ML20198F851
| ML20198F851 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 12/16/1998 |
| From: | Feigenbaum T NORTH ATLANTIC ENERGY SERVICE CORP. (NAESCO) |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| Shared Package | |
| ML20198F859 | List: |
| References | |
| AR-97001187-02, AR-97001187-2, NYN-98138, NUDOCS 9812280232 | |
| Download: ML20198F851 (2) | |
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""'N* North Atlantic Energy Service Corporation North m ii- 3*
seabroot, N1103ti;4 A1 nktflIIIlO (603) 474-932!
. The Northeast Utilities Sptem December 16,1998 Docket 50-443 NYN-98138 AR 97001187-02 United States Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 Seabrook Station Guarantees of Parments of Deferred Premiums Pursuant to 10CFR 140.21(e), North Atlantic Energy Service Corporation (North Atlantic), on
' behalf of the licensees named in Facility Operating License NPF-86, provides herewith, the Annual Reports for 1997. The Annual Reports provided below demonstrate the collective ability of the licensees to meet their obligation for payment of deferred premiums.
Annual Reports for 1997 (containing certified fmancial statements) are enclosed for the following:
- North Atlantic Energy Corporation e Connecticut Light and Power i e The United Illuminating Company f e Massachusetts Municipal Wholesale Electric Company
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e New England Power Company e Commonwealth Energy System (for subsidiary Canal Electric Company) e Eastern Utilities Associates (for subsidiary Montaup Electric Company) yU [
. New llampshire Electric Cooperative, Inc.
- Taunton Municipal Lighting Plant e Hudson Light and Power Department
- Bay Corp Ho< dings, LTD. (for subsidiary Great Bay Power Corporation) l In addition, the Agreement of Joint Ownership, Construction and Operation of New Hampshire Nuclear Units, dated May 1,1973 as amended, and specifically the provisions of Paragraph 10.1, as amended by the Eighteenth Amendment, dated March 14,1986,is incorporated by reference.
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9812290232 98121E PDR ADOCK 05000443 I PDR g W _ >
U.S. Nuclear Regulatory Commission NYN-98138 / Page 2 The enclosed annual reports are submitted pursuant to 10 CFR 50.71 (b).
Should you have any questions regarding this matter, please contact Mr. Terry L. Ilarpster, Director of Licensing Services, (603) 773-7765.
Very truly yours, NORTli ATLANTIC ENERGY SERVICE CORP.
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AMAct um
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- ed C. Feigenba[
Executive Vico-! resident and Chief Nuclear OfIncer j l
cc (without enclosures): l L l
- 11. J. Miller, NRC Regional Administrator
, J. T. liarrison, NRC Project Manager, Project Directorate 1-3 i R. K. Lorson, NRC Senior Resident Inspector L l l
cc:(with enclosures):
United States Nuclear Regulatory Commission Attention: Director of Nuclear Reactor Regulation Washington, DC 20555
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, Wad,'%ie p"m, v uQ, , r "%g ,,
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t Directors Officers John H. Forsgren Michael G. Morris Deborah L. Canyock ,
- Executive Vice President and Chairman Assistant Controller-Chief Financial Officer Management Information and Bruce D. Kenyon Budgeting Services +
Bruce D. Kenyon President and President and Chief Executive Omcer Lori A. Mahler l Chief Executive Officer . Assistant Controller- .
Ted C. Feigenbaum
"' "" 8 .##8 Michael G. Morris Executive Vice President and Chairman Chief Nuclear Omcer Michael J. Mahoney John H. Forsgren Assistant Controller-Rate Regulation Executive Vice President and Chief Financial Omeer Theresa H. Allsop ,
Assistant Secretary Cheryl W. Gris6 SeniorVice President and Robert A.Bersak Chief Administrative Omcer Assistant Secretary .
Sen.ior~Vice President. Secretary O. Kay Comendul i
g,;
and General Counsel Roben C. Aronson
- John B. Keane Assistant Treaserer-Vice President and Treasurer Tmury Operations John J. Roman David TL McHale Vice President and Controller . Assistant Treasurer-Finance Dennis E. Welch Vice President-Environmental.
Safety and Ethics i
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i February 281998 l l
1997 Annual Report North Atlantic Energy Corporation Index Contents Pace
-Balance Sheets.............................................. 2 Statements of Income........................................ 4
' Statements of Cash Flows.................................... 5 Statements of Common Stockholder's Equity................... 6 Notes to Financial Statements............................... 7 Report of Independent Public Accountants.................... 24 Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 26 Selected Financial Data...... .............................. 32 Statistics.................................... ............. 32 Statements of Quarterly Financial Data...................... 32 Bondholder Information..................................... Back Cover 4
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PART I. FINANCIAL INFORMATION e NORTH ATIKITIC ENERGY CORPORATION BALANCE SHEETS At December 31, 1997 1996 (Thousands of Dollars) >
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ASSETS Utility Plant, at original cost:
Electric (Note 1G)..... ................................ $ 779,111 $ 775,794 Less: Accumulated provision for depreciation......... 143,778 124,530 635,333 651,264 Construction work in progress.. .......... ... ...... .. 4,616 8,887 Nuclear fuel, net............. ......................... 27,413 31,765 Total net utility plant............. ............... 667,362 691,916 Other Property and Investments:
Nuclear decommissioning trusts, at market.. ............ 26,547 19,744 26,547 19,744 Current Assets:
Cash............................... .................... 13 299 Special deposits........................................ - 7,039 Receivables from affiliated companies................... 25,695 16,422 Taxes receivable........ .................... .......... 4,613 -
Materials and supplies, at average cost................. 13,003 13,093 Prepayments and other...... ................. .......... 4,220 4,302 47,544 41,155 Dsferred Charges:
Regulatory assets (Note 1H)........ .................... 269,484 259,881 Unamortized debt expense. .............................. 3,702 4.692 273,186 264,573 Total Assets..... ............ ..................... $ 1,014,639 $ 1,017,388 Tha accompanying notes are an integral part of these financial statements.
