UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q/A
AMENDMENT NO. 1
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended JUNE 30, 2004
-------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
----------- ------------------------------ ------------------
1-5324 NORTHEAST UTILITIES 04-2147929
(a Massachusetts voluntary association)
ONE FEDERAL STREET
BUILDING 111-4
SPRINGFIELD, MASSACHUSETTS 01105
Telephone: (413) 785-5871
Indicate by check mark whether the registrant (1) has 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 registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES X NO
--- -----
Indicate by check mark whether the following registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act):
Northeast Utilities YES X NO
--- -----
Indicate the number of shares outstanding of each of the issuers' classes of
common stock, as of the latest practicable date:
Company - Class of Stock Outstanding at July 31, 2004
------------------------ ----------------------------
Northeast Utilities
Common shares, $5.00 par value 128,232,433 shares
FORM 10-Q/A EXPLANATORY NOTE
This Amendment No. 1 to our quarterly report on Form 10-Q (Form 10-Q/A) is being
filed to amend the quarterly report on Form 10-Q for the quarter ended June 30,
2004 of Northeast Utilities (NU), which was originally filed on August 6, 2004
(Original Form 10-Q). Accordingly, pursuant to rule 12b-15 under the Securities
Exchange Act of 1934, as amended, this Form 10-Q/A contains the complete text of
Items 1, 2, and 4 of Part I and Item 6 of Part II, as amended, as well as
certain currently dated certifications. Unaffected items from the quarterly
reports of separate registrants The Connecticut Light and Power Company, Public
Service Company of New Hampshire and Western Massachusetts Electric Company (and
associated certifications) have not been repeated in this Form 10-Q/A.
Subsequent to the filing of the Form 10-Q for the quarter ended June 30, 2004,
NU concluded that it incorrectly applied accrual accounting for certain natural
gas contracts established by the merchant energy segment to mitigate the risk of
electricity purchased in anticipation of winning certain levels of wholesale
electric load in New England. The natural gas basis contracts were originally
accounted for on the accrual basis. The natural gas futures and swaps contracts
were accounted for as cash flow hedges with changes in fair value reflected in
other comprehensive income (a component of shareholders' equity). However,
subsequent to the filing of the second quarter Form 10-Q, NU concluded that
applying accrual accounting for the basis contracts was incorrect. The basis
contracts should have been recorded at current fair value with changes in fair
value impacting earnings. The fair value, which was a negative $0.9 million, has
now been reflected in non-trading derivative liabilities and as an increase to
fuel, purchased and net interchange power expenses. The futures and swaps
contracts should not have been accounted for as cash flow hedges and should also
have been recorded at fair value. The fair value, which was a positive $2.7
million and was previously reflected in other comprehensive income (a component
of shareholders' equity), has now been reflected as a reduction of fuel,
purchased and net interchange power expenses. This Form 10-Q/A reflects the
change from accrual and hedge accounting to fair value accounting for the
aforementioned natural gas derivative contracts. The net income impact of both
of these restatements on both the second quarter and the six months ended June
30, 2004 is a positive $1.1 million.
The natural gas contracts discussed above are accounted for at fair value with
changes in fair value included in earnings. NU concluded that fair value or
mark-to-market accounting should have been applied. To correct this error, NU
restated its condensed consolidated balance sheet as of June 30, 2004, the
condensed consolidated statements of income for the three and six months ended
June 30, 2004, and the condensed consolidated statement of cash flows for the
six months ended June 30, 2004. NU has also restated the notes to its condensed
consolidated financial statements as necessary to reflect the adjustments.
Corrections have been made to cash and cash equivalents, unrestricted cash from
counterparties, and accounts payable, which had no impact on net income. These
corrections reclassified unrestricted cash from counterparties to cash and cash
equivalents because those funds were unrestricted and were used to or were
available to fund the company's operations. The December 31, 2003 condensed
consolidated balance sheet has been restated for these corrections and a
correction to decrease derivative assets and liabilities by the same amount in
order to eliminate certain intercompany derivative assets and liabilities. For
information regarding these restatements and the effects on significant
financial statement line items, see Note 9, "Restatement of Previously Issued
Financial Statements," to the condensed consolidated financial statements.
This amendment does not otherwise reflect events occurring after the filing of
the Original Form 10-Q, which was filed on August 6, 2004. Such events include,
among others, the events described in NU's quarterly report on Form 10-Q for the
quarter ended September 30, 2004, and the events described in NU's current
reports on Form 8-K filed after the filing of the Original Form 10-Q, except for
those reports pertaining to this subject matter. Earnings guidance is not
included in this Form 10-Q/A. For information regarding NU's most recent
earnings guidance, see the current reports on Form 8-K dated January 26, 2005
and February 4, 2005.
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms that
are found in this report:
NU COMPANIES OR SEGMENTS
BMC......................................... BMC Energy LLC
CL&P........................................ The Connecticut Light and Power Company
CRC......................................... CL&P Receivables Corporation
HWP......................................... Holyoke Water Power Company
NGC......................................... Northeast Generation Company
NGS......................................... Northeast Generation Services Company
NU or the company........................... Northeast Utilities
NU Enterprises.............................. NU's competitive subsidiaries comprised of HWP, NGC, NGS, Select
Energy, SESI, and Woods Network. For further information, see Note
8, "Segment Information," to the condensed consolidated financial
statements.
PSNH........................................ Public Service Company of New Hampshire
RMS......................................... R. M. Services, Inc.
Select Energy............................... Select Energy, Inc. (including its wholly owned subsidiary SENY)
SENY........................................ Select Energy New York, Inc.
SESI........................................ Select Energy Services, Inc.
Utility Group............................... NU's regulated utilities comprised of CL&P, PSNH, WMECO, and
Yankee Gas. For further information, see Note 8, "Segment
Information," to the condensed consolidated financial statements.
WMECO....................................... Western Massachusetts Electric Company
Woods Network............................... Woods Network Services, Inc.
Yankee...................................... Yankee Energy System, Inc.
Yankee Gas.................................. Yankee Gas Services Company
THIRD PARTIES
Bechtel..................................... Bechtel Power Corporation
CYAPC....................................... Connecticut Yankee Atomic Power Company
NRG......................................... NRG Energy, Inc.
REGULATORS
CSC......................................... Connecticut Siting Council
DPUC........................................ Connecticut Department of
Public Utility Control
DTE......................................... Massachusetts Department of
Telecommunications and Energy
FERC........................................ Federal Energy Regulatory Commission
NHPUC....................................... New Hampshire Public Utilities Commission
SEC......................................... Securities and Exchange Commission
i
OTHER
Act, the.................................... Public Act No. 03-135
CTA......................................... Competitive Transition Assessment
EPS......................................... Earnings per Share
FASB........................................ Financial Accounting Standards Board
FIN......................................... FASB Interpretation
FMCC........................................ Federally Mandated Congestion Costs
FSP......................................... FASB Staff Position
FTR......................................... Financial Transmission Rights
GSC......................................... Generation Service Charge
IERM........................................ Infrastructure Expansion Rate Mechanism
Incentive Plan.............................. Northeast Utilities Incentive Plan
ISO-NE...................................... New England Independent System Operator
kWh......................................... Kilowatt-hour
LMP......................................... Locational Marginal Pricing
LOCs........................................ Letters of Credit
MW.......................................... Megawatts
NU 2003 Form 10-K........................... The Northeast Utilities and Subsidiaries combined 2003 Form 10-K
as filed with the SEC
NYMEX....................................... New York Mercantile Exchange
OCA......................................... Office of Consumer Advocate
Restructuring
Settlement................................ "Agreement to Settle PSNH Restructuring"
ROE......................................... Return on Equity
RTO......................................... Regional Transmission Organization
S&P......................................... Standard & Poor's
SBC......................................... System Benefits Charge
SCRC........................................ Stranded Cost Recovery Charge
SFAS........................................ Statement of Financial Accounting Standards
SMD......................................... Standard Market Design
TSO......................................... Transitional Standard Offer
ii
Northeast Utilities and Subsidiaries
TABLE OF CONTENTS
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Page
----
Part I. Financial Information
Item 1. Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets
(Unaudited) - June 30, 2004 (Restated) and
December 31, 2003 (Restated)............................ 2
Condensed Consolidated Statements of Income
(Unaudited) - Three and Six Months Ended
June 30, 2004 (Restated) and 2003....................... 4
Condensed Consolidated Statements of Cash Flows
(Unaudited)- Six Months Ended June 30, 2004
(Restated) and 2003..................................... 5
Notes to Condensed Consolidated Financial Statements
(Restated and Unaudited - all companies)................ 6
Item 2. Management's Discussion and
Analysis of Financial Condition
and Results of Operations (Restated).................... 39
Item 4. Controls and Procedures (Restated)...................... 65
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K........................ 66
Signatures.................................................................. 67
iii
NORTHEAST UTILITIES AND SUBSIDIARIES
1
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
(Restated)* (Restated)*
---------------------- ----------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 48,680 $ 43,372
Restricted cash - LMP costs 123,887 93,630
Special deposits 28,147 79,120
Investments in securitizable assets 190,388 166,465
Receivables, net 648,659 704,893
Unbilled revenues 102,597 125,881
Fuel, materials and supplies, at average cost 154,459 154,076
Derivative assets 365,988 249,117
Prepayments and other 69,106 63,780
---------------------- ----------------------
1,731,911 1,680,334
---------------------- ----------------------
Property, Plant and Equipment:
Electric utility 5,702,856 5,465,854
Gas utility 763,605 743,990
Competitive energy 902,871 885,953
Other 238,402 221,986
---------------------- ----------------------
7,607,734 7,317,783
Less: Accumulated depreciation 2,320,807 2,244,263
---------------------- ----------------------
5,286,927 5,073,520
Construction work in progress 354,823 356,396
---------------------- ----------------------
5,641,750 5,429,916
---------------------- ----------------------
Deferred Debits and Other Assets:
Regulatory assets 2,854,344 2,974,022
Goodwill 319,986 319,986
Purchased intangible assets, net 21,153 22,956
Prepaid pension 358,250 360,706
Other 454,831 428,567
---------------------- ----------------------
4,008,564 4,106,237
---------------------- ----------------------
Total Assets $ 11,382,225 $ 11,216,487
====================== ======================
* See Note 9.
The accompanying notes are an integral part of these condensed consolidated
financial statements.
2
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
(Restated)* (Restated)*
---------------------- ----------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks $ 5,807 $ 105,000
Long-term debt - current portion 89,114 64,936
Accounts payable 771,561 728,463
Accrued taxes 27,148 51,598
Accrued interest 43,310 41,653
Derivative liabilities 163,990 112,612
Counterparty deposits 104,976 46,496
Other 214,378 203,080
---------------------- ----------------------
1,420,284 1,353,838
---------------------- ----------------------
Rate Reduction Bonds 1,639,344 1,729,960
---------------------- ----------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,346,185 1,287,354
Accumulated deferred investment tax credits 101,000 102,652
Deferred contractual obligations 436,837 469,218
Regulatory liabilities 1,239,698 1,164,288
Other 248,818 247,526
---------------------- ----------------------
3,372,538 3,271,038
---------------------- ----------------------
Capitalization:
Long-Term Debt 2,510,927 2,481,331
---------------------- ----------------------
Preferred Stock of Subsidiary - Non-Redeemable 116,200 116,200
---------------------- ----------------------
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 150,578,806 shares issued and
128,098,320 shares outstanding in 2004 and 150,398,403
shares issued and 127,695,999 shares outstanding in 2003 752,894 751,992
Capital surplus, paid in 1,110,135 1,108,924
Deferred contribution plan - employee stock
ownership plan (67,274) (73,694)
Retained earnings 841,191 808,932
Accumulated other comprehensive income 45,010 25,991
Treasury stock, 19,573,433 shares in 2004
and 19,518,023 shares in 2003 (359,024) (358,025)
---------------------- ----------------------
Common Shareholders' Equity 2,322,932 2,264,120
---------------------- ----------------------
Total Capitalization 4,950,059 4,861,651
---------------------- ----------------------
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization $ 11,382,225 $ 11,216,487
====================== ======================
* See Note 9.
The accompanying notes are an integral part of these condensed consolidated
financial statements.
3
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------- -----------------------------------
2004 2004
(Restated)* 2003 (Restated)* 2003
--------------- ---------------- --------------- --------------
(Thousands of Dollars, except share information)
Operating Revenues $ 1,524,666 $ 1,330,038 $ 3,362,953 $ 2,914,221
--------------- ---------------- --------------- --------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 912,418 767,002 2,089,729 1,732,605
Other 270,737 230,708 497,262 419,418
Maintenance 67,673 68,280 124,884 114,172
Depreciation 55,561 50,692 110,134 100,165
Amortization 28,087 22,890 57,378 83,303
Amortization of rate reduction bonds 38,294 35,303 81,293 74,503
Taxes other than income taxes 55,695 51,460 133,284 125,434
--------------- ---------------- --------------- --------------
Total operating expenses 1,428,465 1,226,335 3,093,964 2,649,600
--------------- ---------------- --------------- --------------
Operating Income 96,201 103,703 268,989 264,621
Interest Expense:
Interest on long-term debt 33,998 28,546 66,736 61,486
Interest on rate reduction bonds 25,043 27,364 50,738 55,225
Other interest 4,097 3,617 8,444 6,361
--------------- ---------------- --------------- --------------
Interest expense, net 63,138 59,527 125,918 123,072
--------------- ---------------- --------------- --------------
Other Income, Net 2,862 754 4,549 1,330
--------------- ---------------- --------------- --------------
Income Before Income Tax Expense 35,925 44,930 147,620 142,879
Income Tax Expense 10,544 16,672 53,407 53,027
--------------- ---------------- --------------- --------------
Income Before Preferred Dividends of Subsidiary 25,381 28,258 94,213 89,852
Preferred Dividends of Subsidiary 1,389 1,389 2,779 2,779
--------------- ---------------- --------------- --------------
Net Income $ 23,992 $ 26,869 $ 91,434 $ 87,073
=============== ================ =============== ==============
Basic and Fully Diluted Earnings Per Common Share $ 0.19 $ 0.21 $ 0.71 $ 0.69
=============== ================ =============== ==============
Basic Common Shares Outstanding (average) 128,033,513 126,747,117 127,956,640 126,880,397
=============== ================ =============== ==============
Fully Diluted Common Shares Outstanding (average) 128,182,645 126,860,208 128,121,751 126,982,903
=============== ================ =============== ==============
* See Note 9.
The accompanying notes are an integral part of these condensed consolidated
financial statements.
4
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
---------------------------------------------
2004
(Restated)* 2003
------------------- ------------------
(Thousands of Dollars)
Operating Activities:
Income before preferred dividends of subsidiary $ 94,213 $ 89,852
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 110,134 100,165
Deferred income taxes and investment tax credits, net 34,478 (10,383)
Amortization 57,378 83,303
Amortization of rate reduction bonds 81,293 74,503
Amortization/(deferral) of recoverable energy costs 24,193 (9,441)
Increase/(decrease) in prepaid pension 2,456 (15,606)
Regulatory overrecoveries 8,753 49,183
Other sources of cash 18,853 15,256
Other uses of cash (66,519) (70,895)
Changes in current assets and liabilities:
Restricted cash - LMP costs (30,257) -
Receivables and unbilled revenues, net 79,518 173,596
Fuel, materials and supplies 51 (4,208)
Investments in securitizable assets (23,923) 32,376
Other current assets (26,430) (63,608)
Accounts payable 43,098 (123,235)
Accrued taxes (24,450) (109,987)
Other current liabilities 92,446 786
------------------- ------------------
Net cash flows provided by operating activities 475,285 211,657
------------------- ------------------
Investing Activities:
Investments in plant:
Electric, gas and other utility plant (300,248) (226,515)
Competitive energy assets (11,329) (7,534)
------------------- ------------------
Cash flows used for investments in plant (311,577) (234,049)
Buyout/buydown of IPP contracts - (20,437)
Other investment activities 11,450 12,084
------------------- ------------------
Net cash flows used in investing activities (300,127) (242,402)
------------------- ------------------
Financing Activities:
Issuance of common shares 2,786 7,463
Repurchase of common shares - (23,209)
Issuance of long-term debt 82,438 194,851
Retirement of rate reduction bonds (90,616) (82,314)
(Decrease)/increase in short-term debt (99,193) 7,000
Reacquisitions and retirements of long-term debt (23,621) (28,688)
Cash dividends on preferred stock of subsidiaries (2,779) (2,779)
Cash dividends on common shares (38,379) (34,886)
Other financing activities (486) (4,343)
------------------- ------------------
Net cash flows (used in)/provided by financing activities (169,850) 33,095
------------------- ------------------
Net increase in cash and cash equivalents 5,308 2,350
Cash and cash equivalents - beginning of period 43,372 54,678
------------------- ------------------
Cash and cash equivalents - end of period $ 48,680 $ 57,028
=================== ==================
* See Note 9.
The accompanying notes are an integral part of these condensed consolidated
financial statements.
5
NORTHEAST UTILITIES AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)
A. Presentation
Restatement of Previously Issued Financial Statements: Subsequent to
the filing of the Form 10-Q for the quarter ended June 30, 2004,
Northeast Utilities (NU or the company) concluded that it incorrectly
applied accrual accounting for certain natural gas contracts
established to mitigate the risk of electricity purchased in
anticipation of winning certain levels of wholesale electric load in
New England. NU concluded that fair value accounting should have been
applied. To correct this error, the financial and other information
included herein has been restated for this change. Corrections have
been made to cash and cash equivalents, unrestricted cash from
counterparties, accounts payable, derivative assets and derivative
liabilities, which had no impact on net income. For further
information regarding these restatements and the effects on
significant financial statement line items, see Note 9, "Restatement
of Previously Issued Financial Statements."
The accompanying unaudited condensed consolidated financial
statements should be read in conjunction with this complete report on
Form 10-Q/A, the First Quarter 2004 Form 10-Q, and the Annual Reports
of NU, The Connecticut Light and Power Company (CL&P), Public Service
Company of New Hampshire (PSNH), and Western Massachusetts Electric
Company (WMECO), which were filed as part of the NU 2003 Form 10-K,
and the current reports on Form 8-K dated May 19, 2004 and July 14,
2004. The accompanying condensed consolidated financial statements
contain, in the opinion of management, all adjustments necessary to
present fairly NU's and the above companies' financial position at
June 30, 2004, the results of operations for the three-month and
six-month periods ended June 30, 2004 and 2003, and condensed
consolidated statements of cash flows for the six-month periods ended
June 30, 2004 and 2003. All adjustments are of a normal, recurring
nature except those described in Note 1B. Due primarily to the
seasonality of NU's business and to the quarterly earnings profile of
NU Enterprises' merchant energy business segment in 2004, the results
of operations and condensed consolidated statements of cash flows for
the six-month periods ended June 30, 2004 and 2003, are not
indicative of the results expected for a full year.
The condensed 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 condensed consolidated 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 condensed
6
consolidated financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Certain reclassifications of prior period data included in the
accompanying condensed consolidated financial statements have been
made to conform with the current period presentation.
B. New Accounting Standards
Accounting for the Effect of Medicare Changes on Postretirement
Benefits Other Than Pension (PBOP): On December 8, 2003, the
President of the United States signed into law a bill that expands
Medicare, primarily by adding a prescription drug benefit and by
adding a federal subsidy to qualifying plan sponsors of retiree
health care benefit plans. Management believes that NU currently
qualifies for the subsidy for certain retiree groups.
Financial Accounting Standards Board (FASB) Staff Position (FSP) No.
FAS 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003," required NU to make an election whether to either defer the
impact of the subsidy until the FASB issues guidance or to reflect
the impact of the subsidy on December 31, 2003 reported amounts. NU
chose to reflect the impact on December 31, 2003 reported amounts
with no impact on 2003 expenses, assets, or liabilities. The estimate
of the actuarial gain, which decreased the PBOP benefit obligation,
was refined in the first quarter of 2004 to $20 million and is
currently being amortized as a reduction to PBOP expense over 13
years.
The estimated reduction in PBOP expense could change as a result of
the completion of an actuarial estimate of the subsidy based on
recent prescription drug claim experience. The subsidy estimate could
also change as regulations are promulgated by the federal agencies
responsible for administration of the Medicare program.
On May 19, 2004, the FASB issued FSP No. FAS 106-2, "Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003," to provide guidance on
accounting for the effects of the aforementioned Medicare expansion.
This FSP supersedes FSP No. FAS 106-1 and concludes that the effects
of the federal subsidy should be considered an actuarial gain and
treated like similar gains and losses and requires certain
disclosures for employers that sponsor postretirement health care
plans that provide prescription drug benefits which are included in
this report on Form 10-Q. The accounting treatment under FSP No. FAS
106-2 is consistent with FSP No. FAS 106-1 and with NU's accounting
treatment at December 31, 2003.
C. Guarantees
NU provides credit assurance in the form of guarantees and letters of
credit (LOCs) in the normal course of business, primarily for the
financial performance obligations of NU Enterprises. NU would be
required to perform under these guarantees in the event of
non-performance by NU Enterprises, primarily Select Energy, Inc.
(Select Energy). At June 30, 2004, the maximum level of exposure in
accordance with FASB Interpretation No. (FIN) 45, "Guarantor's
7
Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others," under guarantees by
NU, primarily on behalf of NU Enterprises, totaled $897.7 million.
