities. 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 its credit support provider.
At June 30, 2004, CL&P and WMECO held $22 million and $10.8
million, respectively, of unrestricted cash from Select Energy,
which is a counterparty to energy contracts with CL&P and WMECO.
These amounts eliminate in consolidation.
L. Special Deposits
Special deposits represents amounts Select Energy has on deposit
with unaffiliated counterparties and brokerage firms in the
amount of $2.6 million and amounts included in escrow for Select
Energy Services, Inc. (SESI) that have not been spent on
construction projects of $25.5 million at June 30, 2004. Similar
amounts totaled $17 million and $32 million at December 31, 2003,
respectively. 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.
M. Restricted Cash - LMP Costs
Restricted cash - LMP costs represents incremental LMP cost
amounts that have been collected by CL&P and deposited into an
escrow account. At June 30, 2004 and December 31, 2003,
restricted cash - LMP costs totaled $123.9 million and $93.6
million, respectively.
N. Other Income
The pre-tax components of NU's other income items are as follows:
---------------------------------------------------------------------
For the Three Months Ended
---------------------------------------------------------------------
(Millions of Dollars) June 30, 2004 June 30, 2003
---------------------------------------------------------------------
Investment write-downs $(3.8) $(1.1)
Investment income 3.8 4.1
CL&P procurement fee 2.7 -
Charitable donations (0.5) (1.7)
AFUDC - equity funds 0.5 1.8
Gain on sale of RMS 0.6 -
Other, net (0.4) (2.3)
---------------------------------------------------------------------
Totals $ 2.9 $ 0.8
---------------------------------------------------------------------
---------------------------------------------------------------------
For the Six Months Ended
---------------------------------------------------------------------
(Millions of Dollars) June 30, 2004 June 30, 2003
---------------------------------------------------------------------
Investment write-downs $(6.3) $(1.4)
Investment income 7.0 8.0
CL&P procurement fee 5.8 -
Charitable donations (1.5) (4.0)
AFUDC - equity funds 1.9 3.3
Gain on sale of RMS 0.6 -
Other, net (3.0) (4.6)
---------------------------------------------------------------------
Totals $ 4.5 $ 1.3
---------------------------------------------------------------------
O. Estimate of Workers' Compensation and Injuries and Damages Reserves
During the second quarter of 2004, NU engaged an actuary to
assess the workers' compensation and injuries and damages
reserves for claims incurred but not yet reported or included in
specific case reserves. As a result of this assessment, these
reserves were increased resulting in a net income impact of $2.8
million.
2. DERIVATIVE INSTRUMENTS (NU, CL&P, PSNH, 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.
During the second quarter of 2004, a negative $27.2 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. An additional $0.2 million, net of tax,
was recognized in earnings for those derivatives that were determined
to be ineffective and for the ineffective portion of cash flow hedges.
A negative $0.1 million, net of tax, was recognized in earnings for
the ineffective portion of fair value hedges. Also during the first
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 increased by $20.8 million, net
of tax. Accumulated other comprehensive income at June 30, 2004, was
a positive $45.7 million, net of tax (increase to equity), relating to
hedged transactions, and it is estimated that $41.3 million of 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 from the underlying hedged
transaction.
The tables below summarize the derivative assets and liabilities at
June 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 June 30, 2004, the maximum amount of loss on
trading, non-trading, and hedging contracts due to credit risk and
assuming complete performance failure and no value for the collateral
maintained is the total of NU Enterprises' derivative assets of $203
million. 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 $6.8 million and $9.1
million related to energy trading activities and $16.7 million and
$7.6 million related to marketing activities at June 30, 2004 and
December 31, 2003, respectively. These amounts also do not include
option premiums received, which are recorded as other current
liabilities and amounted to $9.2 million and $12.2 million related to
energy trading activities at June 30, 2004 and December 31, 2003,
respectively, and $1.9 million related to marketing activities at
June 30, 2004.
--------------------------------------------------------------------------
At June 30, 2004
--------------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
--------------------------------------------------------------------------
NU Enterprises:
Trading $111.2 $ (82.9) $ 28.3
Non-trading 0.2 (0.1) 0.1
Hedging 91.6 (15.2) 76.4
Utility Group - Gas:
Non-trading - (0.1) (0.1)
Hedging 3.0 - 3.0
Utility Group - Electric:
Non-trading 160.0 (54.5) 105.5
NU Parent:
Hedging - (10.3) (10.3)
--------------------------------------------------------------------------
Total $366.0 $(163.1) $202.9
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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
June 30, 2004 and at December 31, 2003 were assets of $28.3 million and
$32.5 million, respectively.
Select Energy's trading portfolio includes New York Mercantile
Exchange (NYMEX) futures and options, the fair value of which is based
on closing exchange prices; over-the-counter forwards 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 negative $0.7
million of non-trading derivative contracts were recorded in revenues
in the first six 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 $8.2
million at June 30, 2004, and $4.3 million at December 31, 2003 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 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, natural gas, or oil. 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
comprehensive 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 June 30, 2004 the NYMEX futures contracts had notional
values of $65.2 million and were recorded at fair value as derivative
assets of $11.9 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 $79.7 million and
derivative liabilities of $14.7 million at June 30, 2004.
In the second quarter of 2004, Select Energy hedged natural gas
inventory with gas futures, accounted for as fair value hedges. The
changes in fair value of the futures, options and swaps were recorded
as derivative liabilities of $0.5 million, and the changes in fair
value of the hedged inventory of $0.9 million were recorded on the
consolidated balance sheets.
Utility Group - Gas - Non-Trading: Yankee Gas' non-trading derivatives
consist of 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. The net fair value of non-trading derivatives at
June 30, 2004 was a liability 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 June 30, 2004 the
commodity swap agreement had a notional value of $4.3 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, as amended. The fair values of these IPP
non-trading derivatives at June 30, 2004 include a derivative asset
with a fair value of $152 million and a derivative liability with a
fair value of $54.2 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.
To mitigate the risk associated with certain supply contracts, CL&P
purchased FTRs and financial swaps. FTRs and financial swaps are
derivatives that do not qualify for the normal purchases and sales
exception. The fair value of the FTR non-trading derivatives, valued
at cost, at June 30, 2004 was an asset of $7.6 million. The fair
value of the financial swap non-trading derivatives, which are valued
at the mid-point of bid and ask market prices, at June 30, 2004 was a
liability of $0.3 million.
To mitigate the risk associated with end user delivery, PSNH purchased
FTRs. The fair value of PSNH's FTR non-trading derivatives, valued at
cost, at June 30, 2004 was an asset of $0.4 million.
An offsetting regulatory asset or liability was recorded for CL&P and
PSNH, as these contracts are part of procuring energy for requirements
needs, 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 $10.3
million is included as a reduction of long-term debt on the
consolidated balance sheets. The hedge is recorded as a derivative
liability of $10.3 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 six-
month periods ended June 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,
which 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 June 30, 2004, NU maintained $319.9 million of goodwill that is no
longer being amortized, $12.6 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 June 30, 2004 and December 31,
2003, by reportable segment and reporting unit is as follows:
--------------------------------------------------------------------------
(Millions of Dollars) At June 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 June 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 June 30, 2004
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $8.5 $9.2
Customer list 6.6 3.2 3.4
--------------------------------------------------------------------------
Totals $24.3 $11.7 $12.6
--------------------------------------------------------------------------
Intangible assets not subject
to amortization:
Customer relationships $ 5.2
Tradenames 3.3
--------------------------------------------
Totals $ 8.5
--------------------------------------------
--------------------------------------------------------------------------
At December 31, 2003
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization 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 $1.8 million for both the six months
ended June 30, 2004 and 2003, 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. Restructuring and Rate Matters (CL&P, PSNH, WMECO)
Connecticut:
Impacts of Standard Market Design: On March 1, 2003, the New
England Independent System Operator (ISO-NE) implemented Standard
Market Design (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. A
settlement agreement was reached to settle the dispute among all
the parties involved and was filed with the Federal Energy
Regulatory Commission (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, and the
remaining $75 million became available to be refunded to CL&P's
customers. The method in which the $75 million will be refunded
to customers is currently under review by the DPUC with a
decision expected in the third quarter of 2004.
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 SBC allows CL&P to recover certain regulatory and
energy public policy costs, such as public education outreach
costs, hardship protection costs, transition period property
taxes, and displaced workers protection costs. The Generation
Service Charge (GSC) allows CL&P to recover the costs of the
procurement of energy for standard offer service.
On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation
with the DPUC. For the year ended December 31, 2003, total CTA
revenues and excess GSC revenues as filed exceeded the CTA
revenue requirement by $148.3 million. For the same period, SBC
revenues as filed exceeded the SBC revenue requirement by $25.5
million. These amounts were recorded as regulatory liabilities
on the accompanying consolidated balance sheets.
A final decision in the 2003 CTA and SBC docket was issued on
August 4, 2004. In the final decision, the DPUC ordered a refund
to customers of $88.5 million over a seven-month period beginning
with October 2004 consumption. The DPUC ordered that the SBC
rate be reduced to zero effective January 1, 2005. The DPUC also
directed CL&P to impute revenue of $2.7 million to customers
associated with a previously renegotiated IPP contract. CL&P
will likely seek rehearing on this issue, and management cannot
predict the outcome of this issue at this time.
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 income taxes 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 the company's request is
ultimately granted through 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 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
$175.8 million at June 30, 2004. The 2003 SCRC filing was made
on April 30, 2004. Management does not expect the review of the
2003 SCRC filing to have a material effect on PSNH's net income
or financial position. Hearings are currently scheduled for
October 2004.