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, NORTH ATLANTIC ENERGY CORPORATION 6
BALANCE SKEETS At December 31, 1997 1996 l (Thousands of Dollars)
CAPITALIZATION AND LIABILITIES l
Ccpitalization:
l Common stock..$1 par value. Authorized end outstanding 1,000 shares.......................... $ 1 $ 1 Capital surplus, paid in................................ 160,999 160,999
.R2tained earnings....................................... 58,702 53,749 Total common stockholder's equity.............. 219,702 214,749 Long-term debt.......................................... 475,000 495,000 -
Total capit_ ization.. ........ ................ 694,702 709,749
!-CurrantLiabilities:
l Notes payable to affiliated company..................... 9,950 2,500 Long-term debt--current portion......................... 20,000 20,000 Accounts payable........................................ 7,912 20,714 Accounts payable to affiliated companies................ 6,040 5,073
! Accrued interest......................................... 3,025 2,888 ,
Accrued taxes .......................................... . 3,486 l Othar................................................... 1,055 271 1 47,982 54,932 L
i Deferred Credits:
Accumulated deferred income taxes......................, 216,701 196,650 Deferred obligation to affiliated company (Note 6)...... 32,472 33,284
,Othsr................................................... 22,782 22,773 J
271,955 252,707 l I
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. , Commitments and Contingencies (Note 7)- !
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~ Total Capitalization and Liabilities........... $ 1,014,639 $ 1,017,388 j
! Tha'eccompanying notes are an integral part of these financial statements.
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NORTH ATIANTIC ENERGY CORPORATION STATEMENTS OF INCOME For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars)
Operating Revenues................................. $ 192,381 $ 162,152 $ 157,183 Operating Expenses:
Oper.a't <.,n - -
Fuel.......................................... 13,405 15,013 12,030 Other................... .................... 39,091 34,356 36,737 Maintenance. ...................... ............. 24,146 9,154 12,442 Depreciation........... ......................... 25,170 24,056 23,406 Amortization of regulatory assets, net........... 6,270 - -
Federal and state income taxes (Note 5). ........ 14,845 12,341 10,187 Taxes other than income taxes.................... 12,393 1:',343 10,987 Total operating expenses.......... . ...... 135,320 107,263 105,789 Operating Income................................. . 57,061 54,889 51,394 Other Income:
Deferred Seabrook return--other funds.... ....... 7,205 7,700 9,405 Other, net............... .. ............... .... (747) 1,200 1,556 Income taxes......... ............. ............. 4,394 5,052 2,776 Other income, net.......................... 10,852 13,952 13,737 Income before interest charges............. 67,913 68,841 65,131 Interest Charges:
Interest on long-term debt............. ......... 50,722 52,414 62,721 Other interest........... ..... ................. 649 (697) (519)
Deferred Seabrook return--borrowed funds......... (13,411) (14,948) (21,512)
Interest charges, net........ ............. 37,960 36,769 40,690 Net Income.......... . ............... . ..... .. $ 29,953 $ 32,072 $ 24,441 The accompanying notes are an integral part of these financial statements.
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t NORTH ATLANTIC ENERGY CORPORATION
- STATEMENTS OF CASH FIDWS Per the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars) ;
Operating Activities:
Net Income.................................................. $ 29,953 $ 32,072 $ 24,441 Adjustments to reconcile to net cash from operating activities
- Depreciation.............................................. 25,170 24,056 23,406 Amortization of nuclear fuel.............................. 10,705 11,668 9,183 Deferred income taxes and investment tax credits, net..... 22,649 15,749 46,114 :
< Deferred return - Seabrook................................ (20,616) (22,648) (30,917) sale of seabrook 2 steam generator........................ -
20,931 -
loss on reacquired debt.................................. - - (31,886)
Other sources of cash...................................... 11,052 9,175 2,957 Other uses of cash........................................ (2,224) (2,582) (3,375)
Changes in working capital:
Receivables............................................... (9,273) 2,270 (4,709)
Materials and supplies.................................... 90 (824) (2,233)
Accounts payable................... ...................... (11,835) 19,509 2,167
-Accrued taxes............................................. (3,486) 2,140. (93)
Cther working capital (excludes cash) . . . . . . . . . . . . . . . . . . . . . 3,429 (7,675) (12,161)
I Net cash flows from operating activities.............. ....... 55,614 103,841 22,894 Financing Activities:
Icauance of long-term debt.................................. - - 225,000
, Net increase /(decrease) in short-term debt.................. 7,450 (5,500) 8,000 L Rs.cquisitions and retirements of long-term debt............ (20,000) (45,000) (225,000) l Cash dividerds on comon stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (25,000) (38,000) (24,000)
(37,550)
Het cash flows used for financing activities.................. (88,500) (16,000)
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Investment Activities:
l Investment in plante l Electric utility plant.................................... (6,606) (5,921) (6,906)
Nuclear' fuel.............................................. (6,147) (15,752) (16,609)
Net cash flows used for investments in plant................ (12,753) (21,673) (23,515)
NU System Money Pool........................................ - 2,500 26,250 Investment in nuclear decomissioning trusts. . . . ........... (5,597) (4,404) (3,824)
'Other investment activities, net............................ . 222 -
Net cash flows used for investments........................... (18,350) (23,355) (1,089) l ........... ........... ...........
Net (Decrease) / Increase In Cash For The Period. . . . . . . . . . . . . . . . (286) (8,014) 5,805 Ca.% - beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299 8,313 2,508'
. Cnsh - end of pe riod . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 13 $ 299 $ 8,313
- Supplemental Cash Flow Information:
' Cath paid /(refunded) during the year for:
Interest, net of amounts capitalf zed. . . . . . . . . . . . . . . . . . . . . . . . $ 45,297 $ 46,322 $ 73,923 l~ ' Income taxos................................................ $ - $ (13,160) $ (36,679)
, .The ceconpanying notes are an integral part of these financial statements.