Additionally, NU had $53 million of LOCs issued for the benefit of NU
Enterprises outstanding at June 30, 2004.
CL&P had obtained surety bonds in the amount of $31.1 million related
to the collection of March 2003 and April 2003 incremental locational
marginal pricing (LMP) costs in compliance with a Connecticut
Department of Public Utility Control (DPUC) order. Effective April
30, 2004, the DPUC approved CL&P's request to remove this surety bond
requirement, and the surety bonds were cancelled. At June 30, 2004,
NU had outstanding guarantees on behalf of the Utility Group of $11.2
million. This amount is included in the total outstanding NU
guarantee exposure amount of $897.7 million.
Several underlying contracts that NU guarantees and certain surety
bonds contain credit ratings triggers that would require NU to post
collateral in the event that NU's credit ratings are downgraded to
below investment grade.
On June 30, 2004, the Securities and Exchange Commission (SEC) issued
an order allowing NU to expand its financial support of NU
Enterprises. Under the order, NU has authorization from the SEC to
provide up to $750 million of guarantees for NU Enterprises through
June 30, 2007. The guarantees to the Utility Group are subject to a
separate $50 million SEC limitation apart from the current $750
million guarantee limit. The amount of guarantees outstanding for
compliance with the SEC limit for NU Enterprises at June 30, 2004 is
$329.8 million, which is calculated using different, more
probabilistic and fair-value based criteria than the maximum level of
exposure required to be disclosed under FIN 45. FIN 45 includes all
exposures even though they are not reasonably likely to result in
exposure to NU.
D. Unbilled Revenues
Unbilled revenues represent an estimate of electricity or gas
delivered to customers that has not been billed. Unbilled revenues
represent assets on the condensed consolidated balance sheet that
become accounts receivable in the following month as customers are
billed. Such estimates are subject to adjustment when actual meter
readings become available, when changes in estimating methodology
occur and under other circumstances.
The Utility Group estimates unbilled revenues monthly using the
requirements method. The requirements method utilizes the total
monthly volume of electricity or gas delivered to the system and
applies a delivery efficiency (DE) factor to reduce the total monthly
volume by an estimate of delivery losses in order to calculate total
estimated monthly sales to customers. The total estimated monthly
sales amount less total monthly billed sales amount results in a
monthly estimate of unbilled sales. Unbilled revenues are estimated
by applying an average rate to the estimate of unbilled sales. The
estimated DE factor can have a significant impact on estimated
unbilled revenue amounts.
In accordance with management's policy of testing the estimate of
8
unbilled revenues twice each year using the cycle method of
estimating unbilled revenues, testing was performed in the second
quarter of 2004. The cycle method uses the billed sales from each
meter reading cycle and an estimate of unbilled days in each month
based on the meter reading schedule. The cycle method is more
accurate than the requirements method when used in a mostly
weather-neutral month.
The cycle method testing resulted in adjustments to the estimate of
unbilled revenues that had a net positive after-tax earnings impact
of $1.5 million in the second quarter of 2004. There were positive
after-tax impacts on CL&P, WMECO and Yankee Gas of $1.8 million, $0.9
million, and $0.5 million, respectively, while there was a negative
after-tax impact on PSNH of $1.7 million.
E. Regulatory Accounting
The accounting policies of NU's Utility Group conform to accounting
principles generally accepted in the United States of America
applicable to rate-regulated enterprises and historically reflect the
effects of the rate-making process in accordance with Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation."
The transmission and distribution businesses of CL&P, PSNH and WMECO,
along with PSNH's generation business and Yankee Gas' distribution
business, continue to be cost-of-service rate regulated, and
management believes that the application of SFAS No. 71 to those
business portions of the aforementioned companies continues to be
appropriate. Management also believes that it is probable that NU's
operating companies will recover their investments in long-lived
assets, including regulatory assets. In addition, all material net
regulatory assets are earning an equity return, except for
securitized regulatory assets, which are not supported by equity.
Regulatory Assets: The components of regulatory assets are as
follows:
---------------------------------------------------------------------------------------------------------
At June 30, 2004
---------------------------------------------------------------------------------------------------------
NU
Consolidated
(Millions of Dollars) (1) CL&P PSNH WMECO
---------------------------------------------------------------------------------------------------------
Recoverable nuclear costs $ 62.7 $ 1.2 $ 31.5 $ 30.0
Securitized assets 1,570.5 1,059.9 443.9 66.7
Income taxes, net 264.0 151.4 42.2 59.5
Unrecovered contractual
obligations 359.1 211.6 66.3 81.2
Recoverable energy costs 246.6 36.6 206.6 3.4
Other 351.4 138.4 151.5 9.3
---------------------------------------------------------------------------------------------------------
Totals $2,854.3 $1,599.1 $942.0 $250.1
---------------------------------------------------------------------------------------------------------
9
---------------------------------------------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------------------------------------------
NU
Consolidated
(Millions of Dollars) (1) CL&P PSNH WMECO
---------------------------------------------------------------------------------------------------------
Recoverable nuclear costs $ 82.4 $ 16.4 $ 33.3 $ 32.7
Securitized assets 1,664.0 1,123.7 465.3 75.0
Income taxes, net 253.8 140.9 44.2 60.1
Unrecovered contractual
obligations 378.6 221.8 69.9 86.9
Recoverable energy costs 255.7 30.1 218.3 3.7
Other 339.5 140.1 138.4 9.8
-----------------------------------------------------------------------------------------------------------
Totals $2,974.0 $1,673.0 $969.4 $268.2
-----------------------------------------------------------------------------------------------------------
(1) At June 30, 2004 and December 31, 2003, included in the table
are $63.1 million and $63.4 million, respectively, of other
regulatory assets, primarily associated with Yankee Gas' income
taxes, net and other regulatory assets related to environmental
clean-up costs and hardship receivables.
Additionally, NU had approximately $12.6 million and approximately $12
million of regulatory costs at June 30, 2004 and December 31, 2003,
respectively, that are included in deferred debits and other assets -
other on the accompanying condensed consolidated balance sheets. These
amounts represent regulatory costs that have not yet been approved by the
applicable regulatory agency. Management believes these assets are
recoverable in future rates.
Regulatory Liabilities: The Utility Group maintained $1.2 billion of
regulatory liabilities at both June 30, 2004 and December 31, 2003. These
amounts are comprised of the following:
---------------------------------------------------------------------------------------------------------
At June 30, 2004
---------------------------------------------------------------------------------------------------------
NU
Consolidated
(Millions of Dollars) (1) CL&P PSNH WMECO
---------------------------------------------------------------------------------------------------------
Cost of removal $ 333.2 $147.6 $ 88.8 $24.7
CTA, GSC and SBC
overcollections 327.6 327.6 - -
Cumulative deferral - SCRC 175.8 - 175.8 -
Regulatory liabilities
offsetting Utility
Group derivative assets 160.0 159.6 0.4 -
LMP overcollections 83.8 83.8 - -
Other 159.3 78.6 22.9 6.8
---------------------------------------------------------------------------------------------------------
Totals $1,239.7 $797.2 $287.9 $31.5
---------------------------------------------------------------------------------------------------------
10
---------------------------------------------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------------------------------------------
NU
Consolidated
(Millions of Dollars) (1) CL&P PSNH WMECO
---------------------------------------------------------------------------------------------------------
Cost of removal $ 334.0 $150.0 $ 88.0 $25.0
CTA, GSC and SBC
overcollections 333.7 333.7 - -
Cumulative deferral - SCRC 160.4 - 160.4 -
Regulatory liabilities
offsetting Utility
Group derivative assets 116.9 115.4 1.5 -
LMP overcollections 83.6 83.6 - -
Other 135.7 70.3 22.2 2.8
---------------------------------------------------------------------------------------------------------
Totals $1,164.3 $753.0 $272.1 $27.8
---------------------------------------------------------------------------------------------------------
(1) At June 30, 2004 and December 31, 2003, included in the table
are $123.1 million and $111.4 million, respectively, of other
regulatory liabilities, associated with Yankee Gas' cost of
removal, deferred gas costs, pension and other regulatory
liabilities.
Estimated unbilled revenues for PSNH are not considered in the
reconciliation of certain billed revenues to incurred costs through
such rate mechanisms as the Stranded Cost Recovery Charge (SCRC) and
the System Benefits Charge (SBC). Accordingly, changes in estimated
unbilled revenues due to changes in these charges impact PSNH's
earnings in the period of change.
F. Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC) is a
non-cash item that is included in the cost of Utility Group utility
plant and represents the cost of borrowed and equity funds used to
finance construction. The portion of AFUDC attributable to borrowed
funds is recorded as a reduction in other interest expense, and the
cost of equity funds is recorded as other income on the condensed
consolidated statements of income:
-------------------------------------------------------------------------------------------------
For the Six Months Ended
------------------------------------------------------------------------------------------------
(Millions of Dollars) June 30, 2004 June 30, 2003
------------------------------------------------------------------------------------------------
Borrowed funds $2.2 $2.7
Equity funds 1.9 3.3
------------------------------------------------------------------------------------------------
Totals $4.1 $6.0
------------------------------------------------------------------------------------------------
Average AFUDC rates 3.7% 4.5%
------------------------------------------------------------------------------------------------
G. Equity-Based Compensation
NU maintains an Employee Stock Purchase Plan and other long-term,
equity-based incentive plans under the Northeast Utilities Incentive
Plan. NU accounts for these plans under the recognition and
measurement principles of Accounting Principles Board Opinion (APB)
No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. No equity-based employee compensation cost for stock
options is reflected in net income, as all options granted under
those plans had an exercise price equal to the market value of the
underlying common stock on the date of grant. The following table
11
illustrates the effect on net income and earnings per share (EPS) if
NU had applied the fair value recognition provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation," to equity-based employee
compensation:
------------------------------------------------------------------------------------------------------------
For the Six Months Ended
------------------------------------------------------------------------------------------------------------
June 30,
(Millions of Dollars, 2004 June 30,
except per share amounts) (Restated) 2003
------------------------------------------------------------------------------------------------------------
Net income, as reported $91.4 $87.1
Total equity-based employee
compensation expense
determined under fair
value-based method for all
awards, net of related
tax effects 1.0 1.0
------------------------------------------------------------------------------------------------------------
Pro forma net income $90.4 $86.1
------------------------------------------------------------------------------------------------------------
EPS:
Basic and fully diluted -
as reported $0.71 $0.69
Basic and fully diluted -
pro forma $0.71 $0.68
------------------------------------------------------------------------------------------------------------
Net income as reported includes $1.6 million and $0.8 million
expensed for restricted stock and restricted stock units for the six
months ended June 30, 2004 and 2003, respectively. NU accounts for
restricted stock in accordance with APB No. 25 and amortizes the
intrinsic value of the award over the service period.
NU assumes an income tax rate of 40 percent to estimate the tax
effect on total equity-based employee compensation expense determined
under the fair value-based method for all awards.
During the six-month period ended June 30, 2004, no stock options
were awarded.
On March 31, 2004, the FASB issued an exposure draft that, if
finalized as proposed, would require NU to expense equity-based
employee compensation under the fair value-based method beginning on
January 1, 2005.
H. Sale of Customer Receivables
CL&P has an arrangement with a financial institution under which CL&P
can sell up to $100 million of accounts receivable and unbilled
revenues. At both June 30, 2004 and December 31, 2003, CL&P had sold
accounts receivable of $80 million to the financial institution with
limited recourse through CL&P Receivables Corporation (CRC), a wholly
owned subsidiary of CL&P. At June 30, 2004, the reserve requirements
calculated in accordance with the Receivables Purchase and Sale
Agreement were $19.5 million. This reserve amount is deducted from
the amount of receivables eligible for sale at the time.
Concentrations of credit risk to the purchaser under this agreement
with respect to the receivables are limited due to CL&P's diverse
customer base within its service territory. At June 30, 2004, amounts
sold to CRC by CL&P but not sold to the financial institution
totaling $190.4 million are included in investments in securitizable
assets on
12
the accompanying condensed consolidated balance sheets. This amount
would be excluded from CL&P's assets in the event of CL&P's
bankruptcy. On July 7, 2004, CL&P renewed the arrangement with the
financial institution through July 6, 2005.
The transfer of receivables to the financial institution under this
arrangement qualifies for sale treatment under SFAS No. 140,
"Accounting for Transfers and Servicing of Financial Assets and
Extinguishment of Liabilities -- A Replacement of SFAS No. 125."
I. Other Investments
NU has an investment in the common stock of a developer of fuel cell
and power quality equipment. Based on revised information that
affected the fair value of NU's investment, management determined
that at June 30, 2004, the value of NU's investment declined and that
the decline was other than temporary in nature. An after-tax
investment write-down of $2.4 million ($3.8 million on a pre-tax
basis) was recorded to reduce the carrying value of the investment to
$3.8 million.
Yankee Energy System, Inc. (Yankee) maintains a long-term note
receivable from BMC Energy LLC (BMC), an operator of renewable energy
projects. In late-March 2004, based on revised information that
impacts undiscounted cash flow projections and fair value estimates,
management determined that the fair value of the note receivable from
BMC had declined and that the note was impaired. As a result,
management recorded an after-tax investment write-down of $1.5
million ($2.5 million on a pre-tax basis) in the first quarter of
2004.
On June 30, 2004, Yankee sold virtually all of the assets and
liabilities of R.M. Services, Inc. (RMS), a provider of consumer
collection services, for $3 million. In conjunction with the sale, a
gain totaling $0.6 million was included as a gain from the sale of
RMS. For the three and six months ended June 30, 2004, RMS was
consolidated into NU's condensed consolidated financial statements
and had pre-tax losses totaling $0.7 million and $1.7 million,
respectively. These amounts are recorded in other income - other, net
on the accompanying condensed consolidated statements of income. For
the three and six months ended June 30, 2003, which is before RMS was
consolidated, Yankee recorded pre-tax investment write-downs totaling
$1.1 million and $1.4 million, respectively, related to its
investment in RMS.
These charges are disclosed in Note 1N, "Summary of Significant
Accounting Policies - Other Income," and in the Eliminations and
Other segment in Note 8, "Segment Information," to the condensed
consolidated financial statements.
NU has an investment in the common stock of NEON Communications, Inc.
(NEON), a provider of optical networking services. On July 19, 2004,
NEON and Globix Corporation (Globix) announced a definitive merger
agreement in which Globix, an unaffiliated publicly-owned entity
would acquire NEON for shares of Globix common stock. If the merger
is consummated, then NU would receive 1.2748 shares of Globix common
stock for each of the 1.8 million shares of NEON stock it owns.
13
J. Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and short-term cash
investments that are highly liquid in nature and have original
maturities of three months or less. At the end of each reporting
period, overdraft amounts are reclassified from cash and cash
equivalents to accounts payable.
K. Counterparty Deposits
Balances collected from counterparties resulting from Select Energy's
credit management activities totaled $105 million at June 30, 2004
and $46.5 million at December 31, 2003. These amounts are recorded as
current liabilities and included as counterparty deposits on the
accompanying condensed consolidated balance sheets. To the extent
Select Energy requires collateral from counterparties, cash is
received as a part of the total collateral required. The right to
receive such cash collateral in an unrestricted manner is determined
by the terms of Select Energy's agreements. Key factors affecting the
unrestricted status of a portion of this cash collateral include the
financial standing of Select Energy and of NU as its credit
supporter.
L. Special Deposits
Special deposits represents amounts Select Energy has on deposit with
unaffiliated counterparties and brokerage firms in the amount of $2.6
million and amounts included in escrow for Select Energy Services,
Inc. (SESI) that have not been spent on construction projects of
$25.5 million at June 30, 2004. Similar amounts totaled $17 million
and $32 million at December 31, 2003, respectively. Special deposits
at December 31, 2003 also included $30.1 million in escrow that PSNH
funded to acquire Connecticut Valley Electric Company, Inc. on
January 1, 2004.
M. Restricted Cash - LMP Costs
Restricted cash - LMP costs represents incremental LMP cost amounts
that have been collected by CL&P and deposited into an escrow
account. At June 30, 2004 and December 31, 2003, restricted cash -
LMP costs totaled $123.9 million and $93.6 million, respectively.
14
N. Other Income
The pre-tax components of NU's other income items are as follows:
------------------------------------------------------------------------------------------------------------------
For the Three Months Ended
-----------------------------------------------------------------------------------------------------------------
(Millions of Dollars) June 30, 2004 June 30, 2003
-----------------------------------------------------------------------------------------------------------------
Investment write-downs $(3.8) $(1.1)
Investment income 3.8 4.1
CL&P procurement fee 2.7 -
Charitable donations (0.5) (1.7)
AFUDC - equity funds 0.5 1.8
Gain on sale of RMS 0.6 -
Other, net (0.4) (2.3)
-----------------------------------------------------------------------------------------------------------------
Totals $2.9 $0.8
-----------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------
For the Six Months Ended
-----------------------------------------------------------------------------------------------------------------
(Millions of Dollars) June 30, 2004 June 30, 2003
-----------------------------------------------------------------------------------------------------------------
Investment write-downs $(6.3) $(1.4)
Investment income 7.0 8.0
CL&P procurement fee 5.8 -
Charitable donations (1.5) (4.0)
AFUDC - equity funds 1.9 3.3
Gain on sale of RMS 0.6 -
Other, net (3.0) (4.6)
-----------------------------------------------------------------------------------------------------------------
Totals $ 4.5 $ 1.3
-----------------------------------------------------------------------------------------------------------------
O. Estimate of Workers' Compensation and Injuries and Damages Reserves
During the second quarter of 2004, NU engaged an actuary to assess
the workers' compensation and injuries and damages reserves for
claims incurred but not yet reported or included in specific case
reserves. As a result of this assessment, these reserves were
increased by $9.7 million resulting in an after tax charge of $2.8
million.
2. DERIVATIVE INSTRUMENTS (NU, CL&P, PSNH, Select Energy, Yankee Gas)
Derivatives that are utilized for trading purposes are recorded at
fair value with changes in fair value included in earnings. Other
contracts that are derivatives but do not meet the definition of a
cash flow or fair value hedge and cannot be designated as normal
purchases or normal sales are also recorded at fair value with
changes in fair value included in earnings. For those contracts that
meet the definition of a derivative and meet the cash flow hedge
requirements, the changes in the fair value of the effective portion
of those contracts are generally recognized in accumulated other
comprehensive income until the underlying transactions occur. For
contracts that meet the definition of a derivative but do not meet
the hedging requirements, and for the ineffective portion of
contracts that meet the cash flow hedge requirements, the changes in
fair value of those contracts are recognized currently in earnings.
Derivative contracts designated as fair value hedges and the item
they are hedging are both recorded at fair value on the condensed
consolidated balance sheets. Derivative contracts that are entered
into as a normal purchase or sale and are probable of resulting in
physical delivery, and are documented as such, are recorded under
accrual accounting.
During the second quarter of 2004, a negative $27.2 million, net of
tax, was reclassified as an expense from other comprehensive income
in connection
15
with the consummation of the underlying hedged transactions and
recognized in earnings. An additional $0.2 million, net of tax, was
recognized in earnings for those derivatives that were determined to
be ineffective and for the ineffective portion of cash flow hedges. A
negative $0.1 million, net of tax, was recognized in earnings for the
ineffective portion of fair value hedges. Also during the first
quarter of 2004, new cash flow hedge transactions were entered into
that hedge cash flows through 2006. As a result of these new
transactions and market value changes since January 1, 2004,
accumulated other comprehensive income increased by $19.3 million,
net of tax. Accumulated other comprehensive income at June 30, 2004,
was a positive $44.1 million, net of tax (increase to equity),
relating to hedged transactions, and it is estimated that $42.2
million of this net of tax balance will be reclassified as an
increase to earnings within the next twelve months. Cash flows from
hedge contracts are reported in the same category as cash flows from
the underlying hedged transaction.
The restatements discussed in Note 9, "Restatement of Previously
Issued Financial Statements," resulted in $1.6 million being removed
from accumulated other comprehensive income and being recognized as
an increase in earnings. The restatements also resulted in a $0.5
million reduction in earnings for contracts previously recorded on an
accrual basis now subject to fair value accounting.
The tables below summarize the derivative assets and liabilities at
June 30, 2004 and December 31, 2003. The business activities of NU
Enterprises that result in the recognition of derivative assets
include concentrations of credit risk to energy marketing and trading
counterparties. At June 30, 2004, the maximum amount of loss on
trading, non-trading, and hedging contracts due to credit risk and
assuming complete performance failure and no value for the collateral
maintained is the total of NU Enterprises' derivative assets of $203
million. However, a significant portion of these assets is contracted
with investment grade rated counterparties or collateralized with
cash. The amounts below do not include option premiums paid, which
are recorded as prepayments and amounted to $6.8 million and $9.1
million related to energy trading activities and $16.7 million and
$7.6 million related to marketing activities at June 30, 2004 and
December 31, 2003, respectively. These amounts also do not include
option premiums received, which are recorded as other current
liabilities and amounted to $9.2 million and $12.2 million related to
energy trading activities at June 30, 2004 and December 31, 2003,
respectively, and $1.9 million related to marketing activities at
June 30, 2004.