Massachusetts:
Transition Cost Reconciliation: On March 31, 2004, WMECO filed
its 2003 transition cost reconciliation with the Massachusetts
Department of Telecommunications and Energy (DTE). This filing
reconciled the recovery of generation-related stranded costs for
calendar year 2003. The timing of a final decision is uncertain.
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, have
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 their resolution will
have a material adverse effect on NU's consolidated financial
condition or results of operations.
C. Long-Term Contractual Arrangements (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 $4.7 billion at
June 30, 2004, as follows (millions of dollars):
---------------------------------------------------------------------
Year
---------------------------------------------------------------------
2004 $2,441.3
2005 1,440.7
2006 299.1
2007 99.5
2008 83.7
Thereafter 295.7
---------------------------------------------------------------------
Total $4,660.0
---------------------------------------------------------------------
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.
NU's other long-term contractual arrangements have not changed
significantly from the amounts reported at December 31, 2003.
D. Deferred Contractual Obligations (NU, CL&P, PSNH, WMECO)
The purchasers of NU's ownership shares of the Millstone,
Seabrook and Vermont Yankee nuclear power plants assumed the
obligation of decommissioning those plants, but NU still 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 to 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. The MY
settlement agreement includes the collection of approximately $27
million annually for decommissioning and long-term storage of
spent fuel through October 31, 2008. Approval of the MY
settlement agreement by the FERC is anticipated in the fall of
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 termination of the decommissioning contract with
Bechtel Power Corporation (Bechtel) in July 2003, the fact that
CY is now self-performing all work to complete the
decommissioning of the plant, the increases in the projected
costs of spent fuel storage, and increased security and liability
and property insurance. 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
the increased costs. In the filing CY seeks to increase its
annual decommissioning collections from $16.7 million to $93
million for a six-year period beginning January 1, 2005. FERC
proceedings have not yet been scheduled. In total, NU's
estimated remaining decommissioning and plant closure obligation
to CY is $315.5 million at June 30, 2004.
Previously, on June 10, 2004, the DPUC and the OCC filed a
petition with the FERC seeking a declaratory order that CY can
recover all decommissioning costs from its wholesale purchasers,
including CL&P, PSNH and WMECO, but such purchasers may not
recover in their retail rates any costs which FERC might
determine to have been imprudently incurred. CY and the
wholesale purchasers have objected and the matter is pending.
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 these 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. For further information regarding these issues, 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.
5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises)
Total comprehensive income, which includes all comprehensive
income/(loss) items by category, for the six months ended June 30,
2004 and 2003 is as follows:
- ---------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2004
- ---------------------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ---------------------------------------------------------------------------------------------------
Net income* $ 90.3 $43.5 $17.8 $7.1 $21.7 $ 0.2
- ---------------------------------------------------------------------------------------------------
Comprehensive income/(loss) items:
Qualified cash flow
hedging instruments 20.9 - - - 20.8 0.1
Unrealized (losses)/gains
on securities (0.2) - - - 0.2 (0.4)
- ---------------------------------------------------------------------------------------------------
Net change in comprehensive
income/(loss) items 20.7 - - - 21.0 (0.3)
- ---------------------------------------------------------------------------------------------------
Total comprehensive
income/(loss) $111.0 $43.5 $17.8 $7.1 $42.7 $(0.1)
- ---------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2003
- ---------------------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ---------------------------------------------------------------------------------------------------
Net income* $ 87.1 $30.0 $21.9 $8.7 $17.1 $ 9.4
- ---------------------------------------------------------------------------------------------------
Comprehensive (loss)/income items:
Qualified cash flow
hedging instruments (13.9) - - - (9.8) (4.1)
Unrealized gains
on securities 0.7 0.1 - - - 0.6
- ---------------------------------------------------------------------------------------------------
Net change in comprehensive
(loss)/income items (13.2) 0.1 - - (9.8) (3.5)
- ---------------------------------------------------------------------------------------------------
Total comprehensive income $ 73.9 $30.1 $21.9 $8.7 $ 7.3 $ 5.9
- ---------------------------------------------------------------------------------------------------
*Net income after preferred dividends of subsidiary.
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 six months ended
June 30, 2004 and the twelve months ended December 31, 2003 are as
follows:
--------------------------------------------------------------------------
At June 30, At December 31,
(Millions of Dollars, Net of Tax) 2004 2003
--------------------------------------------------------------------------
Balance at beginning of period $24.8 $15.5
--------------------------------------------------------------------------
Hedged transactions recognized
into earnings (27.2) (5.3)
Change in fair value 33.1 5.0
Cash flow transactions entered
into for the period 15.0 9.6
--------------------------------------------------------------------------
Net change associated with the
current period hedging transactions 20.9 9.3
--------------------------------------------------------------------------
Total fair value adjustments included
in accumulated other
comprehensive income $45.7 $24.8
--------------------------------------------------------------------------
Accumulated other comprehensive income items unrelated to NU's
qualified cash flow hedging instruments totaled $0.9 million and $1.2
million in gains at June 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 June 30, 2004 and 2003, 626,302 options and
2,862,471 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:
--------------------------------------------------------------------------
(Millions of Dollars, Six Months Ended June 30,
Except for Share Information) 2004 2003
--------------------------------------------------------------------------
Income before preferred
dividends of subsidiary $93.1 $89.9
Preferred dividends
of subsidiary 2.8 2.8
--------------------------------------------------------------------------
Net income $90.3 $87.1
--------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 127,956,640 126,880,397
Dilutive effects of employee
stock options 165,111 102,506
--------------------------------------------------------------------------
Fully diluted EPS common shares
outstanding (average) 128,121,751 126,982,903
--------------------------------------------------------------------------
Basic and fully diluted EPS $0.71 $0.69
--------------------------------------------------------------------------
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 substantially all
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 six months ended June 30, 2004 and 2003 are estimated as
follows:
--------------------------------------------------------------------------
For the Six Months Ended June 30,
--------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
--------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
--------------------------------------------------------------------------
Service cost $ 20.3 $ 17.5 $ 3.0 $ 2.7
Interest cost 59.4 58.5 12.7 13.4
Expected return
on plan assets (87.5) (91.3) (6.2) (7.5)
Amortization of
unrecognized net
transition
(asset)/obligation (0.7) (0.7) 5.9 5.9
Amortization of
prior service cost 3.6 3.6 (0.2) (0.2)
Amortization of
actuarial loss/(gain) 7.8 (3.5) - -
Other amortization, net - - 5.7 3.2
--------------------------------------------------------------------------
Total - net periodic
expense/(income) $ 2.9 $(15.9) $20.9 $17.5
--------------------------------------------------------------------------
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.
The actuarial gain resulting from the expansion of the Medicare
program decreased the PBOP accumulated plan benefit obligation by $20
million and is currently being amortized as a reduction to PBOP
expense over 13 years. For the six months ended June 30, 2004, this
reduction in PBOP expense totaled approximately $1.4 million,
including amortization of the actuarial gain of $0.8 million and a
reduction in interest cost based on a lower PBOP benefit obligation of
$0.6 million.
As a result of ongoing 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. As NU
appealed the ruling, these amounts are not included in the pension and
PBOP information above.
There is no immediate impact of the court order, and if NU is
ultimately required to provide retroactive benefits, then the amount
of the benefits would be recorded as a pension plan amendment, which
would be amortized as a prior service cost and would increase pension
expense over a 13-year amortization period.
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 75 percent of NU's total revenues for the
six months ended June 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 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 $314.5
million or 22 percent for the six months ended June 30, 2004 and
approximately $349.1 million or 30 percent for the six months ended
June 30, 2003, of total NU Enterprises' revenues. Total CL&P
purchases from NU Enterprises 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 $53 million and $68.2 million of total NU
Enterprises' revenues for the six months ended June 30, 2004 and 2003,
respectively. Total WMECO purchases from NU Enterprises are
eliminated in consolidation. Select Energy revenues related to
contracts with NSTAR companies represented $158.4 million or 11
percent of total NU Enterprises' revenues for the six months ended
June 30, 2004. Select Energy also provides BGS in the New Jersey
market. Select Energy revenues related to these contracts represented
$213.7 million or 18 percent of total NU Enterprises' revenues for the
six months ended June 30, 2003. No other individual customer
represented in excess of 10 percent of NU Enterprises' revenues for
the six months ended June 30, 2004 or 2003.