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NORTH ATLAh'rIC ENERGY CORPORATION STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Capital Retained Common Surplus, Earnings Stock Paid In (a) Total (Thousands of Dollars)
Balcnce at January 1, 1995 ............. $ 1 $ 160,999 $ 59,236 $ 220,236 Net income for 1995........ .. ..... 24,441 24,441 Cash dividends on common stock...... (24,00's) (24,000) 1 Bnlance at December 31, 1995.. ... .... 1 160,999 59,677 220,677 Net income for 1996......... ... .. 32,072 32,072 Cash dividends on common stock... .. (38,000) (38,000)
Balance at December 31, 1996............ 1 160,999 53,749 214,749 Net income for 1997.. . ............ 29,953 29,953
- Cash dividends on common stock...... (25,000) (25,000) l __........ .......... ....._... ......_...
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-Balence at December 31, 1997............ $ 1 $ 160,999 $ 50,702 $ 219,702 l
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l i (a) All retained earnings are available for distribution, plus an allowance of
$10 million.
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The accompanying notes are an integral part of these financial statements.
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North Atlantic Energy Corporation NOTES TO FINANCIAL STATEMENTS
- 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES I A. About North Atlantic Energy Corporation North Atlantic Energy Corporation (NAEC or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Holyoke Water Power Company (HWP), are the ope *;ating subsidiaries comprising the Northeast Utilities system (t he NU system) and are wholly owned by Northeast Utilities (hU).
The NU system furnishes franchised retail electric service in Connecticut, New Hampshire, and western Massachusetts thicough CL&P, PSNH, WMECO, and HWP. NAEC sells all of its entitlement to the capacity and output of the Seabrook nuclear power plant, (Seabrook, a 1,148-megawatt nuclear generating unit) to PSNH.
In addition to its franchised retai] service, the NU system furnishes firm and other wholesale electric services to various municipalities and other utilities, and participates in limited retail access programs, providing off-system retail electric service. The NU system serves about 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues.
Other wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilitics. Northeast Utilities Service Company (NUSCO) provides. centralized accounting, administrative, information resources, engineering, financial, , legal, operational, planning, purchasing and other companies. serviks to the NU system North Atlantic Energy Service'.Gorporation (NAESCO) acts as agent for NAEC and CL&P and .has operational responsibility for Seabrook. Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear generating facilities.
B. Presentation
.The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years ' data have been made to conform with-the current year's presentation.
All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return l on equity and are subject to approval by various federal and !
state regulatory agencies.
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North Atlcntic Energy Corporation NOTES TO FINANCIAL STATEMENTS C. Public Utility Regulation NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and it and its subsidiaries, including NAEC, are subject to the provisions of the 1935 Act.
Arrangements among the NU system companies, outside agencies aa i other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. NAEC is subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions.
For information regarding proposed changes in the nature of industry regulation, see Note 7A, " Commitments and Contingencies - Restructuring and Rate Matters."
D. New Accounting Standards The Financial Accounting Standards Board (FASB) issued a new accounting standard in February 1997: Statement of Financial Accounting Standards (SFAS) 129, " Disclosure of Information about Capital Structure." SFAS 129 establishes standards for disclosing information about an entity's capital structure.
NAEC's current disclosures are consistent with the requirements of SFAS 129.
During June 1997, the FASB issued SFAS 130, " Reporting Comprehensive Income." SFAS 130 establishes standards for the reporting and disclosure of comprehensive income. To date, NAEC has not had material transactions that would be required to be reported as comprehensive income. Management believes that the implementation of SFAS 130 will not have a material impact on NAEC's current disclosures.
E. Jointly Owned Electric Utility Plant NAEC has a 35.98 percent joint-ownership interest in l Seabrook which includes the 0.4 percent ownership interest in Seabrook 1 which NAEC acquired from Vermont Electric Generation and Transmission Cooperative in February 1994. NAEC sells all of its share of the power generated by Seabrook to PSNH under two long-term contracts (the Seabrook Power Contracts) . As of December 31, 1997 and 1996, plant-in-service included approximately $723.2 million and $718.7 million, respectively, and the accumulated provision for depreciation included ;
approximately $116.1 million and $102.0 million, respectively, j for NAEC's share of Seabrook 1. NAEC's share of Seabrook 1 expenses is included in the corresponding operating expenses on the accompanying Statements of Income. ,
F. Depreciation The provision for depreciation is calculated using the ;
straight-line method based on estimated remaining lives of 8
North Atlcntic Energy Corporation l
NOTES TO FINANCIAL STATEMENTS depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate l regulatory agency. Except for major facilities, depreciation
! rates are applied to the average plant-in-service during the l period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.5 percent in 1997, 3.4 percent in 1996 and 3.3 percent in 1995. See Note 2, " Nuclear Decommissioning," for additional information on nuclear plant decommissioning.