---------------------------------------------------------------------------------------------------------------
At June 30, 2004
---------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------------------------------------------------
NU Enterprises:
Trading $111.2 $ (82.9) $ 28.3
Non-trading 2.9 (1.0) 1.9
Hedging 88.9 (15.2) 73.7
Utility Group - Gas:
Non-trading - (0.1) (0.1)
Hedging 3.0 - 3.0
Utility Group - Electric:
Non-trading 160.0 (54.5) 105.5
NU Parent:
Hedging - (10.3) (10.3)
---------------------------------------------------------------------------------------------------------------
Total $366.0 $(164.0) $202.0
---------------------------------------------------------------------------------------------------------------
16
---------------------------------------------------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------------------------------------------------
NU Enterprises:
Trading $ 71.8 $ (39.3) $ 32.5
Non-trading 1.6 (0.8) 0.8
Hedging 55.8 (12.7) 43.1
Utility Group - Gas:
Non-trading 0.2 (0.2) -
Hedging 2.8 - 2.8
Utility Group - Electric:
Non-trading 116.9 (56.0) 60.9
NU Parent:
Hedging - (3.6) (3.6)
----------------------------------------------------------------------------------------------------------------
Total $249.1 $(112.6) $136.5
----------------------------------------------------------------------------------------------------------------
NU Enterprises - Trading: To gather market intelligence and utilize
this information in risk management activities for the wholesale
marketing activities, Select Energy conducts limited energy trading
activities in electricity, natural gas, and oil, and therefore,
experiences net open positions. Select Energy manages these open
positions with strict policies that limit its exposure to market risk
and require daily reporting to management of potential financial
exposures.
Derivatives used in trading activities are recorded at fair value and
included in the condensed consolidated balance sheets as derivative
assets or liabilities. Changes in fair value are recognized in
operating revenues in the condensed consolidated statements of income
in the period of change. The net fair value positions of the trading
portfolio at June 30, 2004 and at December 31, 2003 were assets of
$28.3 million and $32.5 million, respectively.
Select Energy's trading portfolio includes New York Mercantile
Exchange (NYMEX) futures and options, the fair value of which is
based on closing exchange prices; over-the-counter forwards and
options, the fair value of which is based on the mid-point of bid and
ask market prices; and bilateral contracts for the purchase or sale
of electricity or natural gas, the fair value of which is determined
using available information from external sources. Select Energy's
trading portfolio also includes transmission congestion contracts
(TCC). The fair value of the TCCs included in the trading portfolio
is based on published market data.
NU Enterprises - Non-Trading: Certain Non-trading derivative
contracts are used for delivery of energy related to Select Energy's
wholesale and retail marketing activities. These contracts are
subject to fair value accounting because these contracts are
derivatives that cannot be designated as normal purchases or sales,
as defined. These contracts cannot be designated as normal purchases
or sales either because they are included in the New York energy
market that settles financially or because management did not elect
the normal purchases and sales designation.
Market information for the TCCs classified as non-trading is not
available, and those contracts cannot be reliably valued. Management
believes the amounts paid for these contracts, which total $8.2
million at June 30, 2004, and $4.3 million at December 31, 2003 are
included in premiums paid, are equal to their fair value.
17
Other non-trading natural gas derivative contracts with June 30, 2004
fair values of $1.8 million are used to mitigate the risk of
electricity price changes on Select Energy's fixed-price electricity
purchase contracts. These derivatives do not meet criteria to be
accounted for as cash flow hedges and are accounted for at fair value
as non-trading contracts. The contracts are natural gas basis and
natural gas futures and swaps contracts with fair values determined
by prices provided by external sources and actively quoted markets.
Select Energy held none of these contracts at December 31, 2003.
NU Enterprises - Hedging: Select Energy utilizes derivative financial
and commodity instruments, including futures and forward contracts,
to reduce market risk associated with fluctuations in the price of
electricity and natural gas purchased to meet firm sales commitments
to certain customers. Select Energy also utilizes derivatives,
including price swap agreements, call and put option contracts, and
futures and forward contracts to manage the market risk associated
with a portion of its anticipated supply and delivery requirements.
These derivatives have been designated as cash flow hedging
instruments and are used to reduce the market risk associated with
fluctuations in the price of electricity, natural gas, or oil. A
derivative that hedges exposure to the variable cash flows of a
forecasted transaction (a cash flow hedge) is initially recorded at
fair value with changes in fair value recorded in accumulated other
comprehensive income. Cash flow hedges impact net income when the
forecasted transaction being hedged occurs, when hedge
ineffectiveness is measured and recorded, when the forecasted
transaction being hedged is no longer probable of occurring, or when
there is accumulated other comprehensive loss and the hedge and the
forecasted transaction being hedged are in a loss position on a
combined basis.
Select Energy maintains natural gas service agreements with certain
customers to supply gas at fixed prices for terms extending through
2006. Select Energy has hedged its gas supply risk under these
agreements through NYMEX futures contracts. Under these contracts,
which also extend through 2006, the purchase price of a specified
quantity of gas is effectively fixed over the term of the gas service
agreements. At June 30, 2004 the NYMEX futures contracts had notional
values of $65.2 million and were recorded at fair value as derivative
assets of $11.9 million.
Select Energy also maintains various physical and financial
instruments to hedge its electric and gas purchases and sales through
2006. These instruments include forwards, futures, options, financial
collars, swaps and financial transmission rights (FTRs). These
hedging contracts, which are valued at the mid-point of bid and ask
market prices, were recorded as derivative assets of $77 million
and derivative liabilities of $14.7 million at June 30, 2004.
In the second quarter of 2004, Select Energy hedged natural gas
inventory with gas futures, accounted for as fair value hedges. The
changes in fair value of the futures, options and swaps were recorded
as derivative liabilities of $0.5 million, and the changes in fair
value of the hedged inventory of $0.9 million were recorded on the
condensed consolidated balance sheets.
Utility Group - Gas - Non-Trading: Yankee Gas' non-trading
derivatives consist of firm sales contracts with options to curtail
delivery. These contracts are subject to fair value accounting
because these contracts are derivatives that cannot be designated as
normal purchases or sales, as defined, because of the optionality in
the contract terms. The net fair
18
value of non-trading derivatives at June 30, 2004 was a liability of
$0.1 million.
Utility Group - Gas - Hedging: Yankee Gas maintains a master swap
agreement with a financial counterparty to purchase gas at fixed
prices. Under this master swap agreement, the purchase price of a
specified quantity of gas for an unaffiliated customer is effectively
fixed over the term of the gas service agreements with that customer
for a period not extending beyond 2005. At June 30, 2004 the commodity
swap agreement had a notional value of $4.3 million and was recorded at
fair value as a derivative asset of $3 million. The firm commitment
contract that is hedged is also recorded as a liability on the
accompanying condensed consolidated balance sheets, and changes in fair
values of the hedge and firm commitment have offsetting impacts in
earnings.
Utility Group - Electric - Non-Trading: CL&P has two independent power
producer (IPP) contracts to purchase power that contain pricing
provisions that are not clearly and closely related to the price of
power and therefore do not qualify for the normal purchases and sales
exception to SFAS No. 133, as amended. The fair values of these IPP
non-trading derivatives at June 30, 2004 include a derivative asset
with a fair value of $152 million and a derivative liability with a
fair value of $54.2 million. An offsetting regulatory liability and an
offsetting regulatory asset were recorded, as these contracts are part
of the stranded costs, and management believes that these costs will
continue to be recovered or refunded in rates.
To mitigate the risk associated with certain supply contracts, CL&P
purchased FTRs and financial swaps. FTRs and financial swaps are
derivatives that do not qualify for the normal purchases and sales
exception. The fair value of the FTR non-trading derivatives, valued at
cost, at June 30, 2004 was an asset of $7.6 million. The fair value of
the financial swap non-trading derivatives, which are valued at the
mid-point of bid and ask market prices, at June 30, 2004 was a
liability of $0.3 million.
To mitigate the risk associated with end user delivery, PSNH purchased
FTRs. The fair value of PSNH's FTR non-trading derivatives, valued at
cost, at June 30, 2004 was an asset of $0.4 million.
An offsetting regulatory asset or liability was recorded for CL&P and
PSNH, as these contracts are part of procuring energy for requirements
needs, and management believes that these costs will continue to be
recovered or refunded in rates.
NU Parent - Hedging: In March of 2003, NU parent entered into a fixed
to floating interest rate swap on its $263 million, 7.25 percent fixed-
rate note that matures on April 1, 2012. As a matched-terms fair value
hedge, the changes in fair value of the swap and the hedged debt
instrument are recorded on the condensed consolidated balance sheets
but are equal and offsetting in the condensed consolidated statements
of income. The cumulative change in the fair value of the hedged debt
of $10.3 million is included as a reduction of long-term debt on the
condensed consolidated balance sheets. The hedge is recorded as a
derivative liability of $10.3 million. The resulting changes in
interest payments made are recorded as adjustments to interest expense.
19
3. GOODWILL AND OTHER INTANGIBLE ASSETS (Yankee Gas, NU Enterprises)
SFAS No. 142, "Goodwill and Other Intangible Assets," requires that
goodwill and intangible assets deemed to have indefinite useful lives be
reviewed for impairment at least annually by applying a fair value-based
test. NU uses October 1st as the annual goodwill impairment testing date.
Goodwill impairment is deemed to exist if the net book value of a
reporting unit exceeds its estimated fair value and if the implied fair
value of goodwill based on the estimated fair value of the reporting unit
is less than the carrying amount. There were no impairments or adjustments
to the goodwill balances during the six-month periods ended June 30, 2004
and 2003.
NU's reporting units that maintain goodwill are generally consistent with
the operating segments underlying the reportable segments identified in
Note 8, "Segment Information," to the condensed consolidated financial
statements. Consistent with the way management reviews the operating
results of its reporting units, NU's reporting units under the NU
Enterprises reportable segment include: 1) the merchant energy reporting
unit and 2) the energy services reporting unit. The merchant energy
reporting unit is comprised of the operations of Select Energy, Northeast
Generation Company (NGC) and the generation operations of Holyoke Water
Power Company (HWP), while the energy services reporting unit is comprised
of the operations of SESI, Northeast Generation Services Company (NGS) and
Woods Network Services, Inc. (Woods Network). As a result, NU's reporting
units that maintain goodwill are as follows: the Yankee Gas reporting
unit, which is classified under the Utility Group - gas reportable
segment; the merchant energy reporting unit, which is classified under the
NU Enterprises - merchant energy reportable segment; and the energy
services reporting unit, which is classified under NU Enterprises -
eliminations and other. The goodwill balances of these reporting units are
included in the table herein.
At June 30, 2004, NU maintained $319.9 million of goodwill that is no
longer being amortized, $12.6 million of identifiable intangible assets
subject to amortization and $8.5 million of intangible assets not subject
to amortization. At December 31, 2003, NU maintained $319.9 million of
goodwill that is no longer being amortized, $14.4 million of identifiable
intangible assets subject to amortization and $8.5 million of intangible
assets not subject to amortization. A summary of NU's goodwill balances at
June 30, 2004 and December 31, 2003, by reportable segment and reporting
unit is as follows:
-----------------------------------------------------------------------------------------------------
(Millions of Dollars) At June 30, 2004 At December 31, 2003
-----------------------------------------------------------------------------------------------------
Utility Group - Gas:
Yankee Gas $287.6 $287.6
NU Enterprises:
Merchant Energy 3.2 3.2
Energy Services 29.1 29.1
-----------------------------------------------------------------------------------------------------
Totals $319.9 $319.9
-----------------------------------------------------------------------------------------------------
The goodwill recorded related to the acquisition of Yankee Gas is not
being recovered from the customers of Yankee Gas.
At June 30, 2004 and December 31, 2003, NU's intangible assets and related
accumulated amortization, all of which related to NU Enterprises,
consisted of the following:
20
------------------------------------------------------------------------------------------------------------------------------
At June 30, 2004
------------------------------------------------------------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
------------------------------------------------------------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $8.5 $9.2
Customer list 6.6 3.2 3.4
------------------------------------------------------------------------------------------------------------------------------
Totals $24.3 $11.7 $12.6
------------------------------------------------------------------------------------------------------------------------------
Intangible assets not subject
to amortization:
Customer relationships $5.2
Tradenames 3.3
-----------------------------------------------------------------------------
Totals $8.5
-----------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------
At December 31, 2003
------------------------------------------------------------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
------------------------------------------------------------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $ 7.2 $10.5
Customer list 6.6 2.7 3.9
------------------------------------------------------------------------------------------------------------------------------
Totals $24.3 $ 9.9 $14.4
------------------------------------------------------------------------------------------------------------------------------
Intangible assets not subject
to amortization:
Customer relationships $ 5.2
Tradenames 3.3
---------------------------------------------------------------------------
Totals $ 8.5
---------------------------------------------------------------------------
NU recorded amortization expense of $1.8 million for both the six months
ended June 30, 2004 and 2003, related to intangible assets. Based on the
current amount of intangible assets subject to amortization, the estimated
annual amortization expense for 2004 and for each of the succeeding 5
years from 2005 through 2009 is $3.6 million in 2004 through 2007 and no
amortization expense in 2008 or 2009. These amounts may vary as
acquisitions and dispositions occur in the future.
4. COMMITMENTS AND CONTINGENCIES
A. Restructuring and Rate Matters (CL&P, PSNH, WMECO)
Connecticut:
Impacts of Standard Market Design: On March 1, 2003, the New England
Independent System Operator (ISO-NE) implemented Standard Market
Design (SMD). As part of SMD, LMP is utilized to assign value and
causation to transmission congestion and line losses. Transmission
congestion costs represent the additional costs incurred due to the
need to run uneconomic generating units in certain areas that have
transmission constraints, which prevent these areas from obtaining
alternative lower-cost generation. Line losses represent losses of
electricity as it is sent over transmission lines.
CL&P was billed $186 million of incremental LMP costs in 2003 by its
standard offer service suppliers, including affiliate Select Energy,
or by ISO-NE and collected $158 million from its customers. CL&P and
its suppliers disputed the responsibility for the $186 million of
incremental LMP costs incurred. A settlement agreement was reached to
21
settle the dispute among all the parties involved and was filed with
the Federal Energy Regulatory Commission (FERC) on March 3, 2004. NU
recorded a pre-tax loss in 2003 of approximately $60 million
(approximately $37 million after-tax) related to this settlement
agreement. The settlement agreement was approved by the FERC on June
28, 2004.
On July 8, 2004, CL&P paid the standard offer service suppliers $83
million as part of the approved settlement agreement, and the
remaining $75 million became available to be refunded to CL&P's
customers. The method in which the $75 million will be refunded to
customers is currently under review by the DPUC with a decision
expected in the third quarter of 2004.
CTA and SBC Reconciliation: The Competitive Transition Assessment
(CTA) allows CL&P to recover stranded costs, such as securitization
costs associated with the rate reduction bonds, amortization of
regulatory assets, and IPP over market costs, while the SBC allows
CL&P to recover certain regulatory and energy public policy costs,
such as public education outreach costs, hardship protection costs,
transition period property taxes, and displaced workers protection
costs. The Generation Service Charge (GSC) allows CL&P to recover the
costs of the procurement of energy for standard offer service.
On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with
the DPUC. For the year ended December 31, 2003, total CTA revenues
and excess GSC revenues as filed exceeded the CTA revenue requirement
by $148.3 million. For the same period, SBC revenues as filed
exceeded the SBC revenue requirement by $25.5 million. These amounts
were recorded as regulatory liabilities on the accompanying condensed
consolidated balance sheets.
A final decision in the 2003 CTA and SBC docket was issued on August
4, 2004. In the final decision, the DPUC ordered a refund to
customers of $88.5 million over a seven-month period beginning with
October 2004 consumption. The DPUC ordered that the SBC rate be
reduced to zero effective January 1, 2005. The DPUC also directed
CL&P to impute revenue of $2.7 million to customers associated with a
previously renegotiated IPP contract. CL&P will likely seek rehearing
on this issue, and management cannot predict the outcome of this
issue at this time.
In the 2001 CTA and SBC reconciliation filing, and subsequently in a
September 10, 2002 petition to reopen related proceedings, CL&P
requested that a deferred intercompany liability associated with
income taxes be excluded from the calculation of CTA revenue
requirements. On September 10, 2003, the DPUC issued a final decision
denying CL&P's request, and on October 24, 2003, CL&P appealed the
DPUC's final decision to the Connecticut Superior Court. The appeal
has been fully briefed and is in the argument phase, and a decision
from the Connecticut Superior Court could be rendered by the end of
2004. If the company's request is ultimately granted through court
proceedings, then there could be additional amounts due to CL&P from
its customers. The 2004 impact of including the deferred intercompany
liability in CTA revenue requirements has been a reduction of
approximately $19.3 million in revenue.
22
New Hampshire:
SCRC Reconciliation Filing: The SCRC allows PSNH to recover its
stranded costs. On an annual basis, PSNH files with the New Hampshire
Public Utilities Commission (NHPUC) a SCRC reconciliation filing for
the preceding calendar year. This filing includes the reconciliation
of stranded cost revenues billed with stranded costs, and transition
energy service (TS) revenues billed with TS costs. The NHPUC reviews
the filing, including a prudence review of PSNH's generation
operations. The cumulative deferral of SCRC revenues in excess of
costs was $175.8 million at June 30, 2004. The 2003 SCRC filing was
made on April 30, 2004. Management does not expect the review of the
2003 SCRC filing to have a material effect on PSNH's net income or
financial position. Hearings are currently scheduled for October
2004.
Massachusetts:
Transition Cost Reconciliation: On March 31, 2004, WMECO filed its
2003 transition cost reconciliation with the Massachusetts Department
of Telecommunications and Energy (DTE). This filing reconciled the
recovery of generation-related stranded costs for calendar year 2003.
The timing of a final decision is uncertain. Management does not
expect the outcome of this docket to have a material adverse impact
on WMECO's net income or financial position.
B. NRG Energy, Inc. Exposures (CL&P, Yankee Gas)
Certain subsidiaries of NU, including CL&P and Yankee Gas, have
entered into transactions with NRG Energy, Inc. (NRG) and certain of
its subsidiaries. On May 14, 2003, NRG and certain of its
subsidiaries filed voluntary bankruptcy petitions. On December 5,
2003, NRG emerged from bankruptcy. NU's NRG-related exposures as a
result of these transactions relate to 1) the recovery of congestion
charges incurred by NRG prior to the implementation of SMD on March
1, 2003, 2) the recovery of CL&P's station service billings from NRG,
and 3) the recovery of Yankee Gas' and CL&P's expenditures that were
incurred related to an NRG subsidiary's generating plant construction
project that is now abandoned. While it is unable to determine the
ultimate outcome of these issues, management does not expect their
resolution will have a material adverse effect on NU's consolidated
financial condition or results of operations.
C. Long-Term Contractual Arrangements (Select Energy)
Select Energy maintains long-term agreements to purchase energy in
the normal course of business as part of its portfolio of resources
to meet its actual or expected sales commitments. The aggregate
amount of these purchase contracts was $4.7 billion at June 30, 2004,
as follows (millions of dollars):
23
---------------------------------------------------------------------
Year
---------------------------------------------------------------------
2004 $2,441.3
2005 1,440.7
2006 299.1
2007 99.5
2008 83.7
Thereafter 295.7
---------------------------------------------------------------------
Total $4,660.0
---------------------------------------------------------------------
Select Energy's purchase contract amounts can exceed the
amount expected to be reported in fuel, purchased and net
interchange power as energy trading purchases are classified
net with the corresponding revenues.
NU's other long-term contractual arrangements have not changed
significantly from the amounts reported at December 31, 2003.
D. Deferred Contractual Obligations (NU, CL&P, PSNH, WMECO)
The purchasers of NU's ownership shares of the Millstone, Seabrook
and Vermont Yankee nuclear power plants assumed the obligation of
decommissioning those plants, but NU still has significant
decommissioning and plant closure cost obligations to the companies
that own the Yankee Atomic (YA), Connecticut Yankee (CY) and Maine
Yankee (MY) nuclear power plants (collectively, the Yankee
Companies). Each plant has been shut down and is undergoing
decommissioning. The Yankee Companies collect decommissioning and
closure costs through wholesale, FERC-approved rates charged under
power purchase agreements to several New England utilities, including
NU's electric utility companies CL&P, PSNH and WMECO. These companies
in turn pass these costs on to their customers through state
regulatory commission-approved retail rates. YA has received FERC
approval to collect all presently estimated decommissioning costs. MY
and various other parties filed a settlement agreement with the FERC.
The MY settlement agreement includes the collection of approximately
$27 million annually for decommissioning and long-term storage of
spent fuel through October 31, 2008. Approval of the MY settlement
agreement by the FERC is anticipated in the fall of 2004.
CY's estimated decommissioning and plant closure costs for the period
2000 through 2023 have increased by approximately $395 million over
the April 2000 estimate of $436 million approved by the FERC in a
2000 rate case settlement. The revised estimate reflects the
termination of the decommissioning contract with Bechtel Power
Corporation (Bechtel) in July 2003, the fact that CY is now
self-performing all work to complete the decommissioning of the
plant, the increases in the projected costs of spent fuel storage,
and increased security and liability and property insurance. NU's
share of CY's increase in decommissioning and plant closure costs is
approximately $194 million. On July 1, 2004, CY filed with the FERC
for recovery of the increased costs. In the filing CY seeks to
increase its annual decommissioning collections from $16.7 million to
$93 million for a six-year period beginning January 1, 2005. FERC
proceedings have not yet been scheduled. In total, NU's estimated
remaining decommissioning and plant closure obligation to CY is
$315.5 million at June 30, 2004.
