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 September 30, 2003
------------------March 31, 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)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
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)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
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 October 31, 2003April 30, 2004
- ------------------------ ------------------------------------------------------------
Northeast Utilities
Common shares, $5.00 par value 127,369,219127,981,582 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 throughoutin this report:
NU COMPANIES OR SEGMENTS
Boulos....................... E.S. Boulos Company
CL&P.........................&P.......................... The Connecticut Light and Power Company
CRC..........................CRC........................... CL&P Receivables Corporation
HWP..........................HWP........................... Holyoke Water Power Company
NGC..........................NGC........................... Northeast Generation Company
NGS..........................NGS........................... Northeast Generation Services Company
NU or the company............company............. Northeast Utilities
NU Enterprises...............Enterprises................ NU's competitive subsidiaries comprised of
Select Energy, NGC, SESI, NGS, HWP, and Woods
Network. For further information, see Note 7,8,
"Segment Information," to the consolidated
financial statements.
PSNH.........................PSNH.......................... Public Service Company of New Hampshire
RMS..........................RMS........................... R. M. Services, Inc.
Select Energy................Energy................. Select Energy, Inc. (including its wholly owned
subsidiary SENY)
SENY.........................SENY.......................... Select Energy New York, Inc.
SESI.........................SESI.......................... Select Energy Services, Inc.
Utility Group................Group................. NU's regulated utilities comprised of CL&P,
PSNH, WMECO, and Yankee Gas. For further
information, see Note 7,8, "Segment Information,"
to the consolidated financial statements.
WMECO........................WMECO......................... Western Massachusetts Electric Company
Woods Network................Network................. Woods Network Services, Inc.
Yankee.......................Yankee........................ Yankee Energy System, Inc.
Yankee Gas...................Gas.................... Yankee Gas Services Company
THIRD PARTIES
Bechtel......................Bechtel....................... Bechtel Power Corporation
CVEC......................... Connecticut Valley Electric Company
CYAPC........................CYAPC......................... Connecticut Yankee Atomic Power Company
MGT.......................... Meriden Gas Turbines, LLC
NRG..........................NRG........................... NRG Energy, Inc.
NRG-PM....................... NRG Power Marketing, Inc.
REGULATORS
DPUC.........................CSC........................... Connecticut Siting Council
DPUC.......................... Connecticut Department of
Public Utility Control
DTE..........................DTE........................... Massachusetts Department of
Telecommunications and Energy
FERC.........................FERC.......................... Federal Energy Regulatory Commission
NHPUC........................NHPUC......................... New Hampshire Public Utilities Commission
SEC..........................SEC........................... Securities and Exchange Commission
OTHER
ABO.......................... Accumulated Benefit Obligation
Act, the.....................the...................... Public Act No. 03-135
C&LM......................... Conservation and Load Management
CSC.......................... Connecticut Siting Council
CTA..........................CTA........................... Competitive Transition Assessment
DE........................... Delivery Efficiency
DIG.......................... Derivative Implementation Group
EITF......................... Emerging Issues Task Force
EPS..........................EPS........................... Earnings per Share
FASB.........................FASB.......................... Financial Accounting Standards Board
FIN..........................FIN........................... FASB Interpretation
Fitch........................ Fitch Ratings
FMCC.........................FMCC.......................... Federally Mandated Congestion Costs
GSC..........................FSP........................... FASB Staff Position
GSC........................... Generation Service Charge
IERM.........................IERM.......................... Infrastructure Expansion Rate Mechanism
Incentive Plan...............Plan................ Northeast Utilities Incentive Plan
ISO-NE.......................ISO-NE........................ New England Independent System Operator
kWh..........................kWh........................... Kilowatt-hour
LMP..........................LMP........................... Locational Marginal Pricing
MW...........................LOCs.......................... Letters of Credit
MW............................ Megawatts
NU 20022003 Form 10-K............10-K............. The Northeast Utilities and Subsidiaries
combined 20022003 Form 10-K as filed with the SEC
NYMEX........................NYMEX......................... New York Mercantile Exchange
O&M.......................... Operation and Maintenance
Restructuring
Settlement.................Settlement.................. "Agreement to Settle PSNH Restructuring"
RMR.......................... Reliability Must Run
SBC..........................ROE........................... Return on Equity
RTO........................... Regional Transmission Organization
S&P........................... Standard & Poor's
SBC........................... System Benefits Charge
SCRC.........................SCRC.......................... Stranded Cost Recovery Charge
SFAS.........................SFAS.......................... Statement of Financial Accounting Standards
SMD..........................SMD........................... Standard Market Design
TSO..........................TSO........................... Transitional Standard Offer
VIE..........................VIE........................... Variable Interest Entity
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
(Unaudited)
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 - September 30, 2003(Unaudited)
March 31, 2004 and December 31, 2002...............2003................. 2
Consolidated Statements of Income - (Unaudited)
Three Months Ended March 31, 2004 and Nine Months Ended
September 30, 2003 and 2002............................2003........... 4
Consolidated Statements of Cash Flows - Nine(Unaudited)
Three Months Ended September 30, 2003March 31, 2004 and 2002..........2003........... 5
Management's Discussion and Analysis of
Financial Condition and Results of Operations..........Operations........ 6
Independent Accountants' Report............................. 39Report........................... 25
Notes to Consolidated Financial Statements
(unaudited - all companies).................................. 40............................... 26
The Connecticut Light and Power Company
and Subsidiaries
Consolidated Balance Sheets - September 30, 2003(Unaudited)
March 31, 2004 and December 31, 2002............... 682003................. 52
Consolidated Statements of Income - (Unaudited)
Three Months Ended March 31, 2004 and Nine Months Ended
September 30, 2003 and 2002............................ 702003........... 54
Consolidated Statements of Cash Flows - Nine(Unaudited)
Three Months Ended September 30, 2003March 31, 2004 and 2002.......... 712003........... 55
Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 72Operations........ 56
Public Service Company of New Hampshire
and Subsidiaries
Consolidated Balance Sheets - September 30, 2003(Unaudited)
March 31, 2004 and December 31, 2002............... 782003................. 60
Consolidated Statements of Income - (Unaudited)
Three Months Ended March 31, 2004 and Nine Months Ended
September 30, 2003 and 2002............................ 802003........... 62
Consolidated Statements of Cash Flows - Nine(Unaudited)
Three Months Ended September 30, 2003March 31, 2004 and 2002.......... 812003........... 63
Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 82Operations........ 64
Western Massachusetts Electric Company
and Subsidiary
Consolidated Balance Sheets - September 30, 2003(Unaudited)
March 31, 2004 and December 31, 2002............... 882003................. 68
Consolidated Statements of Income - (Unaudited)
Three Months Ended March 31, 2004 and Nine Months Ended
September 30, 2003 and 2002............................ 902003........... 70
Consolidated Statements of Cash Flows - Nine(Unaudited)
Three Months Ended September 30, 2003March 31, 2004 and 2002.......... 912003........... 71
Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 92Operations........ 72
Item 3. Quantitative and Qualitative
Disclosures About Market Risk.......................... 95Risk........................ 74
Item 4. Controls and Procedures................................ 95Procedures.............................. 76
Part II. Other Information
Item 1. Legal Proceedings...................................... 96Proceedings.................................... 77
Item 2. Changes in Securities, Use of Proceeds
and Issuer Purchases of Equity Securities............ 78
Item 6. Exhibits and Reports on Form 8-K....................... 99
Signatures............................................................ 1028-K..................... 79
Signatures.......................................................... 82
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,March 31, December 31,
2004 2003
2002
--------------- ----------------------------- --------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 118,13876,050 $ 54,67837,196
Unrestricted cash from counterparties 70,905 46,496
Restricted cash - LMP costs 45,760 -123,681 93,630
Special deposits 75,657 43,26135,477 79,120
Investments in securitizable assets 215,592 178,908186,821 166,465
Receivables, net 637,039 767,089727,378 704,893
Unbilled revenues 95,498 126,236117,121 125,881
Fuel, materials and supplies, at average cost 160,400 119,853122,487 154,076
Derivative assets 103,768 130,929426,660 301,194
Prepayments and other 81,556 110,26157,413 63,780
--------------- ---------------
1,533,408 1,531,2151,943,993 1,772,731
--------------- ---------------
Property, Plant and Equipment:
Electric utility 5,360,649 5,141,9515,556,220 5,465,854
Gas utility 708,986 679,055757,869 743,990
Competitive energy 886,478 866,294888,700 885,953
Other 209,040 205,115224,972 221,986
--------------- ---------------
7,165,153 6,892,4157,427,761 7,317,783
Less: Accumulated depreciation 2,564,544 2,484,6132,283,625 2,244,263
--------------- ---------------
4,600,609 4,407,8025,144,136 5,073,520
Construction work in progress 374,691 320,567375,262 356,396
--------------- ---------------
4,975,300 4,728,3695,519,398 5,429,916
--------------- ---------------
Deferred Debits and Other Assets:
Regulatory assets 2,947,670 3,076,0952,921,973 2,974,022
Goodwill and other purchased319,986 319,986
Purchased intangible assets, net 343,904 345,86722,054 22,956
Prepaid pension 352,668 328,890359,982 360,706
Other 445,418 433,444451,364 428,567
--------------- ---------------
4,089,660 4,184,2964,075,359 4,106,237
--------------- ---------------
Total Assets $ 10,598,36811,538,750 $ 10,443,88011,308,884
=============== ===============
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,March 31, December 31,
2004 2003
2002
--------------- ----------------------------- --------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ 40,00010,000 $ 56,000105,000
Long-term debt - current portion 59,327 56,90667,676 64,936
Accounts payable 787,024 776,219839,865 768,783
Accrued taxes 68,816 141,66766,192 51,598
Accrued interest 57,820 40,59758,123 41,653
Derivative liabilities 65,866 63,900228,510 164,689
Other 205,501 208,680
----------------238,975 249,576
--------------- 1,284,354 1,343,969---------------
1,509,341 1,446,235
--------------- ---------------
Rate Reduction Bonds 1,772,637 1,899,3121,682,500 1,729,960
--------------- ---------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,362,713 1,436,5071,313,425 1,287,354
Accumulated deferred investment tax credits 103,607 106,471101,714 102,652
Deferred contractual obligations 321,197 354,469455,995 469,218
Regulatory liabilities 1,218,243 1,164,288
Other 878,146 689,287243,239 247,526
--------------- ---------------
2,665,663 2,586,7343,332,616 3,271,038
--------------- ---------------
Capitalization:
Long-Term Debt 2,505,222 2,287,1442,564,737 2,481,331
--------------- ---------------
Preferred Stock of Subsidiaries - NonredeemableNon-Redeemable 116,200 116,200
--------------- ---------------
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 150,098,023150,562,489 shares issued
and 127,254,402127,942,036 shares outstanding in 2004 and
150,398,403 shares issued and 127,695,999 shares
outstanding in 2003 and
149,375,847 shares issued and 127,562,031 shares
outstanding in 2002 750,492 746,879752,812 751,992
Capital surplus, paid in 1,106,466 1,108,3381,110,094 1,108,924
Deferred contribution plan - employee stock
ownership plan (76,970) (87,746)(70,665) (73,694)
Retained earnings 837,963 765,611857,197 808,932
Accumulated other comprehensive (loss)/income (2,862) 14,92742,857 25,991
Treasury stock, 19,566,929 shares in 2004
and 19,518,023 shares in 2003 and 18,022,415 shares in 2002 (360,797) (337,488)(358,939) (358,025)
--------------- ---------------
Common Shareholders' Equity 2,254,292 2,210,5212,333,356 2,264,120
--------------- ---------------
Total Capitalization 4,875,714 4,613,8655,014,293 4,861,651
--------------- ---------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 10,598,36811,538,750 $ 10,443,88011,308,884
=============== ===============
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
Nine Months Ended
September 30, September 30,
-------------------------------- ------------------------------March 31,
---------------------------------
2004 2003 2002 2003 2002
---------------
-------------- --------------
-------------(Thousands of Dollars,
except share information)
Operating Revenues $ 2,054,2741,838,287 $ 1,414,304 $ 5,200,252 $ 3,840,693
------------- --------------1,584,183
-------------- --------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 1,445,482 850,757 3,408,712 2,204,4341,176,215 965,041
Other 224,606 184,110 645,156 580,865227,621 189,272
Maintenance 55,687 68,271 169,859 194,03257,211 45,892
Depreciation 50,879 50,946 151,044 156,75754,573 49,473
Amortization 53,995 59,160 132,791 85,11429,291 57,299
Amortization of rate reduction bonds 40,729 35,380 115,232 116,01642,999 39,200
Taxes other than income taxes 53,169 47,585 178,603 177,043
------------- --------------77,589 73,974
-------------- --------------
Total operating expenses 1,924,547 1,296,209 4,801,397 3,514,261
------------- --------------1,665,499 1,420,151
-------------- --------------
Operating Income 129,727 118,095 398,855 326,432172,788 164,032
Interest Expense:
Interest on long-term debt 32,010 34,137 93,496 101,50032,738 32,940
Interest on rate reduction bonds 26,863 28,751 82,088 87,53925,695 27,861
Other interest 4,474 4,825 10,835 14,569
------------- --------------4,347 2,744
-------------- --------------
Interest expense, net 63,347 67,713 186,419 203,608
------------- --------------62,780 63,545
-------------- --------------
Other Income, Net 4,678 32,059 6,008 19,715
------------- --------------1,687 576
-------------- --------------
Income Before Income Tax Expense 71,058 82,441 218,444 142,539111,695 101,063
Income Tax Expense 25,689 32,476 83,223 42,296
------------- --------------42,863 39,469
-------------- --------------
Income Before Preferred Dividends of Subsidiaries 45,369 49,965 135,221 100,24368,832 61,594
Preferred Dividends of Subsidiaries 1,390 1,390
4,169 4,169
------------- -------------- -------------- --------------
Income Before Cumulative Effect of Accounting Change 43,979 48,575 131,052 96,074
Cumulative effect of accounting change,
net of tax benefit of $2,553 (4,741) - (4,741) -
------------- -------------- -------------- --------------
Net Income $ 39,23867,442 $ 48,575 $ 126,311 $ 96,074
============= ==============60,204
============== ==============
Basic and Fully Diluted Earnings Per Common Share:
Income Before Cumulative Effect of Accounting Change $ 0.35 $ 0.38 $ 1.03 $ 0.74
Cumulative effect of accounting change,
net of tax benefit (0.04) - (0.04) -
------------- -------------- -------------- --------------
Basic and Fully Diluted Earnings Per Common Share $ 0.310.53 $ 0.38 $ 0.99 $ 0.74
============= ==============0.47
============== ==============
Basic Common Shares Outstanding (average) 127,167,690 129,344,724 126,976,161 129,508,840
============= ==============127,879,766 127,013,678
============== ==============
Fully Diluted Common Shares Outstanding (average) 127,303,973 129,508,794 127,086,417 129,737,249
=============128,061,086 127,111,272
============== ============== ==============
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
NineThree Months Ended
September 30,
------------------------------March 31,
-------------------------------
2004 2003
2002
------------- -------------------------
(Thousands of Dollars)
Operating Activities:
Income before preferred dividends of subsidiaries $ 135,22168,832 $ 100,24361,594
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 151,044 156,75754,573 49,473
Deferred income taxes and investment tax credits, net (48,815) (54,207)20,028 (22,468)
Amortization 132,791 85,11429,291 57,299
Amortization of rate reduction bonds 115,232 116,016
(Deferral)/amortization42,999 39,200
Amortization of recoverable energy costs (5,480) 19,557
Prepaid10,189 6,269
Increase/(decrease) in prepaid pension (23,778) (55,436)
Cumulative effect of an accounting change (4,741) -724 (7,650)
Regulatory recoveries 117,138 48,915overrecoveries 13,670 54,301
Other sources of cash 14,911 73,2419,884 9,737
Other uses of cash (122,284) (57,044)(42,504) (46,365)
Changes in current assets and liabilities:
Restricted cash - LMP costs (45,760)(30,051) -
Unrestricted cash from counterparties (24,409) (17,936)
Receivables and unbilled revenues, net 160,789 29,223(13,725) 74,564
Fuel, materials and supplies (40,548) (23,285)
Accounts payable 10,805 (52,846)
Accrued taxes (72,851) 23,75431,589 8,622
Investments in securitizable assets (36,684) 49,570(20,356) 23,149
Other current assets and(67,493) (87,989)
Accounts payable 71,082 (88,484)
Accrued taxes 14,594 (56,908)
Other current liabilities (excludes cash) 25,686 12,678
---------- ----------87,245 69,338
------------- ------------
Net cash flows provided by operating activities 462,676 472,250
---------- ----------256,162 125,746
------------- ------------
Investing Activities:
Investments in plant:
Electric, gas and other utility plant (372,854) (308,757)(132,073) (91,808)
Competitive energy assets (13,144) (18,128)
Nuclear fuel - (434)
---------- ----------(5,697) (4,984)
------------- ------------
Cash flows used for investments in plant (385,998) (327,319)
Buyout/buydown of IPP contracts (20,437) (5,152)
Payment for acquisitions, net of cash acquired - (15,300)(137,770) (96,792)
Other investment activities net 8,777 6,957
---------- ----------6,087 6,571
------------- ------------
Net cash flows used in investing activities (397,658) (340,814)
---------- ----------(131,683) (90,221)
------------- ------------
Financing Activities:
Issuance of common shares 9,940 7,4452,522 6,979
Repurchase of common shares (915) (23,209) (30,136)
Issuance of long-term debt 250,384 263,000
Issuance of rate reduction bonds - 50,00082,438 44,338
Retirement of rate reduction bonds (126,374) (132,883)
Net (decrease)(47,460) (42,901)
(Decrease)/increase in short-term debt (16,000) 25,233(95,000) 39,000
Reacquisitions and retirements of long-term debt (33,607) (285,146)(6,405) (14,324)
Cash dividends on preferred stock (4,169) (4,169)of subsidiaries (1,390) (1,390)
Cash dividends on common shares (53,959) (50,164)(19,177) (17,469)
Other financing activities net (4,564) (548)
---------- ----------(238) (204)
------------- ------------
Net cash flows used in financing activities (1,558) (157,368)
---------- ----------(85,625) (9,180)
------------- ------------
Net increase/(decrease)increase in cash and cash equivalents 63,460 (25,932)38,854 26,345
Cash and cash equivalents - beginning of period 37,196 54,678
96,658
---------- ----------------------- ------------
Cash and cash equivalents - end of period $ 118,13876,050 $ 70,726
========== ==========
81,023
============= ============
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
This discussion should be read in conjunction with the consolidated
financial statements and footnotes in this Form 10-Q, the first and second quarter 2003current reports on
Form 10-Q8-K dated January 22, 2004 and March 30, 2004, and the NU 20022003 Form
10-K.
FINANCIAL CONDITION
Overview
- --------
Consolidated: Northeast Utilities (NU or the company) earned $44 million, or
$0.35 per share in the third quarter of 2003, before the cumulative effect of
accounting change, compared with $48.6 million, or $0.38 per share, in the
third quarter of 2002. After the cumulative effect of an accounting change,
NU earned $39.2 million, or $0.31 a share, in the third quarter of 2003.
Third quarter 2003 results included a negative $4.7 million after-tax
cumulative effect of accounting change as a result of the adoption of
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46,
"Consolidation of Variable Interest Entities," related to the consolidation
of R. M. Services, Inc. (RMS), a bill collection company that was once a
subsidiary of Yankee Energy System, Inc. (Yankee). NU merged with Yankee in
March 2000 and sold RMS in June 2001, retaining a preferred equity interest.
In connection with the adoption of FIN 46, effective July 1, 2003, NU was
required to consolidate RMS into NU's financial statements and adjusted its
equity interest as a cumulative effect of an accounting change.
Third quarter 2002 results included a net after-tax gain of $14.5 million, or
$0.11 per share, related to the elimination of certain reserves associated
with NU's ownership share of the Seabrook nuclear unit (Seabrook). NU sold
its 40.04 percent ownership share of Seabrook in November 2002.
For the first nine months of 2003, NU earned $126.3 million after the
cumulative effect of the accounting change, or $0.99 per share, compared with
net income of $96.1 million, or $0.74 per share, for the first nine months of
2002. The results for the first nine months of 2002 included elimination of
the aforementioned Seabrook reserves, as well as after-tax write-downs
totaling $10 million, or $0.08 per share, related to NU's investments in NEON
Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics) and
approximately $13 million, or $0.10 per share, of investment tax credits
related to divested generation reflected by Western Massachusetts Electric
Company (WMECO) as a result of a regulatory decision. The results for the
first nine months of 2003 did not include any similar write-downs or
investment tax credits. All per share amounts are reported on a fully diluted basis.
Third quarter results benefited from improved results at NU Enterprises,
lower regulated company controllable operation and maintenance costs, and
lower interest costs. Those factors were offset by lower pension income andFINANCIAL CONDITION AND BUSINESS ANALYSIS
Overview
- --------
Consolidated Results: Northeast Utilities (NU or the absence of earnings related to Seabrook.
Net income for NU Enterprises forcompany) earned $67.4
million, or $0.53 per share, in the first nine monthsquarter of 2003 was $242004, compared with
earnings of $60.2 million, or a $62.7 million increase in net income, compared to a loss of
$38.7 million for the first nine months of 2002. Net income for the first
nine months of 2003 for the Utility Group was $111 million, or a $47.5
million decrease from 2002 net income of $158.5 million. The reduction in
Utility Group net income was the result of the absence of approximately $13
million of investment tax credits that were reflected in the second quarter
of 2002 at WMECO, as well as lower pension income and the loss of net income
related to Seabrook in 2003 as compared to 2002. NU's earnings$0.47 per share,
also benefited modestly from its share repurchase program. NU repurchased
approximately 1.6 million shares at an average price of $14.14 in the first quarter of
2003. There have been no further share repurchasesHigher first quarter earnings in 2004 were primarily a result of
improved results at NU Enterprises. NU Enterprises earned $18.8 million in
the second
or third quartersfirst quarter of 2003. NU had approximately 1272004, compared with $5.2 million shares
outstanding at September 30,in the first quarter
of 2003.
NU's revenues duringin the first nine monthsquarter of 20032004 increased to $5.2$1.8 billion from
$3.8$1.6 billion in the same period of 2002, or an increase of $1.4 billion.
Of the $1.4 billion increase in NU's revenues, $1.1 billion related to NU
Enterprises. NU Enterprises' wholesale revenues increased primarily due to
$400 million in higher requirements sales and $600 million in higher short-
term and non-requirements sales. A contributing factor to the higher short-
term sales is the change in settlement methodology at the New England
Independent System Operator (ISO-NE) as a result of the implementation of
Standard Market Design (SMD).2003. The increase in revenues
is alsoprimarily was due to increasesan increase in electricrevenues at NU Enterprises' merchant
energy business segment and firm natural gas sales at the Utility Groupan increase in 2003
as compared to 2002.
Utility Group: Utility Group net income was lower due to the absence of
approximately $13 million of investment tax credits that were reflected in
the second quarter of 2002 at WMECO, as well as lower pension income and the
loss of net income related to Seabrook. Lower pension income and the lack of
Seabrook earnings resulted in approximately a $13 million and a $9 million
decrease, respectively, in net income in 2003 as compared to 2002.
As a result of adjustments to estimated unbilled electric revenues, third
quarter 2003 Utility Group retail electric
sales increased 4.9 percent in the
third quarter of 2003 compared to 2002. Absent that adjustment, Utility
Group retail electric sales would have decreased 0.3 percent. An adjustment
to estimated unbilled revenues had a negative impact on Yankee Gas Services
Company (Yankee Gas). Combined, the adjustments to estimated unbilled
revenues increased NU's net income by approximately $5.7 million in the third
quarter of 2003, resulting from a process to validaterates and update the
assumptions used to estimate unbilled revenues. For further information
regarding unbilled revenues, see "Critical Accounting Policies and Estimates
Updates - Adjustments to Estimates of Unbilled Revenues," included in this
Management's Discussion and Analysis.
Earnings before preferred dividends at The Connecticut Light and Power
Company (CL&P) totaled $30.4 million in the third quarter of 2003 and $63.2
million in the first nine months of 2003, compared to $29.3 million in the
third quarter of 2002 and $62.4 million in the first nine months of 2002.
Earnings for the three and nine months ended September 30, 2003 were
negatively impacted by lower pension income and lower earnings on a reduced
level of regulatory assets but were positively impacted by the adjustment to
the estimate of unbilled revenues.
Public Service Company of New Hampshire (PSNH) earned $12.6 million in the
third quarter of 2003 and $34.5 million in the first nine months of 2003,
compared to $19.5 million in the third quarter of 2002 and $46.4 million in
the first nine months of 2002. Lower PSNH net income resulted from higher
pension expense and a lower level of regulatory assets earning a return,
primarily due to the sale of Seabrook. These decreases were offset by an
increase to revenues as a result of an adjustment to the estimate of unbilled
revenues. The reduction in the level of net regulatory assets will continue
to negatively affect PSNH's 2003 to 2002 net income comparisons.
Additionally, net income for the first nine months of 2002 includes $4.2
million related to the positive resolution of certain contingencies related
to a PSNH regulatory proceeding.
Net income at WMECO was $5.2 million in the third quarter of 2003 and $13.9
million in the first nine months of 2003, compared to $4.7 million in the
third quarter of 2002 and $26.9 million in the first nine months of 2002.
The net income decrease in year to date 2003 earnings was due primarily to
the recognition of $13 million in investment tax credits in the second
quarter of 2002 as a result of a regulatory decision.
Yankee Gas lost $9.6 million in the third quarter of 2003 and earned $3.4
million in the first nine months of 2003, compared to a loss of $5.8 million
in the third quarter of 2002 and net income of $6.2 million in the first nine
months of 2002. Lower Yankee Gas earnings are primarily due to lower
revenues in the third quarter as a result of a downward adjustment in
estimated unbilled revenues offset by the positive impact of colder
temperatures in 2003 compared to 2002.
NU expects that pension income will decline from approximately $73 million in
2002 to approximately $32 million in 2003. Of the $41 million decline,
approximately 70 percent ($29 million) will reduce pre-tax earnings. The
remaining 30 percent ($12 million) relates to employees working on capital
projects and will be reflected as capital expenditures. The $29 million
increase in operating expenses is reflected evenly throughout the year and
has resulted in a decline of approximately $4.4 million in net income per
quarter during 2003.sales.
NU Enterprises: NU Enterprises, Inc. is the parent company of Select
Energy, Inc. (Select Energy), Northeast Generation Company (NGC), Select
Energy Services, Inc. (SESI), Northeast Generation Services Company (NGS),
and their respective subsidiaries, and Woods Network Services, Inc. (Woods
Network), all of which are collectively referred to as "NU Enterprises."
The ongoing
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
businesses, which includes approximately 1,440 megawatts (MW) of primarily
pumped storage and hydroelectric generation assets and Select Energy's
retail business. The energy services business segment consists of the
operations of NGS, SESI and Woods Network.
NU Enterprises earned $6.9$18.8 million, or $0.15 per share, in the thirdfirst
quarter of 2003 and $242004, compared with $5.2 million, or $0.04 per share, in the
first quarter of 2003. The performance of Select Energy's retail business
improved in the first quarter of 2004, earning $2.3 million compared with a
loss of $1.9 million in the first nine months of 2003,
compared to a loss of $9 million in the third quarter of 2002 and a loss of
$38.7 million in the first nine months of 2002. NU Enterprises' net income
improved due to better margins on wholesale and retail contracts, better
performance at NGC, which owns nearly 1,300 megawatts (MW) of primarily
hydroelectric and pumped storage generating capacity in Massachusetts and
Connecticut, and the absence of natural gas trading positions in 2003.
Natural gas trading positions in the first half of 2002 resulted in trading
losses. Over the past year, Select Energy has significantly reduced its
trading activities.
Select Energy's merchant energy business includes a wholesale business and a
retail marketing business. The wholesale business includes wholesale
origination, portfolio management and the operation of more than 1,400 MW of
pumped storage, hydroelectric and coal-fired generation assets. The
wholesale business earned $4.5 million in the third quarter of 2003 and $23.9
million in the first nine months of 2003, compared to losses of $2.4 million
in the third quarter of 2002 and $13.6 million in the first nine months of
2002. The wholesale business benefited from a return to normal precipitation
in western New England during the first nine months of 2003, compared with
the same period of 2002, which increased conventional hydroelectric output.
This increase in output resulted in $3.7 million of additional net income in
2003, as compared to 2002. The wholesale business also benefited from the
absence of natural gas trading losses in 2003. The retail marketing business lost $1.6 million in the first nine months of
2003 compared to a loss of $26.3 million in the first nine months of 2002.
The 2003 improved retail
results are primarily due to improved margins and growth in retail electric
sales.
Select Energy's wholesale business earned $16.8 million in the first
quarter of 2004, compared with $6.8 million in the same period of 2003.
Select Energy's earnings profile in the first half of 2004 will be quite
different from the first six months of 2003, particularly in the wholesale
business. Select Energy's cost per kilowatt-hour (kWh) for procuring
electricity is relatively flat throughout 2004. However, contracted sales
along with improved managementprices to some of gas retail
contracts.Select Energy's wholesale customers were relatively high
in the first quarter and will be lower in the second quarter, creating
better wholesale margins in the first quarter of 2004 and lower margins in
the second quarter. As a result, earnings at NU Enterprises in the second
quarter of 2004 are expected to be significantly below the $11.9 million NU
Enterprises earned in the second quarter of 2003. However, NU Enterprises'
earnings in the first half of 2004 are expected to be higher than the $17.1
million earned in the first half of 2003.
The energy services businesses earnedbusiness segment lost $0.2 million in the thirdfirst quarter
of 2003 and $2.1 million in the first nine months of 20032004, compared towith earnings of $1.7 million in the third quarter of 2002 and $1.8 million in the first
nine months of 2002.
NU Enterprises parent costs totaled $0.2 million in the third quarter of 2003
and $0.4 million in the first nine monthsquarter of
2003 comparedprimarily due to $0.2 millionproject delays as a result of colder than average
January weather and the slow commercial construction sector in the third quarter of 2002 and $0.6New England.
NU Enterprises parent company expenses totaled $0.1 million in the first
nine monthsquarter of 2002.both 2004 and 2003.
Utility Group: Earnings at the Utility Group were lower, totaling $54.8
million, or $0.43 per share in the first quarter of 2004, compared with
$59.4 million, or $0.47 per share in 2003, primarily due to higher
depreciation and pension expense during the first quarter of 2004 as
compared with the first quarter of 2003. These factors were partially
offset by an increase in retail electric sales of 2.7 percent in the first
quarter of 2004, compared with the first quarter of 2003. Higher earnings
at The Connecticut Light and Power Company (CL&P) and Public Service
Company of New Hampshire (PSNH) were more than offset by lower results at
Yankee Gas Services Company (Yankee Gas) and Western Massachusetts Electric
Company (WMECO). Included in Utility Group earnings in 2004 and 2003 are
$7.3 million and $8 million, respectively, related to the regulated
transmission business. Transmission business earnings for the first
quarter of 2004 are lower than the same period in 2003 due to lower
revenues and higher interest charges. Transmission revenues are lower 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
quarter of 2003, revenues were not subject to such a tracking mechanism and
were positively impacted by high usage. For further information see Note 8,
"Segment Information," to the consolidated financial statements.
Earnings after preferred dividends of $1.4 million in both periods at CL&P
totaled $26.2 million in the first quarter of 2004, compared with $25.3
million in 2003. CL&P's higher earnings resulted from distribution rate
increases which took effect on January 1, 2004, transmission rate increases
and a 2 percent increase in retail electric sales offset by higher
depreciation and pension expense in the first quarter of 2004, compared
with the first quarter of 2003.
PSNH earned $11.8 million in the first quarter of 2004, compared with $10.8
million in 2003. The increase in earnings at PSNH was primarily due to a
6.9 percent increase in retail electric sales offset by higher pension
expense in the first quarter of 2004, compared with the first quarter of
2003.
Earnings at WMECO totaled $3.5 million in the first quarter of 2004,
compared with $6.1 million in 2003. Lower earnings at WMECO were primarily
due to lower pension income and higher interest expense in the first
quarter of 2004 compared with the first quarter of 2003 due to the issuance
of 10-year notes on September 30, 2003, as well as a 0.7 percent decrease
in retail sales.
Yankee Gas earned $11.9 million in the first quarter of 2004, compared with
$15.8 million in 2003. Lower Yankee Gas earnings resulted from higher
pension expense and an August 2003 change in the Yankee Gas rate design.
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 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.
This decrease was offset by a 6.8 percent increase in firm natural gas
sales in the first quarter of 2004, compared with the first quarter of
2003, which reflected a negative adjustment to the estimate of unbilled
revenues in the first quarter of 2003. Excluding the adjustment to the
estimate of unbilled revenues, firm natural gas sales decreased by 0.5
percent in the first quarter of 2004, compared with the first quarter of
2003.
Future Outlook
- --------------
Consolidated: NU has narrowed its forecastedcontinues to project consolidated earnings in 2003 to between
$1.20 per share and $1.30 per share from its previous forecast of between
$1.10 per share and $1.30 per share. That range excludes any potential
losses at Select Energy due to the ongoing dispute over locational marginal
pricing (LMP) costs, which are estimated to be $90 million. NU also has
established a forecasted earnings range of between
$1.20 per share and $1.40 per share for 2004.in 2004, including approximately $0.10
per share of parent company interest and other expenses.
Utility Group: The forecasted earnings in 2003 reflect earnings of between
$1.10 per share and $1.15 per share at the Utility Group. The NU consolidated earnings rangeestimate of between $1.20 per share andto
$1.40 per share for 2004 reflectsincludes 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. Based on first
quarter 2004 results, management expects 2004 NU Enterprises' earnings to
be in the mid to upper end of that range. NU continues to project 2004
merchant energy business segment earnings of $24 million to $31 million.