G. Seabrook Power Contracts PSNH and NAEC have entered into two power contracts that obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook 1 for the term of Seabrook l's Nuclear Regulatory Commission (NRC) operating license. Under j these contracts, PSNH is obligated to pay NAEC's cost of l service during this period, regardless if Seabrook 1 is operating. NAEC's cost of service includes all of its Seabrook-related costs, including operation and maintenance (O&M) expenses, fuel expense, income and property tax expense, '1 depreciation expense, certain overhead and other costs and a return on its allowed investment. j i
The Seabrook Power Contracts established the value of the initial investment in Seabrook (initial investment) at $700-million. As prescribed by the 1989 rate agreement with the State of New Hampshire (Rate Agreement), as of May 1, 1996, NAEC phased into rates 100 percent of the recoverable portion of its investment in Seabrook 1. From June 5, 1992 (the date NU acquired PSNH and NAEC acquired Seabrook 1 from PSNH - the Acquisition Date) through November 1997, NAEC recorded $203.9 million of deferred return on its investment in Seabrook 1. At November 30, 1997, NAEC's utility plant included $84.1 million of deferred return that was transferred as part of the Seabrook plant assets to NAEC on the Acquisition Date. Beginning on December 1, 1997, the deferred return, including the portion transferred to NAEC is currently being billed through the Seablook Power Contracts to PSNH, and will be fully recovered from customers by May 2001. NAEC is depreciating its initial investment over the term of Seabrook l's operating license (39 years), and any cubsequent plant additions are depreciated on a i straight-line basis over the remaining term of the Seabrook
- j. Power Contracts at the time the subsequent additions are placed in service.
i l If Seabrook 1 is shut down prior to the expiration of the NRC operating license, PENH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook 1 has operated. These termination costs will reimburse NAEC for its share of Seabrook 1 shut-down and l 9
North Atlantic Energy Corporation NOTES TO FINANCIAL STATEMENTS decommissioning costs, and will pay NAEC a return of and on any undepreciated balance of its initial investment over the remaining term of the Seabrook Power Contracts, and the return of and on any capital additions to the plant made after the Acquisition Date over a period of five years after shut down (net of any tax benefits to NAEC attributable to the ;
cancellation).
H. Regulatory Accounting and Assets The accounting policies of the company and the accompanying financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, " Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of- service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators also may reduce or eliminate the value of an asset, or create a liability. If any portion of the company's operations no longer were subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off all of its related regulatory assets and liabilities unless there is a formal transition plan which provides for the recovery, through established rates, for the collection of approved stranded costs and to maintain the cost-of-service basis for the remaining regulated operations. At the time of transition, NAEC would be required to determine any impairment to the carryir _, costs of deregulated plant and inventory assets.
The issue of restructuring the electric utility industry in New Hampshire is currently the focus of negotiations and proceedings within the federal and state court systems. The outcome of these court proceedings will impact NAEC due to NAEC's contractual relationship with PSNH through the Seabrook Power Contracts. However, management believes that NAEC's use of regulatory accounting remains appropriate while this issue remains in litigation.
For more information on NAEC's regulatory environment and the potential impacts of restructuring, see Note 7A, " Commitments and Contingencies Restructuring an( Rate Matters," and Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
SFAS 121, " Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the evaluation of long-lived assets, including regulatory assets,
! for impairment when certain events occur or when conditions l exist that indicate the carrying amounts of assets may not be l
recoverable. SFAS 121 requires that any long-lived assets I which are no longer probable of recovery through future l 10
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NOTES TO FINANCIAL STATEMENTS revenues be revalued based on estimated future cash flows. If this revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. SFAS 121 did not l have a material impact on the company's financial position or l results of operations as of December 31, 1997. Management continues to believe that it is probable that the company will recover its investments in long-lived assets through future revenues. This conclusion may change in the future as the implementation of restructuring plans within New Hampshire will subject NAEC to competitive market conditions. As a 3 result, NAEC will be required to assess the carrying amounts l of its long-lived assets in accordance with SFAS 121. l l
The cornonents of NAEC's regulatory assets are as follows:
At December 31, 1997 1996 (Thousands of Dollars)
Deferred costs-Seabrook 1 (Note 1K) ..... .................... $199,753 $185,078 Income taxes, net (Note.11) .......... 48,736 47,185 Recoverable energy costs (Note 1J) ... 2,057 2,217 ,
Unamortized loss on reacquired '
debt............................... 18.938 25,401
$269,484 $259,881 I. Income Taxes The tax effect of temporary differences (differences between I the periods in which transactions affect income in the financial statements and the periods in which they af fect the determination'of taxable income) is accounted for in accordance with the ratemaking treatment of the applicable regulatory I commissions. See Note 5, " Income Tax Expense" for the components of income tax expense.
The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows:
At December 31, 1997 1996 (Thousands of Dollars)
Accelerated depreciation and other plant-related differences.... .$159,251 $136,234 Regulatory assets - income tax gross up........................... 17,094 16,516 Other................................ 40,356 43,900 j S216,701 $196,650
'J. Recoverable Energy Costs j Under the Energy Policy Act of 1992 (Energy Act), NAEC is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants 11
North Atlcntic Energy Corporation NOTES TO FINANCIAL STATEMEN_TS owned by the United States Department of Energy (D&D assessment) The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates, like any other fuel cost. NAEC is currently recovering these costs through the Seabrook Power Contracts. As of December 31, 1997, NAEC's total D&D deferral was approximately $2.0 million.
K. Deferred Cost - Seabrock 1 As presc _lbed by the Rate Agreement as of May 1, 1996, NAEC phased into rates 100 percent of the recoverable portion of its investment in Seabrook 1. This plan is in compliance with SFAS 92, " Regulated Enterprises - Accounting for Phase-In Plans." See Note 1G, " Summary of Significant Accounting Policies Seabrook Power Contracts," for terms of Seabrook l's phase-in. See Note 7A, " Commitments. and Contingencies -
Restructuring and Rate Matters," for the possible impacts of the NHPUC's decision related to industry restructuring.
L. Market Risk-Management Policies NAEC utilizes market risk-management instruments to hedge '
well-defined risks associated with variable interest rates. l To qualify for hedge treatment, the underlying hedged item i must expose the company to risks associated with market fluctuations and the market risk-management instrument used must be designated as a hedge and must reduce the company's l exposure to market fluctuations throughout the period.
Amounts receivable or payable under interest-rate management instruments are accrued and offset against interest expense.
NAEC does not use market risk-management instruments for speculative purposes. For further information, see Note 8,
" Market Risk Management."
M. Spent Nuclear Fuel Under the Nuclear Waste Policy Act of 1982, NAEC must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on 1 or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis.