24
Previously, on June 10, 2004, the DPUC and the OCC filed a petition
with the FERC seeking a declaratory order that CY can recover all
decommissioning costs from its wholesale purchasers, including CL&P,
PSNH and WMECO, but such purchasers may not recover in their retail
rates any costs which FERC might determine to have been imprudently
incurred. CY and the wholesale purchasers have objected and the
matter is pending.
NU cannot at this time predict the timing or outcome of the FERC
proceeding required for the collection of the increased
decommissioning costs. Management believes that these costs have been
prudently incurred and will ultimately be recovered from the
customers of CL&P, PSNH and WMECO. However, there is a risk that some
portion of these increased costs may not be recovered, or will have
to be refunded if recovered, as a result of the FERC proceedings. For
further information regarding these issues, see Part II, Item 1,
"Legal Proceedings," in this report on Form 10-Q.
E. Consolidated Edison, Inc. Merger Litigation
Certain gain and loss contingencies continue to exist with regard to
the 1999 merger agreement between NU and Consolidated Edison, Inc.
(Con Edison) and the related litigation. Interrogatory appeals in the
case are now pending, and no trial date has been set. At this stage
of the litigation, management can predict neither the outcome of this
matter nor its ultimate effect on NU.
5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises)
Total comprehensive income, which includes all comprehensive income/(loss)
items by category, for the six months ended June 30, 2004 and 2003 is as
follows:
------------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2004 (Restated - See Note 9)
------------------------------------------------------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
------------------------------------------------------------------------------------------------------------------------------------
Net income* $ 91.4 $43.5 $17.8 $7.1 $22.8 $ 0.2
------------------------------------------------------------------------------------------------------------------------------------
Comprehensive income/(loss) items:
Qualified cash flow
hedging instruments 19.3 - - - 19.2 0.1
Unrealized (losses)/gains
on securities (0.2) - - - 0.2 (0.4)
------------------------------------------------------------------------------------------------------------------------------------
Net change in comprehensive
income/(loss) items 19.1 - - - 19.4 (0.3)
------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive
income/(loss) $110.5 $43.5 $17.8 $7.1 $42.2 $(0.1)
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2003
------------------------------------------------------------------------------------------------------------------------------------
NU
(Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other
------------------------------------------------------------------------------------------------------------------------------------
Net income* $87.1 $30.0 $21.9 $8.7 $17.1 $9.4
------------------------------------------------------------------------------------------------------------------------------------
Comprehensive (loss)/income items:
Qualified cash flow
hedging instruments (13.9) - - - (9.8) (4.1)
Unrealized gains
on securities 0.7 0.1 - - - 0.6
------------------------------------------------------------------------------------------------------------------------------------
Net change in comprehensive
(loss)/income items (13.2) 0.1 - - (9.8) (3.5)
------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive income $73.9 $30.1 $21.9 $8.7 $ 7.3 $5.9
------------------------------------------------------------------------------------------------------------------------------------
* Net income after preferred dividends of subsidiary.
25
Amounts included in the Other column primarily relate to NU parent and
Northeast Utilities Service Company.
Additionally, NU's total comprehensive income for the three months ended
June 30, 2004 was $26.1 million.
Accumulated other comprehensive income fair value adjustments in NU's
qualified cash flow hedging instruments for the six months ended June 30,
2004 and the twelve months ended December 31, 2003 are as follows:
-------------------------------------------------------------------------------------------------------------
At June 30, At December 31,
(Millions of Dollars, Net of Tax) 2004 2003
-------------------------------------------------------------------------------------------------------------
Balance at beginning of period $24.8 $15.5
-------------------------------------------------------------------------------------------------------------
Hedged transactions recognized
into earnings (27.2) (5.3)
Change in fair value 36.7 5.0
Cash flow transactions entered
into for the period 9.8 9.6
-------------------------------------------------------------------------------------------------------------
Net change associated with the
current period hedging transactions 19.3 9.3
-------------------------------------------------------------------------------------------------------------
Total fair value adjustments included
in accumulated other
comprehensive income $44.1 $24.8
-------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive income items unrelated to NU's qualified
cash flow hedging instruments totaled $0.9 million and $1.2 million in
gains at June 30, 2004 and December 31, 2003, respectively. These amounts
primarily relate to unrealized gains on investments in marketable debt and
equity securities, net of related income taxes.
6. EARNINGS PER SHARE (NU)
EPS is computed based upon the weighted average number of common shares
outstanding during each period. Diluted EPS is computed on the basis of
the weighted average number of common shares outstanding plus the
potential dilutive effect if certain securities are converted into common
stock. At June 30, 2004 and 2003, 626,302 options and 2,862,471 options,
respectively, were excluded from the following table as these options were
antidilutive. The following table sets forth the components of basic and
fully diluted EPS:
----------------------------------------------------------------------------------------------------
Six Months Ended June 30,
(Millions of Dollars, 2004
Except for Share Information) (Restated) 2003
----------------------------------------------------------------------------------------------------
Income before preferred
dividends of subsidiary $94.2 $89.9
Preferred dividends
of subsidiary 2.8 2.8
----------------------------------------------------------------------------------------------------
Net income $91.4 $87.1
----------------------------------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 127,956,640 126,880,397
Dilutive effects of employee
stock options 165,111 102,506
----------------------------------------------------------------------------------------------------
Fully diluted EPS common shares
outstanding (average) 128,121,751 126,982,903
----------------------------------------------------------------------------------------------------
Basic and fully diluted EPS $0.71 $0.69
----------------------------------------------------------------------------------------------------
26
7. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All
Companies)
NU's subsidiaries participate in a uniform noncontributory defined
benefit retirement plan (Pension Plan) covering substantially all
regular NU employees and also provide certain health care benefits,
primarily medical and dental, and life insurance benefits through a
benefit plan to retired employees (PBOP Plan). The components of net
periodic benefit expense/(income) for the Pension Plan and the PBOP
Plan for the six months ended June 30, 2004 and 2003 are estimated as
follows:
-----------------------------------------------------------------------------------------------------------------
For the Six Months Ended June 30,
-----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
-----------------------------------------------------------------------------------------------------------------
Service cost $ 20.3 $ 17.5 $ 3.0 $ 2.7
Interest cost 59.4 58.5 12.7 13.4
Expected return
on plan assets (87.5) (91.3) (6.2) (7.5)
Amortization of
unrecognized net
transition
(asset)/obligation (0.7) (0.7) 5.9 5.9
Amortization of
prior service cost 3.6 3.6 (0.2) (0.2)
Amortization of
actuarial loss/(gain) 7.8 (3.5) - -
Other amortization, net - - 5.7 3.2
-----------------------------------------------------------------------------------------------------------------
Total - net periodic
expense/(income) $ 2.9 $(15.9) $20.9 $17.5
-----------------------------------------------------------------------------------------------------------------
A portion of these expenses/(income) is capitalized related to employees
working on capital projects.
NU does not expect to make any contributions to the Pension Plan in 2004.
NU anticipates contributing approximately $10.4 million quarterly totaling
$41.7 million in 2004 to fund its PBOP Plan.
The actuarial gain resulting from the expansion of the Medicare program
decreased the PBOP accumulated plan benefit obligation by $20 million and
is currently being amortized as a reduction to PBOP expense over 13 years.
For the six months ended June 30, 2004, this reduction in PBOP expense
totaled approximately $1.4 million, including amortization of the
actuarial gain of $0.8 million and a reduction in interest cost based on a
lower PBOP benefit obligation of $0.6 million.
As a result of ongoing litigation with nineteen former employees, in April
2004 NU was ordered by the court to modify its retirement plan to include
special retirement benefits for fifteen of these former employees
retroactive to the dates of their retirement. As NU appealed the ruling,
these amounts are not included in the pension and PBOP information above.
There is no immediate impact of the court order, and if NU is ultimately
required to provide retroactive benefits, then the amount of the benefits
would be recorded as a pension plan amendment, which would be amortized as
a prior service cost and would increase pension expense over a 13-year
amortization period.
27
8. SEGMENT INFORMATION (All Companies)
NU is organized between the Utility Group and NU Enterprises businesses
based on a combination of factors, including the characteristics of
each business' products and services, the sources of operating revenues
and expenses and the regulatory environment in which they operate.
Based on enhanced information that is reviewed by NU's chief operating
decision maker, separate detailed information regarding the Utility
Group's transmission businesses and NU Enterprises' merchant energy
business is now included in the following segment information. Segment
information for all periods has been restated to conform to the current
presentation except for total asset information for the transmission
business segment.
The Utility Group segment, including both the regulated electric
distribution and transmission businesses, as well as the gas
distribution business comprised of Yankee Gas, represents approximately
69 percent and 75 percent of NU's total revenues for the six months
ended June 30, 2004 and 2003, respectively, and includes the operations
of the regulated electric utilities, CL&P, PSNH and WMECO, whose
complete condensed consolidated financial statements are included in
NU's combined report on Form 10-Q. PSNH's distribution segment includes
generation activities. Also included in this combined report on Form
10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's
transmission businesses. Utility Group revenues from the sale of
electricity and natural gas primarily are derived from residential,
commercial and industrial customers and are not dependent on any single
customer.
The NU Enterprises merchant energy business segment includes Select
Energy, NGC, the generation operations of HWP, and their respective
subsidiaries, while the eliminations and other business segment
includes SESI, NGS, Woods Network, and their respective subsidiaries
and intercompany eliminations. The results of NU Enterprises parent are
also included within eliminations and other.
Effective January 1, 2004, Select Energy began serving a portion of
CL&P's transitional standard offer (TSO) load for 2004. Total Select
Energy revenues from CL&P for CL&P's standard offer load, TSO load and
for other transactions with CL&P, represented approximately $314.5
million or 22 percent for the six months ended June 30, 2004 and
approximately $349.1 million or 30 percent for the six months ended
June 30, 2003, of total NU Enterprises' revenues. Total CL&P purchases
from NU Enterprises are eliminated in consolidation.
Additionally, WMECO's purchases from Select Energy for standard offer
and default service and for other transactions with Select Energy
represented approximately $53 million and $68.2 million of total NU
Enterprises' revenues for the six months ended June 30, 2004 and 2003,
respectively. Total WMECO purchases from NU Enterprises are eliminated
in consolidation. Select Energy revenues related to contracts with
NSTAR companies represented $158.4 million or 11 percent of total NU
Enterprises' revenues for the six months ended June 30, 2004. Select
Energy also provides BGS in the New Jersey market. Select Energy
revenues related to these contracts represented $213.7 million or 18
percent of total NU Enterprises' revenues for the six months ended June
30, 2003. No other individual customer represented in excess of 10
percent of NU Enterprises' revenues for the six months ended June 30,
2004 or 2003.
28
Eliminations and other in the NU consolidated following tables includes
the results for Mode 1 Communications, Inc., an investor in NEON, the
results of the non-energy-related subsidiaries of Yankee (Yankee Energy
Services Company, RMS, Yankee Energy Financial Services, and NorConn
Properties, Inc.), the non-energy operations of HWP, the results of
NU's parent and service companies, and write-downs of certain of the
company's investments. Interest expense included in eliminations and
other primarily relates to the debt of NU parent. Inter-segment
eliminations of revenues and expenses are also included in eliminations
and other. Eliminations and other includes NU's investment in RMS.
Virtually all of the assets and liabilities of RMS were sold on June
30, 2004.
NU's segment information for the three months and six months ended June
30, 2004 and 2003 is as follows (some amounts between segment schedules
may not agree due to rounding):
------------------------------------------------------------------------------------------------------------------------------------
For the Six Months Ended June 30, 2004
------------------------------------------------------------------------------------------------------------------------------------
Utility Group
--------------------------------------------------
Distribution
(Millions of ------------------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
------------------------------------------------------------------------------------------------------------------------------------
Operating revenues $2,023.8 $ 243.3 $ 64.5 $1,417.4 $(386.0) $ 3,363.0
Depreciation and
amortization (215.3) (12.9) (10.0) (9.6) (1.0) (248.8)
Other
operating
expenses (1,646.8) (205.2) (30.4) (1,345.9) 383.1 (2,845.2)
------------------------------------------------------------------------------------------------------------------------------------
Operating income/
(loss) 161.7 25.2 24.1 61.9 (3.9) 269.0
Interest
Expense, net (79.2) (8.4) (5.6) (25.9) (6.8) (125.9)
Other income/
(loss), net 7.1 (0.6) (0.2) 2.9 (4.7) 4.5
Income tax
(expense)/
benefit (30.9) (4.1) (5.8) (16.1) 3.5 (53.4)
Preferred
dividends (2.8) - - - - (2.8)
------------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 55.9 $ 12.1 $ 12.5 $ 22.8 $ (11.9) $ 91.4
------------------------------------------------------------------------------------------------------------------------------------
Total assets (1) $8,383.4 $1,058.0 $ - $2,144.5 $(203.7) $11,382.2
------------------------------------------------------------------------------------------------------------------------------------
Total investments
in plant $ 189.3 $ 22.5 $ 81.3 $ 11.3 $ 7.2 $ 311.6
------------------------------------------------------------------------------------------------------------------------------------
29
(1) Information for segmenting total assets between electric distribution and
transmission is not available at June 30, 2004. On a NU consolidated
basis, these distribution and transmission assets are disclosed in the
electric distribution column above.
------------------------------------------------------------------------------------------------------------------------------------
For the Six Months Ended June 30, 2004
------------------------------------------------------------------------------------------------------------------------------------
Utility Group
--------------------------------------------------
Distribution
(Millions of ------------------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
------------------------------------------------------------------------------------------------------------------------------------
Operating revenues $964.1 $72.0 $33.5 $ 621.1 $(166.0) $ 1,524.7
Depreciation and
amortization (105.1) (6.5) (5.2) (4.8) (0.4) (122.0)
Other
operating
expenses (790.2) (65.3) (17.2) (598.3) 164.5 (1,306.5)
------------------------------------------------------------------------------------------------------------------------------------
Operating income/
(loss) 68.8 0.2 11.1 18.0 (1.9) 96.2
Interest
expense, net (39.3) (4.5) (3.3) (12.2) (3.8) (63.1)
Other income/
(loss), net 3.8 (0.1) 0.2 1.6 (2.6) 2.9
Income tax
(expense)/
benefit (10.3) 4.6 (2.7) (3.4) 1.2 (10.6)
Preferred
dividends (1.4) - - - - (1.4)
------------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 21.6 $ 0.2 $ 5.3 $ 4.0 $ (7.1) $ 24.0
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
For the Six Months Ended June 30, 2003
------------------------------------------------------------------------------------------------------------------------------------
Utility Group
--------------------------------------------------
Distribution
(Millions of ------------------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
------------------------------------------------------------------------------------------------------------------------------------
Operating revenues $1,894.0 $223.1 $55.8 $1,168.0 $(426.7) $2,914.2
Depreciation and
amortization (226.0) (11.5) (9.2) (10.2) (1.1) (258.0)
Other
operating
expenses (1,500.6) (181.7) (27.8) (1,107.0) 425.5 (2,391.6)
------------------------------------------------------------------------------------------------------------------------------------
Operating income/
(loss) 167.4 29.9 18.8 50.8 (2.3) 264.6
Interest
expense, net (83.8) (6.6) (2.8) (23.1) (6.8) (123.1)
Other(loss)/
income, net (0.5) (0.9) (0.1) 2.8 0.1 1.4
Income tax
(expense)/
benefit (31.5) (9.4) (4.1) (13.4) 5.4 (53.0)
Preferred
dividends (2.8) - - - - (2.8)
------------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 48.8 $ 13.0 $11.8 $ 17.1 $ (3.6) $ 87.1
------------------------------------------------------------------------------------------------------------------------------------
Total investments
in plant $ 155.5 $ 22.6 $43.8 $ 7.5 $ 4.6 $ 234.0
------------------------------------------------------------------------------------------------------------------------------------
30
------------------------------------------------------------------------------------------------------------------------------------
For the Three Months Ended June 30, 2003
------------------------------------------------------------------------------------------------------------------------------------
Utility Group
--------------------------------------------------
Distribution
(Millions of ------------------------------- NU Eliminations
Dollars) Electric Gas Transmission Enterprises and Other Totals
------------------------------------------------------------------------------------------------------------------------------------
Operating revenues $883.6 $ 72.1 $24.7 $555.1 $(205.5) $1,330.0
Depreciation and
amortization (92.7) (5.7) (4.6) (5.3) (0.6) (108.9)
Other
operating
expenses (722.2) (66.8) (14.7) (519.1) 205.4 (1,117.4)
------------------------------------------------------------------------------------------------------------------------------------
Operating income/
(loss) 68.7 (0.4) 5.4 30.7 (0.7) 103.7
Interest
expense, net (41.4) (3.4) (1.5) (12.0) (1.2) (59.5)
Other(loss)/
income, net (0.1) (0.6) - 2.5 (1.0) 0.8
Income tax
(expense)/
benefit (11.2) 1.5 (0.1) (9.3) 2.4 (16.7)
Preferred
dividends (1.4) - - - - (1.4)
------------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 14.6 $ (2.9) $ 3.8 $ 11.9 $ (0.5) $ 26.9
------------------------------------------------------------------------------------------------------------------------------------
Utility Group segment information related to the regulated electric
distribution and transmission businesses for CL&P, PSNH and WMECO for
the three months and six months ended June 30, 2004 and 2003 is as
follows:
-------------------------------------------------------------------------------------------------------
CL&P - For the Six Months Ended June 30, 2004
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $1,384.0 $43.8 $1,427.8
Depreciation and
amortization (113.8) (7.4) (121.2)
Other
operating
expenses (1,173.0) (20.1) (1,193.1)
-------------------------------------------------------------------------------------------------------
Operating income 97.2 16.3 113.5
Interest
expense, net (50.7) (4.2) (54.9)
Other income, net 10.1 - 10.1
Income tax
expense (18.7) (3.7) (22.4)
Preferred
dividends (2.8) - (2.8)
-------------------------------------------------------------------------------------------------------
Net income $ 35.1 $ 8.4 $ 43.5
-------------------------------------------------------------------------------------------------------
Total investments
in plant $ 122.2 $66.2 $ 188.4
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
CL&P - For the Three Months Ended June 30, 2004
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $ 656.3 $22.8 $ 679.1
Depreciation and
amortization (59.9) (3.7) (63.6)
Other
operating
expenses (554.9) (11.4) (566.3)
-------------------------------------------------------------------------------------------------------
Operating income 41.5 7.7 49.2
Interest
expense, net (25.2) (2.6) (27.8)
Other income, net 4.9 0.1 5.0
Income tax
expense (6.0) (1.7) (7.7)
Preferred
dividends (1.4) - (1.4)
-------------------------------------------------------------------------------------------------------
Net income $ 13.8 $ 3.5 $ 17.3
-------------------------------------------------------------------------------------------------------
31
-------------------------------------------------------------------------------------------------------
CL&P - For the Six Months Ended June 30, 2003
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $1,285.6 $35.6 $1,321.2
Depreciation and
amortization (149.1) (6.9) (156.0)
Other
operating
expenses (1,042.8) (18.6) (1,061.4)
-------------------------------------------------------------------------------------------------------
Operating income 93.7 10.1 103.8
Interest
expense, net (54.6) (2.1) (56.7)
Other income/
(loss), net 2.2 (0.2) 2.0
Income tax
expense (15.5) (0.8) (16.3)
Preferred
dividends (2.8) - (2.8)
-------------------------------------------------------------------------------------------------------
Net income $ 23.0 $ 7.0 $ 30.0
-------------------------------------------------------------------------------------------------------
Total investments
in plant $ 103.3 $33.9 $ 137.2
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
CL&P - For the Three Months Ended June 30, 2003
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $599.5 $15.8 $615.3
Depreciation and
amortization (70.4) (3.4) (73.8)
Other
operating
expenses (495.3) (9.5) (504.8)
-------------------------------------------------------------------------------------------------------
Operating income 33.8 2.9 36.7
Interest
expense, net (26.9) (1.1) (28.0)
Other income, net 1.2 - 1.2
Income tax
(expense)/benefit (4.8) 1.0 (3.8)
Preferred
dividends (1.4) - (1.4)
-------------------------------------------------------------------------------------------------------
Net income $ 1.9 $ 2.8 $ 4.7
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
PSNH - For the Six Months Ended June 30, 2004
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $457.6 $13.0 $470.6
Depreciation and
amortization (81.5) (1.7) (83.2)
Other
operating
expenses (328.7) (7.0) (335.7)
-------------------------------------------------------------------------------------------------------
Operating income 47.4 4.3 51.7
Interest
expense, net (21.5) (0.8) (22.3)
Other loss, net (2.2) - (2.2)
Income tax
expense (8.1) (1.3) (9.4)
-------------------------------------------------------------------------------------------------------
Net income $ 15.6 $ 2.2 $ 17.8
-------------------------------------------------------------------------------------------------------
Total investments
in plant $ 51.9 $13.7 $ 65.6
-------------------------------------------------------------------------------------------------------
32
-------------------------------------------------------------------------------------------------------
PSNH - For the Three Months Ended June 30, 2004
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $219.9 $ 6.5 $226.4
Depreciation and
amortization (35.6) (0.9) (36.5)
Other
operating
expenses (165.8) (3.9) (169.7)
-------------------------------------------------------------------------------------------------------
Operating income 18.5 1.7 20.2
Interest
expense, net (10.6) (0.4) (11.0)
Other loss, net (0.5) - (0.5)
Income tax
expense (2.2) (0.5) (2.7)
-------------------------------------------------------------------------------------------------------