Eliminations and other in the NU consolidated following 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 six months ended
June 30, 2004 and 2003 is as follows (some amounts between segment
schedules may not agree due to rounding):
- ---------------------------------------------------------------------------------------------------
For the Six Months Ended June 30, 2004
- ---------------------------------------------------------------------------------------------------
Utility Group
-------------------------------------
Distribution
(Millions of --------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
- ---------------------------------------------------------------------------------------------------
Operating revenues $2,023.8 $ 243.3 $ 64.5 $1,417.4 $(386.0) $ 3,363.0
Depreciation and
amortization (215.3) (12.9) (10.0) (9.6) (1.0) (248.8)
Other
operating
expenses (1,646.8) (205.2) (30.4) (1,347.7) 383.1 (2,847.0)
- ---------------------------------------------------------------------------------------------------
Operating income/
(loss) 161.7 25.2 24.1 60.1 (3.9) 267.2
Interest
expense, net (79.2) (8.4) (5.6) (25.9) (6.8) (125.9)
Other income/
(loss), net 7.1 (0.6) (0.2) 2.9 (4.7) 4.5
Income tax
(expense)/
benefit (30.9) (4.1) (5.8) (15.4) 3.5 (52.7)
Preferred
dividends (2.8) - - - - (2.8)
- ---------------------------------------------------------------------------------------------------
Net income/(loss) $ 55.9 $ 12.1 $ 12.5 $ 21.7 $ (11.9) $ 90.3
- ---------------------------------------------------------------------------------------------------
Total assets (1) $8,411.1 $1,058.0 $ - $2,248.4 $(203.7) $11,513.8
- ---------------------------------------------------------------------------------------------------
Total investments
in plant $ 189.3 $ 22.5 $ 81.3 $ 11.3 $ 7.2 $ 311.6
- ---------------------------------------------------------------------------------------------------
(1) Information for segmenting total assets between electric distribution
and transmission is not available at June 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 June 30, 2004
- ---------------------------------------------------------------------------------------------------
Utility Group
-------------------------------------
Distribution
(Millions of --------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
- ---------------------------------------------------------------------------------------------------
Operating revenues $964.1 $72.0 $33.5 $621.1 $(166.0) $ 1,524.7
Depreciation and
amortization (105.1) (6.5) (5.2) (4.8) (0.4) (122.0)
Other
operating
expenses (790.2) (65.3) (17.2) (600.1) 164.5 (1,308.3)
- ---------------------------------------------------------------------------------------------------
Operating income/
(loss) 68.8 0.2 11.1 16.2 (1.9) 94.4
Interest
expense, net (39.3) (4.5) (3.3) (12.2) (3.8) (63.1)
Other income/
(loss), net 3.8 (0.1) 0.2 1.6 (2.6) 2.9
Income tax
(expense)/
benefit (10.3) 4.6 (2.7) (2.7) 1.2 (9.9)
Preferred
dividends (1.4) - - - - (1.4)
- ---------------------------------------------------------------------------------------------------
Net income/(loss) $ 21.6 $ 0.2 $ 5.3 $ 2.9 $ (7.1) $ 22.9
- ---------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
For the Six Months Ended June 30, 2003
- ---------------------------------------------------------------------------------------------------
Utility Group
-------------------------------------
Distribution
(Millions of --------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
- ---------------------------------------------------------------------------------------------------
Operating revenues $1,894.0 $223.1 $55.8 $1,168.0 $(426.7) $2,914.2
Depreciation and
amortization (226.0) (11.5) (9.2) (10.2) (1.1) (258.0)
Other
operating
expenses (1,500.6) (181.7) (27.8) (1,107.0) 425.5 (2,391.6)
- ---------------------------------------------------------------------------------------------------
Operating income/
(loss) 167.4 29.9 18.8 50.8 (2.3) 264.6
Interest
expense, net (83.8) (6.6) (2.8) (23.1) (6.8) (123.1)
Other(loss)/
income, net (0.5) (0.9) (0.1) 2.8 0.1 1.4
Income tax
(expense)/
benefit (31.5) (9.4) (4.1) (13.4) 5.4 (53.0)
Preferred
dividends (2.8) - - - - (2.8)
- ---------------------------------------------------------------------------------------------------
Net income/(loss) $ 48.8 $ 13.0 $11.8 $ 17.1 $ (3.6) $ 87.1
- ---------------------------------------------------------------------------------------------------
Total investments
in plant $ 155.5 $ 22.6 $43.8 $ 7.5 $ 4.6 $ 234.0
- ---------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
For the Three Months Ended June 30, 2003
- ---------------------------------------------------------------------------------------------------
Utility Group
-------------------------------------
Distribution
(Millions of --------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
- ---------------------------------------------------------------------------------------------------
Operating revenues $883.6 $ 72.1 $24.7 $555.1 $(205.5) $1,330.0
Depreciation and
amortization (92.7) (5.7) (4.6) (5.3) (0.6) (108.9)
Other
operating
expenses (722.2) (66.8) (14.7) (519.1) 205.4 (1,117.4)
- ---------------------------------------------------------------------------------------------------
Operating income/
(loss) 68.7 (0.4) 5.4 30.7 (0.7) 103.7
Interest
expense, net (41.4) (3.4) (1.5) (12.0) (1.2) (59.5)
Other(loss)/
income, net (0.1) (0.6) - 2.5 (1.0) 0.8
Income tax
(expense)/
benefit (11.2) 1.5 (0.1) (9.3) 2.4 (16.7)
Preferred
dividends (1.4) - - - - (1.4)
- ---------------------------------------------------------------------------------------------------
Net income/(loss) $ 14.6 $ (2.9) $ 3.8 $ 11.9 $ (0.5) $ 26.9
- ---------------------------------------------------------------------------------------------------
Utility Group segment information related to the regulated electric
distribution and transmission businesses for CL&P, PSNH and WMECO for
the three months and six months ended June 30, 2004 and 2003 is as
follows:
---------------------------------------------------------------------
CL&P - For the Six Months Ended June 30, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $1,384.0 $43.8 $1,427.8
Depreciation and
amortization (113.8) (7.4) (121.2)
Other
operating
expenses (1,173.0) (20.1) (1,193.1)
---------------------------------------------------------------------
Operating income 97.2 16.3 113.5
Interest
expense, net (50.7) (4.2) (54.9)
Other income, net 10.1 - 10.1
Income tax
expense (18.7) (3.7) (22.4)
Preferred
dividends (2.8) - (2.8)
---------------------------------------------------------------------
Net income $ 35.1 $ 8.4 $ 43.5
---------------------------------------------------------------------
Total investments
in plant $ 122.2 $66.2 $ 188.4
---------------------------------------------------------------------
---------------------------------------------------------------------
CL&P - For the Three Months Ended June 30, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $656.3 $22.8 $679.1
Depreciation and
amortization (59.9) (3.7) (63.6)
Other
operating
expenses (554.9) (11.4) (566.3)
---------------------------------------------------------------------
Operating income 41.5 7.7 49.2
Interest
expense, net (25.2) (2.6) (27.8)
Other income, net 4.9 0.1 5.0
Income tax
expense (6.0) (1.7) (7.7)
Preferred
dividends (1.4) - (1.4)
---------------------------------------------------------------------
Net income $ 13.8 $ 3.5 $ 17.3
---------------------------------------------------------------------
---------------------------------------------------------------------
CL&P - For the Six Months Ended June 30, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $1,285.6 $35.6 $1,321.2
Depreciation and
amortization (149.1) (6.9) (156.0)
Other
operating
expenses (1,042.8) (18.6) (1,061.4)
---------------------------------------------------------------------
Operating income 93.7 10.1 103.8
Interest
expense, net (54.6) (2.1) (56.7)
Other income/
(loss), net 2.2 (0.2) 2.0
Income tax
expense (15.5) (0.8) (16.3)
Preferred
dividends (2.8) - (2.8)
---------------------------------------------------------------------
Net income $ 23.0 $ 7.0 $ 30.0
---------------------------------------------------------------------
Total investments
in plant $ 103.3 $33.9 $ 137.2
---------------------------------------------------------------------
---------------------------------------------------------------------
CL&P - For the Three Months Ended June 30, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $599.5 $15.8 $615.3
Depreciation and
amortization (70.4) (3.4) (73.8)
Other
operating
expenses (495.3) (9.5) (504.8)
---------------------------------------------------------------------
Operating income 33.8 2.9 36.7
Interest
expense, net (26.9) (1.1) (28.0)
Other income, net 1.2 - 1.2
Income tax
(expense)/benefit (4.8) 1.0 (3.8)
Preferred
dividends (1.4) - (1.4)
---------------------------------------------------------------------
Net income $ 1.9 $ 2.8 $ 4.7
---------------------------------------------------------------------
---------------------------------------------------------------------
PSNH - For the Six Months Ended June 30, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $457.6 $13.0 $470.6
Depreciation and
amortization (81.5) (1.7) (83.2)
Other
operating
expenses (328.7) (7.0) (335.7)
---------------------------------------------------------------------
Operating income 47.4 4.3 51.7
Interest
expense, net (21.5) (0.8) (22.3)
Other loss, net (2.2) - (2.2)
Income tax
expense (8.1) (1.3) (9.4)
---------------------------------------------------------------------
Net income $ 15.6 $ 2.2 $ 17.8
---------------------------------------------------------------------
Total investments
in plant $ 51.9 $13.7 $ 65.6
---------------------------------------------------------------------
---------------------------------------------------------------------
PSNH - For the Three Months Ended June 30, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $219.9 $ 6.5 $226.4
Depreciation and
amortization (35.6) (0.9) (36.5)
Other
operating
expenses (165.8) (3.9) (169.7)
---------------------------------------------------------------------
Operating income 18.5 1.7 20.2
Interest
expense, net (10.6) (0.4) (11.0)
Other loss, net (0.5) - (0.5)
Income tax expense (2.2) (0.5) (2.7)
---------------------------------------------------------------------
Net income $ 5.2 $ 0.8 $ 6.0
---------------------------------------------------------------------
---------------------------------------------------------------------
PSNH - For the Six Months Ended June 30, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $421.4 $12.7 $434.1
Depreciation and
amortization (42.8) (1.4) (44.2)
Other
operating
expenses (322.6) (6.2) (328.8)
---------------------------------------------------------------------
Operating income 56.0 5.1 61.1
Interest
expense, net (22.6) (0.5) (23.1)
Other (loss)/
income, net (2.5) 0.1 (2.4)