Earnings for the remainder of 2004, specifically the second quarter, at the
Utility Group.merchant energy business will be negatively impacted by the change in
Select Energy's earnings profile discussed previously. The energy services
business segment, comprised of NGS, SESI and Woods Network, was below
forecast for the first quarter, but is still expected to earn between $4
million and $7 million in 2004.
Liquidity
- ---------
Consolidated: NU continues to maintain a high level of liquidity. NU had
$147 million of cash, including cash and cash equivalents and unrestricted
cash from counterparties at March 31, 2004, Utility Groupcompared with $83.7 million at
December 31, 2003.
NU's net cash flows provided by operating activities increased to $256.2
million in the first quarter of 2004 from $125.7 million in the first
quarter of 2003. Cash flows provided by operating activities increased due
to increases in working capital items, primarily accounts payable and
accrued taxes. Accounts payable increased in the first quarter of 2004 due
primarily to an increase in CL&P accounts payable resulting from
transitional standard offer (TSO) supply purchases at higher prices and an
increased percentage of TSO purchases from unaffiliated suppliers. In the
first quarter of 2003, accounts payable decreased due to a lower level of
Select Energy wholesale electricity purchases. Accrued taxes decreased in
2003 due to the payment of taxes on the gain on the sale of Seabrook.
These first quarter 2003 decreases were partially offset by a decrease in
accounts receivable related to a lower level of Select Energy sales in the
first quarter of 2003 compared to the last quarter of 2002 and a decrease
in investments in securitizable assets. Regulatory overrecoveries also
decreased primarily due to lower stranded cost and generation service
collections in the first quarter of 2004 compared to 2003. The lower level
of collections caused lower current taxable income and an increase in
deferred income taxes from 2003.
During the first quarter of 2004 NU issued $82.4 million in long-term debt,
including $75 million at Yankee Gas and $7.4 million at SESI. NU also repaid
$47.5 million of rate reduction bonds.
On March 31, 2004, NU paid a dividend of $0.15 per share. On April 13,
2004, the NU Board of Trustees approved a dividend of $0.15 per share,
payable June 30, 2004, to shareholders of record as of June 1, 2004.
Subject to the NU Board of Trustees' approval and future earnings rangelevels,
management anticipates recommending increases to the NU common dividend.
The NU Board of Trustees will address the issue of a dividend increase at
the company's annual meeting on May 11, 2004.
NU's capital expenditures totaled $137.8 million in the first quarter of
2004, compared with a budget of $173.7 million. The lower level of capital
expenditures was primarily related to delays in certain transmission
projects. NU's 2004 capital spending is dependent on a number of factors,projected to total $701 million,
including $412 million by CL&P, $150 million by PSNH, $39 million by WMECO,
$60 million by Yankee Gas, and $40 million by other NU subsidiaries.
Delays in certain major projects could cause NU's actual capital spending
to be below this projection.
On April 14, 2004, Standard & Poor's (S&P) lowered the outcome of state rate cases involvingoutlook for NU to
"negative" from "stable," citing increased competitive business exposure,
increased projected capital expenditures at CL&P and PSNH and a
Federal Energy Regulatory Commission (FERC) rate case involving NU's
transmission tariffs. A final decision fromthe relatively low
return on equity (ROE) at CL&P that was authorized by the Connecticut
Department of Public Utility Control (DPUC) in CL&P'sthe December 2003 rate case
is due on December 15, 2003
with new rates effective on January 1, 2004. The filing of a PSNH rate case
is expected by the end of this year with new rates effective on February 1,
2004. On October 22, 2003, the FERC preliminarily approved NU's requested
transmission tariff, allowing rates to go into effect on October 28, 2003,
subject to refund. This new formula tariff will provide NU with more timely
recovery of the costs associated with its transmission capital program.
NU Enterprises: The forecasted earnings in 2003 reflect earnings of between
$0.20 per share and $0.25 per share at NU Enterprises. The NU consolidated
earnings range of between $1.20 per share and $1.40 per share for 2004
reflects earnings of between $0.22 and $0.30 per share at NU Enterprises.
The 2003 NU Enterprises earnings range excludes any potential negative impact
on Select Energy from an ongoing LMP dispute involving Select Energy's
contract to provide CL&P with 50 percent of its standard offer service
through the end of 2003. The LMP dispute, now before an administrative law
judge at the FERC, relates to whether CL&P's standard offer suppliers,
including Select Energy, or CL&P's retail customers are responsible for
incremental costs associated with the implementation of SMD and LMP beginning
in March 2003. Select Energy's portion of these costs is $90 million. A
FERC decision is expected in 2004. For further information regarding the LMP
dispute, see "Impacts of Standard Market Design," in this Management's
Discussion and Analysis.
The 2004 earnings range of between $0.22 per share and $0.30 per share
represents earnings of between $28 million and $38 million. Management
estimates that between $24 million and $31 million of those earnings in 2004
will come from the wholesale and retail merchant energy business and between
$4 million and $7 million from the energy services business. Those ranges
are heavily dependent on NU Enterprises' ability to achieve targeted
wholesale and retail origination margins, successfully manage its contract
portfolios and achieve targeted growth in the services business.
Other: NU continues to project parent company debt and other expenses of
approximately $0.10 per share in 2003. The 2004 earnings range also reflects
$0.10 per share of parent company after-tax expenses, primarily related to
interest expense.
Liquidity
- ---------
Consolidated: NU's liquidity continues to be strong as NU had $118.1 million
of cash and cash equivalents on hand at September 30, 2003. NU's net cash
flows from operating activities decreased to $462.7 million in the first nine
months of 2003 from $472.3 million in the first nine months of 2002. The
decrease in cash flows from operating activities resulted from the payment of
$193 million of taxes, primarily on the gain on the sale of Seabrook,
increases in other uses of cash, which relate primarily to other regulatory
assets and increases in restricted cash, due to the placing of incremental
LMP costs collected into an escrow account beginning in July 2003. These
decreases were partially offset by a $35 million increase in income before
preferred dividends of subsidiaries combined with the positive impacts of
increased amortization from recovery of regulatory assets, lower pension
income, decreases in accounts receivable, and increases in accounts payable.
NU's liquidity was also enhanced by recent financings. On June 3, 2003, NU
issued $150 million of five-year notes at an interest rate of 3.3 percent.
The proceeds from the issuance of these notes were primarily used to
refinance Select Energy's short-term debt. On September 30, 2003, WMECO
issued $55 million of ten-year 5 percent notes, the proceeds from which WMECO
used to repay a similar level of borrowings from the NU system Money Pool.
On October 1, 2003, CL&P fixed the interest rate on $62 million of variable-
rate tax-exempt borrowings for five years at 3.35 percent. In the first nine
months of 2003, NU also repaid $33.6 million of long-term debt and $126.4
million of rate reduction bonds.
NU's capital expenditures totaled $386 million in the first nine months of
2003 compared to $327.3 million in the first nine months of 2002. NU
currently projects capital expenditures of approximately $600 million in
2003.
The level of common dividends totaled $54 million in the first nine months of
2003, compared with $50.2 million in the first nine months of 2002. The
increase in the level of common dividends resulted from NU paying two $0.1375
per share quarterly common dividends and one $0.15 per share quarterly common
dividend in the first nine months of 2003, compared to two $0.125 per share
quarterly common dividends and one $0.1375 per share quarterly common
dividend in the first nine months of 2002. On October 14, 2003, the NU Board
of Trustees declared a common dividend of $0.15 per share payable on
December 31, 2003, to shareholders of record on December 1, 2003. The dividend
increase was consistent with management's objective to continue to increase
the dividend level annually, subject to NU's ability to meet earnings targets
and the judgment of its Board of Trustees at the time the dividends are
declared.
In the third quarter 2003, Fitch Ratings (Fitch) raised the outlook of NU's
and CL&P's credit ratings to stable from negative. The change in outlook is
a result of Fitch's belief that the risks associated with CL&P's standard
offer service contract with NRG Energy, Inc. (NRG) had declined. For more
information on NRG see the "NRG Exposures" section of this Management's
Discussion and Analysis and Note 4B, "Commitments and Contingencies - NRG
Energy, Inc. Exposures," to the consolidated financial statements.decision.
Utility Group: At September 30, 2003, NU'sMarch 31, 2004, the Utility Group had $10 million in
borrowings outstanding on its $300 million revolving credit line. This
credit line expires onis scheduled to mature in November 11, 2003,2004 and management expectswill be renewed for
at least one year.
In addition to extend
thisits revolving credit line, from November 2003 through November 2004.
At September 30, 2003, CL&P had $40has an arrangement with a
financial institution under which CL&P can sell up to $100 million of
accounts receivable and unbilled revenuesrevenues. At March 31, 2004, CL&P had sold under its arrangement with a financial institution to
sell up to $100 million in
accounts receivable and unbilled revenues. This
arrangement expires in July 2004.totaling $80 million to that financial institution.
For more information regarding CL&P's
accounts receivable facility,the sale of receivables, see Note 1F, "Sale1H,
"Summary of Significant Accounting Policies - Sale of Customer Receivables,"Receivables"
to the consolidated financial statements.
On January 30, 2004, Yankee Gas sold $75 million of first mortgage bonds
carrying an interest rate of 4.8 percent that will mature on January 1,
2014. The proceeds from these bonds were primarily used to reduce short-
term debt, which was increasing as a result of Yankee Gas' capital
expenditures.
CL&P is seeking approval from its preferred shareholdershas an application pending with the DPUC to permanently amend
its charterissue up to eliminate a requirement$280 million
of long-term debt in 2004 and another $600 million for the period 2005
through 2007. The majority of that unsecured debt represent no more
than 10 percent of total capitalization. At September 30, 2003,would be issued to finance CL&P's
unsecured debt represented approximately 3 percentelectric transmission and distribution initiatives. CL&P also has $59
million of CL&P's total
capitalization. CL&P is offering its preferred holders a payment of 1
percent of the $116.2 million par value of their shares if the preferred
holders vote in favor of the amendment and CL&P implements it. Preferred
holders of record as of September 30, 2003, are eligible to votefirst mortgage bonds that can be called at a special
meeting, which will be held on November 25, 2003. Holders of at least two-
thirds of CL&P's approximately 2.3 million shares of preferred stock must
vote in favor of the change for it to pass. Management believes thatpremium beginning
June 1, 2004. At March 31, 2004, CL&P will benefithad $160.5 million in short-term
debt outstanding from such a change duethe NU Money Pool.
PSNH has an application pending with the New Hampshire Public Utilities
Commission (NHPUC) to increased financial flexibility. In
the event that this change fails or if CL&P chooses notissue up to implement it, CL&P
is also asking preferred holders to endorse another 10-year waiver that would
allow CL&P's unsecured debt to rise to 20 percent of total capitalization.
CL&P preferred holders approved a similar waiver in 1993 that is scheduled to
expire in March 2004.
Prior to July 1, 2003, CL&P recovered approximately $30$50 million of incremental LMP costsdebt. At March 31, 2004,
PSNH had $35 million in short-term debt outstanding from its customers and has withheld payment of these
incremental LMP costs from its standard offer service suppliers. This
positively impacted CL&P's liquidity. In July 2003, CL&P began depositing
new recoveries into an escrow account. Accordingly, further recovery of
these costs did not impact CL&P's liquidity. When the LMP dispute is
resolved, there will be a negative impact on CL&P's liquidity for the amounts
recovered but not deposited into the escrow account, as these amounts are
paid to standard offer service suppliers or returned to customers.NU Money Pool.
NU Enterprises: At March 31, 2004, NU Enterprises had $30 million inno borrowings and
$123.2$63.8 million in letters of credit (LOCs) outstanding on NU parent's $350
million revolving credit line. This credit line expires onis scheduled to mature in
November 11, 2003,2004 and
management expects to extend this credit line from November 2003 through
November 2004.
At September 30, 2003, Select Energy has incurred and billed CL&P for
incremental LMP costs in the amount of approximately $71 million. As a
result of the LMP dispute, Select Energy has not received any amounts from
CL&P, which has negatively impacted Select Energy's liquidity. This negative
impact is expected to continuebe renewed.
Additionally, SESI had borrowed $7.4 million during the first quarter of
2004 to increase untilfinance the resolutionimplementation of energy saving improvements at
customer facilities. These borrowings are recovered under the LMP
dispute.terms of
SESI's energy savings contracts.
On March 26, 2004, Moody's Investors Service placed NGC's bonds under
review for possible downgrade, but expected NGC's bonds to maintain an
investment grade rating after the review was completed. On April 14, 2004,
S&P lowered the ratings on NGC's bonds to BB+, S&P's highest non-investment
grade rating, from BBB-, S&P's lowest investment grade rating. The S&P
rating decrease was based in part on its own forecast of NGC's
profitability in a merchant energy market which included a low forecasted
level of natural gas prices. S&P also lowered its outlook on NU to
"negative" from "stable" at the same time. The downgrade is not expected
to have an impact on NGC's financial performance.
Impacts of Standard Market Design
- ---------------------------------
Consolidated: On March 1, 2003, ISO-NEthe New England Independent System Operator (ISO-NE)
implemented SMD.Standard Market Design (SMD). As part of SMD, LMPlocational
marginal pricing (LMP) is now 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.
The costs associated with
transmission congestion and line losses are now assigned to the pricing zone
in which they occur and the calculation of line losses is now based on an
economic formula. Prior to March 1, 2003, those costs were spread across
virtually all New England electric customers based on engineering data of
actual line losses experienced. As part of the implementation of SMD, ISO-NE
established eight separate pricing zones in New England: three in
Massachusetts and one in each of the five other New England states. The
three components of the LMP for each zone are 1) an energy cost, 2)
congestion costs and 3) line loss charges assigned to the zone. LMP is
increasing costs in zones that have inadequate or less cost-efficient
generation and/or transmission constraints, such as Connecticut, and
decreasing costs in zones that have sufficient or excess generation, such as
Maine. The implementation of SMD has also impacted pricing under wholesale
energy contracts depending on the energy delivery points chosen under those
contracts.
Utility Group: Connecticut has been designated a single pricing zone by ISO-
NE. For the seven-month period from March 1, 2003 through September 30,
2003, incremental LMP costs have totaled approximately $132.5 million,
including $71 million related to Select Energy. Approximately 70 percent of
these incremental costs (approximately $90 million, or approximately $13
million per month on average) were associated with line losses, with monthly
line losses ranging from $9.5 million to $17 million. LMP costs also include
approximately $41 million related to congestion costs for the seven-month
period with monthly congestion costs ranging from $0.2 million to $16.5
million.
In October 2003, incremental LMP costs amounted to approximately $13.7
million, including $8.6 million of line loss charges and $5.2 million of
congestion costs.
Management currently estimates that total incremental LMP costs for CL&P for
2003 will be approximately $180 million (approximately $120 million in line
losses and approximately $60 million in congestion costs). Actual
incremental LMP costs could be higher if congestion and line loss charges are
greater than anticipated as a result of unusual weather and other factors
management cannot predict.
CL&P's standard offer service contracts were executed in the fall of 1999
with the delivery points in the contracts at the suppliers' choice at any
point on the New England power pool. Prior to March 1, 2003, delivery by the
suppliers anywhere on the New England power pool resulted in the suppliers
being charged and paying their respective share of socialized congestion
costs. Subsequent to March 1, 2003, the delivery points chosen by the
suppliers have been zones with no or negative congestion and/or line losses.
Management believes that under the legal interpretation of the terms of its
standard offer service contracts with its standard offer suppliers, the
incremental costs associated with line losses and congestion between the
delivery points chosen by the suppliers and CL&P's service territory in
Connecticut are the responsibility of CL&P's customers.
The $132.5was billed $186 million of incremental LMP costs incurred from March 1, 2003
through September 30, 2003 have been recorded as recoverable energy costs,
and approximately $95.6 million has been billed to CL&P's customers and
reflected in revenues through September 30, 2003. The remaining balance is
included in recoverable energy costs, which collectively is a component of
regulatory assets. Management believes that these congestion and line loss
charges are unavoidable, are part of the prudent cost of providing regulated
electric service in Connecticut and should be paid for by CL&P's customers.
Accordingly, CL&P sought and received approval on May 1, 2003, for recovery
of these costs through the energy adjustment clause (EAC), subject to refund.
CL&P began recovery of the March 2003 LMP costs in its May 2003 billings and
continues to bill LMP costs on a two-month lag.
The DPUC directed CL&P to pursue legal remedies against its standard offer
suppliers in an effort to assign liability for incremental LMP costs to those
suppliers. The DPUC indicated that it will support CL&P's efforts and that
CL&P's failure to aggressively pursue legal remedies may result in ultimate
disallowance of recovery of LMP-related costs. The DPUC also required CL&P
to obtain surety bonds, which are guaranteed by NU parent, for the $31.1
million of March 2003 and April 2003 incremental LMP costs. Amounts
collected from customers beginning with May 2003 incremental LMP costs that
were recovered in July 2003 were deposited into an escrow account. At
September 30, 2003, $45.8 million was deposited in the escrow account and is
included in restricted cash - LMP costs on the accompanying consolidated
balance sheet.
In response to the DPUC decision of May 1, 2003, CL&P has filed for a
declaratory judgment from the FERC to determine whether CL&P's standard offer
service suppliers, are responsibleincluding affiliate Select Energy, or by ISO-NE in 2003.
CL&P and its suppliers disputed the responsibility for incremental LMP costs. Additionally,
CL&P has withheld payment of all $132.5the $186 million of
incremental LMP costs to
its standard offer service suppliers, pending resolution of this matter.
Hearings on this issue before a FERC administrative law judge occurred in
October 2003. As a result of these hearings,incurred. A settlement agreement was reached among
all the parties agreedinvolved 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
athis settlement conference before a FERCagreement. This settlement judge, which occurred from
November 4, 2003 to November 5, 2003. No settlement has been reached as of
November 7, 2003. Resolution of this issueagreement will not be final
until it is approved by the FERC, will likely occur in
2004, and amanagement expects to receive FERC
administrative law judge decision may be issuedapproval of the settlement agreement in the fourth quarterfirst half of 2003.2004.
Nuclear Decommissioning and Plant Closure Costs
- -----------------------------------------------
The purchasers of NU's ownership shares of the Millstone, Seabrook and
Vermont Yankee 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 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 is currently
negotiating a settlement with the FERC and others to collect its presently
estimated decommissioning costs.
CY's estimated decommissioning and plant closure costs for the period 2000
through 2023 have increased approximately $390 million over the April 2000
estimate of $434 million approved by the FERC in a rate case settlement.
The revised estimate reflects the fact that CY is now self-performing all
work to complete the decommissioning of the plant due to the termination of
the decommissioning contract with Bechtel Power Corporation in July 2003,
the increases in the projected costs of spent fuel storage, and increased
security and liability and property insurance. NU's share of CY's
increased decommissioning and plant closure costs is approximately $191
million. CY has not yet applied to the FERC for recovery of this amount.
In total, NU's estimated remaining decommissioning and plant closure
obligation to CY is $320.7 million.
NU cannot at this time predict the timing or outcome of the FERC proceeding
required for the collection of the increased decommissioning costs.
Management continues to believebelieves that these incremental LMP costs have been prudently incurred and will
ultimately be recovered from itsthe customers based
upon the legal interpretation of the standard offer supply contracts.
Management will continue to evaluate the likelihood of recoveryCL&P, PSNH and WMECO.
However, there is a risk that some portion of these increased costs in the fourth quarter.
Another factor affecting the level of CL&P's operating costs is the
designation of certain generating units by ISO-NE as units needed for system
reliability. Some companies have applied to the FERC for "reliability must
run" (RMR) treatment for their units. There are two methods of RMR treatment
that have been allowed by the FERC, both of which allow these units
to receive cost of service-based payments in excess of their operational
energy costs, that recognize their reliability value. The two methods
allowed have provided certain generating units with the ability to collect
non-energy related costs through fixed cost payments and/or through the
submission of bid prices that include non-energy costs. The latter method
provided these units with a temporary safe harbor from the ISO-NE price cap
under certain circumstances. Prior to March 1, 2003, all RMR costs were
spread across New England with all utilities being billed by ISO-NE based
upon their share of New England's load. NU's regulated electric distribution
companies were responsible for approximately 25 percent of these costs.
Effective with the March 1, 2003 implementation of SMD, RMR costs were no
longer spread across New England but rather they were allocated to the
pricing zone in which the RMR unit is located. The only pricing zone
currently experiencing an RMR cost increase in which NU's regulated electric
distribution companies operate is Connecticut, where certain of the RMR units
reside. Prior to RMR, other reliability costs have been approved for recovery
by the DPUC in CL&P's 2001 Competitive Transition Assessment (CTA)
reconciliation filing. RMR costs incurred by CL&P during 2002 totaling $7.8
million have been fully recovered from customers and are subject to review in
CL&P's 2002 CTA reconciliation filing, which was filed on March 31, 2003.
For the nine-month period ended September 30, 2003, CL&P incurred $40.3 million
of RMR costs and recorded these costs as a regulatory asset. Management
believes that these costs willmay not
be recovered in CL&P's 2003 CTA reconciliation
filing.
As part of the SMD implementation on March 1, 2003, ISO-NE now calculates
line loss charges based on an economic formula and not on actual losses
experienced. To date, ISO-NE has not filed its methodology for determining
line loss charges with the FERC, and CL&P has been unable to verify the
validity or accuracy of ISO-NE's billings. Accordingly, on July 23, 2003,
CL&P filed a complaint with the FERC requesting that ISO-NE provide its
methodology for determining such charges. In October 2003, the FERC rejected
this complaint.
On July 25, 2003, CL&P filed with the DPUC a request for approval of a formal
recovery mechanism that would allow for the 2004 and beyond tracking and
recovery of all Federally Mandated Congestion Costs (FMCC) as outlined in
Connecticut Public Act No. 03-135 (the Act). The major cost components of
FMCC are congestion costs, line losses and RMR costs. Management anticipates
that this matter will be resolved by the DPUC by the end of 2003.
NU Enterprises: Select Energy continues to provide 50 percent of CL&P's
standard offer service. If it is ultimately concluded that some or all of
the incremental LMP costs, which began on March 1, 2003, are the
responsibility of the standard offer service suppliers, NU Enterprises' and
NU's pre-tax earnings for the nine months ended September 30, 2003, would be
reduced by up to $71 million with no incremental impact on Select Energy's
cash flows. Management currently expects Select Energy's share of
incremental LMP costs for 2003 to be approximately $90 million, depending on
the level of line losses and congestion costs experienced. Management
believes that these costs are not contractually Select Energy's
responsibility, but will continue to assess the collectibility of Select
Energy's accounts receivable from CL&P based on developments at the FERC.
Select Energy's standard offer service contract with CL&P expires on
December 31, 2003. NU Enterprises' and NU's 2003 earnings estimates do not
include the impact of these incremental LMP costs.
For information regarding commitments and contingencies related to the
accounting for the implementation of SMD, see Note 4A, "Commitments and
Contingencies - Restructuring and Rate Matters," to the consolidated
financial statements.
NRG Exposures
- -------------
Certain subsidiaries of NU have entered into various transactions with
subsidiaries of NRG. On May 14, 2003, NRG and certain of its subsidiaries
filed voluntary bankruptcy petitions in the United States Bankruptcy Court
for the Southern District of New York. NRG-related exposures to certain
subsidiaries of NU as a result of these transactions are as follows:
Standard Offer Service Contract: NRG Power Marketing, Inc. (NRG-PM) has a
contract with CL&P to supply 45 percent of CL&P's standard offer service
load through December 31, 2003. NRG-PM attempted to terminate the contract
with CL&P, but the FERC ordered NRG-PM to continue serving CL&P under its
standard offer supplier contract. Subsequently, NRG-PM received a temporary
restraining order from the United States District Court for the Southern
District of New York (District Court) and stopped serving CL&P with standard
offer supply on June 12, 2003. NRG-PM was ultimately ordered by the FERC and
the District Court to resume serving CL&P's standard offer service load and
did so on July 2, 2003. During the period NRG-PM did not serve CL&P under
its standard offer service contract, CL&P purchased power from the spot market
at prices in excess of NRG-PM's contract price. This excess amounted to $7.9
million and was collected by CL&P from its customers. As a result of the
settlement described below, this amount will be collected from NRG-PM.
On November 4, 2003, CL&P, NRG, the NRG Creditors' Committee, the DPUC, the
Office of Consumer Counsel and the attorney general of Connecticut entered
into a comprehensive settlement agreement. Under the settlement agreement,
which is subject to the approval of the bankruptcy court and the FERC, NRG
will continue to deliver power to CL&P under the terms and conditions of the
standard offer service contract through the end of its term, which is
December 31, 2003. The disputes relating to responsibility for incremental
LMP costs will be determined by the District Court and the FERC respectively,
with payment, if any, to be made to NRG from amounts withheld and to be
withheld from NRG by CL&P. CL&P will also retain the $7.9 million withheld
from NRG for replacement power purchased by CL&P during the period June 12,
2003 through July 2, 2003. The parties will exchange releases of all claims
relating to the standard offer service contract.
Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit
against NRG in Connecticut Superior Court seeking judgment for unpaid pre-
March 1, 2003, congestion charges under its standard offer supply contract.
On August 5, 2002, CL&P withheld the then unpaid congestion charges from
payments due to NRG for standard offer service and continues to withhold
these amounts. The total amount of congestion costs withheld from NRG was
$27.5 million. If it is ultimately concluded that CL&P is responsible for
pre-March 1, 2003 congestion costs, management believes CL&P would be allowed
to recover these costs from its customers.
Station Service: Since December 1999, CL&P has provided NRG's Connecticut
generating plants with station service, which includes energy and/or delivery
services provided when a generator is off-line or unable to satisfy its
station service requirements. Pursuant to the parties' interconnection
agreement dated July 1, 1999, CL&P provides this service at DPUC-approved
retail rates. NRG has disputed its obligation and has refused to pay CL&P
but has stated that it intends to assume the station service contract in
bankruptcy proceedings. NRG and CL&P stipulated to an order in bankruptcy
court requiring the determination of the amount owed by NRG for station
service under binding arbitration. If NRG assumes the contract, NRG will be
required to pay the amount determined in the arbitration to CL&P. Management
will continue to pursue recovery from NRG of the station service balance,
including $4.2 million NRG placed in an escrow account related to this
matter. During the second quarter of 2003, as a result of NRG's bankruptcy,
the amount due from NRG in excess of the escrow amount was reserved.
Management believes that amounts not collected from NRG are ultimately
recoverable from CL&P's customers. Therefore, a regulatory asset of $10.6
million was recorded. At September 30, 2003, NRG owed CL&P $15.4 million for
station service.
Through September 30, 2003, legal costs incurred by CL&P related to NRG's
bankruptcy amounted to $1.6 million. This amount has also been recorded as a
regulatory asset, and CL&P will continue to defer these legal costs as they
are incurred.
Meriden Gas Turbines, LLC: Yankee Gas, E.S. Boulos Company (Boulos), which
is a subsidiary of NGS, and CL&P have exposures to Meriden Gas Turbines, LLC
(MGT), an NRG subsidiary that is not included in NRG's voluntary bankruptcy
proceedings petition.
Yankee Gas has incurred and expended costs in excess of $16 million in the
construction of a natural gas pipeline to a generating plant that MGT was
constructing. Yankee Gas drew down on a $16 million letter of credit when
MGT stated that it was abandoning construction of the generating plant. NRG
has contested the draw down on the letter of credit in a lawsuit filed in
Connecticut Superior Court. Yankee Gas has a counterclaim pending against
MGT to recover additional monies in accordance with the contract that are in
excess of the $16 million letter of credit.
Boulos has a 50 percent interest in a joint venture that was building
switchyards for the MGT generating plant. To date, Boulos has $0.4 million
of accounts receivable from performing its 50 percent share of the joint
venture's work on the MGT. In addition, the joint venture has outstanding
payables of $2.6 million for which it has corresponding receivables from the
general contractor; Boulos' share equaling $1.3 million. The joint venture
has commenced a legal proceeding against the general contractor to collect
the amounts owed. The joint venture is also a party to a mechanics lien
foreclosure action in which one of its subcontractors is attempting to
foreclose upon a mechanics lien filed on the MGT generating plant. Boulos'
total exposure to NRG on this project is $1.7 million. MGT also currently
owes CL&P $0.5 million for work on the South Kensington switching station,
which was to be the interconnection point for the MGT generating plant.
Management does not expect that the resolution of the aforementioned MGT
disputes will have a material adverse effect on the financial condition or
results of operations of NU and its subsidiaries.
NU Enterprises
- --------------
Subsidiaries:Business Segments: NU Enterprises Inc. isaligns its businesses into two business
segments, the parent company ofmerchant energy business segment and the energy services
business segment. The merchant energy business segment includes Select
Energy,
NGC, SESI, NGS, and their respective subsidiaries, and Woods Network, which
are collectively referred to as "NU Enterprises." The ongoing generation
operations of HWP are also included in the results of NU Enterprises. Select
Energy engages inEnergy's wholesale and retail energy marketing activities and
limited energy trading activities for price discovery and risk management of
wholesale activities.
NU Enterprises includes 1,438businesses. Also included are
1,440 MW of generation capacity,assets, consisting of 1,2911,293 MW of primarily pumped
storage and hydroelectric generation assets at NGC and 147 MW of coal-fired
generation at HWP, which are used toHWP. These generation assets support Select Energy'sthe merchant energy
business.
In October 2003, NU revised an earlier application made tobusiness segment.
The energy services business segment includes the SEC seeking to
expand its ability to support its unregulated businesses. The new
application primarily seeks to 1) reclassify Select Energyoperations of SESI, NGS,
and Select Energy
New York, Inc. (SENY) as allowable retained businesses under the Public
Utility Holding Company Act of 1935 (1935 Act) not subject to the limitations
of a 15 percent capitalization test imposed by the Securities and Exchange
Commission's (SEC) 1935 Act Rule 58 (Rule 58 Investment Limit), 2) permit NU
to guarantee the obligations of its unregulated businesses up to $750 million
through September 30, 2006, and 3) increase its allowable investments in
exempt wholesale generators (EWGs) from $481 million to $1 billion. If
granted, the SEC's order would reduce the Rule 58 Investment Limit by the
amount of NU's investment in Select Energy and SENY at June 30, 2003, but not
limit NU's future investment in Select Energy and SENY. NU has no present
plans to significantly expand its EWG portfolio at this time. However, if an
investment opportunity becomes available, NU will be able to pursue it within
the new allowable EWG investment level. NU expects SEC approval in late 2003
or early 2004.Woods Network. SESI performs energy management services for large
industrial, commercial andcustomers, institutional facilities includingand the United States
Department of Defense,government and engages in energy relatedenergy-related construction services. NGS operates and
maintains NGC's and HWP's generation assets and provides third-party
electrical services.
Results and engineering contracting services.
Outlook: Financial performance at NU Enterprises improved significantlyearned $18.8 million in the first
nine monthsquarter of 20032004, compared with $5.2 million in the first quarter of 2003.
During 2004, NU expects that NU Enterprises will earn in the range of $28
million to the same period$38 million, or $0.22 to $0.30 per share. Management estimates
that between $24 million and $31 million of those earnings in 2002.
The wholesale business, which is part of NU Enterprises'2004 will
come from the merchant energy business line, has obtained two significant contracts sincesegment and between $4 million and
$7 million from the second
quarter of 2003. Select Energy has been awarded a contractenergy services business segment. Those ranges are
heavily dependent on NU Enterprises' ability to provide over
700 MW of default service to residential, commercialachieve targeted wholesale
and industrial customers
of Massachusetts Electric Company and Nantucket Electric Company,
subsidiaries of National Grid Company. The contract period, which begins on
November 1, 2003 and runs through October 31, 2004, is expected to generate
revenues in excess of $100 million. The second contract calls for Select
Energy to provide approximately 40 MW of last resort service to customers of
Narragansett Electric Company from September 1, 2003 to August 31, 2004 with
expected revenues of approximately $6.5 million.
Management currently believes that the wholesale business will meet its 2003
net income estimate of between $27 and $30 million. To meet this estimate,
the wholesale business will need toretail origination margins, successfully manage its portfoliocontract portfolios
and achieve targeted growth in the energy services business segment. Based
on first quarter 2004 results, management expects 2004 NU Enterprises'
earnings to be in the mid to upper end of contracts. Forthat range.
In the first nine monthsquarter of 2003, the wholesale business
produced net income of $23.9 million. The wholesale business is expected to
have net income2004, Select Energy won contracts in the fourth quarterNew Jersey
Basic Generation Service and Maryland utility auctions. As a result of
between $3 millionthese contracts, Select Energy will serve a peak load of 1,300 MW in 2004,
450 MW in 2005 and $6 million.350 MW in 2006. 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 March 31,
2004 market information, Select Energy's wholesale electric business has
already contracted for more than 80 percent of the business needed to reach its
2004 gross margin targets, assuming satisfactory portfolio management for the
remainder of the year.
The second businessactivity included in NU Enterprises' merchant energy business
segment is theretail marketing. Select Energy's retail marketing business, which also improved its financial performancebusinesses
earned $2.3 million in 2003 compared to 2002. For the first nine monthsquarter of 2003, the retail
marketing business produced a net loss of $1.6 million2004, compared with a net
loss of
$26.3 million in 2002. Retail marketing is also expected to have a
net loss in the fourth quarter of between $0.4 million and $2.4 million
resulting in a net loss in the range of $2 million to $4$1.9 million for the year.same period in 2003. The improved retail results are
primarily due to improved margins and growth in retail electric sales.
Select Energy's retail business has already contracted for more than 70
percent of the business needed to achieve 2004 margin targets.