Net income $ 5.2 $ 0.8 $ 6.0
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
PSNH - For the Six Months Ended June 30, 2003
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
------------------------------------------------------------------------------------------------------
Operating revenues $421.4 $12.7 $434.1
Depreciation and
amortization (42.8) (1.4) (44.2)
Other
operating
expenses (322.6) (6.2) (328.8)
-------------------------------------------------------------------------------------------------------
Operating income 56.0 5.1 61.1
Interest
expense, net (22.6) (0.5) (23.1)
Other (loss)/
income, net (2.5) 0.1 (2.4)
Income tax
expense (11.9) (1.8) (13.7)
-------------------------------------------------------------------------------------------------------
Net income $ 19.0 $ 2.9 $ 21.9
------------------------------------------------------------------------------------------------------
Total investments
in plant $ 40.7 $ 9.2 $ 49.9
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
PSNH - For the Three Months Ended June 30, 2003
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $197.9 $ 5.5 $203.4
Depreciation and
amortization (6.1) (0.7) (6.8)
Other
operating
expenses (163.3) (3.6) (166.9)
-------------------------------------------------------------------------------------------------------
Operating income 28.5 1.2 29.7
Interest
expense, net (11.2) (0.3) (11.5)
Other loss, net (1.2) - (1.2)
Income tax
expense (5.4) (0.5) (5.9)
-------------------------------------------------------------------------------------------------------
Net income $ 10.7 $0.4 $ 11.1
-------------------------------------------------------------------------------------------------------
33
-------------------------------------------------------------------------------------------------------
WMECO - For the Six Months Ended June 30, 2004
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $182.3 $ 7.7 $190.0
Depreciation and
amortization (20.1) (0.9) (21.0)
Other
operating
expenses (145.1) (3.3) (148.4)
-------------------------------------------------------------------------------------------------------
Operating income 17.1 3.5 20.6
Interest
expense, net (7.0) (0.6) (7.6)
Other loss, net (0.9) - (0.9)
Income tax
expense (4.0) (1.0) (5.0)
-------------------------------------------------------------------------------------------------------
Net income $ 5.2 $ 1.9 $ 7.1
-------------------------------------------------------------------------------------------------------
Total investments
in plant $ 15.2 $ 1.4 $ 16.6
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
WMECO - For the Three Months Ended June 30, 2004
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $ 88.0 $ 4.1 $ 92.1
Depreciation and
amortization (9.6) (0.5) (10.1)
Other
operating
expenses (69.6) (1.8) (71.4)
-------------------------------------------------------------------------------------------------------
Operating income 8.8 1.8 10.6
Interest
expense, net (3.5) (0.3) (3.8)
Other loss, net (0.6) - (0.6)
Income tax
expense (2.1) (0.5) (2.6)
-------------------------------------------------------------------------------------------------------
Net income $ 2.6 $ 1.0 $ 3.6
-------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------
WMECO - For the Six Months Ended June 30, 2003
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $186.9 $ 7.5 $194.4
Depreciation and
amortization (34.1) (0.9) (35.0)
Other
operating
expenses (135.1) (3.0) (138.1)
-------------------------------------------------------------------------------------------------------
Operating income 17.7 3.6 21.3
Interest
expense, net (6.6) (0.2) (6.8)
Other loss, net (0.2) - (0.2)
Income tax
expense (4.1) (1.5) (5.6)
-------------------------------------------------------------------------------------------------------
Net income $ 6.8 $ 1.9 $ 8.7
-------------------------------------------------------------------------------------------------------
Total investments
in plant $ 11.5 $ 0.7 $ 12.2
-------------------------------------------------------------------------------------------------------
34
-------------------------------------------------------------------------------------------------------
WMECO - For the Three Months Ended June 30, 2003
-------------------------------------------------------------------------------------------------------
(Millions of
Dollars) Distribution Transmission Totals
-------------------------------------------------------------------------------------------------------
Operating revenues $ 86.4 $ 3.3 $ 89.7
Depreciation and
amortization (16.2) (0.5) (16.7)
Other
operating
expenses (63.7) (1.5) (65.2)
-------------------------------------------------------------------------------------------------------
Operating income 6.5 1.3 7.8
Interest
expense, net (3.3) (0.1) (3.4)
Other loss, net (0.2) - (0.2)
Income tax
expense (1.0) (0.6) (1.6)
-------------------------------------------------------------------------------------------------------
Net income $ 2.0 $ 0.6 $ 2.6
-------------------------------------------------------------------------------------------------------
NU Enterprises' segment information for the three months and six months
ended June 30, 2004 and 2003 is as follows. Information regarding the
energy services business segment is included in the eliminations and
other column:
---------------------------------------------------------------------------------------------------------------------------
NU Enterprises - For the Six Months Ended June 30, 2004
---------------------------------------------------------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
---------------------------------------------------------------------------------------------------------------------------
Operating revenues $1,285.0 $132.4 $1,417.4
Depreciation and
amortization (8.6) (1.0) (9.6)
Other
operating
expenses (1,212.7) (133.2) (1,345.9)
---------------------------------------------------------------------------------------------------------------------------
Operating income 63.7 (1.8) 61.9
Interest
expense, net (21.6) (4.3) (25.9)
Other (loss)/
income, net (0.1) 3.0 2.9
Income tax
(expense)/
benefit (17.3) 1.2 (16.1)
---------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 24.7 $ (1.9) $ 22.8
---------------------------------------------------------------------------------------------------------------------------
Total assets $1,833.0 $311.5 $2,144.5
---------------------------------------------------------------------------------------------------------------------------
Total investments
in plant $ 9.9 $ 1.4 $ 11.3
---------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------------
NU Enterprises - For the Three Months Ended June 30, 2004
---------------------------------------------------------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
---------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 550.5 $ 70.6 $ 621.1
Depreciation and
amortization (4.3) (0.5) (4.8)
Other
operating
expenses (525.8) (72.5) (518.3)
---------------------------------------------------------------------------------------------------------------------------
Operating income 20.4 (2.4) 18.0
Interest
expense, net (10.4) (1.8) (12.2)
Other income, net - 1.6 1.6
Income tax
(expense)/
benefit (4.4) 1.0 (3.4)
---------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 5.6 $ (1.6) $ 4.0
---------------------------------------------------------------------------------------------------------------------------
35
---------------------------------------------------------------------------------------------------------------------------
NU Enterprises - For the Six Months Ended June 30, 2003
---------------------------------------------------------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
---------------------------------------------------------------------------------------------------------------------------
Operating revenues $1,055.1 $112.9 $1,168.0
Depreciation and
amortization (8.8) (1.4) (10.2)
Other
operating
expenses (997.4) (109.6) (1,107.0)
---------------------------------------------------------------------------------------------------------------------------
Operating income 48.9 1.9 50.8
Interest
expense, net (19.9) (3.2) (23.1)
Other (loss)/
income, net (2.2) 5.0 2.8
Income tax
expense (11.3) (2.1) (13.4)
---------------------------------------------------------------------------------------------------------------------------
Net income $ 15.5 $ 1.6 $ 17.1
---------------------------------------------------------------------------------------------------------------------------
Total investments
in plant $ 6.8 $ 0.7 $ 7.5
---------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------------
NU Enterprises - For the Three Months Ended June 30, 2003
---------------------------------------------------------------------------------------------------------------------------
(Millions of Eliminations
Dollars) Merchant Energy and Other Totals
---------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 492.1 $ 63.0 $ 555.1
Depreciation and
amortization (4.4) (0.9) (5.3)
Other
operating
expenses (458.6) (60.5) (519.1)
---------------------------------------------------------------------------------------------------------------------------
Operating income 29.1 1.6 30.7
Interest
expense, net (10.1) (1.9) (12.0)
Other (loss)/
income, net (1.0) 3.5 2.5
Income tax
expense (7.4) (1.9) (9.3)
---------------------------------------------------------------------------------------------------------------------------
Net income $ 10.6 $ 1.3 $ 11.9
---------------------------------------------------------------------------------------------------------------------------
9. RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS (NU, Select
Energy)
Subsequent to the filing of the Form 10-Q for the quarter ended June
30, 2004, NU concluded that it incorrectly applied accrual accounting
for certain natural gas contracts established by the merchant energy
segment to mitigate the risk of electricity purchased in anticipation
of winning certain levels of wholesale electric load in New England. NU
concluded that fair value accounting for the aforementioned natural gas
derivative contracts should have been applied. To correct this error,
NU restated its condensed consolidated balance sheet as of June 30,
2004, the condensed consolidated statements of income for the three and
six months ended June 30, 2004, and the condensed consolidated
statement of cash flows and the condensed consolidated statement of
comprehensive income for the six months ended June 30, 2004. NU has
also restated the notes to its condensed consolidated financial
statements as necessary to reflect the adjustments. Corrections have
been made to cash and cash equivalents, unrestricted cash from
counterparties, and accounts payable, which had no impact on net
income. These corrections reclassified unrestricted cash from
counterparties to cash and cash equivalents because those funds are
unrestricted and were used to or were available to fund the company's
operations. The December 31, 2003 condensed consolidated balance sheet
has been restated for these corrections and a correction to decrease
derivative assets and liabilities by the same amount in order to
eliminate certain intercompany derivative assets and liabilities.
36
The effects of the revisions on the condensed consolidated balance
sheets as of June 30, 2004 and December 31, 2003, the condensed
consolidated statements of income for the three and six months ended
June 30, 2004, and the condensed consolidated statement of cash flows
and condensed consolidated statement of comprehensive income for the
six months ended June 30, 2004 are summarized in the following tables
(in thousands, except share information):
-------------------------------------------------------------------------------------------------------------
Condensed Consolidated Balance Sheets At June 30, 2004
-------------------------------------------------------------------------------------------------------------
Previously
Reported As Restated
-------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ 75,265 $ 48,680
Unrestricted cash from counterparties 104,976 -
Derivative assets 365,991 365,988
Accounts payable 903,122 771,561
Derivative liabilities 163,050 163,990
Accumulated deferred income taxes 1,346,602 1,346,185
Retained earnings 840,082 841,191
Accumulated other comprehensive income 46,645 45,010
-------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------
At December 31, 2003
-------------------------------------------------------------------------------------------------------------
Previously
Reported As Restated
-------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ 37,196 $ 43,372
Unrestricted cash from counterparties 46,496 -
Derivative assets 301,194 249,117
Accounts payable 768,783 728,463
Derivative liabilities 164,689 112,612
-------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------
Condensed Consolidated Three Months Ended Six Months Ended
Statements of Income June 30, 2004 June 30, 2004
-------------------------------------------------------------------------------------------------------------
Previously As Previously As
Reported Restated Reported Restated
-------------------------------------------------------------------------------------------------------------
Fuel, purchased and net
interchange power $914,200 $912,418 $2,091,511 $2,089,729
Income before income
tax expense 34,143 35,925 145,838 147,620
Income tax expense 9,871 10,544 52,734 53,407
Income before
preferred dividends
of subsidiaries 24,272 25,381 93,104 94,213
Net income $ 22,883 $ 23,992 $ 90,325 $ 91,434
-------------------------------------------------------------------------------------------------------------
Basic and fully
diluted earnings
per common share $0.18 $0.19 $0.71 $0.71
-------------------------------------------------------------------------------------------------------------
37
--------------------------------------------------------------------------------------------------
Condensed Consolidated Six Months Ended
Statement of Cash Flows June 30, 2004
--------------------------------------------------------------------------------------------------
Previously
Reported As Restated
--------------------------------------------------------------------------------------------------
Income before preferred
dividends of subsidiary $ 93,104 $ 94,213
Adjustments to reconcile net cash
flows provided by operating activities:
Other sources of cash 19,270 18,853
Other current assets (26,433) (26,430)
Accounts payable 134,339 43,098
Other current liabilities 34,661 92,446
Other operating activities 253,105 253,105
--------------------------------------------------------------------------------------------------
Net cash flows provided by
operating activities 508,046 475,285
--------------------------------------------------------------------------------------------------
Net increase in cash and cash equivalents 38,069 5,308
Cash and cash equivalents -
beginning of period 37,196 43,372
--------------------------------------------------------------------------------------------------
Cash and cash equivalents -
end of period $ 75,265 $ 48,680
--------------------------------------------------------------------------------------------------
Additionally, NU's total comprehensive income for the three and six
months ended June 30, 2004, which was $26.6 million and $111 million,
respectively, has been restated and now totals $26.1 million and $110.5
million, respectively.
--------------------------------------------------------------------------------------------------
Condensed Consolidated Six Months Ended
Statement of Comprehensive Income June 30, 2004
--------------------------------------------------------------------------------------------------
Previously
Reported As Restated
--------------------------------------------------------------------------------------------------
Net income $ 90.3 $ 91.4
-------------------------------------------------------------------------------------------------
Comprehensive income/(loss) items:
Qualified cash flow hedging instruments 20.9 19.3
Unrealized losses on securities (0.2) (0.2)
-------------------------------------------------------------------------------------------------
Net change in comprehensive
income/(loss) items 20.7 19.1
-------------------------------------------------------------------------------------------------
Total comprehensive income $111.0 $ 110.5
-------------------------------------------------------------------------------------------------
38
NORTHEAST UTILITIES AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
FORM 10-Q/A EXPLANATORY NOTE
Subsequent to the filing of the Form 10-Q for the quarter ended June 30, 2004,
NU concluded that it incorrectly applied accrual accounting for certain natural
gas contracts established by the merchant energy segment to mitigate the risk of
electricity purchased in anticipation of winning certain levels of wholesale
electric load in New England. NU concluded that fair value, or mark-to-market,
accounting should have been applied. To correct this error, NU restated its
condensed consolidated balance sheet as of June 30, 2004, the condensed
consolidated statements of income for the three and six months ended June 30,
2004, and the condensed consolidated statement of cash flows for the six months
ended June 30, 2004. NU has also restated the notes to its condensed
consolidated financial statements as necessary to reflect the adjustments.
Corrections have been made to cash and cash equivalents, unrestricted cash from
counterparties, and accounts payable, which had no impact on net income. These
corrections reclassified unrestricted cash from counterparties to cash and cash
equivalents because those funds are unrestricted and were used to or were
available to fund the company's operations. The December 31, 2003 condensed
consolidated balance sheet has been restated for these corrections and a
correction to decrease derivative assets and liabilities by the same amount in
order to eliminate certain intercompany derivative assets and liabilities. For
information regarding these restatements and the effects on significant
financial statement line items, see Note 9, "Restatement of Previously Issued
Financial Statements," to the condensed consolidated financial statements. This
Management's Discussion and Analysis of Financial Condition and Results of
Operations gives effect to this restatement.
This amendment does not otherwise reflect events occurring after the filing of
the Original Form 10-Q, which was filed on August 6, 2004. Such events include,
among others, the events described in NU's quarterly report on Form 10-Q for the
quarter ended September 30, 2004, and the events described in NU's current
reports on Form 8-K filed after the filing of the Original Form 10-Q, except for
those reports pertaining to this subject matter. For information regarding NU's
most recent earnings guidance, see the current reports on Form 8-K dated January
26, 2005 and February 4, 2005.
This discussion should be read in conjunction with the condensed consolidated
financial statements and footnotes in this Form 10-Q/A, the First Quarter 2004
Form 10-Q, the NU 2003 Form 10-K, and the current reports on Form 8-K dated May
19, 2004 and July 14, 2004. All per share amounts are reported on a fully
diluted basis.
FINANCIAL CONDITION AND BUSINESS ANALYSIS
Executive Summary
-----------------
The following items in this executive summary are explained in more detail in
this report on Form 10-Q:
39
Results and Outlook:
o Earnings at Northeast Utilities (NU or the company) decreased by $2.9
million in the second quarter of 2004 compared with the same period of
2003, and increased by $4.3 million for the first six months of 2004
compared with the first six months of 2003.
o Results for the second quarter and first half of 2004 include the
write-down of half of NU's $7.5 million investment in a developer of
fuel cell and power quality equipment. That write-down reduced earnings
by $0.02 per share.
o Regulated retail electric sales increased 4.6 percent in the first half
of 2004, compared with the first half of 2003, on a weather adjusted
basis. Second quarter retail electric sales increased 5.7 percent in
2004 compared with the same period of 2003, on a weather adjusted
basis.
o NU is in the process of performing a comprehensive review of all of its
business lines and developing five-year business plans. NU is also
conducting an assessment of its corporate and shared services functions
to ensure these functions are effectively aligned with NU's strategic
plan.
Regulatory Items:
o On June 14, 2004, the transmission segment of NU's regulated companies
reached a settlement agreement with parties to its rate case in the
transmission rate case that allows transmission to implement
formula-based rates as proposed with an 11.0 percent return on equity
(ROE) until the Federal Energy Regulatory Commission (FERC) establishes
an ROE for the regional transmission organization (RTO). The FERC is
expected to issue a decision on the settlement agreement in the second
half of 2004.
o A settlement agreement reached to settle the dispute over standard
market design (SMD) locational marginal pricing (LMP) costs, which was
filed with the FERC on March 3, 2004, was approved on June 28, 2004.
The settlement agreement had no impact on 2004 earnings.
o The Connecticut Department of Public Utility Control (DPUC) issued a
final decision on August 4, 2004, on reconsideration of items in the
December 2003 Connecticut Light and Power Company (CL&P) distribution
rate case decision. The final decision was generally favorable, and
reconsideration was granted on all issues raised by CL&P.
o On July 2, 2004, Yankee Gas Services Company (Yankee Gas) filed a rate
case with the DPUC to increase retail rates by $26.5 million, or 7.2
percent, effective January 1, 2005.
o On August 4, 2004, the DPUC issued a final decision accepting the
settlement filed in April 2004 by Yankee Gas, which provided for the
termination of Yankee Gas' Infrastructure Expansion Rate Mechanism
(IERM).
o A settlement agreement was filed for approval in July 2004 with the New
Hampshire Public Utilities Commission (NHPUC) to raise Public Service
Company of New Hampshire (PSNH) retail distribution rates by $3.5
million on October 1, 2004 and $10 million on June 1, 2005.
40
o On July 19, 2004, the Massachusetts Department of Telecommunications
and Energy (DTE) issued an order approving Western Massachusetts
Electric Company's (WMECO) financing of its prior spent nuclear fuel
liability through the issuance of up to $52 million in debt. WMECO
plans to issue this debt by the end of 2004.
o In June 2004, the FERC approved a 40-year license extension for
Northeast Generation Company's (NGC) Housatonic hydroelectric
generation units in Connecticut. That license covers 115 megawatts (MW)
of capacity.
Liquidity:
o At June 30, 2004, NU had $48.7 million of cash and cash equivalents
compared with $43.4 million at December 31, 2003.
o On May 11, 2004, NU announced an 8.3 percent increase in its quarterly
dividend. On September 30, 2004, NU will pay a dividend of $0.1625 per
share to shareholders of record as of September 1, 2004.
o NU's capital expenditures have been lower than projected at the
beginning of 2004. NU's capital expenditures totaled $311.6 million for
the first six months of 2004, compared with $234 million for the first
six months of 2003. NU's 2004 capital spending was originally budgeted
to total $738 million, but is now projected to total $674.2 million due
to delays in certain transmission projects.
Overview
--------
Consolidated: NU earned $24 million, or $0.19 per share, in the second quarter
of 2004, compared with earnings of $26.9 million, or $0.21 per share in the
second quarter of 2003. For the first six months of 2004, NU earned $91.4
million or $0.71 per share, compared with earnings of $87.1 million, or $0.69
per share, in the first six months of 2003. The results for the second quarter
of 2004 and first six months of 2004 include an after-tax write-down of $2.4
million, or $0.02 per share, of NU's investment in a developer of fuel cell and
power quality equipment. NU's remaining investment in that company is $3.8
million. The results for the second quarter also include the positive after-tax
impact of $1.1 million related to the mark-to-market accounting for certain
natural gas contracts.
A summary of NU's earnings/(losses) by business segment for the second quarter
and first six months of 2004 and 2003 is as follows:
--------------------------------------------------------------------------------------------------------------------
For the Three Months For the Six Months
Ended June 30, Ended June 30,
--------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
--------------------------------------------------------------------------------------------------------------------
Utility Group $27.1 $15.5 $80.5 $73.6
NU Enterprises 4.0 11.9 22.8 17.1
Other (7.1) (0.5) (11.9) (3.6)
--------------------------------------------------------------------------------------------------------------------
Net income $24.0 $26.9 $91.4 $87.1
--------------------------------------------------------------------------------------------------------------------
NU's revenues during the first six months of 2004 increased to $3.4 billion from
$2.9 billion in the same period of 2003. The increase in revenues was primarily
due to an increase of approximately $230 million in revenues at NU Enterprises'
41
merchant energy business segment as a result of $192 million in higher revenues
from higher electric and gas prices and an increase in volumes that accounted
for the remainder of that increase. NU's revenue increase is also the result of
a $183 million increase in Utility Group revenues due to an increase in retail
electric sales volume that accounted for $133 million of that increase and an
increase in retail electric prices that accounted for the remainder of that
increase.