The DOE was originally scheduled to begin accepting delivery of spent fuel in 1998. However, delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. The company has primary responsibility for the interim storage of its spent nuclear fuel. Current capability to store spent fuel at Seabrook is estimated to be adequate until the year 2010. Meeting spent fuel storage 12
North Atlantic Enargy Corporation NOTES TO FINANCIAL STATEMENTS ,
l requirements beyond this period could require new and separate i been storage facilities, the costs for which have not determined.
In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled that the lack of an interim storage I facility does not excuse the DOE from meeting its contractual !
obligation to begin accepting spent nuclear fuel no later than l January 31, 1998. Currently, the DOE has not taken the spent ;
nuclear fuel as scheduled, and, as a result, may have to pay contract damages. The ultimate outcome of this legal proceeding is uncertain at this time.
- 2. NUCLEAR DECOMMISSIONING )
The Seabrook 1 nuclear power plant has a service life that is expected to end in the year 2026. Upon retirement, this unit must be decommissioned. A current decommissioning study concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning Seabrook 1.
Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology and inflation.
NAEC's 35.98 percent ownership of the estimated costs of decommissioning Seabrook 1, in year-end 1997 dollars, is $170.2 million. Seabrook 1 decommissioning costs will be increased annually by an escalation rate. Nuclear decommissioning costs are accrued over the expected service life of the unit and are included in depreciation expense on the Statements of Income. Nuclear decommissioning costs amounted to $4.5 million in 1997, $3.5 million in 1996, and $3.0 million in 1995. Nuclear decommissioning, i
as a cost of removal, is included in the accumulated provision for depreciation on the Balance Sheets. At December 31, 1997 and 1996, I the balance in the accumulated reserve for depreciation amounted to
$26.5 million and $19.7 million, respectively.
Under the terms of the Rate Agreement, PSNH is obligated to pay i NAEC's share of Seabrook l's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license.
NAEC's portion o' the cost of decommissioning Seabrook 1 is paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes escalated collections for Seabrook 1 and after-tax earnings on the Seabrook decommissioning fund of 6.5 percent.
As of December 31, 1997, NAEC (including payments made prior to the l Acquisition Date by PSNH) had paid approximately $21.1 million into Seabrook l's decommissioning financing fund. Earnings on the decommissioning financing fund increase the decommissioning trust balance and the accumulated reserve for depreciation. Unrealized gains and losses associated with the decommissioning financing fund also impact the balance of the trust and the accumulated reserve for depreciation.
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1 North Atlantic Energy Corporation NOTES TO FINANCIAL STATEMENTS ]
1 Changes in requirements or technology, the timing of funding or l dismantling, or adoption of a decommissioning method other than l immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. PSNH attempts to recover i sufficient amounts through its allowed rates to cover NAEC's l expected decommissioning costs. Only the portion of currently I estimated total decommissioning cost that has been accepted by regulatory agencies is reflected in PSNH's rates. Based on present estimates and assuming Seabrook 1 operates to the end of its licensing period, NAEC expects that the decommissioning financing fund will be substantially funded when seabrook 1 is retired from service.
Proposed Accounting: The staff of the SEC has questioned certain -
current accounting practices of the electric utility industry, including NAEC, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in the financial statements. In response to these questions, the FASB has agreed to review the accounting for closure and removal costs, including decommissioning. If current electric utility industry accounting practices for nuclear power plant decommissioning are changed, the annual provision for decommissioning could increase relative to 1997, and the estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation), with recognition of an increase in the cost of the related nuclear power plant. Management believes that NAEC will continue to be allowed to recover decommissioning costs through the Seabrook Power Contracts.
- 3. SHORT-TERM DEBT The amount of short-term borrowings that may be incurred by NAEC is subject to periodic approval by either the SEC under the 1935 Act or by its state regulator. Under the SEC restrictions, NAEC was authorized, as of January 1, 1998, to incur short-term borrowings up to a maximum of $60 million.
Money Pool: Certain subsidiaries of NU, including NAEC, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the j system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow.
- Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate.
However, borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU ,
parent's original borrowing. Effective during May 1997, NAEC l became a full participant of the NU Money Pool. At December 31, 1997 and 1996, NAEC had $9.95 million and $2.5 million, I respectively, of borrowings outstanding from the Pool. The 14
North AtlEntic Enargy Corporation NOTES TO FINANCIAL STATEMENTS interest rate on borrowings from the Pool at December 31, 1997 and 1996 was 5.8 percent and 6.3 percent, respectively.
Maturities of NAEC's short-term debt obligations were for periods of three months or less.
For further information on short-term debt, see the MD&A.
- 4. LONG-TERM DEBT Details of long-term debt outstanding are:
December 31, 1997 1996 (Thousands of Dollars)
First Mortgage Bonds:
9.05% Series A, due 2002.. ........ $295,000 $315,000 Notes:
Variable - Rate Facility, due 2000 200,000 200,000 j Less: Amounts due within one year.. 20,000 20,000 i Long-term debt, net......... $475,000 $495,000 Long-term debt maturities and cash sinking-fund requirements on ,
debt outstanding at December 31, 1997 is $20 million for the year ;
1998, $70 million for 1999, $270 million for 2000, $70 million for 2001, and $65 million for 2002.
Market risk management instruments with financial institutions effectively fix the interest rate on NAEC's $200 million variable-rate bank note at 7.823 percent. For more information on the interest-rate management instruments, see Note 8, " Market Risk Management."
The Series A Bonds are not redeemable prior to maturity except out of proceeds et sales of property subject to the lien of the Series l A First Mortgage Bond Indenture (Indenture), at general redemption I prices established by the Indenture, and out of condermtation or l
insurance proceeds and through the operation of the sinking fund.
Essentially all of NAEC's utility plant is subject to the lien of its Indenture.