Income tax expense (11.9) (1.8) (13.7)
---------------------------------------------------------------------
Net income $ 19.0 $ 2.9 $ 21.9
---------------------------------------------------------------------
Total investments
in plant $ 40.7 $ 9.2 $ 49.9
---------------------------------------------------------------------
---------------------------------------------------------------------
PSNH - For the Three Months Ended June 30, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $197.9 $ 5.5 $203.4
Depreciation and
amortization (6.1) (0.7) (6.8)
Other
operating
expenses (163.3) (3.6) (166.9)
---------------------------------------------------------------------
Operating income 28.5 1.2 29.7
Interest
expense, net (11.2) (0.3) (11.5)
Other loss, net (1.2) - (1.2)
Income tax expense (5.4) (0.5) (5.9)
---------------------------------------------------------------------
Net income $ 10.7 $ 0.4 $ 11.1
---------------------------------------------------------------------
---------------------------------------------------------------------
WMECO - For the Six Months Ended June 30, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $182.3 $ 7.7 $190.0
Depreciation and
amortization (20.1) (0.9) (21.0)
Other
operating
expenses (145.1) (3.3) (148.4)
---------------------------------------------------------------------
Operating income 17.1 3.5 20.6
Interest
expense, net (7.0) (0.6) (7.6)
Other loss, net (0.9) - (0.9)
Income tax
expense (4.0) (1.0) (5.0)
---------------------------------------------------------------------
Net income $ 5.2 $ 1.9 $ 7.1
---------------------------------------------------------------------
Total investments
in plant $ 15.2 $ 1.4 $ 16.6
---------------------------------------------------------------------
---------------------------------------------------------------------
WMECO - For the Three Months Ended June 30, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $ 88.0 $ 4.1 $ 92.1
Depreciation and
amortization (9.6) (0.5) (10.1)
Other
operating
expenses (69.6) (1.8) (71.4)
---------------------------------------------------------------------
Operating income 8.8 1.8 10.6
Interest
expense, net (3.5) (0.3) (3.8)
Other loss, net (0.6) - (0.6)
Income tax
expense (2.1) (0.5) (2.6)
---------------------------------------------------------------------
Net income $ 2.6 $ 1.0 $ 3.6
---------------------------------------------------------------------
---------------------------------------------------------------------
WMECO - For the Six Months Ended June 30, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $186.9 $ 7.5 $194.4
Depreciation and
amortization (34.1) (0.9) (35.0)
Other
operating
expenses (135.1) (3.0) (138.1)
---------------------------------------------------------------------
Operating income 17.7 3.6 21.3
Interest
expense, net (6.6) (0.2) (6.8)
Other loss, net (0.2) - (0.2)
Income tax
expense (4.1) (1.5) (5.6)
---------------------------------------------------------------------
Net income $ 6.8 $ 1.9 $ 8.7
---------------------------------------------------------------------
Total investments
in plant $ 11.5 $ 0.7 $ 12.2
---------------------------------------------------------------------
---------------------------------------------------------------------
WMECO - For the Three Months Ended June 30, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $86.4 $ 3.3 $ 89.7
Depreciation and
amortization (16.2) (0.5) (16.7)
Other
operating
expenses (63.7) (1.5) (65.2)
---------------------------------------------------------------------
Operating income 6.5 1.3 7.8
Interest
expense, net (3.3) (0.1) (3.4)
Other loss, net (0.2) - (0.2)
Income tax
expense (1.0) (0.6) (1.6)
---------------------------------------------------------------------
Net income $ 2.0 $ 0.6 $ 2.6
---------------------------------------------------------------------
NU Enterprises' segment information for the three months and six months
ended June 30, 2004 and 2003 is as follows. Information regarding the
energy services business segment is included in the eliminations and
other column:
--------------------------------------------------------------------------
NU Enterprises - For the Six Months Ended June 30, 2004
--------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
--------------------------------------------------------------------------
Operating revenues $1,285.0 $132.4 $1,417.4
Depreciation and
amortization (8.6) (1.0) (9.6)
Other
operating
expenses (1,214.5) (133.2) (1,347.7)
--------------------------------------------------------------------------
Operating income 61.9 (1.8) 60.1
Interest
expense, net (21.6) (4.3) (25.9)
Other (loss)/
income, net (0.1) 3.0 2.9
Income tax
(expense)/
benefit (16.6) 1.2 (15.4)
--------------------------------------------------------------------------
Net income/(loss) $ 23.6 $ (1.9) $ 21.7
--------------------------------------------------------------------------
Total assets $1,936.9 $311.5 $2,248.4
--------------------------------------------------------------------------
Total investments
in plant $ 9.9 $ 1.4 $ 11.3
--------------------------------------------------------------------------
--------------------------------------------------------------------------
NU Enterprises - For the Three Months Ended June 30, 2004
--------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
--------------------------------------------------------------------------
Operating revenues $ 550.5 $ 70.6 $ 621.1
Depreciation and
amortization (4.3) (0.5) (4.8)
Other
operating
expenses (527.6) (72.5) (600.1)
--------------------------------------------------------------------------
Operating income 18.6 (2.4) 16.2
Interest
expense, net (10.4) (1.8) (12.2)
Other income, net - 1.6 1.6
Income tax
(expense)/
benefit (3.7) 1.0 (2.7)
--------------------------------------------------------------------------
Net income/(loss) $ 4.5 $ (1.6) $ 2.9
--------------------------------------------------------------------------
Total assets $1,936.9 $311.5 $2,248.4
--------------------------------------------------------------------------
--------------------------------------------------------------------------
NU Enterprises - For the Six Months Ended June 30, 2003
--------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
--------------------------------------------------------------------------
Operating revenues $1,055.1 $112.9 $1,168.0
Depreciation and
amortization (8.8) (1.4) (10.2)
Other
operating
expenses (997.4) (109.6) (1,107.0)
Operating income 48.9 1.9 50.8
Interest
expense, net (19.9) (3.2) (23.1)
Other (loss)/
income, net (2.2) 5.0 2.8
Income tax
expense (11.3) (2.1) (13.4)
--------------------------------------------------------------------------
Net income $ 15.5 $ 1.6 $ 17.1
--------------------------------------------------------------------------
Total investments
in plant $ 6.8 $ 0.7 $ 7.5
--------------------------------------------------------------------------
--------------------------------------------------------------------------
NU Enterprises - For the Three Months Ended June 30, 2003
--------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
--------------------------------------------------------------------------
Operating revenues $ 492.1 $ 63.0 $ 555.1
Depreciation and
amortization (4.4) (0.9) (5.3)
Other
operating
expenses (458.6) (60.5) (519.1)
--------------------------------------------------------------------------
Operating income 29.1 1.6 30.7
Interest
expense, net (10.1) (1.9) (12.0)
Other (loss)/
income, net (1.0) 3.5 2.5
Income tax
expense (7.4) (1.9) (9.3)
--------------------------------------------------------------------------
Net income $ 10.6 $ 1.3 $ 11.9
--------------------------------------------------------------------------
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 1 $ 5,814
Unrestricted cash from affiliated counterparty 22,000 -
Restricted cash - LMP costs 123,887 93,630
Investments in securitizable assets 190,388 166,465
Receivables, net 45,658 60,759
Accounts receivable from affiliated companies 83,796 73,986
Unbilled revenues 7,994 6,961
Materials and supplies, at average cost 32,310 31,583
Derivative assets 159,565 115,370
Prepayments and other 7,856 12,521
---------------- ----------------
673,455 567,089
---------------- ----------------
Property, Plant and Equipment:
Electric utility 3,522,606 3,355,794
Less: Accumulated depreciation 1,053,411 1,018,173
---------------- ----------------
2,469,195 2,337,621
Construction work in progress 231,717 224,277
---------------- ----------------
2,700,912 2,561,898
---------------- ----------------
Deferred Debits and Other Assets:
Regulatory assets 1,599,068 1,673,010
Prepaid pension 312,345 305,320
Other 103,029 99,577
---------------- ----------------
2,014,442 2,077,907
---------------- ----------------
Total Assets $ 5,388,809 $ 5,206,894
================ ================
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ 5,000 $ -
Notes payable to affiliated companies 196,225 91,125
Accounts payable 236,324 138,155
Accounts payable to affiliated companies 138,723 176,948
Accrued taxes 25,980 65,587
Accrued interest 10,299 10,361
Derivative liabilities 54,528 54,566
Other 69,827 49,674
---------------- ----------------
736,906 586,416
---------------- ----------------
Rate Reduction Bonds 1,060,902 1,124,779
---------------- ----------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 635,462 609,068
Accumulated deferred investment tax credits 89,825 90,885
Deferred contractual obligations 296,994 318,043
Regulatory liabilities 797,151 752,992
Other 83,015 79,935
---------------- ----------------
1,902,447 1,850,923
---------------- ----------------
Capitalization:
Long-Term Debt 831,158 830,149
---------------- ----------------
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 349,474 326,629
Retained earnings 331,735 311,793
Accumulated other comprehensive loss (365) (347)
---------------- ----------------
Common Stockholder's Equity 741,196 698,427
---------------- ----------------
Total Capitalization 1,688,554 1,644,776
---------------- ----------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 5,388,809 $ 5,206,894
================ ================
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- ----------------------------
2004 2003 2004 2003
------------- ------------ -------------- -------------
(Thousands of Dollars)
Operating Revenues $ 679,080 $ 615,268 $ 1,427,770 $ 1,321,184
------------ ------------ ------------ ------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 391,607 353,211 861,264 773,416
Other 124,300 100,928 216,437 176,767
Maintenance 18,416 20,676 34,847 31,854
Depreciation 29,425 25,911 58,050 51,327
Amortization of regulatory assets, net 9,143 24,550 8,583 53,832
Amortization of rate reduction bonds 25,086 23,333 54,548 50,819
Taxes other than income taxes 31,937 30,006 80,594 79,368
------------ ------------ ------------ ------------
Total operating expenses 629,914 578,615 1,314,323 1,217,383
------------ ------------ ------------ ------------
Operating Income 49,166 36,653 113,447 103,801