Utility Group: The Utility Group is comprised of CL&P, PSNH, WMECO, and Yankee
Gas. Earnings at the Utility Group increased by $11.6 million in the second
quarter of 2004 compared with the same period of 2003, and increased by $6.9
million for the first six months of 2004 compared with the first six months of
2003. The increase in earnings for the first six months of the year was
primarily due to an increase in retail electric sales of 3.7 percent. A summary
of Utility Group earnings/(losses) by company for the second quarter and first
six months of 2004 and 2003 is as follows:
---------------------------------------------------------------------------------------------------------------------
For the Three Months For the Six Months
Ended June 30, Ended June 30,
---------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
---------------------------------------------------------------------------------------------------------------------
CL&P * $17.3 $ 4.7 $43.5 $30.0
PSNH 6.0 11.1 17.8 21.9
WMECO 3.6 2.6 7.1 8.7
Yankee Gas 0.2 (2.9) 12.1 13.0
---------------------------------------------------------------------------------------------------------------------
Net income $27.1 $15.5 $80.5 $73.6
---------------------------------------------------------------------------------------------------------------------
*After preferred dividends
CL&P's higher earnings resulted from distribution and transmission rate
increases that took effect January 1, 2004. These higher retail rates offset
higher depreciation expense and higher pension expense. Additionally, CL&P also
benefited from a 3.3 percent increase in retail electric sales.
PSNH's lower earnings were due primarily to higher pension expense and lower
unbilled revenues.
The lower year-to-date earnings at WMECO were due to lower pension income and
higher interest expense.
Yankee Gas' second quarter results benefited from a change in rate design
implemented in August 2003 and lower income tax expense. Yankee Gas' current
rate design is intended to recover more costs based on stable, fixed monthly
charges rather than based on variable, usage-based charges as was the rate
design in place earlier in 2003. That shift from more variable to more fixed
charges will reduce quarterly earnings in the higher-use first and fourth
quarters and improve quarterly results in the lower-use second and third
quarters compared to Yankee Gas' previous rate design. Yankee Gas' results for
the first six months of 2004 compared to 2003 continue to reflect the impact of
the change in rate design. The reduction in income tax expense was a result of
revisions to estimates of deferred taxes associated with Yankee Gas' plant
assets.
Included in Utility Group earnings are earnings related to the regulated
transmission business. Transmission business earnings were $5.3 million in the
second quarter of 2004 and $12.5 million for the first six months of the year
compared with earnings of $3.8 million in the second quarter of 2003 and $11.8
million for the first six months of 2003. Transmission business earnings for the
42
periods in 2004 are higher than the same periods in 2003 primarily due to higher
revenues. Transmission revenues are higher in 2004 due to a revenue tracking
mechanism that was put in place in 2004 to match revenues and costs of providing
transmission service. In the first six months of 2004, $70.2 million of
transmission projects were placed in service. The revenue tracking mechanism
allows immediate recovery of these costs. During the first six months of 2003,
revenues were not subject to such a tracking mechanism.
NU Enterprises: NU Enterprises, Inc. is the parent company of NGC, Northeast
Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select
Energy Services, Inc. (SESI), and their respective subsidiaries, and Woods
Network Services, Inc. (Woods Network), all of which are collectively referred
to as "NU Enterprises." The generation operations of Holyoke Water Power Company
(HWP) are also included in the results of NU Enterprises. The companies included
in the NU Enterprises segment are grouped into two business segments: the
merchant energy business segment and the energy services business segment. The
merchant energy business segment is comprised of Select Energy's wholesale
business, which includes approximately 1,440 MW of primarily pumped storage and
hydroelectric generation assets owned by NGC and Select Energy's retail
business. The energy services business consists of the operations of NGS, SESI
and Woods Network.
NU Enterprises earnings decreased by $7.9 million in the second quarter of 2004
compared with the second quarter of 2003, but increased by $5.7 million for the
first six months of 2004 compared with the first six months of 2003. The
improved six-month earnings are a result of improved margins and higher retail
volumes on merchant energy contracts. A summary of NU Enterprises'
earnings/(losses) by business for the second quarter and first six months of
2004 and 2003 is as follows:
---------------------------------------------------------------------------------------------------------------------
For the Three Months For the Six Months
Ended June 30, Ended June 30,
---------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2004 2003 2004 2003
---------------------------------------------------------------------------------------------------------------------
Merchant energy $ 5.6 $10.6 $24.7 $15.5
Energy services (1.4) 1.4 (1.6) 1.8
Parent company (0.2) (0.1) (0.3) (0.2)
---------------------------------------------------------------------------------------------------------------------
Net income $ 4.0 $11.9 $22.8 $17.1
---------------------------------------------------------------------------------------------------------------------
A $5 million decrease in quarterly profitability was largely anticipated at the
merchant energy business and was due primarily to the structuring of some of
Select Energy's full requirements wholesale power contracts, which produced
higher per megawatt-hour revenues in the first quarter of 2004 and lower
revenues in the second quarter of 2004. Select Energy's cost per kilowatt-hour
(kWh) for procuring electricity is relatively flat throughout 2004. However,
contracted sales prices to some of Select Energy's wholesale customers were
relatively high in the first quarter and were lower in the second quarter,
creating better wholesale margins in the first quarter of 2004 and lower margins
in the second quarter. This decrease was offset by the retail business' improved
volumes and improved margins on those volumes. However, earnings were higher in
the first half of 2004 compared with the first half of 2003 as a result of
improved margins. Merchant energy second quarter earnings included an after-tax
positive $1.1 million related to changes in fair value of certain natural gas
contracts established to mitigate the risk of electricity purchased in
anticipation of winning certain levels of wholesale electric load in New
England. The use of fair value accounting for these contracts will likely result
in earnings volatility in future periods.
43
The decreases in second quarter and year-to-date earnings at the energy services
business are due in part to a $1.8 million after-tax loss recorded in the second
quarter on a construction contract.
Liquidity
---------
Consolidated: NU continues to maintain an adequate level of liquidity. At June
30, 2004, NU had $48.7 million of cash and cash equivalents compared with $43.4
million at December 31, 2003.
NU's net cash flows provided by operating activities increased to $475.3 million
in the first six months of 2004 from $211.7 million in the first six months of
2003. The increase is due to changes in working capital items, primarily
accounts payable and accrued taxes. Accounts payable increased in the first six
months of 2004 due primarily to an increase in CL&P accounts payable resulting
from transitional standard offers (TSO) supply purchases at higher prices and an
increased percentage of TSO purchases from unaffiliated suppliers. In the first
six months of 2003, accounts payable decreased due to lower Select Energy
wholesale electricity purchases. Accrued taxes decreased by $110 million in 2003
due primarily to the payment of taxes on the gain on the sale of Seabrook
compared to a decrease of $24.5 million in 2004. These 2003 changes were
partially offset by a decrease in accounts receivable related to a lower level
of Select Energy sales in the first six months of 2003 compared to the last
quarter of 2002 and a decrease in investments in securitizable assets and
regulatory overrecoveries. The decrease in regulatory overrecoveries is
primarily due to lower Competitive Transition Assessment (CTA) and Generation
Service Charge (GSC) collections in the first six months of 2004, which is also
the primary reason for the change in deferred income taxes from the first six
months of 2003 to the first six months of 2004. The change in deferred income
taxes is expected to continue to benefit cash flows from operations due to bonus
tax depreciation on newly completed plant assets. Cash flows from operations,
which have been significantly affected by changes in working capital items, are
not necessarily indicative of the cash flows for the second half of 2004.
On June 30, 2004, NU paid a dividend of $0.15 per share. On May 11, 2004, the NU
Board of Trustees approved a common dividend of $0.1625 per share, payable
September 30, 2004, to shareholders of record at September 1, 2004. The dividend
declared on May 11, 2004 represents an 8.3 percent increase in the common
dividend. This increase is consistent with management's intention of
recommending increases in the common dividend at a rate that is higher than the
expected industry average.
NU's capital expenditures have been lower than projected at the beginning of
2004. NU's capital expenditures totaled $311.6 million for the first six months
of 2004, compared with $234 million for the first six months of 2003. NU's 2004
capital spending was budgeted to total $738 million, but is now projected to
total $674.2 million, including $383.7 million by CL&P, $152.4 million by PSNH,
$39.4 million by WMECO, $60 million by Yankee Gas, and $38.7 million by other NU
subsidiaries. The lower level of capital expenditures was primarily related to
delays in certain transmission projects as a result of appeals of decisions by
the Connecticut Siting Council (CSC) and other legal and regulatory delays.
Further delays in certain major projects could cause NU's actual capital
spending to be below this projection.
In June 2004, Standard & Poor's (S&P) announced a new method of calculating the
capital adequacy of companies engaged in the competitive marketing and trading
of electricity and natural gas. S&P stated that companies rated investment
grade,
44
such as NU and all of its regulated operating companies, should have the
liquidity to meet whatever collateral requirements are necessitated by a
simultaneous downgrade of NU's ratings to below investment grade and a
significant movement in forward energy prices. NU continues to evaluate the
future impact of the new S&P standard and may need to increase its credit lines
to meet S&P's capital adequacy standards. At this time, management does not
believe that the cost of any additional liquidity which may be required will
have a material impact on future earnings.
Utility Group: At June 30, 2004, the Utility Group had $5 million in borrowings
outstanding on its $300 million revolving credit line. This credit line is
scheduled to mature in November 2004 and is expected to be renewed for at least
one year.
In addition to its revolving credit line, CL&P has an arrangement with a
financial institution under which CL&P can sell up to $100 million of accounts
receivable and unbilled revenues. At June 30, 2004, CL&P had sold accounts
receivable totaling $80 million to that financial institution. For more
information regarding the sale of receivables, see Note 1H, "Summary of
Significant Accounting Policies - Sale of Customer Receivables" to the condensed
consolidated financial statements.
On June 23, 2004, the DPUC approved CL&P's request to issue up to $280 million
of debt securities. CL&P expects to issue the debt later in 2004. Proceeds will
be used to repay short-term debt and to refinance a $59 million, 8.5 percent
bond issuance that will be redeemed on August 10, 2004 at a call premium of 3.87
percent. At June 30, 2004, CL&P had $196.2 million in short-term debt
outstanding from the NU Money Pool.
As part of the approved SMD settlement agreement, CL&P paid $83 million to
suppliers on July 8, 2004, and agreed to refund $75 million to its customers. Of
the combined payment and refund amount totaling $158 million, $31 million has
not been funded into the restricted cash - LMP costs account. Additionally, as
part of the DPUC's final decision regarding CL&P's CTA and System Benefits
Charge (SBC) docket, the DPUC ordered a refund to CL&P's customers of $88.5
million over a seven-month period beginning with October 2004 consumption. These
refunds, when combined with CL&P's proposed capital projects and previously
ordered refunds of CTA and SBC amounts, will negatively impact CL&P's liquidity.
However, CL&P expects no difficulty funding these additional requirements.
On July 22, 2004, PSNH issued $50 million of first mortgage bonds at a fixed
interest rate of 5.25 percent. Proceeds were used to pay down short-term debt
and fund PSNH's capital expenditure program. At June 30, 2004, PSNH had $62.1
million in short-term debt outstanding from the NU Money Pool.
On July 19, 2004, the DTE issued an order approving WMECO's financing of its
prior spent nuclear fuel liability through the issuance of up to $52 million in
debt. WMECO plans to issue this debt by the end of 2004.
NU Enterprises: At June 30, 2004, NU Enterprises had $53 million in letters of
credit (LOCs) outstanding on NU parent's $350 million revolving credit line.
This credit line is scheduled to mature in November 2004 and is expected to be
renewed for at least one year.
SESI borrowed $7.4 million during 2004 to finance the implementation of energy
saving improvements at customer facilities. Cash to repay these borrowings is
funded by SESI's energy savings contracts.
45
Nuclear Decommissioning and Plant Closure Costs
-----------------------------------------------
The purchasers of NU's ownership shares of the Millstone, Seabrook and Vermont
Yankee nuclear power plants assumed the obligation of decommissioning those
plants, but NU still has significant decommissioning and plant closure cost
obligations to the companies that own the Yankee Atomic (YA), Connecticut Yankee
(CY) and Maine Yankee (MY) nuclear power plants (collectively, the Yankee
Companies). Each plant has been shut down and is undergoing decommissioning. The
Yankee Companies collect decommissioning and closure costs through wholesale,
FERC-approved rates charged under power purchase agreements to several New
England utilities, including NU's electric utility companies CL&P, PSNH and
WMECO. These companies in turn pass these costs on to their customers through
state regulatory commission-approved retail rates. YA has received FERC approval
to collect all presently estimated decommissioning costs. MY and various other
parties filed a settlement agreement with the FERC, which if approved, provides
for the collection of approximately $27 million annually for decommissioning and
long-term storage of spent fuel through October 31, 2008. Approval of the MY
settlement agreement by the FERC is anticipated in the fall of 2004.
CY's estimated decommissioning and plant closure costs for the period 2000
through 2023 have increased by approximately $395 million over the April 2000
estimate of $436 million approved by the FERC in a 2000 rate case settlement.
The revised estimate reflects the termination of the decommissioning contract
with Bechtel Power Corporation in July 2003, the fact that CY is now
self-performing all work to complete the decommissioning of the plant, the
increases in the projected costs of spent fuel storage, and increased security
and liability and property insurance costs. NU's share of CY's increase in
decommissioning and plant closure costs is approximately $194 million. On July
1, 2004, CY filed with the FERC for recovery of the increased costs. In the
filing CY seeks to increase its annual decommissioning collections from $16.7
million to $93 million for a six-year period beginning January 1, 2005. FERC
proceedings have not yet been scheduled. In total, NU's estimated remaining
decommissioning and plant closure obligation to CY is $315.5 million at June 30,
2004.
Previously, on June 10, 2004, the DPUC and the Office of Consumer Counsel filed
a petition with the FERC seeking a declaratory order that CY can recover all
decommissioning costs from its wholesale purchasers, including CL&P, PSNH and
WMECO, but such purchasers may not recover in their retail rates any costs which
FERC might determine to have been imprudently incurred. CY and the wholesale
purchasers have objected and the matter is pending.
NU cannot at this time predict the timing or outcome of the FERC proceeding
required for the collection of the increased decommissioning costs. Management
believes that these costs have been prudently incurred and will ultimately be
recovered from the customers of CL&P, PSNH and WMECO. However, there is a risk
that some portion of these increased costs may not be recovered, or will have to
be refunded if recovered, as a result of the FERC proceedings. For further
information regarding these issues, see Part II, Item 1, "Legal Proceedings," in
this report on Form 10-Q.
Utility Group Business Development and Capital Expenditures
-----------------------------------------------------------
Connecticut - CL&P: On July 14, 2003, the CSC approved a 345,000 volt
transmission project from Bethel, Connecticut to Norwalk, Connecticut. The
project is estimated to cost approximately $200 million and will help alleviate
identified reliability issues in southwest Connecticut and help reduce
congestion
46
costs for all of Connecticut. An appeal of the CSC decision by the City of
Norwalk is pending. Hearings on the merits of the appeal were held in early July
2004 and a decision on the appeal is expected this summer. Management is
currently reassessing the project's expected cost and completion date. This
project is exempt from the State of Connecticut's moratorium on the approval of
new electric and natural gas transmission projects. At June 30, 2004, CL&P has
capitalized $41.5 million associated with this project.
On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of a
separate 345,000 volt transmission line from Norwalk, Connecticut to Middletown,
Connecticut. The estimated construction costs of this project are approximately
$620 million. CL&P will jointly site this project with UI and CL&P will own 80
percent, or approximately $496 million, of the project. This project is also
exempt from the State of Connecticut's moratorium on the approval of new
electric and natural gas transmission projects. Hearings before the CSC began in
February 2004 and are scheduled to continue through the third quarter of 2004,
with a final CSC decision scheduled for December 2004. Construction is expected
to commence shortly after the final decision. At June 30, 2004, CL&P has
capitalized $13.2 million related to this project.
In September 2002, the CSC approved a plan to replace an undersea electric
transmission line between Norwalk, Connecticut and Northport - Long Island, New
York. The project is expected to cost approximately $100 million and CL&P and
the Long Island Power Authority (LIPA) each own approximately 50 percent of the
line. The project still requires federal and New York State approvals, but is
exempt from the State of Connecticut's moratorium on the approval of new
electric and natural gas transmission projects. On June 24, 2004,
representatives from CL&P, the state of Connecticut, LIPA, and the Cross Sound
Cable Company reached a comprehensive settlement of issues surrounding the
activation of the separate Cross Sound Cable, in which NU has no investment.
Among other items, the settlement agreement calls for the replacement of the
existing Norwalk to Northport transmission line. A timetable for replacement of
the line is due to be filed with the Connecticut Department of Environmental
Protection by October 1, 2004. Management now expects the replacement cable to
be operational by 2008. At June 30, 2004, CL&P has capitalized $6.5 million
related to this project.
In the first six months of 2004, NU placed in service $70.2 million of electric
transmission projects. These projects included CL&P's $36 million upgrade of a
transmission substation in Stamford, Connecticut that will allow more than 100
additional MW to be imported into southwest Connecticut.
Connecticut - Yankee Gas: On June 10, 2004, Yankee Gas submitted a compliance
filing with the DPUC concerning the construction of a 1.2 billion cubic foot
liquefied natural gas storage facility in Waterbury, Connecticut. A final DPUC
decision is anticipated in the third quarter of 2004. If that decision is
acceptable to Yankee Gas, it is expected that Yankee Gas will enter into a final
contract for the construction of the LNG facility, which is now expected to cost
$108 million. Yankee Gas would anticipate beginning construction later in 2004
and for the facility to become operational in 2007 in time for the 2007/2008
heating season. This project is also exempt from the State of Connecticut's
moratorium on the approval of new electric and natural gas transmission
projects. At June 30, 2004, Yankee Gas has capitalized $4.1 million related to
this project.
New Hampshire: In May 2004, PSNH received final approval from the NHPUC to
convert one of three 50 megawatt units at the coal-fired Schiller Station to
burn wood. In its final decision, the NHPUC approved a joint motion for
47
reconsideration with the Office of Consumer Advocate (OCA), the state Office of
Energy and Planning and the New Hampshire Timberland Owners' Association that
modified a risk and reward sharing mechanism approved in an order on February 6,
2004, by the NHPUC. PSNH still is required to obtain various environmental
permits, but expects to begin construction later in 2004 following the receipt
of those permits. The $75 million project, which will reduce air emissions, will
take approximately two years to complete.
The NHPUC's decision approving PSNH's proposal regarding Schiller Station is the
subject of an appeal to the New Hampshire Supreme Court by the state's existing
wood-fired generating plant owners. Management believes that the appeal will not
impair PSNH's ability to proceed with the Schiller Station project.
For further information regarding rate matters associated with business
development and capital expenditures, see "Restructuring and Rate Matters," in
this Management's Discussion and Analysis.
Regional Transmission Organization
----------------------------------
In Order 2000, the FERC required all transmission owning utilities to
voluntarily form RTOs or to state why this process has not begun.
On October 31, 2003, the New England Independent System Operator (ISO-NE), along
with NU and six other New England transmission companies, filed a proposal with
the FERC to create an RTO for New England. On March 24, 2004, the FERC issued an
order conditionally accepting the New England RTO proposal. The RTO is intended
to strengthen the independent and efficient management of the region's power
system while ensuring that customers in New England continue to have the most
reliable system possible to facilitate the benefits of a competitive wholesale
energy market.
In a separate filing made on November 4, 2003, NU along with six other New
England transmission owners requested, consistent with the FERC's pricing policy
for RTOs and Order-2000-compliant independent system operators, that the FERC
approve a single ROE for regional and local rates that would consist of a
proposed 12.8 percent base ROE as well as incentive adders of 0.5 percent for
joining a RTO and 1.0 percent for constructing new transmission facilities
approved by the RTO.
In its March 24, 2004 order the FERC accepted the proposal for the 0.5 percent
incentive adder, but set to hearing the issues of the appropriate base ROE and
the clarification as to which facilities the 1.0 percent incentive adder
applies. A final ruling regarding these issues is expected in 2005.
Restructuring and Rate Matters
------------------------------
Utility Group: On August 26, 2003, the transmission segment of NU's regulated
companies filed its first transmission rate case at the FERC since 1995. In the
filing, the companies requested implementation of a formula rate that would
allow recovery of increasing transmission expenditures on a timelier basis and
that the changes, including a $23.7 million annual rate increase through 2004,
take effect on October 27, 2003. The companies requested that the FERC maintain
their existing 11.75 percent ROE until a ROE for the New England RTO is
established by the FERC. On October 22, 2003, the FERC accepted this filing
implementing the proposed rates subject to refund effective on October 28, 2003
and set several issues for hearing.
48
On June 14, 2004, the transmission segment of NU's regulated companies reached a
settlement agreement with the parties to its rate case that allows transmission
to implement formula-based rates as proposed with an 11.0 percent ROE until the
FERC establishes an ROE for the RTO. The FERC is expected to issue a decision on
the settlement agreement in the second half of 2004.
Revenues billed through June 2004 were based on the original proposed ROE of
11.75 percent. The settlement agreement resulted in the recognition of a $1.8
million regulatory liability for the reduction in ROE from 11.75 percent to 11.0
percent and reduced second quarter 2004 earnings by $1.1 million. In addition, a
regulatory liability for the collection of costs not yet incurred has also been
recognized but had no impact on earnings. This total regulatory liability at
June 30, 2004 was approximately $4 million.