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_- . _-.m .m._.. _m._ . _ _ .. _ - ~ . . _ . _ . _ __....._. _ _ . ..... _ _ . ,
t North Atlantic. Energy Corporation NOTES TO FINANCIAL STATEMENTS i L
- 5. INCOME TAX EXPENSE l The: components of the federal and state income tax provisions !'
charged.to operations are:
+
For the Years' Ended December 31, 1997 1996 1995 :
(Thousands of Dollars) !
Current income taxes:
Fe de ral . . . . . . . . . . . . . . . . . . . . . . $ ( 11, 8 9 0 ) $ (8,570) $ (3 8,703 ) .
State....... . ............... (309) 110 -
Total' current . . ............... (12,199) (8,460) (38,703)
Deferred income taxes, net:
Federal....................... 21,528 14,884 41,885 State......................... 1,121 865 4,229 Total deferred............. 22.649 15,749 46,114 Total income tax expense... $10,450 $ 7,289 $ 7,411 The components of total income tax expense are classified as >
follows:
L For the Years Ended December 31, 1997 1996 1995 ;
i (Thousands of Dollars) l Income' taxes charged-to operating expenses........ . ........... $14,844 $12,341 $10,187 l l
Other income taxes............. (4,394) (5.052) (2,776)
Total income tax expense..... $10,450 $ 7,289 $ 7,411 Deferred income taxes are comprised of the tax effects of ,
r L temporary differences as follows:
'For the Years Ended December-31, 1997 1996 1995 (Thousands of Dollars) o .
Depreciation..... . . ........... $20,823 $12,730 $24,444 Alternative minimum tax........ - - -
Bond redemptions... ........... (2,351) (2,359) 12,087 ;
Seabrook 1 return.............. 3,338 5,438 8,109 '
Other..... .................... 839 (60) 1,474 j' Deferred' income taxes, net. $22,649 $15,749 $46,114 l
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. . . . _ - - . . . ~ - . ..- . . -. . - . . . - - . ~ . .-_. .-. . . - .
North Atlantic Energy Corporation NOTES TO FINANCIAL STATEMENTS A reconciliation. between income tax expense and the expected tax expense at the applicable statutory rate is as follows:
For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars) +
Expected federal income tax at 35 percent of pretax income ............... $14,141 $13,776 $11,148 Tax effect of differences:
Depreciation................. - (1, 04 9 ) (1,343) (2,159) '
Deferred Seabrook 1 return... (2,522) (2,695) (3,292)
State-income taxes, ,
net of federal benefit..... 718 634 2,749 Sale of Seabrook 2 steam generator............. .... . -
(2,516) -
Other, net..................... (833) (567) _(1.035) l Total income tax expense....... $10,450 $ 7,289 $ 7,411
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- 6. DEFERRED OBLIGATION TO AFFILIATED COMPANY f At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with the phase-in under the Rate Agreement, it began !
accruing. a deferred return on the unphased-in' portion of its Seabrook l' investment. From May 16, 1991 to the Acquisition Date,
-PSNH accrued a deferred return of $50.9 million. On the Acquisition Date, PSNH transferred the $50.9 million deferred ;
return to NAEC as part of the Seabrook-related assets.
At the time PSNH transferred the deferred return to NAEC, it i realized, for income tax purposes, a gain that is deferred under '
the consolidated income tax rules. Beginning December 1, 1997, ,
this gain is being restored for income tax purposes as the deferred I return of $50.9 million, and the associated income taxes' of
$33.2 million, are collected by NAEC through the Seabrook Power Contracts. As NAEC recovers the $33.2 million in years eight through ten of the Rate Agreement, it will be obligated to make corresponding: payments to PSNH.
See Note 1G, "reabrook Power Contracts" for further information on the phase-in of the Seabrook power plant and see Note 7A,
" Commitments and Contingencies - Restructuring and Rate Matters" for the possible impacts on NAEC from the NHPUC's decision related to industry restructuring.
- 7. COMMITMENTS AND CONTINGENCIES A. Restructuring and Rate Matters
]
New Hampshire: The 1996 restructuring legislation that the l NHPUC is charged-with implementing provides that the NHPUC may not-adopt a restructuring plan that imposes a severe financial
-hardship - on a utility. Management believes that PSNH is entitled .to full recovery of its prudently incurred costs, 17
l North Atlentic Energy Corporation I
NOTES TO FINANCIAL STATEMENTS including regulatory assets and strandable costs. It bases this belief both on the general nature of public utility industry cost-of-service based regulation and the specific circumstances of the resolution of PSNH's previous bankruptcy proceedings and its acquisition by NU, including the recoveries provided by the Rate Agreement and related agreements.
l
- On February 28, 1997, the NHPUC issued its decision related to restructuring the state's electric utility industry and setting interim stranded cost charges for PSNH pursuant to legislation enacted in New Hampshire in 1996. In the decision,
, the NHPUC announced a departure from cost-based ratemaking and l instead adopted a market-priced approach to ratemaking and stranded cost recovery. Accordingly, unless the NHPUC modifies its position or the litigation described below results in necessary modifications to the final plan which leads management to conclude that the ratemaking approach utilized in the NHPUC's restructuring decision will not go into effect, PSNH no longer will be subject to the provisions of SFAS 71. That would result in PSNH writing off from its i
balance sheet substantially all of its regulatory assets. The amount of the potential write-off triggered by the order is currently estimated at over $400 million, after taxes. PSNH
- does not believe that under the decision, it would be required to recognize any additional loss resulting from the impairment of the value of its other long-lived assets under the provisions of SFAS 121.
! On March 3, 1997, PSNH, NU, NAEC and NUSCO filed for a
- temporary restraining order, preliminary and permanent injunctive relief and for declaratory judgment in the United l States District Court for New Hampshire (District Court).