Intercompany Transactions: For the first nine months of 2003, CL&P's standard offer service purchases from Select
Energy represented approximately $465$148.5 million in the first quarter of total NU Enterprises' revenues.2004, compared
with $141 million during the same period in 2003. Other transactionsenergy purchases
between CL&P and Select Energy amounted to approximately $101totaled $30 million in revenues for
Select Energy in the first nine monthsquarter of
2004 and $36 million in the first quarter of 2003. Select Energy will continue
to provide standard offer service for its affiliate WMECO through December
31, 2003.Additionally, WMECO's
purchases from Select Energy represented approximately
$110$32 million of NU Enterprises' revenues in the first nine monthsquarter
of 2004, compared with $39 million in the first quarter of 2003. These
amounts are eliminated in consolidation. Total Select Energy wholesale
full requirements revenue for the first nine months of 2003 were $1.2
billion.
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 by management to address the market,
credit and operational exposures arising from the company's
merchant energy business
lines:segment, which include: wholesale (which includesmarketing activities (including limited
energy trading for market and price discovery purposes)purposes as well as asset
optimization) and retail marketing.marketing activities. The framework and degree to
which these risks are managed and controlled is consistent with the
limitations imposed by NU's Board of Trustees as established and
communicated in NU's risk management policies and procedures.
Wholesale and Retail Marketing:Merchant Energy Marketing Activities: Select Energy manages its portfolio
of wholesale and retail marketing contracts and assets to maximize value
while maintaining an acceptable level of risk. At forward market prices in
effect at September 30, 2003,March 31, 2004, the wholesale marketing portfolio which includes the CL&P
standard offer service contract that extends through December 31, 2003 and
other contracts that extend to 2013, 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 maycould be
significant volatility in the energy commodities markets that may impactaffect
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 onof its wholesale marketing
portfolio.
The gross margin realized
could be at a level that is not sufficient to cover Select Energy's other
operating costs, including the cost of corporate overhead.
Hedging:Hedging and Non-Trading: For information on derivatives used for hedging
purposes and nontradingnon-trading derivatives, see Note 2, "Derivative Instruments, Market Risk and
Risk Management,"
to the consolidated financial statements.
Energy Trading Activities Within Wholesale: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
impactaffect net income.
Over
the past year, Select Energy has significantly reduced its trading
activities, and trading now mainly supports the wholesale business for price
discovery, market intelligence and deal execution.
At September 30, 2003,March 31, 2004, Select Energy had trading derivative assets of $89$188.3
million and trading derivative liabilities of $52.8$160.9 million, on a counterparty-
by- counterparty basis, for a net
positive position of $36.2$27.4 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
December 31, 2003, relates primarily to price increases, as trading
activity has decreased. Information regarding nontradingnon-trading and other
derivatives is included in Note 2, "Derivative Instruments, Market
Risk and Risk Management," to the
consolidated financial statements.
There can be no assurances that Select Energy will actually realize cash
corresponding to the present positive net fair value of its trading
portfolio.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. Controls are in placeday and segregating
responsibilities between the individuals actually trading (front office)
and those confirming the trades (middle office). The determination of the
portfolio's fair value is the responsibility of the middle office
independent from the front office.
The methods used to determine the fair value of energy trading contracts
are identified and segregated in the table of fair value of contracts at
September 30, 2003.March 31, 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 forwards and options and other transactions for which specific quotes are not available.
Currently, Select Energy currently has one contractno contracts for which fair value is
determined based upon anon a model or other valuation method. Broker quotes for
electricity are available through the year 2005.2006. 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 based on models or other methods 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 sourcedobtained corresponding
purchase or sale contracts for substantially all of the trading contracts
that have maturities in excess of four years.one year. Because these contracts are
sourced, changes in the value of these contracts due to changesfluctuations in
commodity prices are not expected to impactaffect Select Energy's earnings.
As of and for the three and nine months ended September 30, 2003,March 31, 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 - -------------------------------------------------------------------------------
(Millions of Dollars) At September 30, 2003at March 31, 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 $0.2 $0.2 $ - $ 0.1 $ - $ 0.10.4
Prices provided by
external sources 7.9 8.8 16.5 33.2
Prices based on
models or other
valuation methods - 2.9 - 2.95.4 6.8 14.8 27.0
- -------------------------------------------------------------------------------
Totals $ 7.9 $11.8 $16.5 $36.2$5.6 $7.0 $14.8 $27.4
- -------------------------------------------------------------------------------
The fair value of energy trading contracts decreased by $8.8$5.1 million from
$45$32.5 million at June 30,December 31, 2003 to $36.2$27.4 million at September 30, 2003.March 31, 2004. The
change in fair value of contracts since June 30, 2003, primarily represents a credit
reserve established in the third quarter of 2003, which reduced the fair value of contracts.
The fair value of energythe trading contracts decreased by $4.8 million from $41
million at January 1, 2003 to $36.2 million at September 30, 2003. For the
nine months ended September 30, 2003, the change in fair valueportfolio is primarily attributable
to contracts realized or otherwise settled during the period. There were
no changes in valuation techniques andor assumptions was due to a change in the discount rate management uses to determine the fair value of trading
contracts. In the secondfirst quarter of
2003, the rate was changed from a fixed
rate of 5 percent to a market-based LIBOR discount rate.2004.
- -------------------------------------------------------------------------------
Total Portfolio Fair Value
- -------------------------------------------------------------------------------
Three Months Ended
Nine Months Ended
(Millions of Dollars) September 30, 2003 September 30, 2003March 31, 2004
- -------------------------------------------------------------------------------
Fair value of trading contracts outstanding
at the beginning of the period $45.0 $41.0$32.5
Contracts realized or otherwise settled
during the period (2.2) (7.2)
Fair value of new contracts
when entered into during
the period - -
Changes in fair value
attributable to changes in
valuation techniques and
assumptions - 2.3(5.7)
Changes in fair value of contracts (6.6) 0.10.6
- -------------------------------------------------------------------------------
Fair value of trading contracts outstanding
at the end of the period $36.2 $36.2$27.4
- -------------------------------------------------------------------------------
Changing Market: The breadth and depth of the market for energy trading and
marketing
products in Select Energy's market continuesareas of business continue to be 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 has become shorter term in nature with less liquidity, market
pricing information is becoming less readily available, and participants
are more often unable to meet Select Energy's credit standards without
providing cash or letter of creditLOC support. Select Energy is being adversely affected
by these factors, and there could be a continuing adverse impact on Select
Energy's business.business lines due to its increasing reliance on business
arrangements with a more limited number of counterparties, primarily power
generators. The decrease in the number of counterparties participating in
the market for long-term energy contracts also continues to impactaffect Select
Energy's ability to estimate the fair value of its long-term wholesale
energy contracts.
Changes are occurring in the administration of transmission systems and
system operators in
territories in which Select Energy does business. Regional transmission
organizations (RTO) are being contemplated,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. As more2003 and has created both
challenges and opportunities for Select Energy. For information regarding
thesethe effects of SMD on Select Energy and RTOs, see "Impacts of Standard
Market Design," and "Regional Transmission Organization," in this
Management's Discussion and Analysis. As the market changes becomes available,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 as a resultbecause 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, letters of credit,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 EnergyEnergy's entering into
contracts. The appropriateness of these limits is subject to continuing
review. Concentrations among these counterparties may impactaffect 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 September 30, 2003,March 31, 2004, approximately
8083 percent of Select Energy's counterparty credit exposure to wholesale and
trading counterparties was cash collateralized or rated BBB- or better.
Another five
percentSelect Energy held $70.9 million and $46.5 million of counterparty cash
advances at March 31, 2004 and December 31, 2003, respectively. For
further information, see Note 1K, "Unrestricted Cash from Counterparties,"
to the counterparty credit exposure was to unrated municipalities.consolidated financial statements.
Asset Concentrations: At September 30, 2003,March 31, 2004, positions with twofive counterparties
collectively represented approximately $51$132.2 million, or 5770 percent, of
the $89$188.3 million trading derivative assets. The largest counterparty's
position is secured with letters of creditLOCs and cash collateral. Select Energy holds
anparent company guarantees at above investment grade parent guarantee onratings supporting the
second counterparty's position.remaining positions of the counterparties. None of the other
counterparties represented more than 10 percent of trading derivative
assets at September 30, 2003.March 31, 2004.
Select Energy's Credit: A number of Select Energy's contracts require the
posting of additional collateral in the form of cash or letters of creditLOCs 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 $237$311 million of collateral or letters of creditLOCs to various
unaffiliated counterparties and approximately $75$52 million to several
independent system operators and unaffiliated local distribution companies,
which management believes NU would currently be able to provide.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.
NU has applied to the SEC for authority to expand its financial support of
NU Enterprises. NU primarily seeks 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.
If granted, the SEC's order would permit NU's future investment in Select
Energy above the amount now allowed. NU has no present plans to
significantly expand its EWG portfolio. However, if an investment
opportunity becomes available, NU would be able to pursue it within the new
allowable EWG investment level. NU expects SEC approval by mid-2004.
If the application is not granted by mid-2004 as management expects, then
there could be a negative impact on the merchant energy business line's
ability to achieve its 2004 earnings estimate. This business line depends
on NU parent guarantees to support the energy contracts that make up both
its revenues and expenses. At March 31, 2004, NU parent could guarantee an
additional $191 million of merchant energy business line contracts, but
guarantee levels constantly fluctuate with the market value of the
contracts that are guaranteed and NU's ability to issue new guarantees may
be constrained due to the aforementioned SEC limitation.
In addition, at March 31, 2004, the SEC's 15 percent-of-capitalization test
would have enabled NU to invest only up to an additional $95 million in
these businesses, regardless of NU's liquidity resources. This restriction
might, depending upon the amounts and types of obligations being guaranteed
or collateralized limit the ability of NU to utilize its full remaining
guarantee and collateral capacity. In the event such a limit is
approached, NU would seek regulatory relief or would be required to reduce
its investment in such businesses sufficiently to allow it to provide
additional collateral.
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.
Utility Group Business Development and Capital Expenditures
- -----------------------------------------------------------
Connecticut - CL&P: On July 14, 2003, the Connecticut Siting Council (CSC)
approved a 345,000 volt transmission line project from Bethel, Connecticut
to Norwalk, Connecticut, proposed in October 2001 by CL&P.Connecticut. The configuration of the new
transmission line, enhancements to an existing 115,000 volt transmission
line, and work in related substations areproject is estimated to cost approximately
$200 million. The line wouldmillion and will help address the difficulties in serving the
loadalleviate identified reliability issues in
southwest Connecticut that creates high LMPand help reduce congestion costs for all of
Connecticut. An appeal of the CSC decision by the City of Norwalk is
pending. Management does not expect the appeal to be successful.
Management, however, does not know if the pending appeal will affect CL&P's
schedule in Connecticut.
Unless judicial appeals delayconstructing the project CL&P expectsor the in service date, which is
anticipated to begin construction
on portionsbe by the end of the project in the fourth quarter of 2003.2005. This project is exempt from the
State of Connecticut's moratorium on the approval of new electric and
natural gas transmission projects. At September 30, 2003,March 31, 2004, CL&P has capitalized
approximately $13.1$20.3 million related toassociated 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. 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. CL&P expects
the CSC to rule on the application inby the end of 2004 and for construction
to take place from 2005 through 2007. At September 30, 2003,March 31, 2004, CL&P has
capitalized approximately $7.6$10.7 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, at an estimated cost of $80$90 million. CL&P and the Long Island
Power Authority each own approximately 50 percent of the line. The project
still requires federal and New York state approvals. Given the approval
process, changing pricing and operational rules in the New England and New
York energy markets and pending business issues between the parties, the
expected in-service date remains under evaluation. This project is also
exempt from the State of Connecticut's moratorium on the approval of new
electric and natural gas transmission projects. At September 30, 2003,March 31, 2004, CL&P
has capitalized approximately $5.9$5.2 million related to this project.
Connecticut - Yankee Gas had previously sought rate approval from the DPUC to build a 2.0
billion cubic foot liquefied natural gas storage and production facility in
Waterbury, Connecticut. On October 24, 2003,Gas: Yankee Gas received a draft
decision from the DPUC
approvingsupporting the construction and operation of a 1.2 billion cubic foot
liquefied natural gas storage and production facility.facility in Waterbury,
Connecticut. Construction of the facility, which is expected to take
approximately three years, could begin in earlythe second half of 2004. The draft
decision allows for the deferral of prudently incurred costs related to the
project and requires Yankee Gas to file a rate case to recover these investmentsthis
investment when the facility is placed in service. This project is also
exempt from the State of Connecticut's moratorium on the approval of new
electric and natural gas transmission projects. At September 30, 2003,March 31, 2004, Yankee
Gas has capitalized approximately $1.5$2.7 million related to this project.
A final decision fromOn March 25, 2004, the DPUC is
scheduledapproved a nine mile extension of Yankee Gas'
distribution system in southeastern Connecticut to the New England Gas
Company system in Rhode Island. Yankee Gas hopes to place the extension in
service by October 1, 2004 at an approximate cost of $5 million.
New Hampshire: On February 6, 2004, the NHPUC approved a $70 million
proposal by PSNH to replace a nearly 50 year old coal and oil-burning
boiler at Schiller Station in Portsmouth, New Hampshire with a boiler that
would burn wood. However, PSNH will not commence the project based on a
risk and reward sharing mechanism specified in the NHPUC's order. On
March 3, 2004, PSNH filed a joint motion for November 2003.
Inconsideration with the New
Hampshire Office of the Consumer Advocate, the state Office of Energy and
Planning and the New Hampshire Timberland Owners' Association that, if
approved, would modify the sharing mechanism. If the NHPUC approves the
modification and other approvals are received in a timely manner, then PSNH
anticipates completion of the project in 2006.
Regional Transmission Organization
- ----------------------------------
The FERC has required all transmission owning utilities to voluntarily form
RTOs or to state why this process has not begun.
On October 31, 2003, 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 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 realize the benefits of a competitive wholesale energy market.
In a separate filing made on November 4, 2003, NU along with six other New
England transmission owners requested, consistent with the FERC's pricing
policy for RTOs and Order-2000-compliant independent system operators, that
the FERC approve a single ROE for regional and local rates that would
consist of a proposed 12.8 percent base ROE as well as incentive adders of
0.5 percent for joining a RTO and 1.0 percent for constructing new
transmission facilities approved by the sale of Connecticut Valley Electric
Company's (CVEC) assetsRTO. If the FERC approves the
request, then the transmission owners would receive a 13.3 percent ROE for
existing transmission facilities and a 14.3 percent ROE for new
transmission facilities. In its March 24, 2004 order the FERC partially
accepted this ROE proposal, but set certain issues to PSNH. CVEC is a subsidiary of Central Vermont
Public Service Corporation (CVPS). The sale is expected to close in December
2003 and be effective January 1, 2004. The purchase price will be the book
value of CVEC's assets, currently estimated at approximately $9 million and
an additional $21 million to terminate the above-market wholesale power
purchase agreement CVEC has with CVPS. The $21 million payment will be
recovered over the next several years from PSNH's customers as a Part 3
stranded cost.hearing.
Restructuring and Rate Matters
- ------------------------------
Utility Group: On August 26, 2003, NU's electric operating companies filed
their first transmission rate case at the FERC since 1995. In the filing,
NUthese 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. NU askedThese companies requested that the
FERC to maintain NU'stheir existing 11.75 percent return on equity (ROE)ROE until ana ROE for the New
England Regional Transmission Organization (RTO)RTO is established by the FERC. On October 22, 2003, the FERC
approvedaccepted this filing implementing the proposed rates subject to refund
effective on October 28, 2003. On October 31, 2003, ISO-NE, along with NU and six other New England
transmission companies, filed a proposal with theThe FERC set certain issues to create a RTO for
New England. The RTO is intended to strengthen the independent and efficient
management of the region's power system while ensuring that consumers in New
England continue to have the most reliable system possible to realize the
benefits of a competitive wholesale market.
ISO-NE, as an RTO, will have a new independent governance structure, and will
also become the transmission provider for New England by exercising
operational control over New England's transmission facilities pursuant to a
detailed contractual arrangement with the New England transmission owners.
Under this contractual arrangement, the RTO will have clear authority to
direct the transmission owners to operate their facilities in a manner that
preserves system reliability, including requiring transmission owners to
expand existing transmission lines or build new ones when needed for
reliability. Transmission owners will retain their rights over revenue
requirements, rates and rate designs. The filing requests that the FERC
approve the RTO arrangements for an effective date of March 1, 2004.
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 base ROE as well as incentive adders of 50 basis points for joining an
RTO and 100 basis points for constructing new transmission facilities
approved by the RTO. If the FERC approves the request, the transmission
owners would receive a 13.3 percent ROE for existing transmission facilitieshearing, and
a 14.3 percent ROE for new transmission facilities.final decision in the rate case is expected in 2005.
Connecticut - CL&P:
Public Act No. 03-135 and Rate Proceedings Rate Case:Proceedings: On June 25, 2003, the Governor
of Connecticut signed theinto law Public Act into law. The ActNo. 03-135 (the Act) that amended
Connecticut's 1998 electric utility industry legislation. Among key
features, the Act created a Transitional Standard Offer (TSO) period from
2004 through 2006 that allows the base rate cap for customers to return to
1996 levels, which is an increase of up to 11.1 percent. If energy supply
costs exceed levels established in the TSO rate, these costs will be
recovered through an energy adjustment clause or through the FMCC charge in
the case of incremental LMP costs.
On July 1, 2003, CL&P made a filing with the DPUC to establish TSO service
and to set the TSO rates equal to December 31, 1996 total rate levels. Under
the Act, the DPUC must establish the TSO rates no later than December 15,
2003, with an effective date for the TSO rates of January 1, 2004.
To procure TSO service, an auction process was conducted by CL&P. On October
29, 2003, the auction process was completed and CL&P filed the results of the
auction process with the DPUC.
The Act also required
CL&P to file a four-year transmission and distribution plan with the DPUC.
Accordingly, on August 1,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
that amended rate schedules and proposed changes in electric distribution
service and transmission service rates to reflect a four-year planon December 31, 2003. Other parties also filed petitions for
the
provision of such services. The amended rate schedules were designed to
increase CL&P's annual distribution component of revenues by the following
approximate amounts, beginningreconsideration. On January 1,21, 2004, through January 1, 2007:
- -------------------------------------------------------------------------------
Incremental Percentage
Increase in
Year Incremental Increase Total TSO Rates
- -------------------------------------------------------------------------------
2004 $133.5 million 6.0%
2005 23.2 million 1.0%
2006 24.0 million 1.0%
2007 24.1 million 1.0%
- -------------------------------------------------------------------------------
In its rate case, CL&P cited the need for rate increases to recover 1)
increased costs of providing service, including higher pension and health
care costs, 2) an approximately $250 million per year capital program for
distribution, and 3) the recruitment and training of new workers as a result
of the aging of the current skilled electric craft worker population. CL&P
also requested a tracking mechanism that could annually adjust the electric
transmission rates to reflect FERC-approved transmission tariffs.
However, if the transmission rate tracking mechanism filing process does not
prove to be acceptable to the DPUC CL&P proposed amended annual rate
schedules in its rate application that will be designedagreed to adjustreconsider CL&P's
rates for transmission costs during the rate period.items. Hearings on this filing were held in September 2003April 2004 and October 2003 with a final decision is expected
to be issued in December 2003.
Seabrook Disposition of Proceeds:June 2004. However, CL&P sold its sharealso filed an appeal with the
Connecticut Superior Court on January 30, 2004. The appeal was filed in the
event that the outcome of the Seabrook nuclear
unit on November 1, 2002.DPUC's reconsideration is still not
acceptable to CL&P.
CTA and SBC Reconciliation: The Competitive Transition Assessment (CTA)
allows CL&P received $37 million and recorded a gain on
the sale of approximately $16 million. The gain was recordedto recover stranded costs, such as a regulatory
liability and, when offset by the decommissioning top off and other
adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its
applicationsecuritization costs
associated with the DPUC for approvalrate reduction bonds, amortization of the disposition of the proceeds
from the sale. This filing described CL&P's treatment of its share of the
proceeds from the sale. Hearings in this docket were held in September 2003,regulatory
assets, and a final decision is scheduled to be issued in December 2003. Management
does not expectindependent power producer over market costs while the final decision to have a material effect on CL&P's net
income or its financial position.
CTA and System
Benefits Charge (SBC) Reconciliation: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 3, 2003,1, 2004, CL&P filed its annual CTA and SBC reconciliation with the
DPUC. For the year ended December 31, 2002,2003, total CTA revenues and excess
Generation Services
Charge (GSC)GSC revenues exceeded the CTA revenue requirement by approximately
$93.5$148.3 million. This
amount iswas recorded as a regulatory liability and is
included in other deferred credits on the accompanying
consolidated balance sheet. CL&P has proposed that a portion of the CTA/GSC overrecovery be
utilized to reduce the nuclear stranded cost regulatory asset and that the
remaining amount be carried forward through 2003.sheets. For the same period, SBC revenues exceeded
the SBC revenue requirement by approximately $22.4$25.5 million.
In compliance with a prior decision of the DPUC, a portion of the SBC
overrecovery was applied to regulatory assets, and the remaining overrecovery
of $18.6 million was applied to the CTA. Management expects a
final decision in this docket from the DPUC in this docket by the end of 2003. Management does not expect
the final decision to have a material effect on CL&P's net income or its
financial position.2004.
Connecticut - Yankee Gas:
Rate Case: In 2003, Yankee Gas earned a ROE below the DPUC-authorized level
of 11 percent. As a result of higher pension costs and other factors not
addressed by current rate levels, management expects that Yankee Gas will
continue to underearn the DPUC-authorized ROE. Yankee Gas expects to file
a rate case in July 2004 for a rate increase to take effect in January of
2005.
IERM Settlement: On April 29, 2004, Yankee Gas and the Office of Consumer
Counsel filed a settlement agreement which provides for the termination of
Yankee Gas' Infrastructure Expansion Rate Mechanism (IERM): On June 25, 2003, the DPUC
issued a final decision in the 2002. The settlement
finalizes ratemaking treatment for all Yankee Gas IERM docket. The DPUC concluded that the
basic concept of IERM is valid, appropriateprojects and beneficial. The DPUC orderedreturns
Yankee Gas to provide a credit to customers for 2002 and 2003 overrecoveries
during December 2003 through February 2004. As ordered, Yankee Gas submitted
a compliancetraditional capital investment test. The filing withseeks DPUC
approval in the DPUC on August 15, 2003 which included an
estimate of total overrecoveries for 2002 and 2003 of approximately $5.9
million. This amount has been recorded as a regulatory liability. On
September 11, 2003, the DPUC approved Yankee Gas' compliance filing,
including the calculation of the $5.9 million in estimated overrecoveries to
be refunded from December 2003 through February 2004.
On October 1, 2003, Yankee Gas filed with the DPUC its 2004 IERM compliance
filing. This filing is required annually on October 1 of each year to
provide a reconciliation of the system expansion program and the earnings
sharing mechanism projection. At this time, the DPUC has not issued a
schedule for this docket.second quarter.
New Hampshire:
Transition Service: On September 12, 2003, in accordance withDelivery 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 for an updated transitiona delivery service rate of $0.0513 per kilowatt-hour
(kWh), subjectcase and tariffs with the
NHPUC on December 29, 2003 to adjustment, for commercial, industrial, and residential
customers for the periodincrease electricity delivery rates by
approximately $21 million, or 2.6 percent, effective February 2004 through January 2005. The transition
service rate is $0.0467 per kWh for industrial customers and $0.0460 per kWh
for residential and small general service customers. Both rates are for the
period February 2003 through January1, 2004. In
accordance with state law,
these rates are toaddition, PSNH is requesting that recovery of FERC-regulated transmission
costs be PSNH's actual, prudent and reasonable costsadjusted annually through a tracking mechanism. The NHPUC
suspended the proposed rate increase until the conclusion of providing such power.the delivery
rate case. Hearings are scheduled for late November 2003.August 2004, and a decision is
expected in the third or fourth quarter of 2004 with rates retroactively
applied to February 1, 2004.
SCRC Reconciliation Filing: The transition service rates currently in effect are not fully recovering
PSNH's generation and purchased-power costs, including earning a return on
PSNH's generation investment. Transition service underrecoveries, in
addition to other stranded cost components of the Stranded Cost Recovery Charge (SCRC), amounted
allows PSNH to approximately $24 million sincerecover its stranded costs. On an annual basis, PSNH files
with the start of
restructuring on May 1, 2001 through September 30, 2003. This amount
excludes the gain on the sale of Seabrook.
Delivery Rate Case: PSNH's delivery rates are fixed by the Restructuring
Settlement until February 1, 2004. Under the Restructuring Settlement, PSNH
is required to file a rate case by December 31, 2003 to determine PSNH's
delivery rates.
SCRC Reconciliation Filing: On May 1, 2003, PSNH filedNHPUC a SCRC reconciliation filing for the period January 1, 2002, through December 31, 2002 with the New
Hampshire Public Utilities Commission (NHPUC).preceding calendar
year. This filing includedincludes the reconciliation of stranded cost revenues
with stranded costs, the
reconciliation ofand transition energy service (TS) revenues with transition service costs,
andTS
costs. The NHPUC reviews the filing, including a net proceeds calculation related toprudence review of PSNH's
generation operations. The 2003 SCRC filing was made on April 30, 2004.
Management does not expect the sale of North Atlantic Energy
Corporation's share of Seabrook and the subsequent transfer of those net
proceeds to PSNH. Upon the completion of discovery and technical sessions
with NHPUC staff and the New Hampshire Officereview of the Consumer Advocate (OCA),
PSNH, the NHPUC Staff and the OCA entered into a stipulation and settlement
agreement that was filed with the NHPUC on September 15, 2003. An order from
the NHPUC approving the settlement agreement was received in October 2003.
The settlement agreement did not2003 SCRC filing to have a
material impacteffect on PSNH's net income or its financial position.
Massachusetts:
Transition Cost Reconciliation:Reconciliations: On March 31, 2003, WMECO filed its 2002
annual
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 2002 and included
the renegotiated purchased power contract related to the Vermont Yankee
nuclear unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001 annual
transition
cost reconciliation, which addressed WMECO's cost tracking mechanisms. As
part of that order, the DTE directed WMECO to revise its 2002 annual
transition cost reconciliation filing. The revised filing was submitted to
the DTE on September 23,22, 2003. Hearings werehave been held, in October
2003, and the timing of
a final decision from the DTE is expected in the first half of
2004.uncertain. Management does not expect the outcome of
this docket to have a material adverse impact on WMECO's net income or
its financial position.
For information regarding commitments and contingencies relatedOn 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 restructuring and rate matters, see Note 4A, "Commitments and Contingencies -
Restructuring and Rate Matters," to the consolidatedhave a
material adverse impact on WMECO's net income or financial statements.position.
Critical Accounting Policies and Estimates Update
- -------------------------------------------------
Accounting for Incremental LMP Costs:Transmission Revenues Subject to Refund: The determination$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 whether CL&P's
retail11.75 percent, which is unchanged
from the ROE included in previous transmission rates and is currently being
billed. Subsequent to this transmission rate case filing, the FERC
approved ISO New England as a RTO. The FERC set for hearing a proposed
12.8 percent ROE with a 0.5 percent adder for joining a RTO and a 1.0
percent adder for future transmission expansion. The higher proposed RTO
rate and adders are not 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. Any amounts probable of
refund to customers would reduce revenues and be recorded as a regulatory
liability. However, at this time management believes that its request will
be approved by the FERC, and as a result, that no refunds are likely.
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. The rate case is
not expected to be concluded until the third or CL&P's standard offer service suppliers are responsiblefourth quarter of 2004.
The method for incremental LMPrecovering any retroactive rate increase from customers has
not yet been determined.
The costs driving the need for the rate increase, which include pension
expense, depreciation expense, and transmission and reliability expenses,
that have been incurred from February 1, 2004 through March 31, 2004 have
been expensed as incurred. When those incurred costs become probable of
recovery in rates management will record those costs as regulatory assets.
This may result in lower PSNH earnings for the first two or three quarters
of 2004 with an adjustment in the third or fourth quarter of 2004 to
reflect the final rate increase retroactive to February 1, 2004.
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.
Specific authoritative accounting guidance on how to account for the effect
the Medicare federal subsidy has on NU's PBOP Plan has not been finalized
by the Financial Accounting Standards Board (FASB). 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 for 2003 financial reporting. The election
was 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, which decreased the PBOP benefit obligation by $19.5
million and increased actuarial gains by $19.5 million with no impact on
2003 expenses, assets, or liabilities. The actuarial gain, the estimate of
which was refined in the first quarter of 2004 to $20 million, will be
amortized as a reduction to PBOP expense over 13 years beginning in 2004.
PBOP expense in 2004 will also reflect a lower interest cost due to the
reduction in the December 31, 2003 benefit obligation. Management
estimates that the reduction in PBOP expense in 2004 will be approximately
$2 million.
On March 12, 2004, the FASB issued a draft FSP that would supersede FSP No.
FAS 106-1. This draft FSP 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. The accounting treatment under the proposed FSP is consistent
with NU's accounting treatment at December 31, 2003.
The estimated 2004 reduction in PBOP expense of approximately $2 million
could change as a result of the implementationcompletion of an actuarial estimate of the
SMD in New
England andsubsidy based on recent prescription drug claim experience. The subsidy
estimate could also change as regulations are promulgated by the impacts on Select Energy, NU Enterprises, CL&P and NU are
described in "Impacts of Standard Market Design" included in this Management
Discussion and Analysis.
There are significant accounting conclusions related to the incremental LMP
dispute. Management continues to believe that the incremental LMP costs
recorded as a regulatory asset are probable of future recovery from customers
and has recorded a regulatory assetfederal
agencies responsible for these costs on CL&P's financial
statements. Management must maintain this belief as CL&P argues before the
FERC that the incremental LMP costs should be the responsibilityadministration of the standard offer suppliers as ordered by the DPUC. If at anytime before the
regulatory asset is fully recovered management cannot conclude that the costs
are probable of future recovery, then the remaining regulatory asset would be
written off. To the extent incremental LMP costs have been recovered through
the EAC, management must determine whether or not a regulatory liability is
required. Incremental LMP costs incurred and recovered are currently
included in accounts payable to the standard offer service suppliers. To the
extent CL&P is unable to collect these costs from its customers, CL&P would
not pay the suppliers for these costs which are included in accounts payable.
As a result, CL&P would have no negative earnings impact; rather Select
Energy would be required to write off its accounts receivable from CL&P and
record a corresponding loss.
Determining what party will ultimately be responsible for incremental LMP
costs requires a significant amount of judgment. Hearings on this issue
before a FERC administrative law judge occurred in October 2003. As a result
of these hearings, the parties agreed to a settlement conference before a
FERC settlement judge, which occurred from November 4, 2003 to November 5,
2003. No settlement has been reached as of November 7, 2003. Resolution of
this issue by the FERC will likely be in 2004, and a FERC administrative law
judge decision may be issued in the fourth quarter of 2003. At this point,
management believes that it is premature to record a reserve for incremental
LMP costs. Management continues to believe that these incremental LMP costs
will ultimately be recovered from CL&P's customers based upon its legal
interpretation of standard offer supply contracts. Management will continue
to evaluate the likelihood of recovery of these costs in the fourth quarter.
All developments through the time NU's 2003 annual report on Form 10-K is
filed will be evaluated, and any resulting impacts on the amounts included in
NU's financial statements will be reflected in 2003 earnings and the
December 31, 2003 consolidated balance sheet.
Adjustments to Estimates of 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. Billed
revenues are based on meter readings.
Unbilled revenues are estimated 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 to
calculate the 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. Small differences in the actual DE
factor to the estimated DE factor can have a significant impact on estimated
unbilled revenue amounts.
In the third quarter of 2003, the unbilled sales estimates for all Utility
Group companies were tested using the cycle method and will be tested at
least annually hereafter. The cycle method is historically more accurate
than the requirements method, when used in a mostly weather-neutral month.
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 testing indicated that the estimate of total unbilled
revenues should be adjusted, which resulted in a net positive after-tax
earnings impact of approximately $5.7 million in the third quarter of 2003.
The positive after-tax impacts on CL&P, PSNH, and WMECO were $7.2 million,
$3.3 million, and $0.3 million, respectively. There was a negative after-tax
impact on Yankee Gas of $5.1 million.
The estimate of unbilled revenues is sensitive to numerous factors that can
impact the amount of energy that is ultimately delivered to customers.
Estimating the impact of these factors is complex and requires management
judgment.
Energy Trading and Derivative Accounting: In April 2003, the FASB issued
Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities," which
amended existing derivative accounting guidance. SFAS No. 149 incorporates
interpretations that were included in previous Derivative Implementation
Group (DIG) guidance, clarifies certain conditions, and amends other existing
pronouncements. It was effective for contracts entered into or modified
after June 30, 2003. The new rules indicate that derivative contracts that
are subject to unplanned netting and can be settled for cash versus physical
delivery would no longer qualify for the normal purchases and sales
exception, which would require fair value accounting. Management has
determined that the adoption of SFAS No. 149 did not change NU's accounting
for wholesale and retail marketing contracts that were entered into prior to
July 1, 2003 or affect the ability of NU to elect the normal purchases and
sales exception.
Emerging Issues Task Force (EITF) Issue No. 03-11 "Reporting Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, and 'Not Held
for Trading Purposes' as Defined in EITF Issue No. 02-3, 'Issues related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities'" was derived from EITF Issue No. 02-3, which requires net
reporting in the income statement in revenues of energy trading activities.