Wholesale transmission revenues are based on rates and formulas that are
approved by the FERC. Most of NU's wholesale transmission revenues are collected
through a combination of the New England Regional Network Service (RNS) tariff
and NU's Local Network Service (LNS) tariff. The RNS tariff, which is
administered by ISO-NE, recovers the revenue requirements associated with
transmission facilities that are deemed by the FERC to be Pool Transmission
Facilities. This regional rate is reset on June 1st of each year. The LNS tariff
which was accepted by the FERC on October 22, 2003, provides for the recovery of
NU's total transmission revenue requirements, net of revenues received from
other sources, including revenues received under the RNS rates. NU's LNS rate is
a formula rate which is also reset on June 1st of each year. Additionally, NU's
LNS tariff provides for a true-up to actual costs which ensures that NU recovers
its total annual transmission revenue requirements, including the allowed ROE.
The calculation of new rates under the LNS tariff, as well as the true-up
calculation, are filed with FERC.
Connecticut - CL&P:
Impacts of Standard Market Design: On March 1, 2003, the ISO-NE implemented SMD.
As part of SMD, LMP is utilized to assign value and causation to transmission
congestion and line losses. Transmission congestion costs represent the
additional costs incurred due to the need to run uneconomic generating units in
certain areas that have transmission constraints, which prevent these areas from
obtaining alternative lower-cost generation. Line losses represent losses of
electricity as it is sent over transmission lines.
CL&P was billed $186 million of incremental LMP costs in 2003 by its standard
offer service suppliers, including affiliate Select Energy, or by ISO-NE and
collected $158 million from its customers. CL&P and its suppliers disputed the
responsibility for the $186 million of incremental LMP costs incurred. A
settlement agreement was reached to settle the dispute among all the parties
involved and was filed with the FERC on March 3, 2004. NU recorded a pre-tax
loss in 2003 of approximately $60 million (approximately $37 million after-tax)
related to this settlement agreement. The settlement agreement was approved by
the FERC on June 28, 2004.
On July 8, 2004, CL&P paid the standard offer service suppliers $83 million as
part of the approved settlement agreement, and the remaining $75 million became
available to be refunded to CL&P's customers. The method in which the $75
million will be refunded to customers is currently under review by the DPUC with
a decision expected in the third quarter of 2004.
49
Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor of
Connecticut signed into law Public Act No. 03-135 (the Act) that amended
Connecticut's 1998 electric utility industry legislation. The Act required CL&P
to file a four-year transmission and distribution plan with the DPUC. On
December 17, 2003, the DPUC issued its final decision in the rate case.
CL&P filed a petition for reconsideration of certain items in the rate case on
December 31, 2003. Other parties also filed petitions for reconsideration. On
January 21, 2004, the DPUC agreed to reconsider CL&P's items and issued a final
decision on the reconsideration on August 4, 2004. The final decision allows
CL&P to recover approximately $32 million related to these items beginning
August 1, 2004. The DPUC has authorized using the existing CTA overrecoveries to
recover the approximately $24 million net present value of these additional
amounts in lieu of an increase in rates.
The final decision could have a positive pre-tax impact of up to approximately
$12 million in 2004. The DPUC's conclusion on streetlighting refund periods and
methodologies was also included in the final decision and could significantly
reduce the $12 million pre-tax impact. In addition, the impact could also be
offset by CL&P's earnings sharing mechanism. Management has not determined the
amount of these potential offsets.
CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such
as securitization costs associated with the rate reduction bonds, amortization
of regulatory assets, and independent power producer (IPP) over market costs,
while the SBC allows CL&P to recover certain regulatory and energy public policy
costs, such as public education outreach costs, hardship protection costs,
transition period property taxes, and displaced workers protection costs. The
GSC allows CL&P to recover the costs of the procurement of energy for standard
offer service.
On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the DPUC.
For the year ended December 31, 2003, total CTA revenues and excess GSC revenues
as filed exceeded the CTA revenue requirement by $148.3 million. For the same
period, SBC revenues as filed exceeded the SBC revenue requirement by $25.5
million. These amounts were recorded as regulatory liabilities on the
accompanying condensed consolidated balance sheets.
A final decision in the 2003 CTA and SBC docket was issued on August 4, 2004. In
the final decision, the DPUC ordered a refund to customers of $88.5 million over
a seven-month period beginning with October 2004 consumption. The DPUC ordered
that the SBC rate be reduced to zero effective January 1, 2005. The DPUC also
directed CL&P to impute revenue of $2.7 million to customers associated with a
previously renegotiated IPP contract. CL&P will likely seek rehearing on this
issue, and management cannot predict the outcome of this issue at this time.
In the 2001 CTA and SBC reconciliation filing, and subsequently in a September
10, 2002 petition to reopen related proceedings, CL&P requested that a deferred
intercompany liability associated with income taxes be excluded from the
calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued
a final decision denying CL&P's request, and on October 24, 2003, CL&P appealed
the DPUC's final decision to the Connecticut Superior Court. The appeal has been
fully briefed and is in the argument phase, and a decision from the Connecticut
Superior Court could be rendered by the end of 2004. If the company's request is
ultimately granted through court proceedings, then there could be additional
amounts due to CL&P from its customers. The 2004 impact of including the
deferred intercompany liability in CTA revenue requirements has been a reduction
of approximately $19.3 million in revenue.
50
Connecticut - Yankee Gas:
Rate Case Filing: On July 2, 2004, Yankee Gas filed a rate case with the DPUC to
increase retail rates by $26.5 million, or 7.2 percent, effective January 1,
2005. Yankee Gas also requested an authorized ROE of 10.75 percent in the rate
case filing. The requested increase in rates results from increased costs of
distribution delivery services such as pension and healthcare, as well as
additional investments needed to maintain a safe and reliable gas distribution
system. Yankee Gas expects a decision from the DPUC on the rate case by the end
of 2004 and anticipates that it will underearn its currently authorized 11.0
percent ROE in 2004.
IERM Settlement: On April 29, 2004, Yankee Gas and the OCC filed a settlement
agreement that provides for the termination of Yankee Gas' IERM, which tracked
the revenue and expenses associated with its system expansion program. The
settlement finalizes ratemaking treatment for all Yankee Gas IERM projects and
returns Yankee Gas to a traditional capital investment test. A final decision
approving the settlement was issued on August 4, 2004. The settlement agreement
temporarily lowers the ROE on certain IERM assets to Yankee Gas' debt rate and
will not have a material adverse impact on Yankee Gas' net income or financial
position.
New Hampshire:
Delivery Rate Case: PSNH's delivery rates were fixed by the "Agreement to Settle
PSNH Restructuring" (Restructuring Settlement) until February 1, 2004.
Consistent with the requirements of the Restructuring Settlement and state law,
PSNH filed a delivery service rate case and tariffs with the NHPUC on December
29, 2003 to increase electricity delivery rates by approximately $21 million, or
2.6 percent, effective February 1, 2004.
On July 14, 2004, PSNH filed with the NHPUC a revenue requirements settlement
agreement among several parties, including the NHPUC staff and the OCA. If
approved by the NHPUC, the settlement would allow increases in PSNH's delivery
rates totaling $3.5 million annually, effective prospectively on October 1,
2004, and an incremental $10 million increase annually effective prospectively
on June 1, 2005, for a total rate increase of $13.5 million. On July 29, 2004,
PSNH filed with the NHPUC a rate design settlement agreement among several
parties, including the NHPUC staff. If approved by the NHPUC, these two
settlement agreements would resolve all delivery service rate case issues. A
hearing took place on August 3, 2004, and a decision is expected by the end of
the third quarter of 2004.
Transition Energy Service: In accordance with the Restructuring Settlement and
state law, PSNH files for updated transition energy service (TS) rates annually.
The TS rate recovers PSNH's generation and purchased power costs, including a
return on PSNH's generation investment. PSNH defers any difference between its
TS revenues and the actual costs incurred. On December 19, 2003, the NHPUC
issued an order approving a $0.0536 per kWh TS rate effective February 1, 2004
through January 31, 2005.
The December 2003 order also addressed the issue of cost deferrals by requiring
a review of TS costs in July 2004 for a possible TS rate change effective August
1, 2004. Accordingly, PSNH filed a petition with the NHPUC on July 1, 2004
requesting a change in the TS rate from the current $0.0536 per kWh to $0.0594
per kWh based on actual costs and underrecoveries incurred to date and updated
cost projections. A hearing took place on July 26, 2004, and an order changing
51
the TS rate to $0.0579 per kWh, effective August 1, 2004 was issued by the NHPUC
on August 2, 2004.
SCRC Reconciliation Filing: The Stranded Cost Recovery Charge (SCRC) allows PSNH
to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a
SCRC reconciliation filing for the preceding calendar year. This filing includes
the reconciliation of stranded cost revenues billed with stranded costs, and TS
revenues billed with TS costs. The NHPUC reviews the filing, including a
prudence review of PSNH's generation operations. The cumulative deferral of SCRC
revenues in excess of costs was $175.8 million at June 30, 2004. The 2003 SCRC
filing was made on April 30, 2004. Management does not expect the review of the
2003 SCRC filing to have a material effect on PSNH's net income or financial
position. Hearings are currently scheduled for October 2004.
Estimated unbilled revenues for PSNH are not considered in the reconciliation of
certain billed revenues to incurred costs through rate mechanisms such as the
SCRC and the SBC. Accordingly, changes in estimated unbilled revenues due to
changes in these charges impact PSNH's earnings in the period of change.
Massachusetts:
Transition Cost Reconciliation: On March 31, 2004, WMECO filed its 2003
transition cost reconciliation with the DTE. This filing reconciled the recovery
of generation-related stranded costs for calendar year 2003. The timing of a
final decision is uncertain. Management does not expect the outcome of this
docket to have a material adverse impact on WMECO's net income or financial
position.
NU Enterprises
--------------
Business Segments: NU Enterprises aligns its businesses into two business
segments, the merchant energy business segment and the energy services business
segment. The merchant energy business segment includes Select Energy's wholesale
and retail marketing businesses. Also included in this segment are 1,440 MW of
generation assets, consisting of 1,293 MW of primarily pumped storage and
hydroelectric generation assets at NGC and 147 MW of coal-fired generation at
HWP.
In June 2004, the FERC approved a 40-year license extension for NGC's Housatonic
hydroelectric generation units in Connecticut. That license covers four
conventional stations and one pumped storage station, which together account for
approximately 115 MW of capacity.
The energy services business segment includes the operations of SESI, NGS, and
Woods Network. SESI performs energy management services for large commercial
customers, institutional facilities and the United States government and
energy-related construction services. NGS operates and maintains NGC's and HWP's
generation assets and provides third-party electrical services. Woods Network is
a network design, products and service company.
Outlook: The energy services business segment is not expected to earn any higher
than the low end of its previous earnings range of between $4 million and $7
million.
In the second quarter of 2004, Select Energy won 12-month contracts to serve
various NSTAR subsidiaries. Under these contracts, Select Energy will serve
approximately 1,100 MW and will earn more than $225 million of revenues over the
52
contract term of July 1, 2004 through June 30, 2005. Select Energy will continue
to bid on contracts in 2004 that will take effect in 2004 and beyond. Select
Energy's ability to secure a significant amount of wholesale load is a critical
factor in NU Enterprises' ongoing profitability. Based upon June 30, 2004 market
information, Select Energy's wholesale electric and gas business has already
contracted approximately 80 percent of the sales needed to reach its 2004 gross
margin targets, assuming satisfactory portfolio management for the remainder of
the year.
The retail marketing portion of NU Enterprises' merchant energy business segment
has already contracted for more than 75 percent of the business needed to
achieve 2004 gross margin targets.
Intercompany Transactions: CL&P's standard offer purchases from Select Energy
represented $108.3 million for the three months ended June 30, 2004, compared
with $138.9 million during the same period in 2003. Other energy purchases
between CL&P and Select Energy totaled $27.7 million for the three months ended
June 30, 2004 and $33.2 million during the same period in 2003. Additionally,
WMECO's purchases from Select Energy represented $21 million for the three
months ended June 30, 2004, compared with $29.2 million during the same period
in 2003. These amounts are eliminated in consolidation.
CL&P's standard offer purchases from Select Energy represented $256.8 million
for the first six months of 2004, compared with $279.9 million during the same
period in 2003. Other energy purchases between CL&P and Select Energy totaled
$57.7 million for the first six months of 2004 and $69.2 million during the same
period in 2003. Additionally, WMECO's purchases from Select Energy represented
$53 million for the first six months of 2004, compared with $68.2 million during
the same period in 2003. These amounts are eliminated in consolidation.
NU Enterprises' Market and Other Risks
--------------------------------------
Overview: For further information on risk management activities, see
"Competitive Energy Subsidiaries' Market and Other Risks" in NU's combined
report on Form 10-K.
Risk management within Select Energy is organized to address the market, credit
and operational exposures arising from the merchant energy business segment,
which include: wholesale marketing activities (including limited energy trading
for market and price discovery purposes as well as asset optimization) and
retail marketing activities. The framework for managing these risks is set forth
in NU's risk management policies and procedures, which are periodically reviewed
by the NU Board of Trustees.
A significant portion of Select Energy's merchant energy marketing activities is
providing electricity to full requirements customers, which are primarily
regulated local distribution companies (LDCs) and commercial and industrial
retail customers. Under the terms of full requirements contracts, Select Energy
is required to provide a percentage of the LDC's electricity requirements at all
times. The volumes sold under these contracts vary based on the usage of the
LDC's retail electric customers, and usage is dependent upon factors outside of
Select Energy's control, such as the weather. The varying sales volumes could be
different than the supply volumes that Select Energy expected to utilize, either
53
from generation or from electricity purchase contracts, to serve the full
requirements contracts. Differences between actual sales volumes and supply
volumes can require Select Energy to purchase additional electricity or sell
excess electricity, both of which are subject to market conditions such as
weather, plant availability, transmission congestion, and potentially volatile
price fluctuations that can impact prices and, in turn, Select Energy's margins.
The pricing terms of full requirement contracts and of supply contracts can
affect the timing of Select Energy's margins. Many full requirements contracts
have higher prices in certain months, while certain supply contracts have one
price for the entire contract term. Accordingly, Select Energy's margins will
tend to be higher in the months when the full requirements contract price is
high and lower or could be negative when the full requirements contract price is
lower.
Energy Sourcing Activities: In June 2004, Select Energy began purchasing
fixed-price electricity and some electricity with prices indexed to gas for 2005
and 2006 in anticipation of winning full requirements contract sales and sales
to load-serving entities. Purchasing electricity in advance of winning contracts
exposes Select Energy to the risk of electricity price decreases before the full
requirement quantities are contracted and before contract prices are known.
To mitigate the risk of electricity price decreases on the fixed-price
electricity that was purchased, Select Energy in June 2004 began selling
contracts for wholesale natural gas delivery (basis contracts) and natural gas
futures and swaps contracts for 2005 and 2006. Select Energy expected that the
result of this risk mitigation strategy would be that decreases in the value of
the fixed-price electricity purchase contracts would be offset in part by
increases in the value of the gas contracts, and vice versa. Select Energy
intends to purchase natural gas when quantities and prices of electricity are
secured by full requirements contracts or sales contracts with load-serving
entities. Natural gas was sold in this risk mitigation strategy due to the high
liquidity of the natural gas market compared to the low liquidity of electricity
in the Northeast.
The electricity contracts are accounted for on the accrual basis, which will
result in earnings recognition when the electricity is delivered in 2005 and
2006. These electricity purchase contracts are expected to be used to meet
electricity sales contract requirements, which are a key component of Select
Energy's business. Select Energy believes that this electricity will be
delivered to its customers.
The use of fair value accounting for the natural gas basis and futures and swaps
contracts will expose Select Energy's and NU's earnings to future changes in
natural gas prices, which could be significant. This can reasonably be expected
to create uncertainty regarding Select Energy's and NU's earnings and earnings
trends. The electricity contracts are not expected to be accounted for at fair
value, and changes in the value of these contracts, which could be significant,
will not impact earnings until the electricity is delivered.
The natural gas basis and futures and swaps contracts are included in
non-trading derivative assets and liabilities in the table in Note 2,
"Derivative Instruments," to the condensed consolidated financial statements.
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. There could be significant volatility
in the energy commodities markets that could affect merchant energy assets and
54
contracts between now and when the energy is delivered and the contracts are
settled. Accordingly, there can be no assurances that Select Energy will realize
the gross margin expected from its wholesale marketing portfolio.
Hedging and Other Non-Trading: For information on derivatives used for hedging
purposes and non-trading derivatives, see Note 2, "Derivative Instruments," to
the condensed consolidated financial statements.
Wholesale Contracts Defined as "Energy Trading": Energy trading transactions at
Select Energy include financial transactions and physical delivery transactions
for electricity, natural gas and oil in which Select Energy is attempting to
profit from changes in market prices. Energy trading contracts are recorded at
fair value, and changes in fair value affect net income.
At June 30, 2004, Select Energy had trading derivative assets of $111.2 million
and trading derivative liabilities of $82.9 million, for a net positive position
of $28.3 million for the entire trading portfolio. These amounts are combined
with other derivatives and are included in derivative assets and derivative
liabilities on the accompanying condensed consolidated balance sheets. The
increase in both derivative asset and liability amounts from March 31, 2004,
relates primarily to price increases. Information regarding non-trading and
other derivatives is included in Note 2, "Derivative Instruments," to the
consolidated financial statements.
There can be no assurances that Select Energy will realize cash corresponding to
the present positive net fair value of its trading positions. Numerous factors
could either positively or negatively affect the realization of the net fair
value amount in cash. These include the volatility of commodity prices, changes
in market design or settlement mechanisms, the outcome of future transactions,
the performance of counterparties, and other factors.
Select Energy has policies and procedures requiring all trading positions to be
marked-to-market at the end of each business day and segregating
responsibilities between the individuals actually trading (front office) and
those confirming the trades (middle office). The determination of the
portfolio's fair value is the responsibility of the middle office independent
from the front office.
The methods used to determine the fair value of energy trading contracts are
identified and segregated in the table of fair value of contracts at June 30,
2004. A description of each method is as follows: 1) prices actively quoted
primarily represent New York Mercantile Exchange futures and options that are
marked to closing exchange prices; 2) prices provided by external sources
primarily include over-the-counter forwards and options, including bilateral
contracts for the purchase or sale of electricity or natural gas, and are marked
to the mid-point of bid and ask market prices; and 3) prices based on models or
other valuation methods primarily include transactions for which specific quotes
are not available. Currently, Select Energy has no contracts for which fair
value is determined based on a model or other valuation method. Broker quotes
for electricity are available through the year 2006. Broker quotes for natural
gas are available through 2013.
Generally, valuations of short-term contracts derived from quotes or other
external sources are more reliable should there be a need to liquidate the
contracts, while valuations for longer-term contracts are less certain.
Accordingly, there is a risk that contracts will not be realized at the amounts
recorded. However, Select Energy has obtained corresponding purchase or sale
contracts for substantially all of the trading contracts that have maturities in
excess of one year. Because these contracts are sourced, changes in the value of
55
these contracts due to fluctuations in commodity prices are not expected to
affect Select Energy's earnings.
As of and for the six months ended June 30, 2004, the sources of the fair value
of trading contracts and the changes in fair value of these trading contracts
are included in the following tables. Intercompany transactions are eliminated
and not reflected in the amounts below.
-------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Fair Value of Trading Contracts at June 30, 2004
-------------------------------------------------------------------------------------------------------------------
Maturity Maturity Maturity Total
Less than of One to in Excess of Fair
Sources of Fair Value One Year Four Years Four Years Value
-------------------------------------------------------------------------------------------------------------------
Prices actively quoted $0.3 $0.1 $ - $ 0.4
Prices provided by
external sources 6.3 7.5 14.1 27.9
-------------------------------------------------------------------------------------------------------------------
Totals $6.6 $7.6 $14.1 $28.3
-------------------------------------------------------------------------------------------------------------------
The fair value of energy trading contracts increased $0.9 million from $27.4
million at March 31, 2004 to $28.3 million at June 30, 2004. The change in the
fair value of the trading portfolio is primarily attributable to changes in
energy commodity prices during the period. There were no changes in valuation
techniques or assumptions in the second quarter of 2004.
--------------------------------------------------------------------------------------------------------
Total Portfolio Fair Value
--------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
(Millions of Dollars) June 30, 2004 June 30, 2004
--------------------------------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the beginning
of the period $27.4 $32.5
Contracts realized or otherwise
settled during the period (0.4) (6.1)
Changes in fair value of contracts 1.3 1.9
--------------------------------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the end
of the period $28.3 $28.3
--------------------------------------------------------------------------------------------------------
Changing Market: The breadth and depth of the market for energy marketing
products in Select Energy's areas of business have been adversely affected by
the withdrawal or financial weakening of a number of companies, particularly
power marketers, who have historically done significant amounts of business with
Select Energy. In general, the market for such products is shorter term in
nature with less liquidity, market pricing information is less readily
available, and participants are sometimes unable to meet Select Energy's credit
standards without providing cash or LOC support. Select Energy is being
adversely affected by these factors, and there could be a continuing adverse
impact on Select Energy's business lines due to its increasing reliance on
business arrangements with a more limited number of counterparties, primarily
power generators.
Changes are occurring in the administration of transmission systems in
territories in which Select Energy does business. RTOs are being proposed and
approved, and other changes in market design are occurring within transmission
regions. For example, SMD was implemented in New England on March 1, 2003 and
has created both challenges and opportunities for Select Energy. For information
regarding the effects of SMD on Select Energy and RTOs, see "Restructuring and
Rate Matters," and "Regional Transmission Organization," in this Management's
Discussion and Analysis. As the market continues to evolve, there could be
additional adverse effects that management cannot determine at this time.