Interest Expense:
Interest on long-term debt 10,346 9,900 20,245 20,012
Interest on rate reduction bonds 16,128 17,762 32,718 35,906
Other interest 1,324 353 1,905 756
------------ ------------ ------------ ------------
Interest expense, net 27,798 28,015 54,868 56,674
------------ ------------ ------------ ------------
Other Income, Net 5,031 1,219 10,098 1,963
------------ ------------ ------------ ------------
Income Before Income Tax Expense 26,399 9,857 68,677 49,090
Income Tax Expense 7,754 3,793 22,419 16,304
------------ ------------ ------------ ------------
Net Income $ 18,645 $ 6,064 $ 46,258 $ 32,786
============ ============ ============ ============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<Table>
<Caption>
Six Months Ended
June 30,
--------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating Activities:
Net income $ 46,258 $ 32,786
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 58,050 51,327
Deferred income taxes and investment tax credits, net 15,709 (22,612)
Amortization of regulatory assets, net 8,583 53,832
Amortization of rate reduction bonds 54,548 50,819
Amortization of recoverable energy costs (6,486) (28,779)
Increase in prepaid pension (7,025) (14,283)
Regulatory overrecoveries 17,223 63,513
Other sources of cash 14,079 6,792
Other uses of cash (32,567) (40,882)
Changes in current assets and liabilities:
Restricted cash - LMP costs (30,257) -
Unrestricted cash from affiliated counterparty (22,000) -
Receivables and unbilled revenues, net 4,258 9,070
Materials and supplies (727) 1,622
Investments in securitizable assets (23,923) 32,376
Other current assets 4,665 9,950
Accounts payable 59,944 17,015
Accrued taxes (39,607) (9,481)
Other current liabilities 20,053 (5,223)
------------ -----------
Net cash flows provided by operating activities 140,778 207,842
------------ -----------
Investing Activities:
Investments in plant (188,349) (137,157)
NU system Money Pool borrowing 105,100 17,200
Other investment activities (804) (2,809)
------------ -----------
Net cash flows used in investing activities (84,053) (122,766)
------------ -----------
Financing Activities:
Retirement of rate reduction bonds (63,877) (59,510)
Capital contribution from Northeast Utilities 23,000 -
Increase in short-term debt 5,000 -
Cash dividends on preferred stock (2,779) (2,779)
Cash dividends on common stock (23,537) (20,037)
Other financing activities (345) (300)
------------ -----------
Net cash flows used in financing activities (62,538) (82,626)
------------ -----------
Net (decrease)/increase in cash (5,813) 2,450
Cash - beginning of period 5,814 159
------------ -----------
Cash - end of period $ 1 $ 2,609
============ ===========
</Table>
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 Quarter 2004 Form 10-Q, and the NU
2003 Form 10-K.
RESULTS OF OPERATIONS
The components of significant income statement variances for the second
quarter of 2004 and the first six months of 2004 are provided in the table
below.
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Second Six
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues: $ 64 10% $107 8%
Operating Expenses:
Fuel, purchased and net
interchange power 38 11 88 11
Other operation 23 23 40 22
Maintenance (2) (11) 3 9
Depreciation 3 14 7 13
Amortization of
regulatory assets, net (15) (63) (45) (84)
Amortization of rate
reduction bonds 2 8 4 7
Taxes other than income taxes 2 6 1 2
---- ---- ---- ----
Total operating expenses 51 9 98 8
---- ---- ---- ----
Operating income 13 34 9 9
---- ---- ---- ----
Interest expense, net - - (2) (3)
Other income, net 4 (a) 8 (a)
---- ---- ---- ----
Income before income tax expense 17 (a) 19 40
Income tax expense 4 (a) 6 38
---- ---- ---- ----
Net Income $ 13 (a)% $ 13 41%
==== ==== ==== ====
(a) Percent greater than 100.
Comparison of the Second Quarter of 2004 to the Second Quarter of 2003
Operating Revenues
Operating revenues increased $64 million in the second quarter of 2004,
compared with the same period in 2003, due to higher distribution retail
revenues ($57 million) and higher transmission revenues ($7 million).
Retail revenues were higher due to an increase in TSO service revenues ($53
million), the 2004 collection of Federally Mandated Congestion Costs (FMCC)
($35 million) as compared to the 2003 collection of SMD costs ($30
million), higher sales volumes for distribution revenues ($8 million) and
an increase in the retail transmission rate ($5 million), partially offset
by the 2003 recovery of certain fuel costs ($9 million) and lower rates for
the recovery of system benefit and transition costs ($8 million). Retail
sales in the second quarter of 2004 were 4.8 percent higher than the same
period last year. 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 $38 million
primarily due to higher standard offer service supply costs resulting from
new contracts effective on January 1, 2004 ($51 million), partially offset
by the 2003 recovery of certain fuel costs ($9 million).
Other Operation
Other operation expenses increased $23 million primarily due to higher
reliability must run costs ($15 million) which are recovered through the
FMCC charge and higher administrative and general expenses ($6 million)
primarily due to higher pension costs.
Maintenance
Maintenance expenses decreased $2 million primarily due to lower
distribution maintenance tree trimming expenses.
Depreciation
Depreciation expense increased $3 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 $15 million primarily due
to lower amortization related to the recovery of system benefit and
transition charges ($9 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
Connecticut gross earnings taxes as a result of an increase in revenue and
higher local property taxes.
Other Income, Net
Other income, net increased $4 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 $4 million due to higher income before tax
expense offset by a lower effective tax rate.
Comparison of the First Six Months of 2004 to the First Six Months of 2003
Operating Revenues
Operating revenues increased $107 million in the first six months of 2004,
compared with the same period in 2003, due to higher distribution retail
revenues ($126 million) and higher transmission revenue ($8 million),
partially offset by lower wholesale revenues ($28 million).
Retail revenues were higher due to an increase in TSO revenues ($103
million), the 2004 collection of FMCC ($75 million) as compared to the 2003
collection of SMD costs ($30 million), higher sales volumes for
distribution revenues ($12 million) and an increase in the retail
transmission rate ($13 million), partially offset by the 2003 recovery of
certain fuel costs ($21 million) and lower recovery of system benefit and
transition costs ($21 million). Retail sales in the first six months of
2004 were 3.3 percent higher than the same period last year. Transmission
revenues were higher due to the October 2003 implementation of the
transmission rate case filed at the FERC. Wholesale revenues are lower due
to a lower number of wholesale transactions.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $88 million
primarily due to an increase in the standard offer service requirements
rates for CL&P ($120 million), partially offset by the 2003 recovery of
certain fuel costs ($21 million) and lower wholesale purchases ($12
million).
Other Operation
Other operation expenses increased $40 million primarily due to higher
reliability must run costs ($20 million) which are recovered through the
FMCC charge, higher administrative and general expenses ($9 million)
primarily due to higher pension costs, higher retail transmission expenses
($5 million), higher distribution expenses ($2 million), and higher
customer-related expenses ($2 million).
Maintenance
Maintenance expenses increased $3 million primarily due to the 2003
positive resolution of the CL&P Millstone use of proceeds docket.
Depreciation
Depreciation expense increased $7 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 $45 million primarily due
to lower amortization related to the recovery of system benefit and
transition charges ($31 million), and a reduction to amortization expense
resulting from the implementation of the distribution rate case decision
effective in January 2004 ($15 million).
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $4 million due to the
repayment of additional principal.
Interest Expense, Net
Interest expense, net decreased $2 million due to lower rate reduction bond
interest resulting from lower principal balances outstanding.
Other Income, Net
Other income, net increased $8 million primarily due to the recognition
beginning in 2004 of a procurement fee approved in the TSO docket ($6
million).
Income Tax Expense
Income tax expense increased $6 million due to higher income before tax
expense offset by a lower effective tax rate.
LIQUIDITY
CL&P's net cash flows provided by operating activities decreased to $140.8
million for the six months ended June 30, 2004 from $207.8 million for the
same period in 2003. Cash flows provided by operating activities decreased
due to decreased regulatory overrecoveries and amortization of regulatory
assets and decreases in working capital items, primarily restricted cash -
LMP costs, investments in securitizable assets and accrued taxes. The
decrease in regulatory overrecoveries is primarily due to lower stranded
cost and generation service collections in the first six months of 2004
compared to 2003. The lower level of collections caused lower current
taxable income and an increase in deferred income taxes from 2003. 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. These decreases
were partially offset by an accounts payable increase in the first six
months of 2004 resulting from TSO supply purchases at higher prices and an
increased percentage of TSO purchases from unaffiliated suppliers. The
reclassification of overdraft amounts and a timing difference of payments
also contributed to the increase in accounts payable offset by a decrease
in the payments made to Select Energy.
CL&P's net cash flows used in investing activities decreased to $84.1
million for the first six months of 2004 from $122.8 million for the same
period of 2003. The decrease in investing activities is primarily due to
the level of NU Money Pool borrowings offset by higher capital expenditures
during the first six months of 2004 as compared to the same period in 2003.
CL&P's capital expenditures totaled $188.3 million for the six months ended
June 30, 2004 compared to $137.2 million for the same period of 2003.
CL&P's 2004 capital expenditures were budgeted to be $440 million, but are
now projected to be $383.7 million. The lower level of capital
expenditures was primarily related to delays in certain transmission
projects as a result of appeals of decisions by the Connecticut Siting
Council (CSC) and other legal and regulatory delays. Further delays in
certain major projects could cause CL&P's actual capital spending to be
below this projection.