Issue No. 03-11 addresses income statement classification of derivatives that
are not related to energy trading activities. Prior to Issue No. 03-11,
there was no specific accounting guidance that addressed the classification
in the income statement of Select Energy's retail marketing and wholesale
contracts, many of which are derivatives. The only applicable guidance was
EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as
an Agent." The indicators of gross revenue reporting include whether the
entity is the primary obligor in the arrangement, whether the entity has
inventory or credit risk, latitude in establishing price, and discretion in
supplier selection. Indicators of net revenue reporting are whether the
supplier is in the primary obligor in the arrangement, the entity earns a
fixed amount and the supplier has credit risk.
On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that
determining whether realized gains and losses on contracts that physically
deliver and are not held for trading purposes should be reported on a net or
gross basis is a matter of judgment that depends on the relevant facts and
circumstances. The EITF indicated that the indicators set forth in Issue No.
99-19 should continue to be considered and provided no new accounting
guidance. Additionally, the consensus recommends disclosure of where the
gains and losses are recorded in the income statement, and whether they are
presented on a net or gross basis. Issue No. 03-11 is effective for NU
prospectively on October 1, 2003.
Select Energy currently reports the settlement of short-term and long-term
derivative contracts that are not held for trading purposes on a gross basis,
generally with sales in revenues and purchases in expenses. Short-term sales
and purchases represent power that is purchased to serve full requirements
contracts but is ultimately not needed based on the actual load of the full
requirements customers. This excess power is sold to the independent system
operator or to other counterparties. Management is currently evaluating the
impact of the consensus in Issue No. 03-11 as it relates to income statement
classification of Select Energy's short-term energy purchases and sales.
Management will complete this evaluation in the fourth quarter in accordance
with Issue No. 03-11. If management determines that revenues and expenses
related to short-term sales and purchases should be reported net, then there
could be a significant reduction in both Select Energy's revenues and
expenses with no operating income or net income impact. For the first nine
months of 2003, short-term and non-requirements sales amounted to
approximately $600 million.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning
of "not clearly and closely related regarding contracts with a price
adjustment feature" as it relates to the election of the normal purchase and
sales exception to derivative accounting. The implementation of this
guidance is required for the fourth quarter of 2003 for NU. Management is
currently evaluating the impacts of Issue No. C-20, but believes that when it
is implemented, Issue No. C-20 will likely result in CL&P recording the fair
value of two existing power purchase contracts as derivative liabilities with
offsetting regulatory assets, as these contracts are part of stranded costs
and as management believes that these costs will continue to be recovered in
rates. Management's preliminary estimates of the fair values of these long-
term power purchase contracts indicate that the contracts have a combined
negative fair value of approximately $16 million.
Accounting for RMS Variable Interest Entity: On June 30, 2001, NU sold RMS
for $10 million in the form of convertible cumulative 5 percent preferred
stock and a warrant to buy 25 percent of the outstanding common stock of RMS
for $1,000 expiring in 2021. NU also agreed to guarantee a $3 million line
of credit for RMS through 2005. In the second and third quarters of 2003, RMS
began drawing on this line of credit and the balance outstanding at
September 30, 2003 was $0.5 million.
In January 2003, the FASB issued FIN 46 which was effective for NU on July 1,
2003 (NU did not electively delay implementation until the fourth quarter of
2003). RMS is a variable interest entity (VIE), as defined. FIN 46 requires
that the party to a VIE that absorbs the majority of the VIE's losses,
defined as the "primary beneficiary," consolidate the VIE. Upon adoption of
FIN 46, management determined that NU is the "primary beneficiary" of RMS
under FIN 46 and that NU is now required to consolidate RMS into NU's
financial statements. To consolidate RMS, NU adjusted the carrying value of
its preferred stock investment in RMS to the net book value of RMS. This
adjustment resulted in a negative $4.7 million after-tax cumulative effect of
accounting change. NU's remaining investment in RMS totaled $2.7 million at
September 30, 2003. NU has no other VIE's for which NU is defined as the
"primary beneficiary."
Goodwill Impairment Testing: NU conducts annual goodwill impairment testing
as of October 1st. Testing of current goodwill balances commenced in October
of 2003. Management does not expect that the completion of the impairment
testing in the fourth quarter of 2003 will result in an impairment loss.
Pension Plan Accounting: At December 31, 2002, the assets of the NU
noncontributory defined benefit plan (Plan) exceeded the accumulated benefit
obligation (ABO) by approximately $78 million. The ABO is the obligation for
employee service provided to date and does not assume future compensation
increases. At September 30, 2003, the estimated fair value of Plan assets
exceeded the December 31, 2002 ABO by approximately $220 million. If the
ABO, when remeasured next on December 31, 2003, exceeds the fair value of
Plan assets at that time, then NU would be required to record an additional
minimum pension liability.Medicare program.
Other Matters
- -------------
Other
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 components of significantfollowing table provides the variances in income statement variancesline items
for the third
quarterconsolidated statements of 2003 andincome for NU included in this report on
Form 10-Q for the first ninethree months of 2003 are provided in the table
below.ended March 31, 2004:
Income Statement Variances
(Millions of Dollars)
20032004 over/(under) 2002
------------------------------------
Third Nine
Quarter2003
----------------------
Amount Percent Months Percent
------- -------
------ -------
Operating Revenues $640 45% $1,360 35%Revenues: $254 16%
Operating Expenses:
Fuel, purchased and net
interchange power 595 70 1,204 55211 22
Other operation 40 22 6438 20
Maintenance 11 Maintenance (13) (18) (24) (12)25
Depreciation - - (6) (4)5 10
Amortization (5) (9) 48 56(28) (49)
Amortization of rate
reduction bonds 5 15 (1) (1)4 10
Taxes other than income taxes 6 12 2 14 5
---- ---- ------ ----
Total operating expenses 628 48 1,287 37245 17
---- ---- ------ ----
Operating income 12 10 73 229 5
---- ---- ------ ----
Interest expense, net (4) (6) (17) (8)(1) (1)
Other income/(loss),income, net (27) (85) (14) (70)1 (a)
---- ---- ------ ----
Income before income tax expense (11) (14) 76 5311 11
Income tax expense (7) (21) 41 974 9
Preferred dividends of subsidiaries - -
- -
---- ---- ------ ----
Income before cumulative effect
of accounting change (4) (9) 35 36
Cumulative effect of accounting
change, net of tax benefit
of $2,553 (5) (100) (5) (100)
---- ---- ------ ----
Net Income $ (9) (19)% $ 30 31%7 12%
==== ====
====== ====(a) Percent greater than 100.
Comparison of the ThirdFirst Quarter of 20032004 to the ThirdFirst Quarter of 20022003
Operating Revenues
Total revenues increased $640by $254 million or 45 percent in the thirdfirst quarter of 2003,2004,
compared with the same period in 2002,2003, due to higher revenues from NU
Enterprises ($611183 million), higher Utility Group electric revenues ($49
million or $46 million after intercompany eliminations) and higher Utility
Group gas revenues ($29 million after intercompany eliminations)20 million).
The NU Enterprises' revenuerevenues increase is primarily due to higher wholesale
revenues for Select Energythe merchant energy segment resulting from higher short-term sales.electric
prices and higher gas volumes. The Utility Group revenueelectric revenues
increase is primarily due to higher retail revenue ($121105 million),
partially offset by lower wholesale revenue ($8854 million). The regulatedelectric
retail revenue increase is primarily due to increases in the energy service
revenues for CL&P's recovery of
incremental LMP costs&P, PSNH and WMECO ($6976 million), increased electric sales volumesFederally Mandated
Congestion Cost revenues for CL&P ($4440 million) including a positive adjustment in estimated unbilled revenue, and higher price mix among customer classessales volume
($1114 million), partially offset by lower revenues for Yankee ($4 million) primarily due toCL&P EAC revenue as a downward adjustment
in estimated unbilled revenues. The total revenue impactresult of the unbilled
revenues adjustment was a positive $28 million. Regulatedend of
EAC billings in December 2003 ($12 million) and lower rates for CL&P and
WMECO stranded cost recovery ($10 million). Electric retail electric kWh sales
increased by 4.92.7 percent in the thirdfirst quarter of 2003 after
reflecting adjustments to unbilled revenues.2004. The regulatedelectric
wholesale revenue decrease is primarily due to lower PSNH sales as a resultshort-term
transactions ($46 million) and the expiration of owning less
generationlong-term contracts ($8
million). The higher Utility Group gas revenue increase is primarily due
to the salerecovery of Seabrook.higher gas costs. Firm natural gas sales increased by
6.8 percent in the first quarter of 2004 from the same period of 2003,
which reflected a negative adjustment to the estimate of unbilled revenues
in the first quarter of 2003. Excluding the adjustment to the estimate of
unbilled revenues, firm natural gas sales decreased by 0.5 percent in the
first quarter of 2004 from the same period in 2003.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $595by $211 million or
70 percent
in the thirdfirst quarter of 2003,2004, primarily due to higher wholesale energy purchasesactivity at
NU Enterprises ($634138 million after intercompany eliminations), partially offset by lower purchased-power and higher
purchased power costs for the Utility Group ($3573 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 ($76
million) and WMECO ($6 million), higher Yankee Gas expenses due to
increased gas prices and higher sales volume ($25 million), offset by lower
fuel EAC amortization for CL&P ($12 million), lower wholesale transactions
for CL&P ($15 million), and lower expenses for PSNH due to lower regulated
wholesale purchases ($10 million).
Other Operation
Other operation expenseexpenses increased $40$38 million in the first quarter of
2004, primarily due to higher competitive business cost of goods sold expenses and higher expenses resulting from
business growth ($3516 million), higher regulated business administrative and
general expenses ($67 million), primarily due to higher health carepension costs, and lower pension income, and higher
RMR related
transmission expense ($9 million), higher fossil production expense ($3
million), partially offsetand 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 operations 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 $11 million in the first quarter of 2004,
primarily due to the absence of the 2003 positive resolution of the CL&P
Millstone use of proceeds docket ($5 million), higher fossil production
expense ($2 million), higher competitive transmission expense ($2 million),
and higher distribution expense ($2 million).
Depreciation
Depreciation increased by $5 million in the first quarter of 2004 due to
higher Utility Group plant balances.
Amortization
Amortization decreased by $28 million in the first quarter of 2004
primarily due to lower nuclearUtility Group recovery of stranded costs and a
decrease in amortization expense resulting from the saleimplementation of Seabrookthe
CL&P distribution rate case decision effective in January 2004 ($7
million).
Maintenance
Maintenance expense decreased $13 million primarily due to lower transmission
expenses at NU Enterprises ($6 million), lower regulated electric
distribution expenses primarily due to lower storm related expenses ($3
million), and lower nuclear expense due to the 2002 sale of Seabrook ($2
million).
Amortization
Amortization decreased $5 million in 2003, primarily due to lower recovery of
stranded costs by the Utility Group.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $5by $4 million in the first
quarter of 2004 due to an increase
in the scheduled paymentrepayment of principal.more principal as compared to 2003.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $6 million in the third quarter of
2003 primarily due to the recognition in 2002 of a Connecticut sales and use
tax audit settlement ($8 million), partially offset by a payment in 2002 to
compensate the Town of Waterford for lost property tax revenue as a result of
the sale of Millstone in 2001 ($3 million).
Interest Expense, Net
Interest expense, net decreased $4 million primarily due to lower interest at
NU parent and CL&P resulting from lower rates ($4 million) and lower North
Atlantic Energy Corporation (NAEC) interest due to the retirement of debt ($1
million), partially offset by higher competitive business interest as a
result of higher debt levels ($2 million).
Other Income/(Loss), Net
Other income/(loss), net decreased $27 million primarily due to the third
quarter 2002 elimination of certain reserves associated with NU's ownership
share of Seabrook ($25 million).
Income Tax Expense
Income tax expense decreased $7 million primarily due to lower taxable
income.
Cumulative Effect of Accounting Change, Net of Tax Benefit
The cumulative effect of accounting change, net of tax benefit was recorded
in the third quarter of 2003 in connection with the adoption of FIN 46,
effective July 1, 2003, which required NU to consolidate RMS into NU's
financial statements and adjusted its equity interest as a cumulative effect
of an accounting change.
Comparison of the First Nine Months of 2003 to the First Nine Months of 2002
Operating Revenues
Total revenues increased $1.4 billion or 35 percent in the first nine months
of 2003, compared with the same period in 2002, due to higher revenues from
NU Enterprises ($1.1 billion after intercompany eliminations) and higher
Utility Group revenues ($234 million after intercompany eliminations).
NU Enterprises' revenue increase is primarily due to higher wholesale
revenues for Select Energy resulting from the New Jersey basic generation
service and higher short-term sales. The Utility Group revenue increase is
primarily due to higher retail revenue ($311 million), partially offset by
lower wholesale revenue ($72 million). The regulated retail revenue increase
is primarily due to higher retail electric sales volumes ($121 million),
higher CL&P recovery of incremental LMP costs ($99 million), higher Yankee
Gas revenue resulting from higher purchased gas adjustment clause revenue
($47 million) and higher gas sales volumes ($22 million), and higher price
mix among customer classes for the regulated companies ($19 million).
Regulated retail electric kWh sales increased by 4.9 percent and firm natural
gas sales increased by 3.1 percent in 2003, both after the adjustments to
unbilled revenues. The regulated wholesale revenue decrease is primarily due
to lower PSNH 2003 sales as a result of the sale of Seabrook.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $1.2 billion or
55 percent in 2003, primarily due to higher wholesale energy purchases at NU
Enterprises ($1.2 billion after intercompany eliminations) and higher
purchased-power costs for the Utility Group ($33 million after intercompany
eliminations).
Other Operation
Other operation expense increased $64 million primarily due to higher
competitive business expenses resulting from business growth ($43 million),
higher RMR related transmission expense ($17 million), higher conservation
and load management expenditures ($14 million), and higher regulated business
administrative and general expenses ($11 million), primarily due to higher
health care costs and lower pension income, partially offset by lower nuclear
expense due to the sale of Seabrook ($27 million).
Maintenance
Maintenance expense decreased $24 million primarily due to lower nuclear
expense resulting from the sale of Seabrook ($24 million) and lower
competitive transmission expenses ($6 million), partially offset by higher
fossil production expenses resulting from PSNH generation maintenance
overhauls ($5 million).
Depreciation
Depreciation decreased $6 million in 2003 primarily due to lower
decommissioning and depreciation expenses resulting from 2002 depreciation of
Seabrook as compared to no 2003 depreciation ($8 million) and lower NU
Enterprises depreciation due to a study which resulted in lengthening the
useful lives of certain generation assets ($3 million), partially offset by
higher Utility Group depreciation resulting from higher plant balances.
Amortization
Amortization increased $48 million in 2003 primarily due to higher
amortization related to the Utility Group's recovery of stranded costs, in
part resulting from higher wholesale revenue from the sale of independent
power producer related energy.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds decreased $1 million due to the
scheduled payment of principal.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $2 million primarily due to the
recognition in 2002 of a Connecticut sales and use tax audit settlement ($8
million), partially offset by a payment in 2002 to compensate the Town of
Waterford for lost property tax revenue as a result of the sale of Millstone
($3 million) and lower New Hampshire property taxes due to the sale of
Seabrook ($2 million).
Interest Expense, Net
Interest expense, net decreased $17 million primarily due to lower interest
for the regulated subsidiaries resulting from lower rates ($10 million),
lower interest at NU parent as a result of the interest rate swap related to
its $263 million fixed-rate senior notes ($7 million) and lower NAEC interest
due to the retirement of debt ($3 million), partially offset by higher
competitive business interest as a result of higher debt levels ($4 million).
Other Income/(Loss), Net
Other income/(loss), net decreased $14 million primarily due to the third
quarter 2002 elimination of certain reserves associated with NU's ownership
share of Seabrook ($25 million), partially offset by a charge in the first quarter
of 2002 reflecting2004 primarily due to an increase in Connecticut gross earnings tax as a
write-downresult of NU's investmentsan increase in NEONrevenues for NU Enterprises, CL&P and Acumentrics ($15 million).Yankee Gas.
Income Tax Expense
Income tax expense increased $41 million due to higher taxable income and the
recording in 2002 of WMECO investmentbefore tax credits resulting from a regulatory
decision ($13 million).
Cumulative Effect of Accounting Change, Net of Tax Benefit
The cumulative effect of accounting change, net of tax benefit was recorded
in the third quarter of 2003 in connection with the adoption of FIN 46 which
required NU to consolidate RMS into NU's financial statements and adjust its
equity interest as a cumulative effect of an accounting change.expense.
INDEPENDENT ACCOUNTANTS' REPORT
To the Board of Trustees and Shareholders
of Northeast Utilities:
We have reviewed the accompanying condensed consolidated balance sheet of
Northeast Utilities and subsidiaries ("the Company") as of September 30,
2003,March 31, 2004,
and the related condensed consolidated statements of income for the
three-month and nine-month periods ended September 30, 2003 and 2002, and of cash flows
for the nine-monththree-month periods ended September 30, 2003March 31, 2004 and 2002.2003. These interim
financial statements are the responsibility of the Company's management.
We conducted our reviews in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical
procedures and of making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit
conducted in accordance with auditing standards generally accepted in the
United States of America, 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 auditing standards generally
accepted in the United States of America, the consolidated balance sheets
and consolidated statements of capitalization of Northeast Utilities and
subsidiaries as of December 31, 20022003 and 2001,2002, and the related consolidated
statements of income, comprehensive income, shareholders' equity, cash
flows, and income taxes for each of the three years thenin the period ended
December 31, 2003 (not presented herein) and in our report dated January 28, 2003 (February 27, 2003 as to Note 8A),February 23,
2004, we expressed an unqualified opinion (which includes an explanatory
paragraphsparagraph 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, and its adoption in 20022003 of
Emerging Issues Task Force Issue 02-3, "Accounting03-11, "Reporting Realized Gains and Losses
on Derivative Instruments that are Subject to FASB Statement No. 133 and not
'Held for Contracts InvolvedTrading Purposes' as Defined in Energy TradingIssue No. 02-3," and Risk
Management Activities"Financial
Accounting Standards Board 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, 20022003 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
NovemberMay 7, 20032004
Northeast Utilities and Subsidiaries
The Connecticut Light and Power Company and Subsidiaries
Public Service Company of New Hampshire and Subsidiaries
Western Massachusetts Electric Company and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)
A. Presentation
The accompanying unaudited financial statements should be read in
conjunction with this complete report on Form 10-Q the first and
second quarter 2003 reports on Form 10-Q, 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 20022003 Form 10-K, and the
current reportreports on Form 8-K dated SeptemberJanuary 22, 2004 and March 30,
2003.2004. The accompanying financial statements contain, in the
opinion of management, all adjustments necessary to present fairly
NU's and each NU company'sthe above companies' financial position at September 30, 2003,March 31, 2004
and the results of operations for the
three-month and nine-month periods ended September 30, 2003 and
2002, and statements of cash flows for the nine-monththree-month
periods ended September 30, 2003March 31, 2004 and 2002.2003. All adjustments are of a
normal, recurring nature except those described in Note 1C.1B. Due
primarily to the seasonality of NU's business and to the quarterly
earnings profile of the merchant energy business segment in 2004,
the results of operations and statements of cash flows for the
nine-monththree-month periods ended September 30,March 31, 2004 and 2003, and 2002, 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 have been made to
conform with the current period presentation. Reclassifications
were made to regulatory asset and liability amounts and special
deposits on the accompanying consolidated balance sheets.
Reclassifications have also been made to the accompanying consolidated balance sheets and
statements of cash flows.
B. New Accounting Standards
Consolidation of Variable Interest Entities: In December 2003, the
Financial Accounting Standards Board (FASB) issued a revised
version of FASB Interpretation No. (FIN) 46, "Consolidation of
Variable Interest Entities," (FIN 46R). FIN 46R was effective for
NU for the first quarter of 2004 and did not have an impact on any
of NU's previously identified variable interest entities (VIE).
Based on management's review of NU's independent power producer (IPP)
contracts, no new VIEs have been identified.
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 March 31, 2004, the maximum level of exposure
in accordance with 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 $748.1 million. Additionally, NU
had $63.8 million of LOCs issued for the benefit of NU Enterprises
outstanding at March 31, 2004. In conjunction with its investment
in R. M. Services, Inc. (RMS), NU guarantees a $3 million line of
credit through 2005, of which $2.2 million was outstanding at March
31, 2004, and is included in the $748.1 million of total guarantees
outstanding. Effective July 1, 2003, the financial statements of
RMS, including its line of credit balance, are consolidated with
NU's financial statements.
CL&P has 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. On
April 30, 2004, the DPUC approved CL&P's request to remove this
surety bond requirement prior to renewal. At March 31, 2004, NU
had outstanding guarantees primarily to the Utility Group of $42.3
million, including the LMP-related surety bonds. This amount is
included in the total outstanding NU guarantee amount of $748.1
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.
NU currently has authorization from the Securities and Exchange
Commission (SEC) to provide up to $500 million of guarantees for NU
Enterprises through June 30, 2004, and has applied for authority to
increase this amount to $750 million through September 30, 2007.
The guarantees to the Utility Group are subject to a separate $50
million SEC limitation apart from the current $500 million
guarantee limit. The amount of guarantees outstanding for
compliance with the SEC limit for NU Enterprises and RMS is $309
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.
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. Billed revenues are
based on meter readings, whereas unbilled revenues are based on
estimates of electricity and gas delivered to customers. Such
estimates are subject to adjustment when actual meter readings become
available, when changes in estimating methodology occur and under
other circumstances.
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
Services Company's (Yankee Gas) distribution business, continue to
be cost-of-service rate regulated, and management believes that the
application of SFAS No. 71 to that portionthose business portions of those businessesthe
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 September 30, 2003
- -------------------------------------------------------------------------------March 31, 2004
--------------------------------------------------------------------------
NU
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
- ---------------------------------------------------------------------------------------------------------------------------------------------------------
Recoverable nuclear costs $ 134.164.9 $ 65.91.2 $ 34.232.4 $ 34.031.3
Securitized assets 1,763.2 1,152.7 475.9 134.61,614.1 1,089.2 454.5 70.4
Income taxes, net 277.6 176.5 42.1 49.8248.0 144.8 43.1 58.6
Unrecovered contractual
obligations 224.4 111.1 55.5 57.8370.9 218.4 68.0 84.5
Recoverable energy costs 305.0 65.1 224.1 3.8263.2 47.2 212.5 3.5
Other 243.4 91.0 140.2 (38.2)
- -------------------------------------------------------------------------------360.9 139.1 156.2 17.7
----------------------------------------------------------------------------
Totals $2,947.7 $1,662.3 $972.0 $241.8
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------$2,922.0 $1,639.9 $966.7 $266.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At December 31, 2002
- -------------------------------------------------------------------------------2003
----------------------------------------------------------------------------
NU
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Recoverable nuclear costs $ 85.482.4 $ 10.616.4 $ 36.833.3 $ 38.032.7
Securitized assets 1,891.8 1,244.5 505.4 141.91,664.0 1,123.7 465.3 75.0
Income taxes, net 331.9 170.5 96.5 54.2253.8 140.9 44.2 60.1
Unrecovered contractual
obligations 239.3 116.8 58.7 63.8378.6 221.8 69.9 86.9
Recoverable energy costs 299.6 49.3 241.7 4.3255.7 30.1 218.3 3.7
Other 228.1 111.0 87.0 (18.5)
- -------------------------------------------------------------------------------339.5 140.1 138.4 9.8
----------------------------------------------------------------------------
Totals $3,076.1 $1,702.7 $1,026.1 $283.7
- -------------------------------------------------------------------------------$2,974.0 $1,673.0 $969.4 $268.2
----------------------------------------------------------------------------
At September 30, 2003March 31, 2004 and December 31, 2002, the Utility Group2003, NU also maintained $71.6$49.4
million and $63.6$63.4 million, respectively, of additional other
regulatory assets, primarily associated with Yankee Gas.Gas' income taxes, net
and other regulatory assets related to environmental clean-up costs
and hardship receivables.
Additionally, the Utility Group maintained $622.3NU had approximately $13 million and $383.1approximately
$12 million of regulatory liabilitiesassets at September 30, 2003March 31, 2004 and December 31,
2002,2003, respectively, primarily associated with CL&P's
Competitive Transition Assessment (CTA), Generation Service Charge
and System Benefits Charge (SBC) and PSNH's Stranded Cost Recovery
Charge (SCRC). These amountsthat are included in deferred creditsdebits and other
liabilitiesassets - 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 byLiabilities: The Utility Group companymaintained $1.2 billion
of regulatory liabilities at both March 31, 2004 and December 31,
2003. These amounts are as
follows:
- -------------------------------------------------------------------------------comprised of the following:
--------------------------------------------------------------------------
At September 30, 2003
- -------------------------------------------------------------------------------March 31, 2004
--------------------------------------------------------------------------
NU
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
--------------------------------------------------------------------------
Cost of removal $ 334.2 $149.5 $ 87.9 $25.1
CTA, GSC and SBC
overcollections 325.4 325.4 - -------------------------------------------------------------------------------
Overrecoveries $622.3 $401.8 $178.2 $2.0
-
-------------------------------------------------------------------------------SCRC overcollections 172.4 - -------------------------------------------------------------------------------172.4 -
Regulatory liabilities
offsetting Utility
Group derivative assets 147.1 146.9 0.2 -
LMP overcollections 83.8 83.8 - -
Other 155.3 72.6 23.3 6.9
--------------------------------------------------------------------------
Totals $1,218.2 $778.2 $283.8 $32.0
--------------------------------------------------------------------------
--------------------------------------------------------------------------
At December 31, 2002
- -------------------------------------------------------------------------------2003
--------------------------------------------------------------------------
NU
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
--------------------------------------------------------------------------
Cost of removal $ 334.0 $150.0 $ 88.0 $25.0
CTA, GSC and SBC
overcollections 333.7 333.7 - -------------------------------------------------------------------------------
Overrecoveries $383.1 $189.7 $187.1 $0.5
-
-------------------------------------------------------------------------------SCRC overcollections 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 September 30, 2003March 31, 2004 and December 31, 2002, the Utility Group2003, NU also maintained $40.3$124.2
million and $5.8$111.4 million, respectively, of additional other
regulatory liabilities, primarily held byassociated with Yankee Gas.
C. New Accounting Standards
Derivative Accounting: Effective January 1, 2001, NU adopted SFAS
No. 133, "AccountingGas' cost of
removal, deferred gas costs, pension and other regulatory
liabilities.
F. Allowance for Derivative Instruments and Hedging
Activities," as amended. In April 2003, the Financial Accounting
Standards Board (FASB) issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities," which amends
SFAS No. 133. This new statement incorporates interpretationsFunds Used During Construction
The allowance for funds used during construction (AFUDC) is a non-
cash item that wereis included in previous Derivative Implementationthe cost of Utility Group (DIG)
guidance, clarifies certain conditions,utility
plant and amends other existing
pronouncements. Itrepresents the cost of borrowed and equity funds used to
finance construction. The portion of AFUDC attributable to
borrowed funds is effective for contracts entered into or
modified after June 30, 2003. The new rules indicate that
derivative contracts that are subject to unplanned netting and can
be settled for cash versus delivery would no longer qualify for the
normal purchases and sales exception, which would require fair
value accounting. Management has determined that the adoption of
SFAS No. 149 did not change NU's accounting for wholesale and
retail marketing contracts that were entered into prior to July 1,
2003, or the ability of NU to elect the normal purchases and sales
exception.
Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Gains
and Losses on Derivative Instruments That Are Subject to FASB
Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, and 'Not Held for Trading Purposes' as Defined
in EITF Issue No. 02-3, 'Issues related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities'" was
derived from EITF Issue No. 02-3, which requires net reporting in
the income statement in revenues of energy trading activities.
Issue No. 03-11 addresses income statement classification of
derivatives that are not related to energy trading activities.
Prior to Issue No. 03-11, there was no specific accounting guidance
that addressed the classification in the income statement of Select
Energy, Inc.'s (Select Energy) retail marketing and wholesale
contracts, many of which are derivatives. The only applicable
guidance was EITF Issue No. 99-19, "Reporting Revenue Grossrecorded as a Principal versus Net as an Agent." The indicatorsreduction of gross revenue
reporting include whether the entity is the primary obligor in the
arrangement, whether the entity has inventory or credit risk,
latitude in establishing price, and discretion in supplier
selection. Indicators of net revenue reporting are whether the
supplier is the primary obligor in the arrangement, the entity
earns a fixed amountother interest
expense, and the supplier has credit risk.
On Julycost of equity funds is recorded as other income
on the consolidated statements of income:
---------------------------------------------------------------------
For the Three Months Ended
---------------------------------------------------------------------
(Millions of Dollars) March 31, 2004 March 31, 2003
the EITF reached a consensus in Issue No. 03-11
that determining whether realized gains and losses on contracts
that physically deliver and are not held for trading purposes
should be reported on a net or gross basis is a matter of judgment
that depends on the relevant facts and circumstances. The EITF
indicated that the indicators set forth in Issue No. 99-19 should
continue to be considered and provided no new accounting guidance.
Additionally, the consensus recommends disclosure of where the
gains and losses are recorded in the income statement, and whether
they are presented on a net or gross basis. Issue No. 03-11 is
effective for NU prospectively on October 1, 2003.
Select Energy currently reports the settlement of short-term and
long-term derivative contracts that are not held for trading
purposes on a gross basis, generally with sales in revenues and
purchases in expenses. Short-term sales and purchases represent
power that is purchased to serve full requirements contracts but is
ultimately not needed based on the actual load of the full
requirements customers. This excess power is sold to the
independent system operator or to other counterparties. Management
is currently evaluating the impact of the consensus in Issue No. 03-
11 as it relates to income statement classification of Select
Energy's short-term energy purchases and sales. Management will
complete this evaluation in the fourth quarter in accordance with
Issue No. 03-11. If management determines that revenues and
expenses related to short-term sales and purchases should be
reported net, then there could be a significant reduction in both
Select Energy's revenues and expenses with no operating income or
net income impact. For the first nine months of 2003, short-term
and non-requirements sales amounted to approximately $600 million.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed
the meaning of "not clearly and closely related regarding contracts
with a price adjustment feature" as it relates to the election of
the normal purchase and sales exception to derivative accounting.
The implementation of this guidance is required for the fourth
quarter of 2003 for NU. Management is currently evaluating the
impacts of Issue No. C-20, but believes that when it is
implemented, Issue No. C-20 will likely result in CL&P recording
the fair value of two existing power purchase contracts as
derivative liabilities with offsetting regulatory assets, as these
contracts are part of stranded costs and as management believes
that these costs will continue to be recovered in rates.
Management's preliminary estimates of the fair values of these long-
term power purchase contracts indicate that the contracts have a
combined negative fair value of approximately $16 million.
Accounting for RMS Variable Interest Entity: On June 30, 2001, NU
sold R. M. Services, Inc. (RMS) for $10 million in the form of
convertible cumulative 5 percent preferred stock and a warrant to
buy 25 percent of the outstanding common stock of RMS for $1,000
expiring in 2021. NU also agreed to guarantee a $3 million line of
credit for RMS through 2005. In the second and third quarters of
2003, RMS has been drawing on this line of credit.
In January 2003, the FASB issued Interpretation No. (FIN) 46,
"Consolidation of Variable Interest Entities," which was effective
for NU on July 1, 2003. NU did not electively delay implementation
until December 31, 2003. RMS is a variable interest entity (VIE),
as defined. FIN 46 requires that the party to a VIE that absorbs
the majority of the VIE's losses, defined as the "primary
beneficiary," consolidate the VIE. Upon adoption of FIN 46,
management determined that NU was the "primary beneficiary" of RMS
under FIN 46 and that NU is now required to consolidate RMS into
NU's financial statements. To consolidate RMS, NU adjusted the
carrying value of its preferred stock investment in RMS to the net
book value of RMS. This adjustment resulted in a negative $4.7
million after-tax cumulative effect of accounting change. NU's
remaining investment in RMS totaled $2.7 million at September 30,
2003. NU has no other VIE's for which NU is defined as the
"primary beneficiary."
Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics
of Both Liabilities and Equity." SFAS No. 150 establishes
standards on how to classify and measure certain financial
instruments with characteristics of both liabilities and equity.
SFAS No. 150 is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise effective for NU for the
third quarter of 2003. As NU no longer has any preferred stock
subject to mandatory redemption outstanding, the adoption of SFAS
No. 150 did not have an impact on NU's consolidated financial
statements.
D. Stock-Based---------------------------------------------------------------------
Borrowed funds $1.3 $1.3
Equity funds 1.3 1.5
---------------------------------------------------------------------
Totals $2.6 $2.8
---------------------------------------------------------------------
Average AFUDC rates 3.4% 4.3%
---------------------------------------------------------------------
G. Equity-Based Compensation
NU maintains an Employee Stock Purchase Plan and other long-term,
stock-basedequity-based incentive plans under the Northeast Utilities
Incentive Plan (Incentive Plan).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 stock-basedequity-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 or above
the market
value of the underlying common stock on the date of grant. At this time, NU has not elected to transition to expensing
stock options under the fair value-based method of accounting for
stock-based employee compensation. The
following tables illustratetable 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 stock-basedequity-based employee compensation related to stock options and NU's Employee Stock
Purchase Plan:compensation:
---------------------------------------------------------------------
For the Three Months Ended
---------------------------------------------------------------------
(Millions of Dollars, September 30, September 30,March 31, March 31,
except per share amounts) 2004 2003 2002
---------------------------------------------------------------------
Net income, as reported $39.2 $48.6$67.4 $60.2
Total stock-basedequity-based employee
compensation expense
determined under fair
value-based method for all
awards, net of related
(0.6) (1.1)
tax effects 0.5 0.5
---------------------------------------------------------------------
Pro forma net income $38.6 $47.5
---------------------------------------------------------------------
EPS:
Basic and fully
Diluted - as reported $ 0.31 $ 0.38
Basic and fully
Diluted - pro forma $ 0.30 $ 0.37
---------------------------------------------------------------------
---------------------------------------------------------------------
For the Nine Months Ended
---------------------------------------------------------------------
(Millions of Dollars, September 30, September 30,
except per share amounts) 2003 2002
---------------------------------------------------------------------
Net income, as reported $126.3 $96.1
Total stock-based employee
compensation expense
determined under
fair value-based method for
all awards, net of related (1.8) (3.4)
tax effects
---------------------------------------------------------------------
Pro forma net income $124.5 $92.7$66.9 $59.7
---------------------------------------------------------------------
EPS:
Basic and fully
diluted - as reported $ 0.99 $ 0.74$0.53 $0.47
Basic and fully
diluted - pro forma $ 0.98 $ 0.71$0.52 $0.47
---------------------------------------------------------------------
Net income as reported includes $0.6 million and $0.1 million
expensed for restricted stock and restricted stock units for the
three months ended March 31, 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 nine-monththree-month period ended September 30, 2003, NU granted
approximately 384,000 shares of restricted stock under the
Incentive Plan. The shares granted had a value of $5.4 million
when granted. This amount was recorded in shareholders' equity.