The case was subsequently transferred to Rhode Island. On March 10, 1997, the Chief Judge of the Rhode Island federal
, court issued a temporary restraining order which stayed the ,
1997 NHPUC's February 28, decision to the extent it established a rate setting methodology that is not designed to recover PSNH's costs of providing service and would require PSNH to write off any regulatory assets.
During 1997, a mediation process ended without a resolution.
The District Court has suspended the procedural schedule associated with this court proceeding pending the resolution ,
of appeals of certain preliminary rulings by the U.S. Circuit Court of Appeals for the First Circuit (First Circuit). On February 3, 1998, the First Circuit denied the appeals taken by would-be intervenors in PSNH's federal court proceeding concerning the NHPUC's final plan on restructuring. The First Circuit affirmed a previous court decision stating that the opposing interests in this case were adequately represented by the NHPUC or by PSNH. As a result of this decision, the proceedings in the District Court may resume. On February 17, 1998, the NHPUC filed a petition for rehearing with the First 18 i
North Atlcntic Enorgy Corporation NOTES TO FINANCIAL STATEMENTS 1
Circuit. The temporary restraining order issued by the District Court in March 1997 will remain in effect until further orders by either court. j During 1997, the NHPUC reopened its proceeding to reconsider certain limited matters in its restructuring orders. The scope of the PSNH-specific re-hearing proceedings included alternative rate-setting methodologies proposed by the intervenors; to decide the appropriate methodology to be used to determine PSNH's interim stranded costs; and to set PSNH's
- interim stranded cost charges utilizing the determined methodology. In testimony filed with the NHPUC in November 1997, PSNH proposed a new methodology to quantify its strandable costs. Under this proposal, PSNH would divest all owned generation and purchased power obligations via auction.
To the extent that the auction fails to produce sufficient revenues to cover the net book value of owned generation and contractual payment obligations of purchased-power, ebe difference would be recovered from customers through a non-bypassable distribution charge. The new proposal also relies upon securitization of certain assets to further reduce rates.
On . December 15, 1997, the NHPUC officially announced that industry restructuring would not take place on January 1, 1998. Management believes that industry restructuring will not take place in New Hampshire until the courts resolve the issues brought before them, or the parties involved reach a sett.lement .
PSNH and NAEC are parties to a variety of financing agreements providing that the credit thereunder can be terminated or accelerated if they do not maintain specified minimum ratios of common equity to capitalization (as defined in each agreement). In addition, PSNH and NAEC are parties to a variety of financing agreements providing in effect that the credit thereunder can be terminated or accelerated if there are actions taken, either by PSNH or NAEC or by the state of New Hampshire, that deprive PSNH and/or NAEC of the benefits of the Rate Agreement and/or the Seabrook Power Contracts.
If the NHPUC's February 28, 1997 decision were to become effective, it would, unless PSNH and NAEC receive waivers from their respective lenders, result in (i) write-offs that would cause PSNH's common equity to fall below the contractual minimums (ii) reductions in income that would cause PSNH's income to fall below the contractual minimums, (iii) potential violation of the contractual provisions with respect to actions depriving PSNH and NAEC of the benefits of the Rate Agreement and (iv) the potential for cross defau%s to other PSNH and NAEC financing documents. Substantially all of PSNH's and NAEC's debt obligations would be affected.
If these events transpired and if the creditors holding PSNH and NAEC debt obligations decide to exercise their rights to 19
North Atlantic Energy Corporation NOTES TO FINANCIAL STATEMENTS demand payment, then either creditors or PSMH and NAEC could initiate proceedings under Chapter 11 of the bankruptcy laws.
As a result of the NHPUC decision and the potential consequences discussed above, the reports of our auditors on the individual financial statements of PSNH and NAEC contain explanatory paragraphs. Those explanatory paragraphs indicate that a substantial doubt exists currently about the ability of PSNH and NAEC to continue as going concerns. The accounts of PSNH and NAEC are included in the consolidated financial statements of NU on the basis of a going concern. While the effect of the implementation of that decision would have a material adverse impact on NU's financial position, results of operations, and cash flows, it would not in and of itself result in defaults under borrowing or other financial agreements of NU or its other subsidiaries.
B. Environmental Matters NAEC is subject to regulation by federal, state and local authorities with respect to air and water quality, the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. NAEC has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. However, the NU system is subject to certain pending enforcement actions and governmental investigation in the environmental area. Management cannot predict the outcome of these enforcement actions and investigations.
Environmental requirements could hinder future construction.
Changing environmental requirements could also require extensive and costly modifications to NAEC's existing investment in Seabrook 1 and could raise operating costs significantly. As a result, NAEC may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation of electricity and the storage, transportation, and disposal of by-products and wastes. NAEC may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot accurately be estimated.
I I
NAEC cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws and regulatory practices, management does not believe the matters disclosed above will have a material effect on NAEC's financial position or future results of operations.
C. Nuclear Insurance Contingencies Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities in the country covered by the 20
North Atlcntic Ensrgy Corporation 1 NOTES TO FINANCIAL STATEMENTS federal government's third-party liability indemnification program, an owner of a nuclear unit could be assessed in proportion to its ownership interest in each of its nuclear units up to $75.5 million. Payments of this assessment would be limited to $10.0 million in any one year per nuclear incident based upon the owner's pro rata ownership interest in l each of its nuclear units. In addition, the owner would be I subject to an additional five percent of $3.8 million, in proportion to its ownership interests in each of its nuclear ,
units, if the sum of all claims and costs from any one nuclear I incident exceeds the maximum amount of financial protection. l Based upon its ownership interest in Seabrook 1, NAEC's maximum 1 liability, including any additional assessments, would be $28.5 million per incident, of which payments would be limited to
$3.6 million per year. !
Insurance has been purchased to cover the primary cost of repair, replacement or decontamination or premature decommissioning of utility property resulting from insured occurrences at Seabrook station. NAEC is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against NAEC with respect to losses arising during the current policy year is approximately $2.6 million.