The level of financing activities for the six months ended June 30, 2004
included a capital contribution from NU in the amount of $23 million. CL&P
also paid $23.5 million in common dividends to NU during the first half of
2004 compared to $20 million during the same period in 2003.
At June 30, 2004, CL&P had $5 million in borrowings outstanding on the
Utility Group's $300 million revolving credit line. This credit line is
scheduled to mature in November 2004 and is expected to be renewed for at
least one year.
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 June 30, 2004, CL&P had sold
accounts receivable totaling $80 million to that financial institution.
For more information regarding the sale of receivables, see Note 1H,
"Summary of Significant Accounting Policies - Sale of Customer Receivables"
to the consolidated financial statements.
On June 23, 2004, the DPUC approved CL&P's request to issue up to $280
million of debt securities. CL&P expects to issue the debt later in 2004.
Proceeds will be used to repay short-term debt and to refinance a $59
million, 8.5 percent bond issuance that will be redeemed on August 10, 2004
at a call premium of 3.87 percent. At June 30, 2004, CL&P had $196.2
million in short-term debt outstanding from the NU Money Pool.
As part of the approved SMD settlement agreement, CL&P paid $83 million to
suppliers on July 8, 2004, and agreed to refund $75 million to its
customers. Of the combined payment and refund amount totaling $158
million, $31 million has not been funded into the restricted cash - LMP
costs account. Additionally, as part of the DPUC's final decision
regarding CL&P's CTA and SBC docket, the DPUC ordered a refund to CL&P's
customers of $88.5 million over a seven-month period beginning with October
2004 consumption. These refunds, when combined with CL&P's proposed
capital projects and previously ordered refunds of CTA and SBC amounts,
will negatively impact CL&P's liquidity. However, CL&P expects no
difficulty funding these additional requirements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
-------------- ---------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 3,464 $ 2,737
Special deposits - 30,104
Receivables, net 69,617 67,121
Accounts receivable from affiliated companies 14,691 11,291
Unbilled revenues 39,399 39,220
Fuel, materials and supplies, at average cost 59,737 54,533
Derivative assets 399 1,510
Prepayments and other 23,471 9,945
------------- ---------------
210,778 216,461
------------- ---------------
Property, Plant and Equipment:
Electric utility 1,577,562 1,517,513
Other 5,706 5,707
------------- ---------------
1,583,268 1,523,220
Less: Accumulated depreciation 650,884 635,029
------------- ---------------
932,384 888,191
Construction work in progress 37,900 37,401
------------- ---------------
970,284 925,592
------------- ---------------
Deferred Debits and Other Assets:
Regulatory assets 941,982 969,434
Other 58,788 60,324
------------- ---------------
1,000,770 1,029,758
------------- ---------------
Total Assets $ 2,181,832 $ 2,171,811
============= ===============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
-------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ - $ 10,000
Notes payable to affiliated companies 62,100 48,900
Accounts payable 44,407 48,408
Accounts payable to affiliated companies 23,861 13,911
Accrued taxes 16,720 2,543
Accrued interest 10,701 10,894
Unremitted rate reduction bond collections 10,435 11,051
Derivative liabilities - 1,414
Other 16,296 16,689
-------------- -------------
184,520 163,810
-------------- -------------
Rate Reduction Bonds 450,814 472,222
-------------- -------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 324,822 338,930
Accumulated deferred investment tax credits 1,861 2,096
Deferred contractual obligations 58,668 64,237
Regulatory liabilities 287,937 272,081
Accrued pension 50,677 44,766
Other 29,453 26,124
-------------- -------------
753,418 748,234
-------------- -------------
Capitalization:
Long-Term Debt 407,285 407,285
-------------- -------------
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 156,446 156,555
Retained earnings 229,483 223,822
Accumulated other comprehensive loss (134) (117)
-------------- -------------
Common Stockholder's Equity 385,795 380,260
-------------- -------------
Total Capitalization 793,080 787,545
-------------- -------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 2,181,832 $ 2,171,811
============== =============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
2004 2003 2004 2003
----------- ----------- ----------- ------------
Operating Revenues $ 226,448 $ 203,364 $ 470,596 $ 434,132
----------- ----------- ----------- ------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 99,960 99,065 202,002 210,565
Other 39,862 36,032 78,554 64,376
Maintenance 20,947 23,732 37,155 37,177
Depreciation 11,433 10,720 22,764 21,327
Amortization/(overrecovery) of regulatory assets, net 14,435 (13,419) 38,950 4,151
Amortization of rate reduction bonds 10,612 9,510 21,468 18,756
Taxes other than income taxes 8,965 8,056 17,985 16,729
---------- ----------- ------------ -----------
Total operating expenses 206,214 173,696 418,878 373,081
---------- ----------- ------------ -----------
Operating Income 20,234 29,668 51,718 61,051
Interest Expense:
Interest on long-term debt 3,934 3,853 7,941 7,700
Interest on rate reduction bonds 6,810 7,334 13,767 14,744
Other interest 293 365 605 612
---------- ----------- ----------- ------------
Interest expense, net 11,037 11,552 22,313 23,056
---------- ----------- ----------- -----------
Other Loss, Net (486) (1,173) (2,259) (2,384)
---------- ----------- ----------- -----------
Income Before Income Tax Expense 8,711 16,943 27,146 35,611
Income Tax Expense 2,686 5,889 9,361 13,730
---------- ----------- ----------- -----------
Net Income $ 6,025 $ 11,054 $ 17,785 $ 21,881
========== =========== =========== ===========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<Table>
<Caption>
Six Months Ended
June 30,
-------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating activities:
Net income $ 17,785 $ 21,881
Adjustments to reconcile to net cash flows
provided by/(used in) operating activities:
Depreciation 22,764 21,327
Deferred income taxes and investment tax credits, net (12,250) 3,179
Amortization/(overrecovery) of regulatory assets, net 38,950 4,151
Amortization of rate reduction bonds 21,468 18,756
Amortization of recoverable energy costs 11,694 11,694
Regulatory recoveries (8,107) 2,806
Other sources of cash 10,491 18,278
Other uses of cash (9,587) (23,785)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net (6,075) 11,341
Fuel, materials and supplies (5,204) 3,538
Other current assets (13,526) (30,795)
Accounts payable 5,949 (11,044)
Accrued taxes 14,177 (49,181)
Other current liabilities (1,231) (9,322)
---------- ----------
Net cash flows provided by/(used in) operating activities 87,298 (7,176)
---------- ----------
Investing Activities:
Investments in plant (56,536) (49,937)
NU system Money Pool borrowing 13,200 86,800
Buyout/buydown of IPP contracts - (20,437)
Payment for acquisition of CVEC (30,104) -
Other investment activities 30,519 10,364
---------- ----------
Net cash flows (used in)/provided by investing activities (42,921) 26,790
---------- ----------
Financing Activities:
Retirement of rate reduction bonds (21,408) (17,830)
Decrease in short-term debt (10,000) -
Cash dividends on common stock (12,124) (5,600)
Other financing activities (118) (98)
---------- ----------
Net cash flows used in financing activities (43,650) (23,528)
---------- ----------
Net increase/(decrease) in cash 727 (3,914)
Cash - beginning of period 2,737 5,319
---------- ----------
Cash - end of period $ 3,464 $ 1,405
========== ==========
</Table>
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 Quarter 2004 Form 10-Q, the NU 2003
Form 10-K, and the current report on Form 8-K dated July 14, 2004.
RESULTS OF OPERATIONS
The components of significant income statement variances for the second
quarter of 2004 and for the first six months of 2004 are provided in the
table below.
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Second Six
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues: $ 23 11% $ 36 8%
Operating Expenses:
Fuel, purchased and net
interchange power 1 1 (9) (4)
Other operation 4 11 14 22
Maintenance (3) (12) - -
Depreciation - - 1 7
Amortization/(overrecovery)
of regulatory assets, net 28 (a) 35 (a)
Amortization of rate
reduction bonds 1 12 3 14
Taxes other than income taxes 1 11 1 8
---- ---- ---- ----
Total operating expenses 32 19 45 12
---- ---- ---- ----
Operating income (9) (32) (9) (15)
---- ---- ---- ----
Interest expense, net - - (1) (3)
Other loss, net 1 59 - -
---- ---- ---- ----
Income before income tax expense (8) (49) (8) (24)
Income tax expense (3) (54) (4) (32)
---- ---- ---- ----
Net Income $ (5) (45)% $ (4) (19)%
==== ==== ==== ====
(a) Percent greater than 100.
Comparison of the Second Quarter of 2004 to the Second Quarter of 2003
Operating Revenues
Operating revenues increased $23 million in the second quarter of 2004, as
compared to the same period in 2003, primarily due to higher distribution
retail revenue ($21 million). Distribution retail revenue increased
primarily due to higher transition service energy revenue ($16 million) as
a result of a combination of increased transition service energy rates as
of February 2004 ($14 million) and higher sales volumes ($2 million),
higher stranded cost revenues ($4 million), and higher retail sales volumes
for the delivery component of rates ($2 million). Retail kilowatt-hour
(kWh) sales increased by 3.3 percent in 2004.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power increased $1 million primarily as
a result of higher retail sales.
Other Operation
Other operation expenses increased $4 million primarily due to higher
transmission expenses ($1 million), higher fossil steam expense ($1
million), and higher administrative expense ($1 million) primarily due to
higher pension costs.
Maintenance
Maintenance expense decreased $3 million primarily due to lower fossil
steam expenses ($4 million), mainly due to a higher level of fossil
production maintenance overhaul expenses in 2003, partially offset by
higher tree trimming expenses ($1 million).