For the nine months ended September 30, 2003, approximately $1.2
million was amortized to expense related to the restricted stock.
During the nine-month period ended September 30, 2003,March 31, 2004, no stock
options were awarded.
E. Other Income/(Loss), Net
The pre-tax components of NU's other income/(loss), net items areOn March 31, 2004, the FASB issued an exposure draft that, if
finalized as follows:
---------------------------------------------------------------------
Forproposed, would require NU to expense equity-based
employee compensation under the Nine Months Ended
---------------------------------------------------------------------
September 30, September 30,
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Investment write-downs $ - $(17.1)
Seabrook-related items - 23.3
Investment income 13.5 19.1
Other, net (7.5) (5.6)
---------------------------------------------------------------------
Totals $ 6.0 $ 19.7
---------------------------------------------------------------------
F.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 September 30,both March 31, 2004 and December 31, 2003,
CL&P had sold accounts receivable of $40$80 million to the financial
institution with limited recourse through CL&P Receivables
Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally,At March 31,
2004, the reserve requirements calculated in accordance with the
Receivables Purchase and Sale Agreement were $23.6 million. This
reserve amount is deducted from the amount of receivables eligible
for sale at September 30, 2003, $6.4
million of assets were designated as collateral and restricted
under the agreement with CRC.time. Concentrations of credit risk to the
purchaser under this agreement with respect to the receivables are
limited due to CL&P's diverse customer base within its service
territory. At September 30, 2003,March 31, 2004, amounts sold to CRC fromby CL&P but not
sold to the financial institution totaling $215.6$186.8 million are
included in investments in securitizable assets on the accompanying
consolidated balance sheets. These amountsThis amount would be excluded from
CL&P's assets in the event of CL&P's bankruptcy. At
December 31, 2002, $40 million of accounts receivable were sold to
the financial institution. On July 9, 2003,
CL&P renewed this arrangement. This agreement expires on July 7,
2004, and management plans to renew this agreement prior to its
expiration.
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 Investment
Yankee Energy System, Inc. (Yankee) maintains a one-year period.
G. Guaranteeslong-term note
receivable from BMC Energy LLC (BMC), an operator of renewable
energy projects. In November 2002, the FASB issued FIN 45, "Guarantor's Accountinglate-March 2004, based on revised information
that impacts undiscounted cash flow projections and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," which requires disclosures
by a guarantor in its interim and annual financial statements about
its obligations under certain guaranteesfair value
estimates, management determined that it has issued and
clarifies that a guarantor is required to recognize, at the
inception of a guarantee, a liability for the fair value of the obligation undertaken in issuingnote
receivable from BMC had declined and that the guarantee.
NU provides credit assurancenote was impaired.
As a result, management recorded an after-tax impairment charge of
$1.5 million in the formfirst quarter of guarantees and letters
of credit 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. At
September 30, 2003, the maximum level of exposure under guarantees
by NU, primarily on behalf of NU Enterprises, totaled approximately
$435 million. Additionally, NU had $123.2 million of letters of
credit issued for the benefit of NU Enterprises outstanding at
September 30, 2003. In conjunction with its investment in RMS, NU
guarantees a $3 million line of credit through 2005, of which $0.5
million was outstanding at September 30, 2003, which2004. This charge is included
in other income, net on the $435accompanying consolidated statements of
income and 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. Yankee's remaining note receivable from BMC totaled
$1.5 million total. Effective July 1, 2003, NU now consolidatesat March 31, 2004 and is included in other deferred
debits and other assets on the accompanying consolidated balance
sheets.
J. Cash and Cash Equivalents
Cash and cash equivalents includes 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 statementsstanding of
RMSSelect Energy and its credit support provider.
L. Special Deposits
Special deposits represents amounts Select Energy has on deposit
with the NU financial statements.
Additionally, CL&P has obtained surety bondscounterparties and brokerage firms in the amount of $31.1$4.8
million related to the March 2003 and April 2003 incremental
locational marginal pricing (LMP) costs to comply with a
Connecticut Department of Public Utility Control (DPUC) order. At
September 30, 2003, NU guaranteed $42.8 million of surety bonds for
NU subsidiaries, including the LMP-related surety bonds. This
amount isamounts included in the total NU guarantee amount of
approximately $435 million. These surety bonds contain ratings
triggersescrow for Select Energy Services,
Inc. (SESI) that would require NU to post additional collateral in the
event that NU's ratings are downgraded.
NU currently has authorization from the Securities and Exchange
Commission (SEC) to provide up to $500 million of guarantees for NU
Enterprises through June 30, 2004, and has applied for authority to
increase this amount to $750 million through September 30, 2006.
The aforementioned surety bonds are subject to a separate $50
million SEC limitation apart from the current $500 million
guarantee limit. The amount of guarantees outstanding for
compliance with the SEC limit is approximately $258 million, which
is calculated using different criteria than the maximum level of
exposure of approximately $435 million required to be disclosed
under FIN 45. The $42.8 million of surety bonds is the same for
both SEC and FIN 45 purposes.
H. Adjustments to Estimates of Unbilled Revenues
Unbilled revenues represent an estimate of electricity or gas
delivered to customers that hashave not been billed. Unbilled revenues
represent assetsspent on the balance sheet that become accounts
receivable in the following month as customers are billed. Billed
revenues are based on meter readings.
Unbilled revenues are estimated monthly using the requirements
method. The requirements method utilizes the total monthly volumeconstruction projects of
electricity or gas delivered to the system$30.7 million at March 31, 2004. Similar amounts totaled $17
million and applies a
delivery efficiency (DE) factor to reduce the total monthly volume
by an estimate of delivery losses to calculate the 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.
In the third quarter of$32 million at December 31, 2003, the unbilled sales estimates for all
Utility Group companies were tested using the cycle method and will
be tested annually hereafter. The cycle method is historically
more accurate than the requirements method, when used in a mostly
weather-neutral month. 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
resulted in an adjustment to the estimate of unbilled revenues that
had a net positive after-tax earnings impact of approximately $5.7respectively.
Special deposits at December 31, 2003 also included $30.1 million
in the third quarter of 2003. The positive after-tax
impactsescrow that PSNH funded to acquire Connecticut Valley Electric
Company, Inc. on CL&P, PSNH, and WMECO were $7.2 million, $3.3 million,
and $0.3 million, respectively. There was a negative after-tax
impact on Yankee Gas of $5.1 million.
I.January 1, 2004.
M. Restricted Cash - LMP Costs and Special Deposits
Restricted cash - LMP costs represents incremental LMP cost amounts
that have been collected by CL&P and deposited into an escrow
account. Special deposits primarily consistAt March 31, 2004 and December 31, 2003, restricted cash -
LMP costs totaled $123.7 million and $93.6 million, respectively.
N. Other Income
The pre-tax components of collateral balances resulting
from Select Energy wholesale activities.NU's other income items are as follows:
---------------------------------------------------------------------
For the Three Months Ended
---------------------------------------------------------------------
(Millions of Dollars) March 31, 2004 March 31, 2003
---------------------------------------------------------------------
Investment income $ 3.3 $ 3.9
Charitable donations (1.0) (2.3)
AFUDC - equity funds 1.3 1.5
Other, net (1.9) (2.5)
---------------------------------------------------------------------
Totals $ 1.7 $ 0.6
---------------------------------------------------------------------
2. DERIVATIVE INSTRUMENTS MARKET RISK AND RISK MANAGEMENT (NU, CL&P, Select Energy, Yankee Gas)
A. Derivative Instruments
Effective January 1, 2001, NU adopted SFAS No. 133, as amended by
SFAS No. 149 in April 2003.
Derivatives that are utilized for trading purposes are recorded at fair
value with changes in fair value included in net income.earnings. Other contracts
that are derivatives but do not meet the definition of a cash flow hedge
and cannot be designated as being used for normal purchases or normal
sales are also recorded at fair value with changes in fair value
included in net income.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 a
component of equity, until the
underlying transactions occur. For
those contracts that meet the definition of a derivative and meet
the fair value hedge requirements, the changes in fair value of the
effective portion of those contracts are generally recognized on
the balance sheet as both the hedge and the hedged item are
recorded at fair value. 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 net income.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 will resultand are probable of
resulting in physical delivery, meet the definitions in SFAS No. 149, and are documented as such, are recorded
under accrual accounting.
For information regarding recent accounting changes related to
trading activities, see Note 1C, "New Accounting Standards," to the
consolidated financial statements.
During the first nine monthsquarter of 2003,2004, a negative $7.8$18.3 million, net of tax,
was reclassified from other comprehensive income in connection with the
consummation of the underlying hedged transactions and recognized in
net income. The related hedged
transactions were also recognized in net income. A negative $0.02earnings. An additional $0.2 million, net of tax, was recognized in
net incomeearnings for those derivatives that were determined to be ineffective
and for the ineffective portion of cash flow hedges. Also during the
thirdfirst quarter of 2003,2004, new cash flow hedge transactions were entered
into that hedge cash flows through 2005.2006. As a result of these new
transactions and market value changes since January 1, 2003,2004, accumulated
other comprehensive income decreasedincreased by $18.7$16.5 million, net of tax.
Accumulated other comprehensive income at September 30, 2003,March 31, 2004, was a negative $3.2positive
$41.3 million, net of tax (decrease(increase to equity), relating to hedged
transactions, and it is estimated that negative $1.6$40.1 million of this balance, net of tax
balance will be reclassified as an increase to net incomeearnings within the next
twelve months. Cash flows from the hedge contracts are reported in the same
category as cash flows from the underlying hedged transaction.
Through the first quarter of 2004 there were no changes to
interpretations of SFAS No. 133, but the FASB continues to consider
changes that could affect the way NU records and discloses derivative
and hedging activities.
The tables below summarize the derivative assets and liabilities at
September 30, 2003 and DecemberMarch 31, 2002.2004. These amounts do not include option premiums paid,
which are recorded as prepayments and amounted to $18.6$6.5 million and $26.7$9.1
million related to energy trading activities and $9.4 million and $7.6
million related to marketing activities at September 30, 2003March 31, 2004 and December 31,
2002,2003, respectively. These amounts also do not include option
premiums received, which are recorded as other current liabilities and
amounted to $15.8$8.4 million and $33.9$12.2 million related to energy trading
activities at September 30, 2003March 31, 2004 and December 31, 2002,2003, respectively. The
premium amounts relate primarily to energy trading activities.
---------------------------------------------------------------------
At September 30,March 31, 2004
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
NU Enterprises:
Trading $188.3 $(160.9) $ 27.4
Non-trading 0.6 (0.1) 0.5
Hedging 81.7 (12.1) 69.6
Utility Group - Gas:
Non-trading - (0.3) (0.3)
Hedging 3.2 - 3.2
Utility Group - Electric:
Non-trading 147.2 (55.1) 92.1
NU Parent:
Hedging 5.7 - 5.7
---------------------------------------------------------------------
Total $426.7 $(228.5) $198.2
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
Select Energy:NU Enterprises:
Trading $123.9 $ 89.0 $(52.8) $36.2
Nontrading 3.6 (1.4) 2.2(91.4) $ 32.5
Non-trading 1.6 (0.8) 0.8
Hedging 7.3 (11.7) (4.4)
---------------------------------------------------------------------
Yankee55.8 (12.7) 43.1
Utility Group - Gas:
Non-trading 0.2 (0.2) -
Hedging 2.32.8 - 2.3
---------------------------------------------------------------------2.8
Utility Group - Electric:
Non-trading 116.9 (56.0) 60.9
NU Parent:
Hedging 1.6 - 1.6(3.6) (3.6)
---------------------------------------------------------------------
Total $103.8 $(65.9) $37.9$301.2 $(164.7) $136.5
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2002
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
Select Energy:
Trading $102.9 $(61.9) $41.0
Nontrading 2.9NU Enterprises - 2.9
Hedging 22.8 (2.0) 20.8
---------------------------------------------------------------------
Yankee Gas:
Hedging 2.3 - 2.3
---------------------------------------------------------------------
Total $130.9 $(63.9) $67.0
---------------------------------------------------------------------
Select Energy Trading: To gather market intelligence and utilize
this information in risk management activities for the wholesale
business,marketing activities, Select Energy conducts limited energy trading
activities in electricity, natural gas, and oil, and therefore,
experiences net open positions. Select Energy manages these open
positions with strict policies that limit its exposure to market risk
and require daily reporting to management of potential financial
exposures.
Derivatives used in trading activities are recorded at fair value and
included in the consolidated balance sheets as derivative assets or
liabilities. Changes in fair value are recognized in operating revenues
in the consolidated statements of income in the period of change. The
net fair value positions of the trading portfolio at September 30, 2003March 31, 2004 and
at December 31, 20022003 were assets of $36.2$27.4 million and $41$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; and a
long-term bilateral energy purchase contract, the fair value of
which is determined using a model. The trading portfolio also
includes a LIBOR-based interest rate swap to mitigate fair value
fluctuations from changes in the LIBOR-based discount rate used to
determine the fair value of certain trading contracts.sources. Select Energy's trading portfolio also includes
transmission congestion contracts.contracts (TCC). The fair value of certain transmission congestion
contractsTCCs
included in the trading portfolio is based on published market data.
Market information
for other transmission congestion contracts is not available, and
those contracts cannot be reliably valued. Management believes the
amounts paid for these contracts, which total $4.6 million, are
equal to their fair value.
Select Energy Nontrading: NontradingNU Enterprises - Non-trading: Non-trading derivative contracts are used
for delivery of energy related to Select Energy's wholesale and retail
and
wholesalemarketing activities. These contracts are not entered into for
trading purposes, but 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 purchasepurchases and sale designation wassales
designation. Changes in fair value of a negative $0.3 million of non-
trading derivative contracts were recorded in revenues in the first
quarter of 2004.
Market information for TCCs included in non-trading is not elected by
management. The net fair values of nontrading derivatives valued
atavailable,
and those contracts cannot be reliably valued. Management believes the
mid-point of bid and ask market prices at September 30, 2003
and December 31, 2002 were assets of $2.2amounts paid for these contracts, which total $2.8 million and $2.9 million,
respectively.
Select Energyare
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 retail 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. HedgesCash 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
2005.2006. Select Energy has hedged its gas supply component of the risk under these
agreements through NYMEX futures contracts. Under these contracts,
which also extend through 2005,2006, the purchase price of a specified
quantity of gas is effectively fixed over the term of the gas service
agreements. At September 30, 2003,March 31, 2004 the NYMEX futures contracts had notional
values of $81.9$53.5 million and were recorded at fair value as derivative
assets of $13.5 million.
Select Energy maintains power swaps to hedge purchases in New England as
well as financial gas contracts and gas futures to hedge electricity
purchase contracts that are indexed to gas prices. These hedging
contracts, which are valued at the mid-point of bid and ask market
prices, were recorded as derivative assets of $45.4 million and
derivative liabilities of $12.7 million at March 31, 2004.
To hedge the congestion price differences associated with LMP in the New
England and the Pennsylvania, New Jersey, Maryland and Delaware (PJM)
regions, Select Energy holds Financial Transmission Rights (FTR) contracts
recorded as a derivative liabilityasset at a fair value of $1.7 million.$1.1 million at
March 31, 2004.
Other hedging derivative liabilities,assets, which are valued at the mid-point of
bid and ask market prices, include forwards, futures, options and swaps
to hedge Select Energy's basic generation service (BGS) contracts in the
PJM region and were recorded at fair value as derivative liabilitiesassets of $5 million. Other derivative liabilities include futures, options
and swaps in the New England region, which were recorded as
derivative liabilities with a fair value of $4.2$10.9
million at September 30, 2003.
SENYMarch 31, 2004.
Select Energy New York, Inc. maintains hedges onfinancial power swaps to hedge
its retail sales portfolio through 2004, which were also valued at the
mid-point of bid and ask market prices andprices. These contracts were recorded
at fair value as a derivative assetassets of $4.1$7.1 million at September 30, 2003.March 31, 2004.
In the first quarter of 2004, Select Energy began hedging natural gas
inventory with gas futures that qualify as fair value hedges. The
changes in fair value of the futures and the hedged inventory are
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 their contract terms. The net
fair values of non-trading derivatives at March 31, 2004 were
liabilities of $0.3 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 agreementagreements with that customer for a period
of time not extending beyond 2005. At September 30, 2003,March 31, 2004 the commodity swap
agreement had a notional value of $7.2$5.3 million and was recorded at fair
value as a derivative asset of $2.3
million$3.2 million.
Utility Group - Electric - Non-trading: CL&P has two 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 March 31, 2004
include a derivative asset with an offsettinga fair value of $145.5 million and a
derivative liability with a fair value of $55 million. An offsetting
regulatory liability and an offsetting regulatory asset were recorded,
as these contracts are part of the firm commitment
recordedstranded costs, and management
believes that these costs will continue to be recovered or refunded in
current liabilities inrates.
To mitigate the accompanying consolidated
balance sheets.risk associated with certain supply contracts, CL&P
purchased FTRs. FTRs are derivatives that do not qualify for the normal
purchases and sales exception. The fair value of these FTR non-trading
derivatives at March 31, 2004 was an asset of $1.5 million.
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-ratefixed-
rate note that matures on April 1, 2012. As a perfectly
matchedmatched-terms fair value
hedge, the changes in fair value of the swap and the hedged debt
instrument are recorded on the consolidated balance sheetsheets but are equal
and offsetting in the consolidated statements of income. The cumulative
change in the fair value of the hedged debt of $1.6$5.7 million is included
as long-term debt on the consolidated balance sheets. Additionally, theThe 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 1 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 three-month periods
ended March 31, 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 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 March 31, 2004, NU maintained $319.9 million of goodwill that is no
longer being amortized, $13.5 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 March 31, 2004 and December 31, 2003, by reportable
segment and reporting unit is as follows:
--------------------------------------------------------------------------
(Millions of Dollars) March 31, 2004 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 March 31, 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 March 31, 2004
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $ 7.9 $ 9.8
Customer list 6.6 2.9 3.7
Customer backlog,
employment related
agreements and other 0.1 0.1 -
--------------------------------------------------------------------------
Totals $24.4 $10.9 $13.5
--------------------------------------------------------------------------
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
Customer backlog,
employment related
agreements and other 0.1 0.1 -
--------------------------------------------------------------------------
Totals $24.4 $10.0 $14.4
--------------------------------------------------------------------------
Intangible assets not
subject to amortization:
Customer relationships $5.2
Tradenames 3.3
-------------------------------------------------
Totals $8.5
-------------------------------------------------
NU recorded amortization expense of $0.9 million for the three months
ended March 31, 2004 and 2003, respectively, related to intangible
assets. Based on the current amount of intangible assets subject to
amortization, the estimated annual amortization expense for 2004 and for
each of the succeeding 5 years from 2005 through 2009 is $3.6 million in
2004 through 2007 and no amortization expense in 2008 or 2009. These
amounts may vary as acquisitions and dispositions occur in the future.
4. COMMITMENTS AND CONTINGENCIES
A. 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.
CL&P was billed $186 million of incremental LMP costs by its
standard offer service suppliers, including affiliate Select
Energy, or by ISO-NE in 2003. CL&P and its suppliers disputed the
responsibility for the $186 million of incremental LMP costs
incurred. A settlement agreement was reached 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. This settlement
agreement will not be final until it is approved by the FERC, and
management expects to receive FERC approval of the settlement
agreement in the first half of 2004.
CTA and SBC Reconciliation: On April 1, 2004, CL&P filed its
annual Competitive Transition Assessment (CTA) and System Benefits
Charge (SBC) reconciliation with the DPUC. For the year ended
December 31, 2003, total CTA revenues and excess Generation Service
Charge (GSC) revenues exceeded the CTA revenue requirement by
$148.3 million. This amount was recorded as a regulatory liability
on the accompanying consolidated balance sheets. For the same
period, SBC revenues exceeded the SBC revenue requirement by $25.5
million. Management expects a decision in this docket from the
DPUC by the end of 2004.
New Hampshire:
SCRC Reconciliation Filing: On an annual basis, PSNH files with
the New Hampshire Public Utilities Commission (NHPUC) a Stranded
Cost Recovery Charge (SCRC) reconciliation filing for the preceding
calendar year. This filing includes the reconciliation of stranded
cost revenues with stranded costs, and transition energy service
(TS) revenues with TS costs. The NHPUC reviews the filing,
including a prudence review of PSNH's generation operations. 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.
Massachusetts:
Transition Cost Reconciliations: On March 31, 2003, WMECO filed its
2002 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 2002 and included the renegotiated purchased power
contract related to the Vermont Yankee nuclear unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001
transition cost reconciliation, which addressed WMECO's cost
tracking mechanisms. As part of that order, the DTE directed WMECO
to revise its 2002 annual transition cost reconciliation filing.
The revised filing was submitted to the DTE on September 22, 2003.
Hearings have been held, and 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.
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.
B. NRG Energy, Inc. Exposures (CL&P, Yankee Gas, NGS)
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 $5.9 billion at March 31,
2004, as follows (millions of dollars):
---------------------------------------------------------------------
Year
---------------------------------------------------------------------
2004 $3,842.5
2005 1,372.5
2006 204.8
2007 109.1
2008 93.3
Thereafter 295.6
---------------------------------------------------------------------
Total $5,917.8
---------------------------------------------------------------------
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 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 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 is currently negotiating a settlement
with the FERC and others to collect its presently estimated
decommissioning costs.
CY's estimated decommissioning and plant closure costs for the
period 2000 through 2023 have increased approximately $390 million
over the April 2000 estimate of $434 million approved by the FERC
in a rate case settlement. The revised estimate reflects the fact
that CY is now self-performing all work to complete the
decommissioning of the plant due to the termination of the
decommissioning contract with Bechtel Power Corporation in July
2003, the increases in the projected costs of spent fuel storage,
and increased security and liability and property insurance. NU's
share of CY's increased decommissioning and plant closure costs is
approximately $191 million. CY has not yet applied to the FERC for
recovery of this amount. In total, NU's estimated remaining
decommissioning and plant closure obligation to CY is $320.7
million.
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 as a
result of the FERC proceedings.
E. Consolidated Edison, Inc. Merger Litigation
There were no material developments in the first quarter of 2004 in
the litigation between NU and Consolidated Edison, Inc. (Con
Edison). Certain gain and loss contingencies continue to exist with
regard to the 1999 merger agreement between NU and Con Edison and
the related litigation.
5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises)
Total comprehensive income, which includes all comprehensive income
items by category, for the three months ended March 31, 2004 and 2003 is
as follows:
- ----------------------------------------------------------------------------------------------
Three Months Ended March 31, 2004
- ----------------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ----------------------------------------------------------------------------------------------
Net income* $67.4 $26.2 $11.8 $3.5 $18.8 $7.1
Comprehensive income items:
Qualified cash flow
hedging instruments 16.5 - - - 16.5 -
Unrealized gains on securities 0.4 - - - - 0.4
- ----------------------------------------------------------------------------------------------
Net change in comprehensive
income items 16.9 - - - 16.5 0.4
- ----------------------------------------------------------------------------------------------
Total comprehensive income $84.3 $26.2 $11.8 $3.5 $35.3 $7.5
- ----------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------
Three Months Ended March 31, 2003
- ----------------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ----------------------------------------------------------------------------------------------
Net income* $60.2 $25.3 $10.8 $6.1 $5.2 $12.8
Comprehensive income items:
Qualified cash flow
hedging instruments (3.7) - - - (2.3) (1.4)
Unrealized (losses)/gains
on securities (0.1) 0.4 0.6 0.1 - (1.2)
- ----------------------------------------------------------------------------------------------
Net change in comprehensive
(loss)/income items (3.8) 0.4 0.6 0.1 (2.3) (2.6)
- ----------------------------------------------------------------------------------------------
Total comprehensive income $56.4 $25.7 $11.4 $6.2 $2.9 $10.2
- ----------------------------------------------------------------------------------------------
*Net income after preferred dividends of subsidiaries.
Amounts included in the Other column primarily relate to NU parent and
Northeast Utilities Service Company (NUSCO).
Accumulated other comprehensive income fair value adjustments in NU's
qualified cash flow hedging instruments are as follows:
--------------------------------------------------------------------------
At March 31, 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 (18.3) (5.3)
Change in fair value 30.8 5.0
Cash flow transactions entered
into for the period 4.0 9.6
--------------------------------------------------------------------------
Net change associated with the
current period hedging transactions 16.5 9.3
--------------------------------------------------------------------------
Total fair value adjustments included
in accumulated other
comprehensive income $41.3 $24.8
--------------------------------------------------------------------------
Accumulated other comprehensive income items unrelated to NU's qualified
cash flow hedging instruments totaled $1.6 million and $1.2 million in
gains at March 31, 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 March 31, 2004 and 2003, 655,326 options and 3,226,913
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, Three Months Ended March 31,
Except for Share Information) 2004 2003
--------------------------------------------------------------------------
Income before preferred
dividends of subsidiaries $68.8 $61.6
Preferred dividends
of subsidiaries 1.4 1.4
--------------------------------------------------------------------------
Net income $67.4 $60.2
--------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 127,879,766 127,013,678
Dilutive effects of employee
stock options 181,320 97,594
--------------------------------------------------------------------------
Fully diluted EPS common shares
outstanding (average) 128,061,086 127,111,272
--------------------------------------------------------------------------
Basic and fully diluted EPS $0.53 $0.47
--------------------------------------------------------------------------
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 three months ended March 31, 2004 and 2003 are estimated as
follows:
--------------------------------------------------------------------------
For the Three Months Ended March 31,
--------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
--------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
--------------------------------------------------------------------------
Service cost $ 9.9 $ 8.8 $ 1.5 $ 1.3
Interest cost 29.5 29.3 6.3 6.7
Expected return
on plan assets (43.7) (45.6) (3.1) (3.7)
Amortization of
unrecognized net
transition
(asset)/obligation (0.4) (0.4) 3.0 3.0
Amortization of
prior service cost 1.8 1.8 (0.1) (0.1)
Amortization of
actuarial loss/(gain) 3.6 (1.8) - -
Other amortization, net - - 2.7 1.6
--------------------------------------------------------------------------
Total - net periodic
expense/(income) $ 0.7 $(7.9) $10.3 $ 8.8
--------------------------------------------------------------------------
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 continues to anticipate contributing approximately $10.3
million quarterly totaling $41 million in 2004 to fund its PBOP Plan.
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.
For further information regarding this matter, See Part II - Item 1.
"Legal Proceedings," included in this combined report on Form 10-Q.
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
68 percent and 75 percent of NU's total revenues for the three months
ended March 31, 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 $179 million
or 22 percent for the three months ended March 31, 2004 and
approximately $177 million or 29 percent for the three months ended
March 31, 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 $32 million and $39 million of total NU
Enterprises' revenues for the three months ended March 31, 2004 and
2003, respectively. Total WMECO purchases from NU Enterprises are
eliminated in consolidation.
Select Energy revenues related to contracts with NSTAR represented $88.7
million or 11 percent of total NU Enterprises' revenues for the three
months ended March 31, 2004. Select Energy also provides BGS in the New
Jersey market. Select Energy revenues related to these contracts
represented $110 million or 16 percent of total NU Enterprises' revenues
for the three months ended March 31, 2003. No other individual
customer, including BGS, represented in excess of 10 percent of NU
Enterprises' revenues for the three months ended March 31, 2004 or 2003.
Eliminations and other in the NU consolidated following tables includes
the results for Mode 1 Communications, Inc., an investor in a fiber-
optic communications network, the results of the nonenergy-related
subsidiaries of Yankee Energy System, Inc., (Yankee Energy Services
Company, RMS, Yankee Energy Financial Services, and NorConn Properties,
Inc.) the results of NU's parent and service companies, and the
company's investment in Acumentrics Corporation. 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, which was consolidated with NU effective July 1,
2003.
NU's segment information for the three months ended March 31, 2004 and
2003 is as follows (some amounts between segment schedules may not agree
due to rounding):
- ------------------------------------------------------------------------------------------------
For the Three Months Ended March 31, 2004
- ------------------------------------------------------------------------------------------------
Utility Group
-------------------------------------
Distribution
(Millions of --------------------- Regulated NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
- ------------------------------------------------------------------------------------------------
Operating revenues $1,059.7 $ 171.2 $ 31.1 $ 796.3 $(220.0) $1,838.3
Depreciation and
amortization (110.2) (6.4) (5.0) (4.7) (0.6) (126.9)
Other
operating
expenses (856.6) (139.8) (13.2) (747.6) 218.6 (1,538.6)
- ------------------------------------------------------------------------------------------------
Operating income/
(loss) 92.9 25.0 12.9 44.0 (2.0) 172.8
Interest
expense, net (39.9) (3.9) (2.3) (13.6) (3.0) (62.7)
Other income/
(loss), net 3.2 (0.5) (0.2) 1.2 (2.1) 1.6
Income tax
(expense)/
benefit (20.6) (8.7) (3.1) (12.8) 2.3 (42.9)
Preferred
dividends (1.4) - - - - (1.4)
- ------------------------------------------------------------------------------------------------
Net income/(loss) $ 34.2 $ 11.9 $ 7.3 $ 18.8 $ (4.8) $ 67.4
- ------------------------------------------------------------------------------------------------
Total assets (1) $8,336.8 $1,066.2 N/A $2,246.0 $(110.2) $11,538.8
- ------------------------------------------------------------------------------------------------
Total investments
in plant $ 97.0 $ 7.8 $ 24.9 $ 5.7 $ 2.4 $ 137.8
- ------------------------------------------------------------------------------------------------
(1) Information for segmenting total assets between distribution and
transmission is not available at March 31, 2004. On a NU consolidated
basis, these distribution and transmission assets are disclosed in the
electric distribution column above.