56
Counterparty Credit: Counterparty credit risk relates to the risk of loss that
Select Energy would incur because of non-performance by counterparties pursuant
to the terms of their contractual obligations. Select Energy has established
written credit policies with regard to its counterparties to minimize overall
credit risk. These policies require an evaluation of potential counterparties'
financial conditions (including credit ratings), collateral requirements under
certain circumstances (including cash advances, LOCs, and parent guarantees),
and the use of standardized agreements that allow for the netting of positive
and negative exposures associated with a single counterparty. This evaluation
results in establishing credit limits prior to Select Energy's entering into
contracts. The appropriateness of these limits is subject to continuing review.
Concentrations among these counterparties may affect Select Energy's overall
exposure to credit risk, either positively or negatively, in that the
counterparties may be similarly affected by changes to economic, regulatory or
other conditions. At June 30, 2004, approximately 79 percent of Select Energy's
counterparty credit exposure to wholesale and trading counterparties was cash
collateralized or rated BBB- or better. Select Energy received $105 million and
$46.5 million of counterparty deposits at June 30, 2004 and December 31, 2003,
respectively. Select Energy used these amounts to fund current operations. For
further information, see Note 1K, "Counterparty Deposits," to the condensed
consolidated financial statements.
Select Energy's Credit: A number of Select Energy's contracts require the
posting of additional collateral in the form of cash or LOCs in the event NU's
ratings were to decline and in increasing amounts dependent upon the severity of
the decline. At NU's present investment grade ratings, Select Energy has not had
to post any collateral based on credit downgrades. Were NU's unsecured ratings
to decline two to three levels to sub-investment grade, Select Energy could,
under its present contracts, be asked to provide approximately $310 million of
collateral or LOCs to various unaffiliated counterparties and approximately $97
million to several independent system operators and unaffiliated local
distribution companies, which management believes NU would currently be able to
provide, subject to the Securities and Exchange Commission (SEC) limits
described below. NU's credit ratings outlooks are currently stable or negative,
but management does not believe that at this time there is a significant risk of
a ratings downgrade to sub-investment grade levels.
On June 30, 2004, the SEC issued an order allowing NU to significantly expand
its financial support of NU Enterprises. The new order allows NU through June
30, 2007 to 1) increase its allowable investments in certain of its unregulated
businesses, presently 15 percent of its consolidated capitalization as permitted
by SEC regulation, by an additional $500 million, 2) increase the limit for its
guarantees of all of its competitive affiliates from $500 million to $750
million, and 3) increase its allowable investments in exempt wholesale
generators (EWGs) from $481 million to $1 billion. The order will permit NU to
fully support the planned level of business activities of Select Energy and its
other unregulated businesses. NU has no present plans to significantly expand
its EWG portfolio. However, if an investment opportunity becomes available, NU
will be able to pursue it within the new allowable EWG investment level.
For further information regarding Select Energy's activities and risks, see Note
2, "Derivative Instruments," and Note 5, "Comprehensive Income," to the
condensed consolidated financial statements.
57
Critical Accounting Policies and Estimates Update
-------------------------------------------------
Derivative Accounting, the Election of Normal, and the Use of Hedge Accounting:
Most of the contracts comprising Select Energy's wholesale and retail marketing
activities are derivatives. The application of derivative accounting under
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended, is complex and requires
management's judgment. Judgment is applied in determining the qualification for
the election of the normal purchases and sale exception (and resulting accrual
accounting), which includes the conclusions that it is probable at the inception
of the contract and throughout its term that it will result in physical delivery
and that the quantities will be used or sold by the business over a reasonable
period in the normal course of business. If facts and circumstances change and
management can no longer support this conclusion, then the normal exception and
accrual accounting would be terminated and fair value accounting would be
applied.
Cash flow hedge contracts that are designated as hedges for contracts for which
the company has elected the normal purchases and sales exception can continue to
be accounted for as cash flow hedges only if the normal exception for the hedged
contract continues to be appropriate. If the normal exception is terminated,
then the hedge designation would be terminated at the same time and fair value
accounting would be applied.
Accounting for Transmission Revenues Subject to Refund: The $23.7 million
transmission rate increase that NU's electric operating companies requested
began being billed subject to refund on October 28, 2003. The rate increase was
based on a proposed ROE of 11.75 percent, which is unchanged from the ROE
included in previous transmission rates and is currently being billed.
Since October 27, 2003, management has evaluated the increase in transmission
revenues that has been collected to determine if any amounts are probable of
refund to customers in the future.
On June 14, 2004, the transmission segment of NU's regulated companies reached a
settlement agreement with the parties to its rate case that allows transmission
to implement formula-based rates as proposed with an 11.0 percent ROE until the
FERC establishes an ROE for the RTO. The FERC is expected to issue a decision on
the settlement agreement in the second half of 2004.
Revenues billed through June 2004 were based on the original proposed ROE of
11.75 percent. The settlement agreement resulted in the recognition of a $1.8
million regulatory liability for the reduction in ROE from 11.75 percent to 11.0
percent and reduced second quarter 2004 earnings by $1.1 million. In addition, a
regulatory liability for the collection of costs not yet incurred has also been
recognized but had no impact on earnings. This total regulatory liability at
June 30, 2004 was approximately $4 million.
A significant portion of NU's transmission businesses' revenue is from charges
to NU's distribution businesses. These distribution businesses recover these
charges through rates charged to their retail customers. WMECO has a rate
tracking mechanism to track transmission expenses charged in distribution rates
to the actual amount of transmission charges incurred. The 2004 rates set in the
CL&P distribution rate case contained a level of transmission expense sufficient
to cover CL&P's anticipated 2004 transmission costs. The June 1, 2005 PSNH rate
increase includes revenues in recognition of the transfer of certain assets from
transmission rates to distribution rates. Neither CL&P nor PSNH have
transmission tracking mechanisms.
58
Accounting for PSNH Rate Case: PSNH requested that an increase in rates be
included in bills starting on February 1, 2004 subject to refund. The NHPUC
denied that request but indicated that any rate changes from the rate case would
be effective from February 1, 2004 forward.
On July 14, 2004, PSNH filed with the NHPUC a settlement agreement among several
parties including the NHPUC staff and the OCA. If approved by the NHPUC, the
settlement would result in increases in PSNH's delivery rates effective
prospectively on October 1, 2004 and effective prospectively on June 1, 2005.
Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas
delivered to customers that has not been billed. Unbilled revenues are assets on
the condensed consolidated balance sheet that become accounts receivable in the
following month as customers are billed. Such estimates are subject to
adjustment when actual meter readings become available, when changes in
estimating methodology occur and under other circumstances.
The Utility Group estimates unbilled revenues monthly using the requirements
method. The requirements method utilizes the total monthly volume of electricity
or gas delivered to the system and applies a delivery efficiency (DE) factor to
reduce the total monthly volume by an estimate of delivery losses in order to
calculate total estimated monthly sales to customers. The total estimated
monthly sales amount less total monthly billed sales amount results in a monthly
estimate of unbilled sales. Unbilled revenues are estimated by applying an
average rate to the estimate of unbilled sales. The estimated DE factor can have
a significant impact on estimated unbilled revenue amounts.
In accordance with management's policy of testing the estimate of unbilled
revenues twice each year using the cycle method of estimating unbilled revenues,
testing was performed in the second quarter of 2004. The cycle method uses the
billed sales from each meter reading cycle and an estimate of unbilled days in
each month based on the meter reading schedule. The cycle method is more
accurate than the requirements method when used in a mostly weather-neutral
month.
The cycle method testing resulted in adjustments to the estimate of unbilled
revenues that had a net positive after-tax earnings impact of $1.5 million in
the second quarter of 2004. There were positive after-tax impacts on CL&P, WMECO
and Yankee Gas of $1.8 million, $0.9 million, and $0.5 million, respectively,
while there was a negative after-tax impact on PSNH of $1.7 million.
Other Matters
-------------
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 4, "Commitments and Contingencies," to
the condensed 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,
59
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.
60
RESULTS OF OPERATIONS - NU CONSOLIDATED
The following table provides the variances in income statement line items for
the condensed consolidated statements of income for NU included in this report
on Form 10-Q for the second quarter of 2004 and the first six months of 2004:
Income Statement Variances
(Millions of Dollars)
2004 over/(under) 2003
----------------------
Second
------- Six
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues: $195 15% $449 15%
Operating Expenses:
Fuel, purchased and net
interchange power 145 19 357 21
Other operation 40 17 78 19
Maintenance - - 10 9
Depreciation 5 10 10 10
Amortization 5 23 (26) (31)
Amortization of rate
reduction bonds 3 8 7 9
Taxes other than income taxes 4 8 8 6
---- ---- ---- ----
Total operating expenses 202 16 444 17
---- ---- ---- ----
Operating income (7) (7) 5 2
---- ---- ---- ----
Interest expense, net 4 6 3 2
Other income, net 2 (a) 3 (a)
---- ---- ---- --
Income before income tax expense (9) (20) 5 3
Income tax expense (6) (37) 1 1
Preferred dividends of
subsidiary - - - -
---- ---- ---- ----
Net Income $ (3) (11)% $ 4 5%
==== ==== ==== ====
(a) Percent greater than 100.
COMPARISON OF THE SECOND QUARTER OF 2004 TO THE SECOND QUARTER OF 2003
OPERATING REVENUES
Total revenues increased $195 million in the second quarter of 2004, compared
with the same period in 2003, due to higher revenues from NU Enterprises ($66
million or $111 million after intercompany eliminations) and higher distribution
revenues ($80 million or $77 million after intercompany eliminations) and higher
regulated transmission revenues ($9 million or $5 million after intercompany
eliminations).
The NU Enterprises' revenues increase is primarily due to higher revenues for
the merchant energy segment resulting from higher electric prices ($59 million),
higher gas volumes ($15 million) and higher gas prices ($2 million), partially
offset by lower electric volumes ($18 million).
The electric distribution revenue increase is primarily due to increases in the
standard offer and default service revenues for CL&P, PSNH and WMECO ($74
million) due mainly to rate increases, Federally Mandated Congestion Cost (FMCC)
revenues for CL&P ($35 million), and higher sales volume for distribution
61
revenues ($12 million), partially offset by lower SMD revenue for CL&P ($30
million), lower CL&P Energy Adjustment Clause (EAC) revenue as a result of the
end of EAC billings in December 2003 ($9 million) and lower revenues for CL&P
and WMECO transition charges ($6 million). Electric retail kWh sales increased
by 4.8 percent in the second quarter of 2004.
Transmission revenues were higher due to the October 2003 implementation of the
transmission rate case filed at the FERC.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $145 million in the
second quarter of 2004, primarily due to higher wholesale costs at NU
Enterprises ($60 million or $57 million after intercompany eliminations) and
higher purchased power costs for the Utility Group ($40 million or $88 million
after intercompany eliminations). The increase for the Utility Group is
primarily due to an increase in the standard offer service requirements rates
for CL&P ($51 million) and an increase for WMECO ($5 million), partially offset
by the 2003 recovery of certain fuel costs ($9 million).
OTHER OPERATION
Other operation expenses increased $40 million in the second quarter of 2004,
primarily due to higher competitive business expenses resulting from business
growth ($15 million), higher reliability must run costs ($15 million) and higher
regulated business administrative and general expenses ($7 million) due to
higher pension costs.
DEPRECIATION
Depreciation increased $5 million in the second quarter of 2004 due to higher
Utility Group plant balances and higher depreciation rates at CL&P resulting
from the distribution rate case decision effective in January 2004.
AMORTIZATION
Amortization increased $5 million in the second quarter of 2004 primarily due to
higher Utility Group recovery of stranded costs offset by a decrease in
amortization expense resulting from the implementation of the CL&P distribution
rate case decision effective in January 2004 ($7 million).
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds increased $3 million in the second quarter
of 2004 due to the repayment of additional principal as compared to 2003.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $4 million in the second quarter of 2004
primarily due to higher Connecticut gross earnings tax as a result of an
increase in revenues for NU Enterprises and CL&P, higher local property taxes,
higher payroll taxes and higher sales tax.
INTEREST EXPENSE, NET
Interest expense, net increased $4 million in the second quarter of 2004
primarily due to higher interest on long-term debt at NU parent related to a
2003 settlement payment to NU as a result of the interest rate swap for the $263
million fixed-rate senior notes and an increase in long-term debt expense due to
the issuance of $150 million of five-year notes at NU parent in June 2003.
OTHER INCOME, NET
Other income, net increased $2 million in the second quarter of 2004 primarily
due to the recognition beginning in 2004 of a CL&P procurement fee approved in
62
the TSO docket decision ($3 million) and a decrease in charitable contributions
($1 million), partially offset by an investment impairment ($3 million).
INCOME TAX EXPENSE
Income tax expense decreased due to lower income before tax expense along with a
lower effective tax rate due to the regulatory treatment of taxes by certain
Utility Group companies.
COMPARISON OF THE FIRST SIX MONTHS OF 2004 TO THE FIRST SIX MONTHS OF 2003
OPERATING REVENUES
Total revenues increased $449 million in the first six months of 2004, compared
with the same period in 2003, due to higher revenues from NU Enterprises ($250
million or $298 million after intercompany eliminations), higher electric
distribution revenues ($130 million or $125 million after intercompany
eliminations), higher gas distribution revenues ($20 million) and higher
regulated transmission revenues ($9 million or $3 million after intercompany
eliminations).
The NU Enterprises' revenues increase is primarily due to higher revenues for
the merchant energy segment resulting from higher electric prices ($180
million), higher gas volumes ($46 million) and higher gas prices ($12 million),
partially offset by lower electric volumes ($11 million).
The electric distribution revenue increase is primarily due to increases in the
standard offer and default service revenues for CL&P, PSNH and WMECO ($150
million) due mainly to rate increases, FMCC revenues for CL&P ($75 million),
higher sales volume for distribution revenues ($19 million) and higher CL&P
retail transmission rates ($13 million), partially offset by lower SMD revenue
for CL&P ($29 million), lower CL&P EAC revenue as a result of the end of EAC
billings in December 2003 ($21 million) and lower revenues for CL&P and WMECO
transition revenues ($16 million). Electric retail kWh sales increased by 3.7
percent in the first six months of 2004. In addition, electric wholesale
revenues decreased by $47 million primarily due to lower short-term transactions
($35 million) and the expiration of long-term contracts ($12 million).
The higher gas distribution revenue is primarily due to the increased recovery
of gas costs. Firm natural gas sales increased by 3.4 percent in the first six
months of 2004 from the same period of 2003.
Transmission revenues were higher due to the October 2003 implementation of the
transmission rate case filed at the FERC.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $357 million in the
first six months of 2004, primarily due to higher wholesale costs at NU
Enterprises ($199 million or $196 million after intercompany eliminations) and
higher purchased power costs for the Utility Group ($108 million or $161 million
after intercompany eliminations). The increase for the Utility Group is
primarily due to an increase in the standard offer service requirements rates
for CL&P ($120 million) and an increase for WMECO ($12 million), higher Yankee
Gas expenses due to increased gas prices ($21 million), partially offset by the
2003 recovery of certain fuel costs ($21 million), lower wholesale purchases for
CL&P ($12 million) and WMECO ($4 million), and lower expenses for PSNH due to
lower regulated energy and capacity purchases ($9 million).
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OTHER OPERATION
Other operation expenses increased $78 million in the first six months of 2004,
primarily due to higher competitive business expenses resulting from business
growth ($31 million), higher reliability must run costs ($20 million), higher
regulated business administrative and general expenses ($15 million) due to
higher pension costs, higher fossil production expense ($3 million), and higher
nuclear related expenses as a result of the absence of the 2003 CL&P Millstone
use of proceeds docket ($2 million). That docket resulted in the recovery of
certain other operation costs and maintenance costs that were expensed in
periods prior to 2003. The recovery of these costs through the use of proceeds
docket resulted in credits to these accounts in the first quarter of 2003.
MAINTENANCE
Maintenance expenses increased $10 million in the first six months of 2004,
primarily due to higher competitive transmission expense ($6 million), the
absence of the 2003 positive resolution of the CL&P Millstone use of proceeds
docket ($5 million), and higher distribution expense ($3 million), partially
offset by lower fossil production expense ($3 million).
DEPRECIATION
Depreciation increased $10 million in the first six months of 2004 due to higher
Utility Group plant balances and higher depreciation rates at CL&P resulting
from the distribution rate case decision effective in January 2004.
AMORTIZATION
Amortization decreased $26 million in the first six months of 2004 primarily due
to lower Utility Group recovery of stranded costs and a decrease in amortization
expense resulting from the implementation of the CL&P distribution rate case
decision effective in January 2004 ($15 million).
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds increased $7 million in the first six
months of 2004 due to the repayment of additional principal as compared to 2003.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $8 million in the first six months of
2004 primarily due to higher Connecticut gross earnings tax as a result of an
increase in revenues for NU Enterprises, CL&P and Yankee Gas, higher local
property taxes, higher payroll taxes and higher sales tax.
INTEREST EXPENSE, NET
Interest expense, net increased $3 million in the first six months of 2004
primarily due to the issuance of $150 million of five-year notes at NU parent in
June 2003.
OTHER INCOME, NET
Other income, net increased $3 million in the first six months of 2004 primarily
due to the recognition beginning in 2004 of a CL&P procurement fee approved in
the TSO docket decision ($6 million) and a decrease in charitable contributions
($3 million), partially offset by investment impairments ($6 million).
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ITEM 4. CONTROLS AND PROCEDURES (RESTATED)
NU, CL&P, PSNH, and WMECO (collectively, the companies) evaluated the design and
operation of their disclosure controls and procedures at June 30, 2004 to
determine whether they are effective in ensuring that the disclosure of required
information is made timely and in accordance with the Exchange Act and the rules
and forms of the SEC. This evaluation was made under the supervision and with
the participation of management, including the companies' principal executive
officers and principal financial officer, as of the end of the period covered by
this report on Form 10-Q/A. The principal executive officers and principal
financial officer previously concluded, based on their review, that the
companies' disclosure controls and procedures were effective to ensure that
information required to be disclosed by the companies in reports that they file
under the Exchange Act (i) is recorded, processed, summarized, and reported
within the time periods specified in SEC rules and forms and (ii) is accumulated
and communicated to management, including the principal executive officers and
principal financial officer, as appropriate to allow timely decisions regarding
required disclosure.
On January 26, 2005, subsequent to the June 30, 2004 disclosure control and
procedures evaluation, it was determined that there was a material weakness in
NU's internal controls over financial reporting. This weakness relates to the
discovery, subsequent to the filing of the June 30, 2004 Form 10-Q, of an
accounting error in which certain natural gas basis contracts at NU's subsidiary
Select Energy were incorrectly accounted for on an accrual basis and certain
natural gas futures and swaps contracts were incorrectly accounted for as cash
flow hedges. This conclusion is based on the intent of these contracts to hedge
electricity contracts, the uncertainty as to if the contracts will result in
physical delivery, and the relationship of these contracts to the status of the
wholesale natural gas business. The controls and procedures that should have
prevented this error will be enhanced and include improved communications,
derivative documentation, reporting relationships, and other items.
This error resulted in the restatement of NU's condensed consolidated financial
statements as of and for the three and six month periods ended June 30, 2004,
and this Form 10-Q/A reflects the change from accrual and hedge accounting to
fair value accounting for the contracts described above. Because of these
restatements, NU's principal executive officer and principal financial officer,
following consultation with and approval of the Audit Committee of the Board of
Trustees, have now concluded that NU's disclosure controls and procedures were
not effective as of June 30, 2004.
The principal executive officer and principal financial officer of CL&P, PSNH,
and WMECO continue to believe that their disclosure controls and procedures were
effective to ensure that information required to be disclosed by CL&P, PSNH, and
WMECO in reports that they file under the Exchange Act i) is recorded,
processed, summarized, and reported within the time periods specified in SEC
rules and forms and ii) is accumulated and communicated to management, including
the principal executive officer and principal financial officer, as appropriate
to allow timely decisions regarding required disclosure.
There were no significant changes in the companies' internal controls over
financial reporting during the quarter ended June 30, 2004 that have materially
affected, or are reasonably likely to materially affect the companies' internal
controls over financial reporting. Changes to address the material weakness
described above were not yet implemented at June 30, 2004.
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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Listing of Exhibits (NU)
Exhibit No. Description
----------- -----------
31 Certification of Charles W. Shivery, Chairman, President
and Chief Executive Officer of Northeast Utilities, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002, dated March 15, 2005
31.1 Certification of David R. McHale, Senior Vice President
and Chief Financial Officer of Northeast Utilities, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002, dated March 15, 2005
32 Certification of Charles W. Shivery, Chairman, President
and Chief Executive Officer of Northeast Utilities and
David R. McHale, Senior 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 March 15, 2005
(b) Reports on Form 8-K:
NU filed a current report on Form 8-K dated May 19, 2004 disclosing:
o The issuance of a news release relating to a decision by the court hearing
its merger litigation with Con Edison.
NU and PSNH filed current reports on Form 8-K dated July 14, 2004 disclosing:
o The filing with the NHPUC of a settlement among several parties with
regards to its delivery service rate case.
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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: March 15, 2005 By /s/ David R. McHale
---------------------------------
David R. McHale
Senior Vice President
and Chief Financial Officer
(for the Registrant and as
Principal Financial Officer)
67