Amortization/(Overrecovery) of Regulatory Assets, Net
Amortization/(overrecovery) of regulatory assets, net increased $28 million
primarily due to higher recovery of stranded and transition service energy
costs as compared to actual costs.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $1 million as a result of
the repayment of additional principal.
Other Loss, Net
Other loss, net decreased $1 million primarily due to a 2004 investment
gain recognized by Properties, Inc.
Income Tax Expense
Income tax expense decreased $3 million primarily due to lower book taxable
income.
Comparison of the First Six Months of 2004 to the First Six Months of 2003
Operating Revenues
Operating revenues increased $36 million in the first six months of 2004
compared with the same period of 2003, primarily due to higher distribution
retail revenue ($48 million), partially offset by lower wholesale revenue
($13 million). Distribution retail revenue increased primarily due to
higher transition service energy revenue ($36 million) as a result of a
combination of increased transition service energy rates as of February
2004 ($27 million) and higher sales volumes ($9 million), higher stranded
cost revenues ($9 million), and higher retail sales volumes for the
delivery component of rates ($5 million). Retail kWh sales increased by
5.1 percent in 2004. The regulated wholesale revenue decrease is primarily
due to a lower number of wholesale transactions in the first quarter of
2004.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power decreased $9 million primarily as
a result of lower regulated energy and capacity purchases.
Other Operation
Other operation expenses increased $14 million primarily due to higher
transmission expenses ($4 million), higher fossil steam expense ($3
million), and higher administrative expenses ($5 million) primarily due to
higher pension costs.
Amortization/(Overrecovery) of Regulatory Assets, Net
Amortization/(overrecovery) of regulatory assets, net increased $35 million
primarily due to higher recovery of stranded and transition service energy
costs as compared to actual 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 $4 million primarily due to lower book taxable
income.
LIQUIDITY
PSNH's net cash flows provided by operating activities totaled $87.3
million for the six months ended June 30, 2004, compared with net cash
flows used in operating activities of $7.2 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 amortization of
regulatory assets. Accrued taxes decreased in 2003 due to the payment of
taxes on the gain on the sale of Seabrook. Amortization of regulatory
assets increased in the first six months of 2004 primarily due to higher
recovery of stranded and transition service energy costs.
There was a higher level of investing activities in the first six months of
2004 primarily due to an increase in capital expenditures offset by a lower
level of borrowings from the NU Money Pool.
PSNH's capital expenditures totaled $56.5 million for the six months ended
June 30, 2004 compared to $49.9 million in the same period of 2003. PSNH's
2004 capital expenditures were budgeted to be $160 million, but are now
projected to be $152.4 million.
There was also a higher level of financing activities during the first six
months of 2004 primarily due to a decrease in short-term debt. PSNH also
paid $12.1 million in dividends to NU in the first half of 2004 compared to
$5.6 million for the same period of 2003. PSNH did not pay dividends to NU
during the first quarter of 2003.
At June 30, 2004, PSNH had no borrowings outstanding on the Utility Group's
$300 million revolving credit line. This credit line is scheduled to
mature in November 2004 and is expected to be renewed for at least one
year.
On July 22, 2004, PSNH issued $50 million of first mortgage bonds at a
fixed interest rate of 5.25 percent. Proceeds were used to pay down short-
term debt and fund PSNH's capital expenditure program. At June 30, 2004,
PSNH had $62.1 million in short-term debt outstanding from the NU Money
Pool.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
-------------- --------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 1 $ 1
Unrestricted cash from affiliated counterparty 10,750 -
Receivables, net 35,087 40,103
Accounts receivable from affiliated companies 9,640 20
Unbilled revenues 14,953 10,299
Materials and supplies, at average cost 1,661 1,584
Prepayments and other 793 1,139
---------------- ----------------
72,885 53,146
---------------- ----------------
Property, Plant and Equipment:
Electric utility 623,293 612,450
Less: Accumulated depreciation 182,498 177,803
---------------- ----------------
440,795 434,647
Construction work in progress 17,083 13,124
---------------- ----------------
457,878 447,771
---------------- ----------------
Deferred Debits and Other Assets:
Regulatory assets 250,118 268,180
Prepaid pension 77,623 75,386
Other 18,784 19,081
---------------- ----------------
346,525 362,647
---------------- ----------------
Total Assets $ 877,288 $ 863,564
================ ================
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
June 30, December 31,
2004 2003
---------------- -----------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ - $ 10,000
Notes payable to affiliated companies 24,300 31,400
Accounts payable 25,283 10,173
Accounts payable to affiliated companies 10,776 13,789
Accrued taxes 6,034 765
Accrued interest 2,696 2,544
Other 21,043 9,785
---------------- ----------------
90,132 78,456
---------------- ----------------
Rate Reduction Bonds 127,628 132,960
---------------- ----------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 216,032 216,547
Accumulated deferred investment tax credits 3,158 3,326
Deferred contractual obligations 81,175 86,937
Regulatory liabilities 31,551 27,776
Other 7,822 8,357
---------------- ----------------
339,738 342,943
---------------- ----------------
Capitalization:
Long-Term Debt 157,454 157,202
---------------- ----------------
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 75,996 69,544
Retained earnings 75,561 71,677
Accumulated other comprehensive loss (87) (84)
---------------- ----------------
Common Stockholder's Equity 162,336 152,003
---------------- ----------------
Total Capitalization 319,790 309,205
---------------- ----------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 877,288 $ 863,564
================ ================
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<Table>
<Caption>
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Operating Revenues $ 92,056 $ 89,665 $ 189,978 $ 194,451
---------- ----------- ---------- -----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 49,540 45,164 106,151 98,167
Other 15,112 13,771 28,972 27,541
Maintenance 3,787 3,459 7,136 6,593
Depreciation 3,732 3,515 7,419 6,986
Amortization of regulatory assets, net 3,730 10,646 8,285 23,094
Amortization of rate reduction bonds 2,596 2,459 5,277 4,928
Taxes other than income taxes 2,990 2,837 6,122 5,809
---------- ----------- ---------- -----------
Total operating expenses 81,487 81,851 169,362 173,118
---------- ----------- ---------- -----------
Operating Income 10,569 7,814 20,616 21,333
Interest Expense:
Interest on long-term debt 1,482 744 2,945 1,536
Interest on rate reduction bonds 2,105 2,267 4,254 4,575
Other interest 194 345 431 721
---------- ----------- ---------- -----------
Interest expense, net 3,781 3,356 7,630 6,832
---------- ----------- ---------- -----------
Other Loss, Net (637) (222) (918) (227)
---------- ----------- ---------- -----------
Income Before Income Tax Expense 6,151 4,236 12,068 14,274
Income Tax Expense 2,571 1,650 4,942 5,620
---------- ----------- ---------- -----------
Net Income $ 3,580 $ 2,586 $ 7,126 $ 8,654
========== =========== ========== ===========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<Table>
<Caption>
Six Months Ended
June 30,
-------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating Activities:
Net income $ 7,126 $ 8,654
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 7,419 6,986
Deferred income taxes and investment tax credits, net (2,221) (9,841)
Amortization of regulatory assets, net 8,285 23,094
Amortization of rate reduction bonds 5,277 4,928
Amortization of recoverable energy costs 298 299
Increase in prepaid pension (2,237) (3,740)
Regulatory overrecoveries 7,977 4,120
Other sources of cash 1,790 291
Other uses of cash (7,664) (6,742)
Changes in current assets and liabilities:
Unrestricted cash from affiliated counterparty (10,750) -
Receivables and unbilled revenues, net (9,258) (89)
Materials and supplies (77) (519)
Other current assets 346 470
Accounts payable 12,097 10,140
Accrued taxes 5,269 126
Other current liabilities 11,409 674
----------- -----------
Net cash flows provided by operating activities 35,086 38,851
----------- -----------
Investing Activities:
Investments in plant (16,627) (12,201)
NU system Money Pool lending (7,100) (6,500)
Other investment activities 734 (279)
----------- -----------
Net cash flows used in investing activities (22,993) (18,980)
----------- -----------
Financing Activities:
Retirement of rate reduction bonds (5,332) (4,973)
Decrease in short-term debt (10,000) (7,000)
Capital contribution from Northeast Utilities 6,500 -
Cash dividends on common stock (3,242) (8,006)
Other financing activities (19) (14)
----------- -----------
Net cash flows used in financing activities (12,093) (19,993)
----------- -----------
Net decrease in cash - (122)
Cash - beginning of period 1 123
----------- -----------
Cash - end of period $ 1 $ 1
=========== ===========
</Table>
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 Quarter 2004 Form 10-Q, and the NU
2003 Form 10-K.
RESULTS OF OPERATIONS
The components of significant income statement variances for the second
quarter of 2004 and the first six months of 2004 are provided in the table
below.
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Second Six
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues: $ 2 3% $ (5) (2)%
Operating Expenses:
Fuel, purchased and net
interchange power 5 10 8 8
Other operation 1 10 1 5
Maintenance - - 1 8
Depreciation - - 1 6
Amortization of
regulatory assets, net (7) (65) (15) (64)
Amortization of rate
reduction bonds - - - -
Taxes other than income taxes - - - -
---- ---- ---- ----
Total operating expenses (1) - (4) (2)
---- ---- ---- ----
Operating income 3 35 (1) (3)
---- ---- ---- ----
Interest expense, net 1 13 1 12
Other loss, net - - - -
---- ---- ---- ----
Income before income tax expense 2 45 (2) (15)
Income tax expense 1 56 - -
---- ---- ---- ----
Net Income $ 1 38% $ (2) (18)%
==== ==== ==== ====
Comparison of the Second Quarter of 2004 to the Second Quarter of 2003
Operating Revenues
Operating revenues increased $2 million in the first quarter of 2004, as
compared to the same period in 2003, primarily due to higher retail revenue
($3 million), partially offset by lower wholesale revenue ($1 million).