- ------------------------------------------------------------------------------------------------
For the Three Months Ended March 31, 2003
- ------------------------------------------------------------------------------------------------
Utility Group
-------------------------------------
Distribution
(Millions of --------------------- Regulated NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
- ------------------------------------------------------------------------------------------------
Operating revenues $1,010.3 $ 151.0 $ 31.2 $ 612.9 $(221.2) $1,584.2
Depreciation and
amortization (130.3) (5.7) (4.6) (4.8) (0.6) (146.0)
Other
operating
expenses (778.2) (114.9) (13.2) (588.1) 220.2 (1,274.2)
- ------------------------------------------------------------------------------------------------
Operating income/
(loss) 101.8 30.4 13.4 20.0 (1.6) 164.0
Interest
expense, net (42.4) (3.2) (1.3) (11.2) (5.5) (63.6)
Other(loss)/
income, net (0.4) (0.5) (0.1) 0.6 1.0 0.6
Income tax
(expense)/
benefit (23.4) (10.9) (4.0) (4.2) 3.1 (39.4)
Preferred
dividends (1.4) - - - - (1.4)
- ------------------------------------------------------------------------------------------------
Net income/(loss) $ 34.2 $ 15.8 $ 8.0 $ 5.2 $ (3.0) $ 60.2
- ------------------------------------------------------------------------------------------------
Total investments
in plant $ 68.5 $ 8.9 $ 13.7 $ 5.0 $ 0.7 $ 96.8
- ------------------------------------------------------------------------------------------------
Utility Group segment information related to the regulated electric
distribution and transmission businesses for CL&P, PSNH and WMECO for the
three months ended March 31, 2004 and 2003 is as follows:
---------------------------------------------------------------------
CL&P - For the Three Months Ended March 31, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $ 727.7 $ 21.0 $ 748.7
Depreciation and
amortization (53.9) (3.6) (57.5)
Other
operating
expenses (618.2) (8.7) (626.9)
---------------------------------------------------------------------
Operating income 55.6 8.7 64.3
Interest
expense, net (25.5) (1.6) (27.1)
Other income/
(loss), net 5.2 (0.1) 5.1
Income tax
expense (12.8) (1.9) (14.7)
Preferred
dividends (1.4) - (1.4)
---------------------------------------------------------------------
Net income $ 21.1 $ 5.1 $ 26.2
---------------------------------------------------------------------
Total investments
in plant $ 60.9 $ 19.7 $ 80.6
---------------------------------------------------------------------
---------------------------------------------------------------------
CL&P - For the Three Months Ended March 31, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $ 686.1 $ 19.8 $ 705.9
Depreciation and
amortization (76.8) (3.4) (80.2)
Other
operating
expenses (547.5) (9.1) (556.6)
---------------------------------------------------------------------
Operating income 61.8 7.3 69.1
Interest
expense, net (27.7) (1.0) (28.7)
Other income/
(loss), net 0.9 (0.2) 0.7
Income tax
expense (12.6) (1.8) (14.4)
Preferred
dividends (1.4) - (1.4)
---------------------------------------------------------------------
Net income $ 21.0 $ 4.3 $ 25.3
---------------------------------------------------------------------
Total investments
in plant $ 46.4 $ 10.0 $ 56.4
---------------------------------------------------------------------
---------------------------------------------------------------------
PSNH - For the Three Months Ended March 31, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $ 237.7 $ 6.5 $ 244.2
Depreciation and
amortization (45.9) (0.8) (46.7)
Other
operating
expenses (163.0) (3.0) (166.0)
---------------------------------------------------------------------
Operating income 28.8 2.7 31.5
Interest
expense, net (10.9) (0.4) (11.3)
Other loss, net (1.7) - (1.7)
Income tax
expense (5.9) (0.8) (6.7)
---------------------------------------------------------------------
Net income $ 10.3 $ 1.5 $ 11.8
---------------------------------------------------------------------
Total investments
in plant $ 28.7 $ 5.1 $ 33.8
---------------------------------------------------------------------
---------------------------------------------------------------------
PSNH - For the Three Months Ended March 31, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $ 223.6 $ 7.2 $ 230.8
Depreciation and
amortization (36.7) (0.7) (37.4)
Other
operating
expenses (159.3) (2.7) (162.0)
---------------------------------------------------------------------
Operating income 27.6 3.8 31.4
Interest
expense, net (11.3) (0.2) (11.5)
Other (loss)/
income, net (1.3) 0.1 (1.2)
Income tax
expense (6.6) (1.3) (7.9)
---------------------------------------------------------------------
Net income $ 8.4 $ 2.4 $ 10.8
---------------------------------------------------------------------
Total investments
in plant $ 17.8 $ 3.6 $ 21.4
---------------------------------------------------------------------
---------------------------------------------------------------------
WMECO - For the Three Months Ended March 31, 2004
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $ 94.3 $ 3.6 $ 97.9
Depreciation and
amortization (10.5) (0.4) (10.9)
Other
operating
expenses (75.4) (1.6) (77.0)
---------------------------------------------------------------------
Operating income 8.4 1.6 10.0
Interest
expense, net (3.5) (0.3) (3.8)
Other loss, net (0.3) - (0.3)
Income tax
expense (1.9) (0.5) (2.4)
---------------------------------------------------------------------
Net income $ 2.7 $ 0.8 $ 3.5
---------------------------------------------------------------------
Total investments
in plant $ 7.4 $ 0.1 $ 7.5
---------------------------------------------------------------------
---------------------------------------------------------------------
WMECO - For the Three Months Ended March 31, 2003
---------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
---------------------------------------------------------------------
Operating revenues $ 100.6 $ 4.2 $ 104.8
Depreciation and
amortization (16.8) (0.4) (17.2)
Other
operating
expenses (71.5) (1.4) (72.9)
---------------------------------------------------------------------
Operating income 12.3 2.4 14.7
Interest
expense, net (3.4) (0.1) (3.5)
Income tax
expense (4.2) (0.9) (5.1)
---------------------------------------------------------------------
Net income $ 4.7 $ 1.4 $ 6.1
---------------------------------------------------------------------
Total investments
in plant $ 4.3 $ 0.1 $ 4.4
---------------------------------------------------------------------
NU Enterprises' segment information for the three months ended March 31,
2004 and 2003 is as follows:
--------------------------------------------------------------------------
NU Enterprises - For the Three Months Ended March 31, 2004
--------------------------------------------------------------------------
(Millions of) Eliminations
Dollars) Merchant Energy and Other Totals
--------------------------------------------------------------------------
Operating revenues $ 734.4 $ 61.9 $ 796.3
Depreciation and
amortization (4.2) (0.5) (4.7)
Other
operating
expenses (686.9) (60.7) (747.6)
--------------------------------------------------------------------------
Operating income 43.3 0.7 44.0
Interest
expense, net (11.1) (2.5) (13.6)
Other (loss)/
income, net (0.2) 1.4 1.2
Income tax
(expense)/
benefit (12.9) 0.1 (12.8)
--------------------------------------------------------------------------
Net income/(loss) $ 19.1 $ (0.3) $ 18.8
--------------------------------------------------------------------------
Total assets $1,956.5 $ 289.5 $2,246.0
--------------------------------------------------------------------------
Total investments
in plant $ 4.7 $ 1.0 $ 5.7
--------------------------------------------------------------------------
--------------------------------------------------------------------------
NU Enterprises - For the Three Months Ended March 31, 2003
--------------------------------------------------------------------------
(Millions of) Eliminations
Dollars) Merchant Energy and Other Totals
--------------------------------------------------------------------------
Operating revenues $ 563.0 $ 49.9 $ 612.9
Depreciation and
amortization (4.3) (0.5) (4.8)
Other
operating
expenses (538.9) (49.2) (588.1)
--------------------------------------------------------------------------
Operating income 19.8 0.2 20.0
Interest
expense, net (9.8) (1.4) (11.2)
Other (loss)/
income, net (1.1) 1.7 0.6
Income tax
expense (4.0) (0.2) (4.2)
--------------------------------------------------------------------------
Net income $ 4.9 $ 0.3 $ 5.2
--------------------------------------------------------------------------
Total investments
in plant $ 4.5 $ 0.5 $ 5.0
--------------------------------------------------------------------------
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 1 $ 5,814
Restricted cash - LMP costs 123,681 93,630
Investments in securitizable assets 186,821 166,465
Receivables, net 54,422 60,759
Accounts receivable from affiliated companies 88,308 73,986
Unbilled revenues 6,491 6,961
Materials and supplies, at average cost 31,934 31,583
Derivative assets 146,943 115,370
Prepayments and other 18,567 12,521
---------------- ----------------
657,168 567,089
---------------- ----------------
Property, Plant and Equipment:
Electric utility 3,415,572 3,355,794
Less: Accumulated depreciation 1,033,195 1,018,173
---------------- ----------------
2,382,377 2,337,621
Construction work in progress 236,635 224,277
---------------- ----------------
2,619,012 2,561,898
---------------- ----------------
Deferred Debits and Other Assets:
Regulatory assets 1,639,935 1,673,010
Prepaid pension 308,695 305,320
Other 102,817 99,577
---------------- ----------------
2,051,447 2,077,907
---------------- ----------------
Total Assets $ 5,327,627 $ 5,206,894
================ ================
The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to affiliated companies $ 160,525 $ 91,125
Accounts payable 250,107 138,155
Accounts payable to affiliated companies 149,125 176,948
Accrued taxes 26,151 65,587
Accrued interest 10,845 10,361
Derivative liabilities 54,960 54,566
Other 41,560 49,674
---------------- ----------------
693,273 586,416
---------------- ----------------
Rate Reduction Bonds 1,090,277 1,124,779
---------------- ----------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 623,971 609,068
Accumulated deferred investment tax credits 90,243 90,885
Deferred contractual obligations 309,310 318,043
Regulatory liabilities 778,221 752,992
Other 77,650 79,935
---------------- ----------------
1,879,395 1,850,923
---------------- ----------------
Capitalization:
Long-Term Debt 830,644 830,149
---------------- ----------------
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 331,573 326,629
Retained earnings 326,248 311,793
Accumulated other comprehensive loss (335) (347)
---------------- ----------------
Common Stockholder's Equity 717,838 698,427
---------------- ----------------
Total Capitalization 1,664,682 1,644,776
---------------- ----------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 5,327,627 $ 5,206,894
================ ================
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)
Three Months Ended
March 31,
---------------------------
2004 2003
-------------- ------------
(Thousands of Dollars)
Operating Revenues $ 748,690 $ 705,916
------------ -----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 469,657 420,205
Other 92,137 75,839
Maintenance 16,431 11,178
Depreciation 28,625 25,416
Amortization of regulatory (liabilities)/assets, net (560) 27,343
Amortization of rate reduction bonds 29,462 27,486
Taxes other than income taxes 48,657 49,362
------------ -----------
Total operating expenses 684,409 636,829
------------ -----------
Operating Income 64,281 69,087
Interest Expense:
Interest on long-term debt 9,899 10,112
Interest on rate reduction bonds 16,590 18,144
Other interest 581 403
------------ -----------
Interest expense, net 27,070 28,659
------------ -----------
Other Income, Net 5,067 744
------------ -----------
Income Before Income Tax Expense 42,278 41,172
Income Tax Expense 14,665 14,450
------------ -----------
Net Income $ 27,613 $ 26,722
============ ===========
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)
Three Months Ended
March 31,
--------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating Activities:
Net income $ 27,613 $ 26,722
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 28,625 25,416
Deferred income taxes and investment tax credits, net 10,851 (21,708)
Amortization of regulatory (liabilities)/assets, net (560) 27,343
Amortization of rate reduction bonds 29,462 27,486
Amortization of recoverable energy costs (17,112) (6,116)
Increase in prepaid pension (3,375) (6,850)
Regulatory overrecoveries 15,336 48,973
Other sources of cash 3,906 14,042
Other uses of cash (19,008) (17,215)
Changes in current assets and liabilities:
Restricted cash - LMP costs (30,051) -
Receivables and unbilled revenues, net (7,515) (15,409)
Materials and supplies (351) (140)
Investments in securitizable assets (20,356) 23,149
Other current assets (6,046) (5,273)
Accounts payable 84,129 2,270
Accrued taxes (39,436) 21,269
Other current liabilities (7,645) (7,571)
----------- ----------
Net cash flows provided by operating activities 48,467 136,388
----------- ----------
Investing Activities:
Investments in plant (80,644) (56,390)
NU system Money Pool borrowing/(lending) 69,400 (28,300)
Other investment activities (205) (900)
----------- ----------
Net cash flows used in investing activities (11,449) (85,590)
----------- ----------
Financing Activities:
Retirement of rate reduction bonds (34,502) (32,187)
Capital contribution from Northeast Utilities 5,000 -
Cash dividends on preferred stock (1,390) (1,390)
Cash dividends on common stock (11,769) (10,018)
Other financing activities (170) (148)
----------- ----------
Net cash flows used in financing activities (42,831) (43,743)
----------- ----------
Net (decrease)/increase in cash (5,813) 7,055
Cash - beginning of period 5,814 159
----------- ----------
Cash - end of period $ 1 $ 7,214
=========== ==========
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 current report on Form 8-K dated January 22,
2004, and the NU 2003 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for
the consolidated statements of income for CL&P included in this report on
Form 10-Q for the three months ended March 31, 2004:
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Amount Percent
------ -------
Operating Revenues: $ 43 6%
Operating Expenses:
Fuel, purchased and net
interchange power 50 12
Other operation 16 21
Maintenance 5 47
Depreciation 3 13
Amortization of regulatory
(liabilities)/assets, net (28) (a)
Amortization of rate
reduction bonds 2 7
Taxes other than income taxes - -
--- ---
Total operating expenses 48 7
--- ---
Operating income (5) (7)
--- ---
Interest expense, net (2) (6)
Other income/(loss), net 4 (a)
--- ---
Income before income tax expense 1 3
Income tax expense - -
--- ---
Net Income $ 1 4%
=== ===
(a) Percent greater than 100.
Comparison of the First Quarter of 2004 to the First Quarter of 2003
Operating Revenues
Operating revenues increased by $43 million in the first quarter of 2004,
compared with the same period in 2003, due to higher retail revenues ($80
million), partially offset by lower wholesale revenues ($35 million).
Retail revenues were higher due to an increase in the TSO rate ($50 million),
Federally Mandated Congestion Costs ($40 million), higher sales volume ($7
million), partially offset by the 2003 recovery of certain fuel costs ($12
million) and lower rates for the recovery of system benefit costs ($8
million). Retail sales in the first quarter of 2004 were 2.0 percent higher
than the same period last year. 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 by $50 million in
the first quarter of 2004, primarily due to higher standard offer service
supply costs resulting from new contracts effective January 1, 2004 ($76
million), partially offset by the 2003 recovery of certain fuel costs ($12
million) and lower wholesale purchases ($14 million).
Other Operation
Other operation expenses increased $16 million in the first quarter of 2004,
primarily due to higher transmission expenses ($9 million) resulting from
higher reliability must run costs, higher administrative expense ($3 million)
primarily due to lower pension income, higher customer-related expenses ($2
million), which are due to an increase in uncollectible accounts expense as a
result of higher revenues and higher conservation and load management
expenses, and due to the 2003 positive resolution of the CL&P Millstone use
of proceeds docket ($2 million).
Maintenance
Maintenance expenses increased $5 million in the first quarter of 2004,
primarily due to the 2003 positive resolution of the CL&P Millstone use of
proceeds docket ($5 million).
Depreciation
Depreciation increased by $3 million in the first quarter of 2004 due to
higher utility plant balances and higher depreciation rates resulting from
the distribution rate case decision effective in January 2004.
Amortization of Regulatory Liabilities/Assets, Net
Amortization of regulatory liabilities/assets, net decreased by $28 million
in the first quarter of 2004 primarily due to lower amortization related to
the recovery of stranded costs ($21 million), and a reduction to amortization
expense ($7 million) resulting from the implementation of the distribution
rate case decision effective in January 2004.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased by $2 million in the first
quarter of 2004 due to the repayment of a higher amount of principal
obligations.
Interest Expense
Interest expense, net decreased in the first quarter of 2004 by $2 million
primarily due to lower rate reduction bond interest resulting from lower
principal balances outstanding.
Other Income, Net
Other income, net increased $4 million in the first quarter of 2004,
primarily due to the recognition beginning in 2004 of a procurement fee ($3
million) approved in the TSO docket decision.
LIQUIDITY
CL&P's net cash flows provided by operating activities decreased to $48.5
million for the three months ended March 31, 2004 from $136.4 million for the
same period in 2003. Cash flows provided by operating activities decreased
due to decreased regulatory overrecoveries and decreases in working capital
items, primarily restricted cash - LMP costs, investments in securitizable
assets and accrued taxes. These decreases were partially offset by an
accounts payable increase in the first quarter of 2004 resulting from TSO
supply purchases at higher prices and an increased percentage of TSO
purchases from unaffiliated suppliers. The decrease in regulatory
overrecoveries is primarily due to lower stranded cost and generation service
collections in the first quarter of 2004 compared to 2003. The lower level
of collections caused lower current taxable income and an increase in
deferred income taxes from 2003.
CL&P's net cash flows used in investing activities decreased to $11.4 million
for the first three months of 2004 from $85.6 million for the same period in
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 quarter of 2004 as compared to the same period in 2003.
CL&P's capital expenditures totaled $80.6 million in the first three months
of 2004 compared to $56.4 million in the first three months of 2003 and are
projected to total $412 million in 2004.
The level of financing activities in 2004 included a capital contribution
from NU in the amount of $5 million. CL&P also paid $11.8 million in
dividends to NU during the three months ended March 31, 2004 and $10 million
during the three months ended March 31, 2003.
At March 31, 2004, CL&P 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 will 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 March 31, 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.
CL&P has an application pending with the DPUC to issue up to $280 million of
long-term debt in 2004 and another $600 million for the period 2005 through
2007. The majority of that debt would be issued to finance CL&P's electric
transmission and distribution initiatives. CL&P also has $59 million of
first mortgage bonds that can be called at a premium beginning June 1, 2004.
At March 31, 2004, CL&P had $160.5 million in short-term debt outstanding
from the NU Money Pool.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 6,065 $ 2,737
Special deposits - 30,104
Receivables, net 71,575 67,121
Accounts receivable from affiliated companies 17,301 11,291
Unbilled revenues 41,623 39,220
Fuel, materials and supplies, at average cost 56,395 54,533
Derivative assets 210 1,510
Prepayments and other 1,739 9,945
------------- --------------
194,908 216,461
------------- --------------
Property, Plant and Equipment:
Electric utility 1,545,495 1,517,513
Other 5,707 5,707
------------- --------------
1,551,202 1,523,220
Less: Accumulated depreciation 646,267 635,029
------------- --------------
904,935 888,191
Construction work in progress 43,765 37,401
------------- --------------
948,700 925,592
------------- --------------
Deferred Debits and Other Assets:
Regulatory assets 966,652 969,434
Other 60,578 60,324
------------- --------------
1,027,230 1,029,758
------------- --------------
Total Assets $ 2,170,838 $ 2,171,811
============= ==============
The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ - $ 10,000
Notes payable to affiliated companies 35,000 48,900
Accounts payable 45,533 48,408
Accounts payable to affiliated companies 25,623 13,911
Accrued taxes 17,198 2,543
Accrued interest 14,060 10,894
Unremitted rate reduction bond collections 11,193 11,051
Derivative liabilities 132 1,414
Other 12,774 16,689
-------------- --------------
161,513 163,810
-------------- --------------
Rate Reduction Bonds 461,974 472,222
-------------- --------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 329,642 338,930
Accumulated deferred investment tax credits 1,978 2,096
Deferred contractual obligations 62,156 64,237
Regulatory liabilities 283,809 272,081
Accrued pension 47,416 44,766
Other 29,130 26,124
-------------- --------------
754,131 748,234
-------------- --------------
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 156,510 156,555
Retained earnings 229,520 223,822
Accumulated other comprehensive loss (95) (117)
-------------- --------------
Common Stockholder's Equity 385,935 380,260
-------------- --------------
Total Capitalization 793,220 787,545
-------------- --------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 2,170,838 $ 2,171,811
============== ==============
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)
Three Months Ended
March 31,
------------------------------
2004 2003
-------------- --------------
(Thousands of Dollars)
Operating Revenues $ 244,148 $ 230,768
------------- ------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 101,122 110,938
Other 39,612 28,906
Maintenance 16,208 13,445
Depreciation 11,331 10,607
Amortization of regulatory assets, net 24,515 17,570
Amortization of rate reduction bonds 10,856 9,246
Taxes other than income taxes 9,020 8,673
------------- ------------
Total operating expenses 212,664 199,385
------------- ------------
Operating Income 31,484 31,383
Interest Expense:
Interest on long-term debt 4,007 3,847
Interest on rate reduction bonds 6,957 7,410
Other interest 312 247
------------- ------------
Interest expense, net 11,276 11,504
------------- ------------
Other Loss, Net (1,773) (1,211)
------------- ------------
Income Before Income Tax Expense 18,435 18,668
Income Tax Expense 6,675 7,841
------------- ------------
Net Income $ 11,760 $ 10,827
============= ============
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)
Three Months Ended
March 31,
-------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating activities:
Net income $ 11,760 $ 10,827
Adjustments to reconcile to net cash flows
provided by/(used in) operating activities:
Depreciation 11,331 10,607
Deferred income taxes and investment tax credits, net (8,251) (8,256)
Amortization of regulatory assets, net 24,515 17,570
Amortization of rate reduction bonds 10,856 9,246
Amortization of recoverable energy costs 5,847 5,847
Regulatory recoveries (5,691) (3,154)
Other sources of cash 6,128 7,345
Other uses of cash (3,956) (6,184)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net (12,867) (3,439)
Fuel, materials and supplies (1,862) (3,916)
Other current assets 8,207 5,998
Accounts payable 8,837 (3,152)
Accrued taxes 14,655 (50,172)
Other current liabilities (597) 1,396
----------- -----------
Net cash flows provided by/(used in) operating activities 68,912 (9,437)
----------- -----------
Investing Activities:
Investments in plant (33,764) (21,411)
NU system Money Pool (lending)/borrowing (13,900) 19,700
Other investment activities 8,448 3,493
----------- -----------
Net cash flows (used in)/provided by investing activities (39,216) 1,782
----------- -----------
Financing Activities:
Retirement of rate reduction bonds (10,248) (8,191)
(Decrease)/increase in short-term debt (10,000) 15,000
Cash dividends on common stock (6,062) -
Other financing activities (58) (48)
----------- -----------
Net cash flows (used in)/provided by financing activities (26,368) 6,761
----------- -----------
Net increase/(decrease) in cash 3,328 (894)
Cash - beginning of period 2,737 5,319
----------- -----------
Cash - end of period $ 6,065 $ 4,425
=========== ===========
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 and the NU 2003 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for
the consolidated statements of income for PSNH included in this report on
Form 10-Q for the three months ended March 31, 2004:
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Amount Percent
------ -------
Operating Revenues: $ 13 6%
Operating Expenses:
Fuel, purchased and net
interchange power (10) (9)
Other operation 11 37
Maintenance 3 21
Depreciation 1 7
Amortization of regulatory assets,
net 7 40
Amortization of rate
reduction bonds 1 17
Taxes other than income taxes - -
---- ----
Total operating expenses 13 7
---- ----
Operating income - -
---- ----
Interest expense, net - -
Other loss, net - -
Income before income tax expense - -
---- ----
Income tax expense (1) (15)
---- ----
Net Income $ 1 9%
==== ====
Comparison of the First Quarter of 2004 to the First Quarter of 2003
Operating Revenues
Operating revenues increased $13 million in the first quarter of 2004, as
compared to the same period in 2003, primarily due to higher retail revenue
($27 million), partially offset by lower wholesale revenue ($14 million).
Retail revenue increased primarily due to higher retail sales volumes ($8
million) and higher TS revenues ($20 million). Retail kWh sales increased by
6.9 percent in 2004. The regulated wholesale revenue decrease is primarily
due to a lower number of wholesale transactions.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power decreased $10 million primarily as
result of lower regulated wholesale purchases.
Other Operation
Other operation expenses increased $11 million primarily due to higher
transmission expenses ($3 million), higher fossil steam expense ($3 million),
higher healthcare and pension costs ($3 million), and higher power pool
related load dispatch expenses ($1 million).
Maintenance
Maintenance expense increased $3 million primarily due to higher fossil steam
expenses ($2 million) and higher tree trimming expenses ($1 million).
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $7 million primarily due to
an increase in the recovery of stranded costs ($5 million) resulting from the
SCRC reconciliation of stranded cost revenues against actual stranded costs.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $1 million as a result of the
repayment of principal.
Income Tax Expense
Income tax expense decreased $1 million primarily as a result of lower
unitary taxable income which resulted in lower state income taxes.
LIQUIDITY
PSNH's net cash flows provided by operating activities totaled $68.9 million
for the three months ended March 31, 2004, compared with net cash flows used
in operating activities of $9.4 million for the same period in 2003. Cash
flows provided by operating activities increased due to changes in working
capital items, primarily accrued taxes. Accrued taxes decreased in 2003 due
to the payment of taxes on the gain of the sale of Seabrook.
There was a higher level of investing activities in the first quarter of 2004
primarily due to lendings to the NU Money Pool. There was also a higher
level of financing activities during the first quarter of 2004 primarily due
to a decrease in short-term debt and the payment of $6.1 million in dividends
to NU. PSNH did not pay dividends to NU during the first quarter of 2003.
PSNH's capital expenditures totaled $33.8 million in the first three months
of 2004 compared to $21.4 million in the first three months of 2003 and are
projected to total $150 million in 2004.
At March 31, 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 will be renewed for at least one year.
PSNH has an application pending with the NHPUC to issue up to $50 million of
debt. At March 31, 2004, PSNH had $35 million in short-term debt outstanding
from the NU Money Pool.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 1 $ 1
Receivables, net 39,221 40,103
Accounts receivable from affiliated companies 11,066 20
Unbilled revenues 9,178 10,299
Materials and supplies, at average cost 1,616 1,584
Prepayments and other 706 1,139
---------------- ----------------
61,788 53,146
---------------- ----------------
Property, Plant and Equipment:
Electric utility 615,423 612,450
Less: Accumulated depreciation 180,049 177,803
---------------- ----------------
435,374 434,647
Construction work in progress 16,839 13,124
---------------- ----------------
452,213 447,771
---------------- ----------------
Deferred Debits and Other Assets:
Regulatory assets 265,999 268,180
Prepaid pension 76,436 75,386
Other 19,065 19,081
---------------- ----------------
361,500 362,647
---------------- ----------------
Total Assets $ 875,501 $ 863,564
================ ================
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2004 2003
---------------- ----------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ 10,000 $ 10,000
Notes payable to affiliated companies 22,400 31,400
Accounts payable 21,643 10,173
Accounts payable to affiliated companies 15,293 13,789
Accrued taxes 3,774 765
Accrued interest 1,234 2,544
Other 9,277 9,785
---------------- ----------------
83,621 78,456
---------------- ----------------
Rate Reduction Bonds 130,248 132,960
---------------- ----------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 215,853 216,547
Accumulated deferred investment tax credits 3,242 3,326
Deferred contractual obligations 84,528 86,937
Regulatory liabilities 31,969 27,776
Other 8,302 8,357
---------------- ----------------
343,894 342,943
---------------- ----------------
Capitalization:
Long-Term Debt 157,326 157,202
---------------- ----------------
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 76,024 69,544
Retained earnings 73,602 71,677
Accumulated other comprehensive loss (80) (84)
---------------- ----------------
Common Stockholder's Equity 160,412 152,003
---------------- ----------------
Total Capitalization 317,738 309,205
---------------- ----------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 875,501 $ 863,564
================ ================
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
-------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating Revenues $ 97,922 $ 104,786
------------ -----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 56,611 53,003
Other 13,860 13,770
Maintenance 3,349 3,134
Depreciation 3,687 3,471
Amortization of regulatory assets, net 4,555 11,273
Amortization of rate reduction bonds 2,681 2,469
Taxes other than income taxes 3,132 2,972
------------ -----------
Total operating expenses 87,875 90,092
------------ -----------
Operating Income 10,047 14,694
Interest Expense:
Interest on long-term debt 1,463 792
Interest on rate reduction bonds 2,149 2,308
Other interest 237 376
------------ -----------
Interest expense, net 3,849 3,476
------------ -----------
Other Loss, Net (281) (5)
------------ -----------
Income Before Income Tax Expense 5,917 11,213
Income Tax Expense 2,371 5,145
------------ -----------
Net Income $ 3,546 $ 6,068
============ ===========
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
-------------------------------
2004 2003
------------- ------------
(Thousands of Dollars)
Operating Activities:
Net income $ 3,546 $ 6,068
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 3,687 3,471
Deferred income taxes and investment tax credits, net (317) (3,795)
Amortization of regulatory assets, net 4,555 11,273
Amortization of rate reduction bonds 2,681 2,469
Amortization of recoverable energy costs 149 149
Increase in prepaid pension (1,050) (1,675)
Regulatory (refunds)/overrecoveries (1,011) 710
Other sources of cash 124 602
Other uses of cash (3,752) (4,921)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net (9,043) 4,258
Materials and supplies (32) (538)
Other current assets 433 161
Accounts payable 12,974 3,362
Accrued taxes 3,009 2,776
Other current liabilities (1,817) 604
----------- ----------
Net cash flows provided by operating activities 14,136 24,974
----------- ----------
Investing Activities:
Investments in plant (7,539) (4,382)
NU system Money Pool lending (9,000) (16,700)
Other investment activities 245 (482)
----------- ----------
Net cash flows used in investing activities (16,294) (21,564)
----------- ----------
Financing Activities:
Retirement of rate reduction bonds (2,712) (2,522)
Increase in short-term debt - 3,000
Capital contribution from Northeast Utilities 6,500 -
Cash dividends on common stock (1,621) (4,003)
Other financing activities (9) (7)
----------- ----------
Net cash flows provided by/(used in) financing activities 2,158 (3,532)
----------- ----------
Net decrease in cash - (122)
Cash - beginning of period 1 123
----------- ----------
Cash - end of period $ 1 $ 1
=========== ==========
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 and the NU 2003 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for
the consolidated statements of income for WMECO included in this report on
Form 10-Q for the three months ended March 31, 2004:
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Amount Percent
------ -------
Operating Revenues $ (7) (7)%
Operating Expenses:
Fuel, purchased and net
interchange power 4 7
Other operation - -
Maintenance - -
Depreciation - -
Amortization of regulatory
assets, net (6) (60)
Amortization of rate
reduction bonds - -
Taxes other than income taxes - -
---- ----
Total operating expenses (2) (2)
---- ----
Operating income (5) (32)
---- ----
Interest expense, net - -
Other loss, net - -
---- ----
Income before income tax expense (5) (47)
Income tax expense (3) (54)
---- ----
Net Income $ (2) (42)%
==== ====
Operating Revenues
Operating revenues decreased $7 million in 2004, compared with the same
period in 2003, primarily due to lower wholesale revenues ($4 million) and
lower retail revenues ($2 million). Wholesale revenues were lower primarily
due to a decrease in wholesale sales transactions. Retail revenues decreased
as a result of lower retail sales. The standard offer service rate was
increased with an offsetting decrease to the transition charge. Retail sales
decreased 0.7 percent.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $4 million
primarily due to higher standard offer supply costs.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense decreased $6 million primarily
due to the lower recovery of stranded costs as a result of the decrease in
the transition component of retail rates.
Income Tax Expense
Income tax expense decreased $3 million primarily due to lower book taxable
income.
LIQUIDITY
WMECO's net cash flows provided by operating activities decreased to $14.1
million for the first three months of 2004 from $25 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 accounts payable.
WMECO's net cash flows used in investing activities were $16.3 million for
the three months ended March 31, 2004, compared with $21.6 million for the
same period of 2003. The lower level of investing activities is primarily
due to a lower level of NU Money Pool lendings offset by higher capital
expenditures during the first quarter of 2004.
WMECO's capital expenditures totaled $7.5 million in the first three months
of 2004 compared to $4.4 million in the first three months of 2003 and are
projected to total $39 million in 2004.
WMECO paid $1.6 million in dividends to NU during the three months ended
March 31, 2004 compared with $4 million during the three months ended
March 31, 2003. Also during the first quarter of 2004, NU made a capital
contribution to WMECO totaling $6.5 million.
At March 31, 2004, WMECO had $10 million of borrowings outstanding on the
Utility Group's $300 million revolving credit line. This credit line is
scheduled to mature in November 2004 and will be renewed for at least one
year.
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 net income,earnings, fair values
or cash flows from market risk-
sensitiverisk-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.
Select Energy Trading Portfolio: At September 30, 2003, Select
Energy calculated the market price resulting from a 10 percent
change in forward market prices. That 10 percent change would
result in approximately a $0.3 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
nonfinancial or nonquantifiable. Such risks principally include
credit risk, which is not reflected in this sensitivity analysis.
Select EnergyNU Enterprises - Wholesale and Retail Marketing and Wholesale Portfolio: When conducting
sensitivity analyses of the change in the fair value of Select Energy's
electricity, natural gas and oil nontrading
derivativeson 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 accountconsideration 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 quotesquoted prices on the futures exchange.
Select Energy has determined a hypothetical change in the fair value for its
wholesale and retail marketing and wholesale portfolio, which includes cash flow hedges and
electricity, natural gas and oil contracts, and generation assets, assuming a 10 percent change in
forward market prices. At September 30, 2003,March 31, 2004, a 10 percent change in market
price would have resulted in an increase or decrease in fair value of approximately $3.5between
$14.3 million and $16.6 million.
The impact of a change in electricity, natural gas and oil prices on Select
Energy's wholesale and retail marketing and wholesale portfolio at September 30, 2003,March 31, 2004, is not
necessarily representative of the results that will be realized when the commodities provided for in
these
contracts are physically delivered.
C.NU Enterprises - Trading Contracts: At March 31, 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 a $0.8 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 written policies and procedures by maintaining a mix of fixed
and variable rate debt. At September 30, 2003,March 31, 2004, approximately 8083 percent (70(73
percent including the debt subject to the fixed to floatingfixed-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 floatingfixed-to-floating interest rate swap, annual interest
expense would have increased by $7.6$4.4 million. At September 30, 2003,March 31, 2004, NU parent
maintained a fixed to floatingfixed-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 independent power producers,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.
NU'sThe Utility Group has a lower level of credit risk related to providing
regulated electric and gas distribution service than NU Enterprises.
However, Utility Group companies are subject to credit risk from certain long-
term or high-volume supply contracts with energy marketing companies.
Credit risks and market risks at NU Enterprises are monitored regularly by a
Risk Oversight Council operating outside of the business unitslines 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 the
NYMEX and have a lower credit risk.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 conditionscondition
(including credit ratings), collateral requirements under certain
circumstances (including cash in advance, letters of credit,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 NUSelect Energy
entering into trading activities.energy contracts. The appropriateness of these limits is
subject to continuing review. Concentrations among these counterparties may
impact NU'sSelect 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 September 30,March 31, 2004 and December 31, 2003, Select Energy maintained collateral
balances from counterparties of $29.2 million. This amount is$70.9 million and $46.5 million,
respectively. These amounts are included in both special depositsunrestricted cash from
counterparties and other current liabilities on the accompanying consolidated
balance sheets.
3. GOODWILL AND OTHER INTANGIBLE ASSETS
Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which ended the amortization of goodwill and certain
intangible assets with indefinite useful lives. SFAS No. 142 also
required that goodwill and intangible assets deemed to have indefinite
useful lives be reviewed for impairment upon adoption of SFAS No. 142
and at least annually thereafter by applying a fair value-based test.
NU selected October 1 as the annual goodwill impairment testing date.
Under SFAS No. 142, goodwill impairment is deemed to exist if the net
book value of a reporting unit exceeds its estimated fair value and if
the implied fair value of goodwill based on the estimated fair value of
the reporting unit is less than the carrying amount of the goodwill.
Excluding adjustments to the purchase price allocation in July 2003
related to the acquisition of Woods Electrical Co., Inc. and Woods
Network Services, Inc. (Woods Network), there were no impairments or
adjustments to the goodwill balances during the nine-month periods ended
September 30, 2003 and 2002. These adjustments primarily related to
the recording of contingent payments based on certain earnings targets
that have been met, as defined in the purchase agreements.
NU's reporting units that maintain goodwill are generally consistent
with the operating segments underlying the reportable segments
identified in Note 7, "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 wholesale and retail
business reporting unit, and 2) the services reporting unit. The
wholesale and retail business reporting unit is comprised of the
operations of Select Energy, Northeast Generation Company (NGC) and the
ongoing generation operations of Holyoke Water Power Company (HWP),
while the services reporting unit is comprised of the operations of
Select Energy Services, Inc. (SESI), Northeast Generation Services
Company (NGS) and Woods Network. As a result, NU's reporting units that
maintain goodwill are as follows: Yankee Gas, classified under the
Utility Group - gas reportable segment, the wholesale and retail
business reporting unit and the services reporting unit which are both
classified under the NU Enterprises reportable segment. The goodwill
balances of these reporting units are included in the table herein.