Retail revenue increased primarily due to higher retail sales volumes.
Retail kWh sales increased by 8.2 percent in 2004. Higher standard offer
service revenues ($5 million) were equally offset by a reduction in
transition charge revenues ($5 million) due to rate changes. 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 $5 million
primarily due to higher standard offer supply costs.
Other Operation
Other operation increased $1 million primarily due to higher pension 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.
Income Tax Expense
Income tax expense increased $1 million primarily due to higher book
taxable income.
Comparison of the First Six Months of 2004 to the First Six Months of 2003
Operating Revenues
Operating revenues decreased $5 million in the first six months of 2004
compared with the same period of 2003, primarily due to lower wholesale and
other revenue ($6 million), partially offset by higher retail revenues ($1
million). Wholesale revenues were lower primarily due to a lower number of
wholesale transactions. Retail revenue increased primarily due to higher
retail sales volumes. Retail kWh sales increased by 3.3 percent in 2004.
An increase in standard offer service revenues ($12 million) was offset by
a decrease in the transition charge rate ($11 million).
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $8 million
primarily due to higher standard offer supply costs.
Other Operation
Other operation increased $1 million primarily due to higher pension costs
($2 million), partially offset by lower transmission expenses.
Maintenance
Maintenance expense increased $1 million primarily due to higher tree
trimming expenses.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $15 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.
LIQUIDITY
WMECO's net cash flows provided by operating activities decreased to $35.1
million for the first six months of 2004 from $38.9 million for the same
period of 2003. Net cash flows provided by operating activities decreased
primarily due to decreases in accounts receivable and amortization of
regulatory assets, partially offset by an increase in other current
liabilities. Amortization of regulatory assets decreased in the first six
months of 2004 primarily due to the lower recovery of stranded costs as a
result of the decrease in the transition component of retail rates. The
increase in other current liabilities in the first six months of 2004 is
primarily due to cash collateral received from Select Energy.
WMECO's net cash flows used in investing activities were $23 million for
the six months ended June 30, 2004, compared with $19 million for the same
period of 2003. The higher level of investing activities is primarily due
to higher capital expenditures during the first six months of 2004.
WMECO's capital expenditures totaled $16.6 million for the six months ended
June 30, 2004 compared to $12.2 million for the same period of 2003.
WMECO paid $3.2 million in dividends to NU in the first half of 2004
compared to $8 million for the same period of 2003. WMECO also received a
capital contribution from NU in the amount of $6.5 million during the six
months ended June 30, 2004.
At June 30, 2004, WMECO had no borrowings outstanding on the Utility
Group's $300 million revolving credit line. This credit line is scheduled
to mature in November 2004 and is expected to be renewed for at least one
year.
On July 19, 2004, the DTE issued an order approving WMECO's financing of
its prior spent nuclear fuel liability through the issuance of up to $52
million in debt. WMECO plans to issue this debt by the end of 2004.
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 June 30, 2004, a 10 percent
change in market price would have resulted in an increase in fair value of
$24.6 million or a decrease in fair value of $22.7 million.
The impact of a change in electricity, natural gas and oil prices on Select
Energy's wholesale and retail marketing portfolio at June 30, 2004, is not
necessarily representative of the results that will be realized when these
contracts are physically delivered.
NU Enterprises - Trading Contracts: At June 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 $0.7
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 June 30, 2004, approximately 83
percent (72 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 $4.4 million. At
June 30, 2004, NU parent maintained a fixed-to-floating interest rate swap
to manage the interest rate risk associated 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 their 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
positively or negatively, in that the counterparties may be similarly
affected by changes to economic, regulatory or other conditions.
At June 30, 2004 and December 31, 2003, Select Energy maintained collateral
balances from counterparties of $105 million and $46.5 million,
respectively. These amounts are included in both unrestricted cash from
counterparties and other current liabilities on the accompanying
consolidated balance sheets.
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 risk such as 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. CONTROLS AND PROCEDURES
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 June 30, 2004 that have
materially affected, or are reasonably likely to materially affect the
companies' internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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
e 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 repudiation 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, leaving intact NU's claim for breach of
the Merger and 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 determination 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. Further action by the Second Circuit
is expected later this summer.
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 Atomic Power Company Decommissioning Dispute
On June 13, 2003, the Connecticut Yankee Atomic Power Company (CYAPC) gave
notice of termination of its contract with Bechtel for the decommissioning
of the Connecticut Yankee nuclear power plant. CYAPC terminated the
contract due to Bechtel's history of incomplete and untimely performance
and refusal to perform remaining decommissioning work.
On June 23, 2003, Bechtel filed a complaint against CYAPC in Connecticut
Superior Court in Middletown, Connecticut. Bechtel seeks a number of
remedies, including money damages, rescission of the contract and the
reasonable value of the work performed to date, attorneys' fees and
punitive damages. On August 22, 2003, CYAPC filed its answer and
counterclaims; the case has been assigned to the complex litigation docket
and discovery is ongoing. A hearing date of August 26, 2004 has been set.
On June 18, 2004, Bechtel initiated notice that it intends to seek from the
court a prejudgment remedy in the amount of $93.5 million by garnishing
CYAPC's assets, the CYAPC's shareholders' contributions to the
decommissioning trust and proceeds of litigation. On July 16, 2004, CYAPC
filed its objection to the motion. A hearing date has not yet been set.
On July 1, 2004, CYAPC filed with the FERC to increase its decommissioning
collections from $16.7 million per year to $93 million per year for the six-
year period beginning January 1, 2005.
For further information relating to the dispute with Bechtel, see Part I,
Item 3, "Legal Proceedings" in NU's 2003 Form 10-K. For further
information relating to decommissioning collections, See Part I, Item 1,
"Business - Nuclear Generation - Decommissioning" in NU's 2003 Form 10-K.
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 June 30, 2004.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Annual Meeting of Shareholders of NU held on May 11, 2004 the
following eleven nominees were elected to serve on the Board of Trustees by
the votes set forth below:
For Withheld Total
1. Richard H. Booth 106,388,501 2,103,147 108,491,648
2. Cotton M. Cleveland 103,622,056 4,869,592 108,491,648
3. Sanford Cloud, Jr. 106,346,006 2,145,642 108,491,648
4. James F. Cordes 106,448,281 2,043,367 108,491,648
5. E. Gail de Planque 106,210,616 2,281,032 108,491,648
6. John H. Forsgren 103,651,100 4,840,548 108,491,648
7. John G. Graham 106,477,215 2,014,433 108,491,648
8. Elizabeth T. Kennan 103,350,481 5,141,167 108,491,648
9. Robert E. Patricelli 103,584,021 4,907,627 108,491,648
10. Charles W. Shivery 103,598,864 4,892,784 108,491,648
11. John F. Swope 103,528,979 4,962,669 108,491,648
NU's shareholders also ratified the Board of Trustees' selection of
Deloitte & Touche LLP to serve as independent auditors of NU and its
subsidiaries for 2004. The vote ratifying such selection was 107,361,178
votes in favor and 597,888 votes against, with 532,582 abstentions.
CL&P. In a written Consent in Lieu of an Annual Meeting of Stockholders of
CL&P (Consent) dated June 28, 2004, stockholders voted to fix the number of
directors for the ensuing year at three. The vote fixing the number of
directors at three was 6,035,205 shares in favor, representing 100 percent
of the issued and outstanding shares of common stock of CL&P. Through the
Consent, the following three directors were elected, each by a vote of
6,035,205 shares in favor, to serve on the Board of Directors for the
ensuing year: David H. Boguslawski, Cheryl W. Grise, and Leon J. Olivier.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Listing of Exhibits (NU)
Exhibit No. Description
----------- -----------
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 August 6, 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 August 6, 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 August 6, 2004
(a) Listing of Exhibits (CL&P)
31 Certification of Cheryl W. Grise, Chief Executive
Officer of The Connecticut Light and Power Company, as
adopted pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002, dated August 6, 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 August 6, 2004
32 Certification of Cheryl W. Grise, 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 August 6, 2004
(a) Listing of Exhibits (PSNH)
31 Certification of Cheryl W. Grise, Chief Executive
Officer of Public Service Company of New Hampshire, as
adopted pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002, dated August 6, 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
August 6, 2004
32 Certification of Cheryl W. Grise, 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 August 6, 2004
(a) Listing of Exhibits (WMECO)
31 Certification of Cheryl W. Grise, Chief Executive Officer
of Western Massachusetts Electric Company, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002,
dated August 6, 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
August 6, 2004
32 Certification of Cheryl W. Grise, 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 August 6, 2004
(b) Reports on Form 8-K:
NU filed a current report on Form 8-K dated May 19, 2004 disclosing:
o The issuance of a news release relating to a decision by the court
hearing its merger litigation with Con Edison.
NU and PSNH filed current reports on Form 8-K dated July 14, 2004
disclosing:
o The filing with the NHPUC of a settlement among several parties with
regards to its delivery service rate case.
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: August 6, 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: August 6, 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: August 6, 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: August 6, 2004 By /s/ John H. Forsgren
-------------- ---------------------------------------
John H. Forsgren
Executive Vice President
and Chief Financial Officer
(for the Registrant and as
Principal Financial Officer)