At September 30, 2003, NU maintained $319.9 million of goodwill that is
no longer being amortized, $15.5 million of identifiable intangible
assets and $8.5 million of intangible assets not subject to
amortization, totaling $343.9 million. At December 31, 2002, NU
maintained $321 million of goodwill that is no longer being amortized,
$18.1 million of identifiable intangible assets and $6.8 million of
intangible assets not subject to amortization, totaling $345.9 million.
These amounts are included on the consolidated balance sheets as
goodwill and other purchased intangible assets, net. A summary of NU's
goodwill balances at September 30, 2003 and December 31, 2002, by
reportable segment and reporting unit is as follows:
--------------------------------------------------------------------------
(Millions of Dollars) September 30, 2003 December 31, 2002
--------------------------------------------------------------------------
Utility Group - Gas:
Yankee Gas $287.6 $287.6
NU Enterprises:
Services 29.1 30.2
Wholesale and Retail Business 3.2 3.2
--------------------------------------------------------------------------
Totals $319.9 $321.0
--------------------------------------------------------------------------
At September 30, 2003 and December 31, 2002, NU's intangible assets and
related accumulated amortization consisted of the following:
--------------------------------------------------------------------------
At September 30, 2003
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $6.5 $11.2
Customer list 6.6 2.4 4.2
Customer backlog,
employment related
agreements and other 0.1 - 0.1
--------------------------------------------------------------------------
Totals $24.4 $8.9 $15.5
--------------------------------------------------------------------------
Intangible assets not subject
to amortization:
Customer relationships $ 5.2
Tradenames 3.3
---------------------------------------------
Totals $ 8.5
---------------------------------------------
--------------------------------------------------------------------------
At December 31, 2002
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $4.6 $13.1
Customer list 6.6 1.7 4.9
Customer backlog,
employment related
agreements and other 0.1 - 0.1
--------------------------------------------------------------------------
Totals $24.4 $6.3 $18.1
--------------------------------------------------------------------------
Intangible assets not
subject
to amortization:
Customer relationships $ 3.8
Tradenames 3.0
---------------------------------------------
Totals $ 6.8
---------------------------------------------
NU recorded amortization expense of $2.6 million and $1.1 million for
the nine months ended September 30, 2003 and 2002, respectively, related
to these intangible assets. Based on the current amount of intangible
assets subject to amortization, the estimated annual amortization
expense for each of the succeeding 5 years from 2004 through 2008 is
$3.6 million in 2004 through 2007 and no amortization expense in 2008.
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:
Implementation 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. Management believes that under the legal interpretation of
the terms of its standard offer service contracts with its standard
offer suppliers, the incremental costs associated with line losses
and congestion between the delivery points chosen by the suppliers
and CL&P's service territory in Connecticut are the responsibility
of CL&P's customers. Management believes that these congestion and
line loss charges are unavoidable, are part of the prudent cost of
providing regulated electric service in Connecticut and should be
paid for by CL&P's customers.
CL&P incurred $132.5 million of incremental LMP costs from March 1,
2003 through September 30, 2003. As incurred, these costs were
recorded as recoverable energy costs and are included in regulatory
assets on the accompanying consolidated balance sheets. CL&P
received approval for recovery of these costs through an additional
charge on customer bills and began recovering them on May 1, 2003,
subject to refund and on a two-month lag. Approximately $95.6
million has been recovered through September 30, 2003. This amount
is included in operating revenues and offset by amortization
expense.
If it is ultimately concluded that the incremental LMP costs are
the responsibility of the standard offer service suppliers, NU
Enterprises' pre-tax earnings for the nine months ended
September 30, 2003 would be reduced by approximately $71 million,
and CL&P would eliminate the accounts payable to the standard offer
service suppliers with a reduction to operating expenses. At the
same time, a regulatory liability in the same amount would be
recorded with a reduction to operating revenues. This amount could
be material and there would be an impact on NU's and NU
Enterprises' net income. Net income could be negatively impacted if
LMP recoveries are refunded to CL&P's customers with carrying
charges, which would result in interest expenses.
CL&P Disposition of Seabrook Proceeds: CL&P sold its share of the
Seabrook nuclear unit on November 1, 2002. CL&P received $37
million and recorded a gain on the sale of approximately $16
million. The gain was recorded as a regulatory liability and, when
offset by the decommissioning top off and other adjustments, will
be refunded to customers. On May 1, 2003, CL&P filed its
application with the DPUC for approval of the disposition of the
proceeds from the sale. This filing described CL&P's treatment of
its share of the proceeds from the sale. Hearings in this docket
were held in September and a final decision is scheduled to be issued
in December 2003. Management does not expect the final decision to
have a material effect on CL&P's net income or its financial
position.
CTA and SBC Reconciliation: On April 3, 2003, CL&P filed its
annual CTA and SBC reconciliation with the DPUC. For the year
ended December 31, 2002, total CTA revenues and excess Generation
Services Charge (GSC) revenues exceeded the CTA revenue requirement
by approximately $93.5 million. This amount is recorded as a
regulatory liability. CL&P has proposed that a portion of the
CTA/GSC overrecovery be utilized to reduce the nuclear stranded
cost regulatory asset and that the remaining amount be carried
forward through 2003. For the same period, SBC revenues exceeded
the SBC revenue requirement by approximately $22.4 million. In
compliance with a prior decision of the DPUC, a portion of the SBC
overrecovery was applied to regulatory assets, and the remaining
overrecovery of $18.6 million was applied to the CTA. Management
expects a final decision from the DPUC in this docket by the end of
2003. Management does not expect the final decision to have a
material effect on CL&P's net income or its financial position.
Massachusetts: On March 31, 2003, WMECO filed its 2002 annual
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
2002 and included the renegotiated purchased power contract related
to the Vermont Yankee nuclear unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001
annual transition cost reconciliation, which addressed WMECO's cost
tracking mechanisms. As part of that order, the DTE directed WMECO
to revise its 2002 annual transition cost reconciliation filing.
The revised filing was submitted to the DTE on September 23, 2003.
Hearings were held in October 2003, and a final decision from the
DTE is expected in the first half of 2004. Management does not
expect the outcome of this docket to have a material adverse impact
on WMECO's net income or its financial position.
B. NRG Energy, Inc. Exposures (CL&P, Yankee Gas, NGS)
Certain subsidiaries of NU, including CL&P, Yankee Gas and NGS,
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. NRG-related
exposures to NU as a result of these transactions relate to 1) the
recovery of CL&P's station service billings from NRG, 2) NRG's
standard offer service contract with CL&P, 3) the recovery of
congestion charges incurred by NRG prior to the implementation of
SMD on March 1, 2003, and 4) the recovery of Yankee Gas', NGS' and
CL&P's expenditures that were incurred related to NRG'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 $4.9 billion at
September 30, 2003, as follows (millions of dollars):
---------------------------------------------------------------------
Year
---------------------------------------------------------------------
2003 $1,412.1
2004 2,345.2
2005 639.2
2006 283.0
2007 225.1
---------------------------------------------------------------------
Total $4,904.6
---------------------------------------------------------------------
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.
D. Deferred Contractual Obligation - Connecticut Yankee Atomic Power
Company (CYAPC) Decommissioning Dispute
In June 2003, CYAPC notified NU that it had terminated its contract
with Bechtel Power Corporation (Bechtel) for the decommissioning of
the Connecticut Yankee nuclear power plant. CYAPC terminated the
contract based on its determination that Bechtel's decommissioning
work has been incomplete and untimely and that Bechtel refused to
perform the remaining decommissioning work. NU's electric
operating subsidiaries collectively own 49.0 percent of CYAPC; CL&P
owns 34.5 percent, PSNH owns 5.0 percent and WMECO owns 9.5
percent.
NU has been notified by CYAPC that it is in the process of
preparing an update to the estimated cost to decommission
Connecticut Yankee. When completed, the new 2003 estimate will
reflect the new estimated cost and schedule to complete the
decommissioning, including the impacts of the Bechtel contract
termination. The new cost estimate is expected to increase
significantly from the previous decommissioning estimate that NU
received from CYAPC in 2002. CYAPC is seeking recovery of the
additional project completion costs and other damages from Bechtel
but may ultimately recover these costs through Federal Energy
Regulatory Commission (FERC)-approved rates charged to CL&P, PSNH
and WMECO. The increase in the CYAPC decommissioning cost estimate
will increase deferred contractual obligations. Past increases to
deferred contractual obligations have been reflected as regulatory
assets by CL&P, PSNH and WMECO for future recovery from retail
customers.
5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO)
Total comprehensive income, which includes all comprehensive income
items by category, for the three months and nine months ended
September 30, 2003 and 2002 is as follows:
- ------------------------------------------------------------------------------------
Three Months Ended September 30, 2003
- ------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ------------------------------------------------------------------------------------
Net income/(loss)* $ 39.2 $29.0 $12.6 $5.2 $6.9 $(14.5)
- ------------------------------------------------------------------------------------
Comprehensive income items:
Qualified cash flow
hedging instruments (4.9) - - - (4.9) -
Unrealized gains on
securities 0.2 - - - - 0.2
- ------------------------------------------------------------------------------------
Net change of
comprehensive income items (4.7) - - - (4.9) 0.2
- ------------------------------------------------------------------------------------
Total comprehensive
income/(loss) $ 34.5 $29.0 $12.6 $5.2 $2.0 $(14.3)
- ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------
Nine Months Ended September 30, 2003
- ------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ------------------------------------------------------------------------------------
Net income/(loss)* $126.3 $59.0 $34.5 $13.9 $24.0 $ (5.1)
- ------------------------------------------------------------------------------------
Comprehensive income items:
Qualified cash flow
hedging instruments (18.7) - - - (14.7) (4.0)
Unrealized gains on
securities 0.9 0.1 0.1 - - 0.7
- ------------------------------------------------------------------------------------
Net change of
comprehensive income items (17.8) 0.1 0.1 - (14.7) (3.3)
- ------------------------------------------------------------------------------------
Total comprehensive
income/(loss) $108.5 $59.1 $34.6 $13.9 $ 9.3 $ (8.4)
- ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------
Three Months Ended September 30, 2002
- ------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ------------------------------------------------------------------------------------
Net income/(loss)* $ 48.6 $27.9 $19.5 $ 4.7 $(9.0) $ 5.5
- ------------------------------------------------------------------------------------
Comprehensive income items:
Qualified cash flow
hedging instruments 5.5 - - - 5.4 0.1
Unrealized gains on
securities (0.8) (0.5) (0.2) (0.1) - -
- ------------------------------------------------------------------------------------
Net change of
comprehensive income items 4.7 (0.5) (0.2) (0.1) 5.4 0.1
- ------------------------------------------------------------------------------------
Total comprehensive
income/(loss) $ 53.3 $27.4 $19.3 $ 4.6 $(3.6) $ 5.6
- ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------
Nine Months Ended September 30, 2002
- ------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
- ------------------------------------------------------------------------------------
Net income/(loss)* $ 96.1 $58.2 $46.4 $26.9 $(38.7) $ 3.3
- ------------------------------------------------------------------------------------
Comprehensive income items:
Qualified cash flow
hedging instruments 43.7 - - - 38.0 5.7
Unrealized gains on
securities (1.2) (0.5) (0.6) (0.1) - -
- ------------------------------------------------------------------------------------
Net change of
comprehensive income items 42.5 (0.5) (0.6) (0.1) 38.0 5.7
- ------------------------------------------------------------------------------------
Total comprehensive
income/(loss) $138.6 $57.7 $45.8 $26.8 $ (0.7) $ 9.0
- ------------------------------------------------------------------------------------
*Net income/(loss) after preferred dividends of subsidiaries.
Amounts included in the Other column primarily relate to NU parent,
Yankee Gas and Northeast Utilities Service Company.
Accumulated other comprehensive income fair value adjustments of NU's
qualified cash flow hedging instruments are as follows:
--------------------------------------------------------------------------
September 30, December 31,
(Millions of Dollars, Net of Tax) 2003 2002
--------------------------------------------------------------------------
Balance at beginning of period $15.5 $(36.9)
--------------------------------------------------------------------------
Hedged transactions recognized
into net income (7.8) 17.0
Change in fair value (1.5) 29.2
Cash flow transactions entered
into for the period (9.4) 6.2
--------------------------------------------------------------------------
Net change associated with the
current period hedging transactions (18.7) 52.4
--------------------------------------------------------------------------
Total fair value adjustments included
in accumulated other
comprehensive (loss)/income $(3.2) $15.5
--------------------------------------------------------------------------
Accumulated other comprehensive income items unrelated to NU's qualified
cash flow hedging instruments totaled $0.3 million in gains and $0.6
million in losses at September 30, 2003 and December 31, 2002,
respectively. These amounts primarily relate to unrealized gains and
losses on investments in marketable debt and equity securities.
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.
The following table sets forth the components of basic and fully diluted
EPS:
--------------------------------------------------------------------------
(Millions of Dollars, Nine Months Ended September 30,
except share information) 2003 2002
--------------------------------------------------------------------------
Income before preferred
dividends of subsidiaries $135.2 $100.3
Preferred dividends
of subsidiaries 4.2 4.2
--------------------------------------------------------------------------
Income before cumulative effect
of accounting change $131.0 $ 96.1
Cumulative effect of accounting
change, net of tax benefit (4.7) -
--------------------------------------------------------------------------
Net income $126.3 $ 96.1
--------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 126,976,161 129,508,840
Dilutive effect of employee
stock options 110,256 228,409
--------------------------------------------------------------------------
Fully diluted EPS common shares
outstanding (average) 127,086,417 129,737,249
--------------------------------------------------------------------------
Basic and fully diluted EPS:
Income before cumulative effect
of accounting change $1.03 $0.74
Cumulative effect of accounting
change, net of tax benefit (0.04) -
--------------------------------------------------------------------------
Net income $0.99 $0.74
--------------------------------------------------------------------------
7. SEGMENT INFORMATION (NU)
NU is organized between the Utility Group and NU Enterprises based on
each segments' regulatory environment or lack thereof. The Utility
Group segment, including both electric and gas utilities, represents
approximately 65 percent and 82 percent of NU's total revenues for the
nine months ended September 30, 2003 and 2002, respectively, and
primarily includes the operations of the electric utilities, CL&P, PSNH
and WMECO, whose complete financial statements are included in NU's
combined report on Form 10-Q. The Utility Group - gas segment includes
the operations of Yankee Gas. 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 segment includes Select Energy, NGC, SESI, NGS, and
their respective subsidiaries. The ongoing generation operations of HWP
and Woods Network are also included in the NU Enterprises segment.
On January 1, 2000, Select Energy began serving one half of CL&P's
standard offer load for a four-year period ending on December 31, 2003,
at fixed prices. Total Select Energy revenues from CL&P for CL&P's
standard offer load and for other transactions with CL&P, represented
approximately $566 million or 23 percent for the nine months ended
September 30, 2003 and approximately $473 million or 40 percent for the
nine months ended September 30, 2002, of total NU Enterprises' revenues.
Total CL&P purchases from NU Enterprises are eliminated in
consolidation. Select Energy also provides basic generation service in
the New Jersey market. Select Energy revenues related to these
contracts represented approximately $324 million or 13 percent of total
NU Enterprises' revenues for the nine months ended September 30, 2003.
Short-term sales to ISO-NE represented approximately $264 million or 11
percent of total NU Enterprises' revenues for the nine months ended
September 30, 2003. Additionally, WMECO's purchases from Select Energy
represented approximately $110 million and $8 million of total NU
Enterprises' revenues for the nine months ended September 30, 2003 and
2002, respectively. No other individual customer represented in excess
of 10 percent of NU Enterprises' revenues for the nine months ended
September 30, 2003 or 2002.
Eliminations and other in the following table includes the results for
Mode 1 Communications, Inc., an investor in a fiber-optic communications
network, the results of the nonenergy-related subsidiaries of Yankee
Energy System, Inc., (Yankee Energy Services Company, RMS, Yankee Energy
Financial Services, and NorConn Properties, Inc.) the companies' parent
and service companies, and the company's investment in Acumentrics
Corporation. 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 also includes NU's investment in RMS, which was
consolidated with NU effective July 1, 2003, resulting in a negative
$4.7 million net of tax cumulative effect of an accounting change.
- -------------------------------------------------------------------------------
For the Three Months Ended September 30, 2003
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $1,141.8 $30.6 $1,143.6 $(261.7) $2,054.3
Depreciation and
amortization (134.7) (5.7) (4.6) (0.6) (145.6)
Other operating
expenses (887.8) (37.4) (1,115.1) 261.3 (1,779.0)
- -------------------------------------------------------------------------------
Operating
income/(loss) 119.3 (12.5) 23.9 (1.0) 129.7
Interest
expense, net (42.8) (3.4) (13.5) (3.7) (63.4)
Other income/
(loss), net 2.7 (0.4) 1.3 1.1 4.7
Income tax
(expense)/
benefit (31.1) 6.7 (4.8) 3.5 (25.7)
Preferred
dividends (1.4) - - - (1.4)
- -------------------------------------------------------------------------------
Income/(loss)
before
cumulative
effect of
accounting
change 46.7 (9.6) 6.9 (0.1) 43.9
Cumulative effect
of accounting
change, net of
tax benefit - - - (4.7) (4.7)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 46.7 $(9.6) $ 6.9 $ (4.8) $ 39.2
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
For the Nine Months Ended September 30, 2003
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $3,130.3 $255.0 $2,499.1 $(684.1) $5,200.3
Depreciation and
amortization (365.3) (17.2) (14.8) (1.8) (399.1)
Other operating
expenses (2,454.8) (220.4) (2,409.6) 682.5 (4,402.3)
- -------------------------------------------------------------------------------
Operating
income /(loss) 310.2 17.4 74.7 (3.4) 398.9
Interest
expense, net (129.4) (9.9) (36.6) (10.6) (186.5)
Other income/
(loss), net 2.3 (1.4) 4.2 0.9 6.0
Income tax
(expense)/
benefit (71.3) (2.7) (18.3) 9.1 (83.2)
Preferred
dividends (4.2) - - - (4.2)
- -------------------------------------------------------------------------------
Income/(loss) before
cumulative
effect of
accounting change 107.6 3.4 24.0 (4.0) 131.0
Cumulative effect
of accounting
change, net of
tax benefit - - - (4.7) (4.7)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 107.6 $ 3.4 $ 24.0 $ (8.7) $ 126.3
- -------------------------------------------------------------------------------
Total assets $7,719.5 $958.2 $2,031.9 $(111.2) $10,598.4
- -------------------------------------------------------------------------------
Total
investments
in plant $ 322.8 $ 37.7 $ 13.1 $ 12.4 $ 386.0
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
For the Three Months Ended September 30, 2002
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $1,106.2 $ 37.8 $ 452.9 $(182.6) $1,414.3
Depreciation and
amortization (134.1) (5.8) (5.0) (0.7) (145.6)
Other operating
expenses (840.9) (37.6) (449.7) 177.5 (1,150.7)
- -------------------------------------------------------------------------------
Operating
income/(loss) 131.2 (5.6) (1.8) (5.8) 118.0
Interest
expense, net (46.6) (3.5) (11.1) (6.5) (67.7)
Other income/
(loss), net 31.3 (0.5) 0.2 1.1 32.1
Income tax
(expense)/
benefit (45.5) 3.8 3.7 5.6 (32.4)
Preferred
dividends (1.4) - - - (1.4)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 69.0 $(5.8) $ (9.0) $ (5.6) $ 48.6
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
For the Nine Months Ended September 30, 2002
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $2,962.6 $192.8 $1,177.5 $(492.2) $3,840.7
Depreciation and
amortization (321.1) (18.1) (17.0) (1.6) (357.8)
Other operating
expenses (2,298.9) (152.9) (1,187.6) 483.0 (3,156.4)
- -------------------------------------------------------------------------------
Operating
income/(loss) 342.6 21.8 (27.1) (10.8) 326.5
Interest
expense, net (140.5) (10.9) (32.8) (19.4) (203.6)
Other income/
(loss), net 33.4 (0.5) (0.5) (12.7) 19.7
Income tax
(expense)/
benefit (79.0) (4.2) 21.7 19.2 (42.3)
Preferred
dividends (4.2) - - - (4.2)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 152.3 $ 6.2 $ (38.7) $ (23.7) $ 96.1
- -------------------------------------------------------------------------------
Total
investments
in plant $ 250.5 $ 41.8 $ 18.1 $ 16.9 $ 327.3
- -------------------------------------------------------------------------------
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
---------------- ----------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 7,324 $ 159
Restricted cash - LMP costs 45,760 -
Investments in securitizable assets 215,592 178,908
Receivables, net 62,896 88,001
Accounts receivable from affiliated companies 47,978 51,060
Unbilled revenues 7,422 5,801
Notes receivable from affiliated companies 26,175 1,900
Fuel, materials and supplies, at average cost 30,033 32,379
Prepayments and other 22,770 19,407
-------------- --------------
465,950 377,615
-------------- --------------
Property, Plant and Equipment:
Electric utility 3,281,684 3,139,128
Less: Accumulated depreciation 1,159,189 1,113,991
-------------- --------------
2,122,495 2,025,137
Construction work in progress 217,233 153,556
-------------- --------------
2,339,728 2,178,693
-------------- --------------
Deferred Debits and Other Assets:
Regulatory assets 1,662,347 1,702,677
Prepaid pension 297,888 276,173
Other 114,855 96,925
-------------- --------------
2,075,090 2,075,775
-------------- --------------
Total Assets $ 4,880,768 $ 4,632,083
============== ==============
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
---------------- ----------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Accounts payable $ 238,833 $ 174,890
Accounts payable to affiliated companies 196,393 117,904
Accrued taxes 59,908 34,350
Accrued interest 9,956 10,077
Other 47,871 48,495
-------------- --------------
552,961 385,716
-------------- --------------
Rate Reduction Bonds 1,153,822 1,245,728
-------------- --------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 713,133 756,461
Accumulated deferred investment tax credits 91,516 93,408
Deferred contractual obligations 212,604 234,537
Other 486,533 276,325
-------------- --------------
1,503,786 1,360,731
-------------- --------------
Capitalization:
Long-Term Debt 829,647 827,866
-------------- --------------
Preferred Stock - Nonredeemable 116,200 116,200
-------------- --------------
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2003 and 2002 60,352 60,352
Capital surplus, paid in 326,703 327,299
Retained earnings 337,547 308,554
Accumulated other comprehensive loss (250) (363)
-------------- --------------
Common Stockholder's Equity 724,352 695,842
-------------- --------------
Total Capitalization 1,670,199 1,639,908
-------------- --------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 4,880,768 $ 4,632,083
============== ==============
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)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
2003 2002 2003 2002
-------------- -------------- -------------- --------------
(Thousands of Dollars)
Operating Revenues $ 797,896 $ 687,938 $ 2,119,080 $ 1,874,089
------------ ------------ ------------ ------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 506,369 406,194 1,279,785 1,109,391
Other 88,757 80,834 265,524 229,610
Maintenance 19,388 23,949 51,242 56,217
Depreciation 26,500 24,445 77,827 73,851
Amortization of regulatory assets, net 23,971 26,163 74,218 41,232
Amortization of rate reduction bonds 27,664 25,120 78,483 74,197
Taxes other than income taxes 32,096 28,287 111,464 107,006
------------ ------------ ------------ ------------
Total operating expenses 724,745 614,992 1,938,543 1,691,504
------------ ------------ ------------ ------------
Operating Income 73,151 72,946 180,537 182,585
Interest Expense:
Interest on long-term debt 9,567 10,682 29,579 31,071
Interest on rate reduction bonds 17,398 18,789 53,304 57,273
Other interest 1,238 648 1,994 1,963
------------ ------------ ------------ ------------
Interest expense, net 28,203 30,119 84,877 90,307
------------ ------------ ------------ ------------
Other Income, Net 2,652 7,911 4,615 14,094
------------ ------------ ------------ ------------
Income Before Income Tax Expense 47,600 50,738 100,275 106,372
Income Tax Expense 17,169 21,441 37,058 43,984
------------ ------------ ------------ ------------
Net Income $ 30,431 $ 29,297 $ 63,217 $ 62,388
============ ============ ============ ============
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)
Nine Months Ended
September 30,
------------------------------
2003 2002
------------- -------------
(Thousands of Dollars)
Operating Activities:
Net income $ 63,217 $ 62,388
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 77,827 73,851
Deferred income taxes and investment tax credits, net (52,396) (59,570)
(Deferral)/amortization of recoverable energy costs (15,733) 23,463
Amortization of regulatory assets, net 74,218 41,232
Amortization of rate reduction bonds 78,483 74,197
Prepaid pension (21,715) (38,506)
Regulatory recoveries 117,279 82,350
Other uses of cash (55,152) (34,656)
Other sources of cash 8,957 16,804
Changes in current assets and liabilities:
Restricted cash - LMP costs (45,760) -
Receivables and unbilled revenues, net 26,566 (49,146)
Fuel, materials and supplies 2,346 (925)
Accounts payable 142,432 60,995
Accrued taxes 25,558 2,493
Investments in securitizable assets (36,684) 49,570
Other current assets and liabilities (excludes cash) (4,063) (1,383)
---------- ----------
Net cash flows provided by operating activities 385,380 303,157
---------- ----------
Investing Activities:
Investments in plant (224,757) (159,946)
NU system Money Pool (lending)/borrowing (24,275) 51,000
Other investment activities, net (2,896) (683)
---------- ----------
Net cash flows used in investing activities (251,928) (109,629)
---------- ----------
Financing Activities:
Repurchase of common shares - (49,996)
Retirement of rate reduction bonds (91,606) (86,819)
Cash dividends on preferred stock (4,169) (4,169)
Cash dividends on common stock (30,055) (45,091)
Other financing activities, net (457) (399)
---------- ----------
Net cash flows used in financing activities (126,287) (186,474)
---------- ----------
Net increase in cash 7,165 7,054
Cash - beginning of period 159 773
---------- ----------
Cash - end of period $ 7,324 $ 7,827
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
CL&P is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the first and second quarter 2003 reports on
Form 10-Q, and the NU 2002 Form 10-K.
RESULTS OF OPERATIONS
The components of significant income statement variances for the third
quarter of 2003 and the first nine months of 2003 are provided in the table
below.
Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
------------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues $110 16% $245 13%
Operating Expenses:
Fuel, purchased and
net interchange power 100 25 170 15
Other operation 8 10 36 16
Maintenance (5) (19) (5) (9)
Depreciation 2 8 4 5
Amortization of regulatory
assets, net (2) (8) 33 80
Amortization of rate
reduction bonds 3 10 4 6
Taxes other than income taxes 4 13 5 4
---- ---- ---- ----
Total operating expenses 110 18 247 15
---- ---- ---- ----
Operating income - - (2) (1)
---- ---- ---- ----
Interest expense, net (2) (6) (5) (6)
Other income, net (5) (66) (9) (67)
---- ---- ---- ----
Income before income tax expense (3) (6) (6) (6)
Income tax expense (4) (20) (7) (16)
---- ---- ---- ----
Net income $ 1 4% $ 1 1%
==== ==== ==== ====
Comparison of the Third Quarter of 2003 to the Third Quarter of 2002
Operating Revenues
Operating revenues increased $110 million or 16 percent in the third quarter
of 2003, compared with the same period in 2002, primarily due to higher
retail revenues resulting from the collection of incremental LMP costs
beginning in May 2003 ($69 million) and from higher retail sales ($33
million) which includes a positive adjustment in estimated unbilled revenue
of approximately $39 million. Retail sales increased 5.4 percent compared
with the same period in 2002 after reflecting adjustments to unbilled sales.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased by $100 million
or 25 percent in the third quarter of 2003, compared with the same period in
2002, primarily due to costs associated with SMD ($69 million) and higher
standard offer purchased power expense as a result of higher retail sales
($15 million).
Other Operation and Maintenance
Other operation and maintenance (O&M) expenses increased $3 million in the
third quarter of 2003, compared with the same period in 2002, primarily due
to higher administrative costs ($7 million) resulting from higher health care
costs and lower pension income and higher RMR related transmission expense
($3 million), partially offset by lower distribution costs ($5 million).
Depreciation
Depreciation expense increased $2 million primarily due to higher utility
plant balances in 2003 resulting from plant additions.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense decreased $2 million primarily
due to lower amortization of recoverable nuclear costs ($8 million),
partially offset by higher amortization related to the recovery of stranded
costs ($6 million).
Taxes Other Than Income Taxes
Taxes other than income taxes increased $4 million in the third quarter of
2003 due to the recognition in 2002 of a Connecticut sales and use tax audit
settlement ($7 million), partially offset by a payment in 2002 to compensate
the Town of Waterford for lost property tax revenue as a result of the sale
of Millstone ($3 million).
Interest Expense, Net
Interest expense, net decreased $2 million primarily due to lower interest on
rate reduction bonds.
Other Income, Net
Other income, net decreased $5 million primarily due to lower interest and
dividend income ($2 million), lower equity in earnings from the nuclear
entitlements ($2 million) and lower conservation and load management (C&LM)
incentive income ($1 million).
Income Tax Expense
Income tax expense decreased $4 million primarily due to lower taxable
income.
Comparison of the First Nine Months of 2003 to the First Nine Months of 2002
Operating Revenues
Operating revenues increased by $245 million or 13 percent in 2003, compared
with the same period in 2002, primarily due to higher retail revenues ($179
million) and higher wholesale revenues ($64 million). Retail revenues were
higher primarily due to the collection of incremental LMP costs beginning in
May 2003 ($99 million) and higher retail sales ($79 million) which includes a
positive adjustment in estimated unbilled revenue of approximately $39
million. Retail kilowatt-hour (kWh) sales increased by 4.8 percent in 2003
after reflecting adjustments to unbilled sales. Wholesale revenues were
higher primarily due to higher market prices in 2003.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $170 million or
15 percent in 2003, primarily due to incremental LMP costs which were
recovered from customers ($99 million) and higher standard offer purchases as
a result of higher retail sales ($42 million).
Other Operation and Maintenance
Other O&M expenses increased by $31 million primarily due to higher
administrative costs ($18 million) resulting from higher health care costs
and lower pension income, higher RMR related transmission costs ($17
million), higher C&LM expenses ($7 million), partially offset by lower
related nuclear expenses ($11 million) as a result of the final DPUC order
regarding the CL&P Millstone use of proceeds docket in the first quarter of
2003.
Depreciation
Depreciation expense increased $4 million primarily due to higher utility
plant balances in 2003 resulting from plant additions.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense increased $33 million
primarily due to higher amortization related to the recovery of stranded
costs ($63 million), partially offset by lower amortization of recoverable
nuclear costs ($30 million).
Taxes Other Than Income Taxes
Taxes other than income taxes increased $5 million primarily due to the
recognition in 2002 of a Connecticut sales and use tax audit settlement ($7
million), partially offset by a payment in 2002 to compensate the Town of
Waterford for lost property tax revenue as a result of the sale of Millstone
($3 million).
Interest Expense, Net
Interest expense, net decreased $5 million primarily due to lower interest on
rate reduction bonds.
Other Income, Net
Other income, net decreased $9 million primarily due to lower interest and
dividend income ($3 million), lower equity in earnings from the nuclear
entitlements ($3 million) and lower C&LM incentive income ($2 million).
Income Tax Expense
Income tax expense decreased $7 million primarily due to lower taxable
income.
LIQUIDITY
CL&P's net cash flows provided by operating activities increased to $385.4
million for the nine months ended September 30, 2003 from $303.2 million for
the same period in 2002. Cash flows provided by operating activities
increased primarily due to the increase in the amortization of regulatory
assets related to the recovery of stranded costs and increases in working
capital items, offset by the placing of incremental LMP costs collected into
an escrow account beginning in July 2003.
On October 1, 2003, CL&P fixed the interest rate on $62 million of variable-
rate tax-exempt borrowings for five years at 3.35 percent.
CL&P's net cash flows used in investing activities increased to $251.9
million for the first nine months of 2003 from $109.6 million for the same
period in 2002. The increase is primarily due to higher capital expenditures
in 2003 and lower NU system Money Pool borrowings in 2003. CL&P's capital
expenditures totaled $224.8 million in the first nine months of 2003 compared
to $159.9 million in the first nine months of 2002.
Financing activities decreased in 2003 as a result of the repurchase of
common shares in 2002. In the first nine months of 2003, CL&P also repaid
$91.6 million of rate reduction bonds.
In the third quarter 2003, Fitch Ratings (Fitch) raised the outlook of CL&P's
credit ratings to stable from negative. The change in outlook is a result of
Fitch's belief that the risks associated with CL&P's standard offer service
contract with NRG had declined.
At September 30, 2003, CL&P had no borrowings outstanding on the Utility
Group's $300 million revolving credit line. This credit line expires on
November 11, 2003, and management expects to extend this credit line from
November 2003 through November 2004.
At September 30, 2003, CL&P had $40 million of accounts receivable and
unbilled revenues sold under its arrangement with a financial institution to
sell up to $100 million in accounts receivable and unbilled revenues. This
arrangement expires in July 2004.
CL&P is seeking approval from its preferred shareholders to permanently amend
its charter to eliminate a requirement that unsecured debt represent no more
than 10 percent of total capitalization. CL&P is offering its preferred
holders a payment of 1 percent of the $116.2 million par value of their
shares if the preferred holders vote in favor of the amendment and CL&P
implements it. Preferred holders of record as of September 30, 2003, are
eligible to vote at a special meeting, which will be held on November 25,
2003. Holders of at least two-thirds of CL&P's approximately 2.3 million
shares of preferred stock must vote in favor of the change for it to pass.
Management believes that CL&P will benefit from such a change due to
increased financial flexibility. In the event that this change fails or if
CL&P chooses not to implement it, CL&P is also asking preferred holders to
endorse another 10-year waiver that would allow CL&P's unsecured debt to rise
to 20 percent of total capitalization. At September 30, 2003, CL&P's
unsecured debt represented approximately 3 percent of CL&P's total long-term
debt. CL&P preferred holders approved a similar waiver in 1993 that is
scheduled to expire in March 2004.
Prior to July 1, 2003, CL&P recovered approximately $30 million of
incremental LMP costs from its customers and has withheld payment of these
incremental LMP costs from its standard offer service suppliers. This
positively impacted CL&P's liquidity. In July 2003, CL&P began depositing
new recoveries into an escrow account. Accordingly, further recovery of
these costs did not impact CL&P's liquidity. When the LMP dispute is
resolved, there will be a negative impact on CL&P's liquidity for the amounts
recovered but not deposited into the escrow account, as these amounts are
paid to standard offer service suppliers or returned to customers.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
---------------- --------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 5,782 $ 5,319
Receivables, net 68,966 68,204
Accounts receivable from affiliated companies 152 9,667
Unbilled revenues 35,450 32,004
Notes receivable from affiliated companies - 23,000
Fuel, materials and supplies, at average cost 52,087 49,182
Prepayments and other 17,257 10,032
------------- -------------
179,694 197,408
------------- -------------
Property, Plant and Equipment:
Electric utility 1,495,740 1,431,774
Other 6,180 6,195
------------- -------------
1,501,920 1,437,969
Less: Accumulated depreciation 718,860 715,800
------------- -------------
783,060 722,169
Construction work in progress 37,105 50,547
------------- -------------
820,165 772,716
------------- -------------
Deferred Debits and Other Assets:
Regulatory assets 972,042 1,026,043
Other 66,437 92,280
------------- -------------
1,038,479 1,118,323
------------- -------------
Total Assets $ 2,038,338 $ 2,088,447
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
--------------- ---------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to affiliated companies $ 53,500 $ -
Accounts payable 35,709 54,588
Accounts payable to affiliated companies 3,212 4,008
Accrued taxes 23,222 65,317
Accrued interest 14,437 11,333
Unremitted rate reduction bond collections 12,636 25,555
Other 17,513 12,674
-------------- --------------
160,229 173,475
-------------- --------------
Rate Reduction Bonds 483,432 510,841
-------------- --------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 339,791 359,910
Accumulated deferred investment tax credits 2,242 2,680
Deferred contractual obligations 50,790 56,165
Accrued pension 43,080 37,933
Other 206,638 218,328
-------------- --------------
642,541 675,016
-------------- --------------
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 2003 and 2002 - -
Capital surplus, paid in 126,608 126,937
Retained earnings 218,292 194,998
Accumulated other comprehensive loss (49) (105)
-------------- --------------
Common Stockholder's Equity 344,851 321,830
-------------- --------------
Total Capitalization 752,136 729,115
-------------- --------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 2,038,338 $ 2,088,447
============== ==============
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)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2003 2002 2003 2002
-------------------------- -------------------------
(Thousands of Dollars)
Operating Revenues $ 241,829 $ 324,818 $ 718,988 $ 816,113
----------- ----------- ----------- -----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 110,121 190,152 362,581 460,575
Other 34,874 33,309 100,382 94,315
Maintenance 13,512 13,342 50,689 45,585
Depreciation 10,963 10,377 32,290 30,681
Amortization of regulatory assets, net 18,264 19,742 22,415 14,532
Amortization of rate reduction bonds 10,666 8,071 29,422 34,739
Taxes other than income taxes 8,655 8,896 25,384 27,003
----------- ----------- ----------- -----------
Total operating expenses 207,055 283,889 623,163 707,430
----------- ----------- ----------- -----------
Operating Income 34,774 40,929 95,825 108,683
Interest Expense:
Interest on long-term debt 3,942 3,895 11,642 12,725
Interest on rate reduction bonds 7,237 7,584 21,981 23,022
Other interest 313 622 925 1,120
----------- ----------- ----------- -----------
Interest expense, net 11,492 12,101 34,548 36,867
----------- ----------- ----------- -----------
Other (Loss)/Income, Net (1,186) 231 (3,570) (887)
----------- ----------- ----------- -----------
Income Before Income Tax Expense 22,096 29,059 57,707 70,929
Income Tax Expense 9,483 9,577 23,213 24,487
----------- ----------- ----------- -----------
Net Income $ 12,613 $ 19,482 $ 34,494 $ 46,442
=========== =========== =========== ===========
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)
Nine Months Ended
September 30,
------------------------------
2003 2002
------------- -------------
(Thousands of Dollars)
Operating activities:
Net income $ 34,494 $ 46,442
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 32,290 30,681
Deferred income taxes and investment tax credits, net (3,602) (17,446)
Amortization of recoverable energy costs 17,541 12,494
Amortization of regulatory assets, net 22,415 14,532
Amortization of rate reduction bonds 29,422 34,739
Regulatory recoveries (1,593) (25,529)
Other sources of cash 20,675 22,347
Other uses of cash (29,932) (21,724)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net 5,307 7,496
Fuel, materials and supplies (2,905) 1,520
Accounts payable (19,673) (15,081)
Accrued taxes (42,095) 24,963
Other current assets and liabilities (excludes cash) (12,126) 11,365
----------- -----------
Net cash flows provided by operating activities 50,218 126,799
----------- -----------
Investing Activities:
Investments in plant (77,373) (75,817)
NU system Money Pool borrowing/(lending) 76,500 (5,800)
Buyout/buydown of IPP contracts (20,437) (5,152)
Other investment activities, net 10,316 (8,179)
----------- -----------
Net cash flows used in investing activities (10,994) (94,948)
----------- -----------
Financing Activities:
Issuance of rate reduction bonds - 50,000
Retirement of rate reduction bonds (27,409) (38,727)
Net decrease in short-term debt - (5,500)
Cash dividends on common stock (11,200) (24,500)
Other financing activities, net (152) (13,885)
----------- -----------
Net cash flows used in financing activities (38,761) (32,612)
----------- -----------
Net increase/(decrease) in cash 463 (761)
Cash - beginning of period 5,319 1,479
----------- -----------
Cash - end of period $ 5,782 $ 718
=========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
PSNH is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the first and second quarter 2003 reports on
Form 10-Q, and the NU 2002 Form 10-K.
RESULTS OF OPERATIONS
The components of significant income statement variances for the third
quarter of 2003 and for the first nine months of 2003 are provided in the
table below.
Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
------------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues $(83) (26)% $(97) (12)%
Operating Expenses:
Fuel, purchased and
net interchange power (80) (42) (98) (21)
Other operation 2 5 6 6
Maintenance - - 5 11
Depreciation - - 2 5
Amortization of regulatory
assets, net (1) (7) 8 54
Amortization of rate
reduction bonds 2 32 (5) (15)
Taxes other than income taxes - - (2) (6)
---- ---- ---- ----
Total operating expenses (77) (27) (84) (12)
---- ---- ---- ----
Operating income (6) (15) (13) (12)
---- ---- ---- ----
Interest expense, net - - (2) (6)
Other income/(loss), net (1) (a) (2) (a)
---- ---- ---- ----
Income before income tax expense (7) (24) (13) (19)
Income tax expense - - (1) (5)
---- ---- ---- ----
Net income $ (7) (35)% $(12) (26)%
==== ==== ==== ====
(a) Percent greater than 100.
Comparison of the Third Quarter of 2003 to the Third Quarter of 2002
Operating Revenues
Total operating revenues decreased $83 million or 26 percent in the third
quarter of 2003 compared with the same period of 2002, due to lower wholesale
revenues primarily due to the impact of the sale of Seabrook ($99 million),
partially offset by higher retail revenue ($16 million) which includes a
positive adjustment in estimated unbilled revenue of approximately $6
million. Retail kWh sales increased by 4.8 percent in 2003 after reflecting
adjustments to unbilled sales.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $80 million
primarily due to lower purchased power expenses as a result of the absence of
Seabrook power contract costs and lower wholesale sales.
Other Operation and Maintenance
Other O&M expenses increased $2 million primarily due to higher
administrative costs primarily resulting from C&LM programs and low income
program costs ($2 million) and higher distribution expenses ($1 million),
partially offset by lower fossil production maintenance expense ($1 million).
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $1 million primarily due to
decreased recovery of stranded costs resulting from the reconciliation of
actual stranded cost revenues against actual stranded costs.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $2 million due to the
scheduled repayment of principal.
Comparison of the First Nine Months of 2003 to the First Nine Months of 2002
Operating Revenues
Total operating revenues decreased $97 million or 12 percent in the first
nine months of 2003 compared with the same period of 2002, due to lower
wholesale revenues ($143 million) primarily due to the impact of the sale of
Seabrook, partially offset by higher retail revenue ($47 million) which
includes a positive adjustment in estimated unbilled revenue of approximately
$6 million. Retail kWh sales increased by 5.5 percent in 2003 after
reflecting adjustments to unbilled sales.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $98 million,
primarily due to lower purchased power expenses as a result of the absence of
Seabrook power contract costs and lower wholesale sales.
Other Operation and Maintenance
Other O&M expense increased $11 million primarily due to higher
administrative costs ($7 million) primarily resulting from C&LM programs and
low income program costs and higher fossil production maintenance expenses
($4 million).
Depreciation
Depreciation increased $2 million primarily due to additions to distribution,
generation and general plant assets.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $8 million primarily due to
increased recovery of stranded costs resulting from the reconciliation of
actual stranded cost revenues against actual stranded costs.
Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds decreased $5 million due to the
scheduled repayment of principal.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $2 million primarily due to lower
property taxes.
Interest Expense, Net
Interest expense, net decreased $2 million primarily due to lower interest
costs associated with the refinancing of the pollution control revenue bonds.
Other Income/(Loss), Net
Other income/(loss), net decreased $2 million primarily due to increased
service fees associated with rate reduction bonds and lower gains on the
disposition of property in 2003.
Income Tax Expense
Income tax expense decreased $1 million primarily due to lower taxable
income.
LIQUIDITY
PSNH's net cash flows provided by operating activities totaled $50.2 million
for the nine months ended September 30, 2003, compared with $126.8 million
for the same period of 2002. Cash flows provided by operating activities
decreased due to changes in working capital items, primarily the payment of
taxes on the gain on the sale of Seabrook.
PSNH's net cash flows used in investing activities were $11 million for the
nine months ended September 30, 2003 compared with $94.9 million for the same
period in 2002. The decrease is primarily due to higher NU system Money Pool
borrowings in 2003. PSNH's capital expenditures totaled $77.4 million in the
first nine months of 2003 compared to $75.8 million in the first nine months
of 2002.
In the first nine months of 2003, PSNH also repaid $27.4 million of rate
reduction bonds.
At September 30, 2003, PSNH had no borrowings outstanding on the Utility
Group's $300 million revolving credit line. This credit line expires on
November 11, 2003, and management expects to extend this credit line from
November 2003 through November 2004.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
-------------- -------------
(Thousands of Dollars)
ASSETS
- ------
Current Assets:
Cash $ 1 $ 123
Receivables, net 37,480 42,203
Accounts receivable from affiliated companies 2,458 6,354
Taxes receivable 1,218 -
Unbilled revenues 9,811 8,944
Fuel, materials and supplies, at average cost 2,370 1,821
Prepayments and other 967 1,470
-------------- -------------
54,305 60,915
-------------- -------------
Property, Plant and Equipment:
Electric utility 602,915 590,153
Less: Accumulated depreciation 201,984 195,804
-------------- -------------
400,931 394,349
Construction work in progress 16,125 11,860
-------------- -------------
417,056 406,209
-------------- -------------
Deferred Debits and Other Assets:
Regulatory assets 241,798 283,702
Prepaid pension 73,321 67,516
Other 21,011 18,304
-------------- -------------
336,130 369,522
-------------- -------------
Total Assets $ 807,491 $ 836,646
============== =============
The accompanying notes are an integral part of these consolidated financial
statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
-------------- ------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
- ------------------------------
Current Liabilities:
Notes payable to banks $ - $ 7,000
Notes payable to affiliated companies 32,200 85,900
Accounts payable 19,106 17,730
Accounts payable to affiliated companies 12,088 6,218
Accrued taxes 412 4,334
Accrued interest 1,045 2,059
Other 10,097 8,005
------------- -------------
74,948 131,246
------------- -------------
Rate Reduction Bonds 135,383 142,742
------------- -------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 208,719 222,065
Accumulated deferred investment tax credits 3,410 3,662
Deferred contractual obligations 57,804 63,767
Other 16,467 13,213
------------- -------------
286,400 302,707
------------- -------------
Capitalization:
Long-Term Debt 157,077 101,991
------------- -------------
Common Stockholder's Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2003 and 2002 10,866 10,866
Capital surplus, paid in 69,568 69,712
Retained earnings 73,317 77,476
Accumulated other comprehensive loss (68) (94)
------------- -------------
Common Stockholder's Equity 153,683 157,960
------------- -------------
Total Capitalization 310,760 259,951
------------- -------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 807,491 $ 836,646
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2003 2002 2003 2002
----------- ------------ ----------- -----------
(Thousands of Dollars)
Operating Revenues $ 103,365 $ 95,684 $ 297,816 $ 278,880
----------- ----------- ----------- -----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 52,194 46,927 150,361 140,510
Other 16,070 12,516 43,611 37,083
Maintenance 3,785 3,798 10,378 10,029
Depreciation 3,544 3,415 10,530 11,038
Amortization of regulatory assets, net 10,647 12,092 32,819 26,277
Amortization of rate reduction bonds 2,399 2,189 7,327 7,080
Taxes other than income taxes 3,134 2,223 8,943 7,966
----------- ----------- ----------- -----------
Total operating expenses 91,773 83,160 263,969 239,983
----------- ----------- ----------- -----------
Operating Income 11,592 12,524 33,847 38,897
Interest Expense:
Interest on long-term debt 767 880 2,303 2,172
Interest on rate reduction bonds 2,228 2,379 6,803 7,245
Other interest 127 542 848 1,377
----------- ----------- ----------- -----------
Interest expense, net 3,122 3,801 9,954 10,794
----------- ----------- ----------- -----------
Other Income/(Loss), Net 1,213 742 986 (2,342)
----------- ----------- ----------- -----------
Income Before Income Tax Expense/(Benefit) 9,683 9,465 24,879 25,761
Income Tax Expense/(Benefit) 4,488 4,735 11,030 (1,181)
----------- ----------- ----------- -----------
Net Income $ 5,195 $ 4,730 $ 13,849 $ 26,942
=========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
------------------------------
2003 2002
------------ -----------
(Thousands of Dollars)
Operating Activities:
Net income $ 13,849 $ 26,942
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 10,530 11,038
Deferred income taxes and investment tax credits, net (11,272) (19,312)
Amortization of recoverable energy costs 448 322
Amortization of regulatory assets, net 32,819 26,277
Amortization of rate reduction bonds 7,327 7,080
Prepaid pension (5,805) (10,264)
Regulatory recoveries 2,879 8,849
Other sources of cash 1,800 16,580
Other uses of cash (11,183) (35,675)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net 7,752 9,771
Fuel, materials and supplies (548) (232)
Accounts payable 7,246 (23,839)
Accrued taxes (3,922) 1,089
Other current assets and liabilities (excludes cash) 384 2,039
---------- ----------
Net cash flows provided by operating activities 52,304 20,665
---------- ----------
Investing Activities:
Investments in plant (20,661) (14,739)
NU system Money Pool (lending)/borrowing (53,700) 20,500
Other investment activities, net (676) 1,334
---------- ----------
Net cash flows (used in)/provided by investing activities (75,037) 7,095
---------- ----------
Financing Activities:
Issuance of long-term debt 55,000 -
Repurchase of common shares - (13,999)
Retirement of rate reduction bonds (7,359) (7,337)
Net (decrease)/increase in short-term debt (7,000) 5,000
Cash dividends on common stock (18,008) (12,005)
Other financing activities, net (22) (17)
---------- ----------
Net cash flows provided by/(used in) financing activities 22,611 (28,358)
---------- ----------
Net decrease in cash (122) (598)
Cash - beginning of period 123 599
---------- ----------
Cash - end of period $ 1 $ 1
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
Management's Discussion and Analysis of
Financial Condition and Results of Operations
WMECO is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the first and second quarter 2003 reports on
Form 10-Q, the NU 2002 Form 10-K, and the current report on Form 8-K dated
September 30, 2003.
RESULTS OF OPERATIONS
The components of significant income statement variances for the third
quarter of 2003 and the first nine months of 2003 are provided in the table
below.
Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
------------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues $ 8 8% $ 19 7%
Operating Expenses:
Fuel, purchased and
net interchange power 5 11 10 7
Other operation 4 28 7 18
Maintenance - - - -
Depreciation - - (1) (5)
Amortization of regulatory
assets, net (1) (12) 7 25
Amortization of rate
reduction bonds - - - -
Taxes other than income taxes 1 41 1 12
---- ---- ---- ----
Total operating expenses 9 10 24 10
---- ---- ---- ----
Operating income (1) (7) (5) (13)
---- ---- ---- ----
Interest expense, net (1) (18) (1) (8)
Other income/(loss), net - - 3 (a)
---- ---- ---- ----
Income before income tax
expense/(benefit) - - (1) (3)
Income tax expense/(benefit) - - 12 (a)
---- ---- ---- ----
Net income $ - -% $(13) (49)%
==== ==== ==== ====
(a) Percent greater than 100.
Comparison of the Third Quarter of 2003 to the Third Quarter of 2002
Operating Revenues
Operating revenues increased $8 million or 8 percent in 2003, compared with
the same period in 2002, due to higher retail revenues ($7 million) and
higher wholesale revenues ($1 million). Retail revenues were higher
primarily due to an increase in the standard offer component of retail
delivery rates and higher retail sales which includes a positive adjustment
in estimated unbilled revenue of approximately $2 million. Retail kWh sales
were 1.9 percent higher after reflecting adjustments to unbilled sales.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $5 million
primarily due to higher standard offer purchases as a result of the higher
standard offer contract costs and the retail sales increase.
Other Operation
Other operation expenses increased $4 million primarily due to higher general
and administrative expenses resulting from higher health care costs and lower
pension income.
Comparison of the First Nine Months of 2003 to the First Nine Months of 2002
Operating Revenues
Operating revenues increased by $19 million or 7 percent in 2003, compared
with the same period in 2002, due to higher retail revenues ($13 million) and
higher wholesale revenues ($6 million). Retail revenues were higher
primarily due to an increase in the standard offer component of retail
delivery rates and higher retail sales which includes a positive adjustment
in estimated unbilled revenue of approximately $2 million. Retail kWh sales
were 3.9 percent higher after reflecting adjustments to unbilled sales.
Wholesale revenues were higher primarily due to higher wholesale sales.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $10 million
primarily due to higher standard offer purchases as a result of the retail
sales increase and the higher standard offer contract costs.
Other Operation
Other operation expenses increased $6 million primarily due to higher general
and administrative expenses resulting from higher health care costs and lower
pension income.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense increased $7 million primarily
due to the higher recovery of stranded costs.
Other Income/(Loss), Net
Other income/(loss), net increased $3 million primarily due to the 2002
adjustment to the gain from the 1999 sale of the fossil units as a result of
a DTE decision in the annual stranded cost reconciliation filing for the
period ended December 31, 1999.
Income Tax Expense/(Benefit)
Income tax expense/(benefit) increased $12 million primarily due to the
recognition in 2002 of investment tax credits as a result of a 2002 DTE
decision.
LIQUIDITY
WMECO's net cash flows provided by operating activities increased to $52.3
million for the first nine months of 2003 from $20.7 million for the same
period of 2002. Net cash flows provided by operating activities increased
primarily due to changes in working capital items, primarily accounts
payable.
On September 30, 2003, WMECO issued $55 million of ten-year 5 percent notes,
the proceeds from which WMECO used to repay a similar level of borrowings
from the NU system Money Pool.
WMECO's net cash flows used in investing activities were $75 million for the
nine months ended September 30, 2003, compared with net cash flows provided
by investing activities of $7.1 million for the same period of 2002. The
change is primarily due to lower NU system Money Pool borrowings in 2003.
WMECO's capital expenditures totaled $20.7 million in the first nine months
of 2003 compared to $14.7 million in the first nine months of 2002.
In the first nine months of 2003, WMECO also repaid $7.4 million of rate
reduction bonds.
At September 30, 2003, WMECO had no borrowings outstanding on the Utility
Group's $300 million revolving credit line. This credit line expires on
November 11, 2003, and management expects to extend this credit line from
November 2003 through November 2004.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TheAdditional 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," Note 2B, "Derivative Instruments, Market Risk and
Risk Management - Market Risk Information," and Note 2C, "Derivative
Instruments, Market Risk and Risk Management - Other Risk Management
Activities," 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 timely made in accordance with the Exchange Act and the rules
and forms of the SEC. These evaluations were 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.forms and ii) is accumulated and communicated to management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding required disclosure. No
significant changes were made to the companies' internal controls or other
factors that could significantly affect these controls subsequent to the date
of their evaluation.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
1. Consolidated Edison, Inc. v. NU - Merger Appeals and Related Litigation
- United States District CourtRetirement Plan Litigation
This litigation consistsmatter involved four separate but related federal court lawsuits brought
by nineteen former employees of NUSCO, WMECO and CL&P who retired between
1991 and 1994. The complaints generally allege that the consolidated civil lawsuits filedcompanies breached
their fiduciary duties to the plaintiffs by making affirmative
misrepresentations to them in response to specific inquiries that caused them
to retire prematurely.
The cases were tried together in a summary bench trial in the United States
District Court forin Hartford, Connecticut in April - May 2002. In a ruling
issued on April 1, 2004, the Southern Districtjudge found in favor of New York (District
Court) by Consolidated Edison, Inc. (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 has been a "Material Adverse Change" with respect to NU
and that certain conditions precedent to Con Edison's obligation to merge
with NU have not been and cannot be satisfied. (Con Edison's amended
complaint further asserts 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 breachfifteen of the Merger Agreement based onnineteen
plaintiffs and ordered NU to modify its repudiation
thereof and its refusalretirement plan so as to proceed withinclude the
merger.
As of June 19, 2003, the parties' motions in liminesuccessful plaintiffs in the District Court
case were fully briefed and are now pending beforespecial retirement plans at issue, retroactive
to the District Court. Con
Edison's July 1, 2003 motiondates of their retirement. NU appealed the court's decision to dismiss NU's "lost premium" counterclaim has
also been fully briefed and is pending. On July 24, 2003, Robert Rimkoski
filed a motion to intervene. On August 7, 2003, NU filed a brief in
opposition to Mr. Rimkoski's motion to intervene. The motions in limine,
motion to dismiss and motion to intervene are scheduled to be heard by the
District Court on November 7, 2003.
2. NRG - Credit Rating Status
On May 14, 2003, NRG and various affiliates filed for Chapter 11 protection
in the
United States Bankruptcy Court for the Southern District of New York
(Bankruptcy Court). The filing affects various relationships between NU
companies and NRG.
A. CL&P Standard Offer Contract
NRG's May 14, 2003, bankruptcy filing included a request by NRG Power
Marketing, Inc. (NRG-PM) to terminate service to CL&P under its standard
offer supply agreement (SOS Agreement). The Bankruptcy Court authorized NRG-
PM to reject the SOS Agreement, but the FERC directed NRG-PM to continue to
perform under its SOS Agreement until the FERC fully considers the matter.
Subsequently, the U.S. District Court for the Southern District of New York
issued a ruling deferring to the FERC on this matter. On July 18, 2003, NRG-
PM and the Creditors Committee filed an appeal with the U.S. Court of Appeals for the Second Circuit on a number of legal
and factual grounds.
For further information on retirement-related matters, see Part I, Item 2,
Note 7, of the "Notes to enjoin the FERC order; this appeal is currently
pending. On August 15, 2003, the FERC issued an order stating that NRG-PM
had failed to demonstrate that premature termination of its SOS Agreement
withConsolidated Financial Statements."
2. Hawkins, Delafield & Wood (Hawkins) v. NU, NUSCO and CL&P
would beOn December 12, 2002, Hawkins, a New York law firm sued by the Connecticut
Resources Recovery Authority (CRRA) as a result of the Enron bankruptcy,
brought an apportionment complaint against a number of former Enron officers,
directors and outside accountants. In addition to the Enron defendants,
Hawkins also named as defendants in its complaint NU, NUSCO and CL&P. Hawkins
asserts in its complaint that in the public interestevent it is found liable to CRRA, then
the apportionment defendants, including NU, NUSCO and therefore, NRG-PM must
continueCL&P, are responsible
for some or all of the $220 million claimed as damages. The case was
subsequently removed to performfederal court where it has been stayed pending a
final transfer order.
3. Enron Bankruptcy Claim
CL&P is asserting damages of in excess of approximately $15 million in
Enron's bankruptcy proceeding arising out of the rejection in March 2003 of
CL&P's power purchase agreement with Enron Power Marketing, Inc. for power
from CRRA's South Meadow project. The Connecticut Attorney General (AG), on
behalf of CRRA, has objected to this claim being heard on the grounds that it
might interfere with the AG's attempt to obtain rescission of the original
CRRA-Enron transaction.
4. CRRA Lawsuit
On March 31, 2004, CL&P was served with two state court complaints from CRRA
(one suit is on behalf of CRRA, the other on behalf of the directors of CRRA)
claiming that CL&P either negligently or fraudulently allowed CRRA and its
directors to become involved with Enron. Damages in excess of $200 million
are claimed. CL&P intends to vigorously defend the matter.
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF
EQUITY SECURITIES
The table below sets forth the information with respect to purchases made by
or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-
18(a)(3) under the SOS Agreement.
On September 15, 2003, NRG-PM andSecurities Exchange Act of 1934), of common stock during
the Official Committee of Unsecured
Creditors for NRG and its debtor subsidiaries (Committee) requested rehearing
of the FERC's August 15, 2003, order and the FERC has not yet acted on that
request. NRG-PM and the Committee also have filed appeals of the FERC's June
25, 2003 order and August 15, 2003 order denying rehearing with the D.C.
District Court of Appeals.
B. Station Service
NRG has disputed its responsibility to pay for the provision of station
service by CL&P to NRG's Connecticut generating plants. The FERC issued a
decision on December 20, 2002, that NRG had agreed that station service from
CL&P would be subject to CL&P's applicable retail rates, and that states have
jurisdiction over the delivery of power to end users even where, as here,
power is not delivered via distribution facilities. NRG refused CL&P's
subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC
for a declaratory order enforcing the FERC's December 20, 2002, decision.
The DPUC proceeding was subsequently stayed due to the bankruptcy filing.
On September 18, 2003, the Bankruptcy Court approved the parties' stipulation
to submit the station service issue to arbitration for a determination of
liability and damages which will fix CL&P's claim in bankruptcy.
For additional information on certain matters involving NRG and its
affiliates, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and Note 4B, "NRG Energy, Inc. Exposures," within
the notes to the consolidated financial statements in this combined report on
Form 10-Q; "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Part II, Item 1. Legal Proceedings" in NU's
report on Form 10-Q for the quartersquarter ended March 31, 2003, and June 30, 2003,
and "Part I, Item 1. Business - Rates and Electric Industry Restructuring -
Connecticut" and "Part I, Item 3. Legal Proceedings"2004.
- --------------------------------------------------------------------------------------------
Total Number of Maximum Number
Shares Purchased of Shares That
as Part of May Yet Be
Total Number Publicly Purchased Under
of Shares Average Price Announced Plans the Plans or
Period Purchased (1) Paid Per Share or Programs Programs
- --------------------------------------------------------------------------------------------
Month #1
(January 1, 2004 to
January 31, 2004) 332 $20.16 - N/A
- --------------------------------------------------------------------------------------------
Month #2
(February 1, 2004
to February 29, 2004) - N/A - N/A
- --------------------------------------------------------------------------------------------
Month #3
(March 1, 2004 to
March 31, 2004) - N/A - N/A
- --------------------------------------------------------------------------------------------
Total 332 $20.16 - N/A
- --------------------------------------------------------------------------------------------
(1) Purchases were made in NU's 2003 annual
report on Form 10-K.
3. Connecticut Yankee Atomic Power Company Decommissioning Dispute
On June 13, 2003, CYAPC gave notice of the termination of its contract with
Bechtelopen market transactions related to a compensation
plan for the decommissioning of the Connecticut Yankee nuclear power
plant. CYAPC terminated the contract, after the failure of settlement
discussions that occurred over an eight month period, due to Bechtel's
history of incomplete and untimely performance and refusal to perform
remaining decommissioning work. Under the agreement, Bechtel had 30 days to
remedy its defaults before the termination became effective.
On June 23, 2003, Bechtel filed a complaint against CYAPC in Connecticut
Superior Court in Middletown, Connecticut. Bechtel's complaint asserts a
number of claims and seeks a variety of remedies, including monetary and
punitive damages and rescission of the contract. Bechtel has since amended
its complaint to add claims for wrongful termination.
On August 22, 2003, CYAPC filed its answer and counterclaims, including
counts for breach of contract, negligent misrepresentation and breach of duty
of good faith and fair dealing. Bechtel has departed the site and the
decommissioning responsibility has been transitioned to CYAPC, which has
recommenced the decommissioning process.
NU's electric operating subsidiaries collectively own 49.0 percent of CYAPC,
as follows: CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent.
For further information relating to this proceeding, see Note 4D, "Deferred
Contractual Obligation - Connecticut Yankee Atomic Power Company (CYAPC)
Decommissioning Dispute," within the notes to the consolidated financial
statements in this combined report of Form 10-Q.certain management employees.
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 Michael G. Morris,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 NovemberMay 7, 20032004
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 NovemberMay 7, 20032004
32 Certification of Michael G. Morris,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
NovemberMay 7, 20032004
(a) Listing of Exhibits (CL&P)
4.2.7.5 Compensation and Multiannual Mode Agreement among the
Connecticut Development Authority, The Connecticut Light
and Power Company and BNY Capital Markets, Inc. dated
September 23, 2003
4.2.8.24.14.1 Amendment No. 3 to the Amended and Restated Receivables
Purchase and SalesCredit Agreement dated as of July 9,March 31, 2004
to Credit Agreement dated as of November 10, 2003, (CLamong
WMECO, CL&P, PSNH, Yankee Gas, the Banks Named Therein
and CRC)Citibank, N.A. as Administrative Agent, (Exhibit B-7
to NU 35-CERT filed April 27, 2004, File No. 70-9755)
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 NovemberMay 7, 20032004
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 NovemberMay 7, 20032004
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
NovemberMay 7, 20032004
(a) Listing of Exhibits (PSNH)
4.7.1 Amendment to Credit Agreement dated as of March 31, 2004
to Credit Agreement dated as of November 10, 2003, among
WMECO, CL&P, PSNH, Yankee Gas, the Banks Named Therein
and Citibank, N.A. as Administrative Agent, (Exhibit B-7
to NU 35-CERT filed April 27, 2004, File No. 70-9755)
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 NovemberMay 7, 20032004
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 NovemberMay 7, 20032004
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 NovemberMay 7, 20032004
(a) Listing of Exhibits (WMECO)
4.4.3 Underwriting4.4.1 Amendment to Credit Agreement between WMECO and the Underwriters
named therein, dated September 25, 2003 (Exhibit 99.1,
WMECO Form 8-K filed October 8, 2003, File No. 0-7624)
4.4.4 Indenture Agreement between WMECO and the Bank of New
York, as Trustee, dated as of September 1, 2003 (Exhibit
99.2, WMECO Form 8-K filed October 8, 2003, File No. 0-
7624)
4.4.5 First Supplemental IndentureMarch 31, 2004
to Credit Agreement between WMECO and
the Bank of New York, as Trustee, dated as of September 1,November 10, 2003, among
WMECO, CL&P, PSNH, Yankee Gas, the Banks Named Therein
and Citibank, N.A. as Administrative Agent, (Exhibit 99.3, WMECO Form 8-KB-7
to NU 35-CERT filed October 8, 2003,April 27, 2004, File No. 0-7624)70-9755)
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 NovemberMay 7, 20032004
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
NovemberMay 7, 20032004
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
NovemberMay 7, 20032004
(a) Listing of Exhibits (NU, CL&P, PSNH and WMECO)
10.30.1 Arrangement with Charles W. Shivery with respect to
interim compensation, effective as of January 1, 2004
10.32 Northeast Utilities Deferred Compensation Plan for
Trustees, amended and restated effective January 1, 2004
10.33 Northeast Utilities Deferred Compensation Plan for
Executives, amended and restated effective January 1,
2004
(b) Reports on Form 8-K:
WMECONU and CL&P filed current reports on Form 8-K dated January 22, 2004
disclosing:
o The delay in filing the agreement reached in principle to settle the SMD
dispute with the FERC.
NU filed a current report on Form 8-K dated SeptemberMarch 30, 2003,2004 disclosing:
o The completionannouncement by the NU Board of the issuanceTrustees that Charles W. Shivery has
been named chairman, president and sale to the publicchief executive officer of $55 million
of 5 percent Senior Notes, Series A, due 2013.NU, effective
immediately.
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: NovemberMay 7, 20032004 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: NovemberMay 7, 20032004 By /s/ John H.Forsgren
---------------- -------------------------------------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: NovemberMay 7, 20032004 By /s/ John H. Forsgren
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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
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Registrant
Date: NovemberMay 7, 20032004 By /s/ John H. Forsgren
---------------- ------------------------------------------------ -----------------------------------
John H. Forsgren
Executive Vice President
and Chief Financial Officer
(for the Registrant and as
Principal Financial Officer)