Insurance has been purchased to cover the excess cost of repair, replacement or decontamination or premature decommissioning of utility property resulting from insured 1 occurrences. NAEC is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. '
The maximum potential assessment against NAEC with respect to losses arising during current policy years is approximately
$3.8 million. The cost of a nuclear incident could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating I reactor operators insured under this coverage are subject to retrospective assessments of $3 million per reactor. The maximum potential assessment against NAEC with respect to losses arising during the crrrent policy period is approximately $1.1 million. Effective January 1, 1998, a new worker policy was purchased which is not subject to retrospective assessments.
Under the terms of the Seabrook Power contracts, ariv nuclear insurance assessments described above would be passed on to PSNH as a " cost of service."
21
^l North Atlantic Energy Corporation NOTES TO FINANCIAL STATEMENTS D. Seabrook 1 Construction Program The construction program for Seabrook 1 is subject to periodic review . and revision by management. NAEC currently forecasts !
construction' expenditures for its share of Seabrook 1 to be ,
(
$35.0.million for the years 1998-2002, including approximately l $8.9 million for 1998. In addition, NAEC estimates that its i share of Seabrook 1 nuclear fuel requirements will be approximately $51.5 million for the years 1998-2002, including
$12.9'million for 1998. F
- 8. MARKET RISK MANAGEMENT NAEC uses swap instruments with financial institutions to hedge against. interest rate risk associated with its $200 million
! variable rate bank note. The interest-rate management instruments employed eliminate the exposure associated with rising interest rates, and ef fectively fix the interest rate for this borrowing arrangement. Under the agreements, NAEC exchanges quarterly l payments based on a differential between a fixed contractual ,
i
- interest. rate and the three-month LIBOR rate at a given time. As I of December 31, 1997, NAEC had outstanding agreements with a total notional value of $200 .million and a positive mark-to-market position of approximately $104 thousand.
Credit Risk: These agreements have been made with various financial institutions, each of which is rated "A3" or better by Moody's rating group. NAEC will be exposed to credit risk on its respective market risk-management instruments if the counterparties fail to perform their obligations. However, management anticipates that the counterparties will be able to fully satisfy their obligations-under the agreements.
l 9. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value'of each of the following financial instruments:
Cash and nuclear decommissioning fund: The carrying amounts approximate fair value.
- .SFAS 115, " Accounting for Certain Investments in Debt and Equity Securitiec," requires investments in debt and equity securities to be presented at fair value. As a result of this requirement, the investments held .in NAEC's nuclear decommissioning fund were n- adjusted to market by approximately $1.5 million as of December 31, 1997 and adjusted to market by approximately $0.3 million as of
- December 31, 1996, with corresponding offsets to the accumulated
. provision for depreciation. The amounts adjusted in 1997 and 1996 represent cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for 1997 and 1996.
Long-term debt: The fair value of NAEC's fixed-rate security is based upon-the quoted market price for that issue or similar issue.
22
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North Atlcntic Ensrgy Corporation NOTES TO FINANCIAL STATEMENTS The adjustable rate security is assumed to have a fair value equal I to its carrying amount.
The carrying amounts of NAEC's financial instruments and the estimated fair values are as follows:
Carrying Fair At December 31. 1997 Amount Value (Thousands of Dollars)
First Mortgage Bonds.. .. ... ........... $295,000 $301,599 Other long-term debt..... . ......... ... $200,000 $200,000 Carrying Fair At December 31, 1996 Amount Value (Thousands of Dollars)
First Mortgage Bonds.... ........... .... $315,000 $316,197 Other long-term debt.............. ...... $200,000 $200,000 The fair values shown above have been reported to meet the disclosure requirements and do not purport to represent the amounts at which those obligations would be settled.
- 10. NUCLEAR PERFORMANCE The three Millstone units are managed by NNECO. Millstone 1, 2, and 3 have been out of service since November 4, 1995, February 21, 1996 and March 30, 1996, respectively, and are on the NRC's watch list. NU has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units.
Subsequent to its January 31, 1996 announcement that Millstone had been placed on its watch list, the NRC stated that the units cannot return to service until independent, third-party verification teams itave reviewed the actions taken to improve the design, configuration, and employee concerns issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to
! service in early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 is currently in extended maintenance status.
l 23
North Atlantic Energy Corporation REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of North Atlantic Energy Corporation:
We have audited the accompanying balance sheets of North Atlantic Energy Corporation (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1997 and 1996, and the related statements of income, common stockholder's equity, and cash flows for each of the 'three years in the period ended December 31, 1997. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion en these financial statements based on our audits.
We condt 4d our audits in accordance with generally accepted auditing standarda. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of North Atlantic Energy Corporation as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
I The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 7A, on February 28, 1997, the State of New Hampshire Public Utilities Commission (the NHPUC) issued an order outlining its final plan to restructure the electric utility industry. The final plan announced a departure from cost-based ratemaking for Public Service Company of New Hampshire (PSNH). PSNH is the sole customer of the Company. The final plan, if implemented, would require PSNH to discontinue the application of Financial Accounting Standard No. 71,
" Accounting for the Effects of Certain Types of Regula tion, " (FAS 71).
l The effects of such a discontinuation would cause PSNH and the Company to be in technical default under their current financial covenants, L which would, if not waived or renegotiated, give rise to the rights of lenders to accelerate the repayment of approximately $686 million of PSNH's indebtedness and approximately $495 million of the Company's I
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__________________A
'Narth Atlantic EnOrgy Corporotion REPORT OF I! DEPENDENT JUBLIC ACCOUNTANTS
<- indebtednesa. These conditions raise substantial doubt about the CG32
' Company's ability to continue as a going concern. The financial-statements. referred to above do not include any adjustments that might result from the outcome of this uncertainty.
s
/s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 20, 1998 f
25
North Atlantic Energy Corporation Management's Discussion and Analysis of Financial Condition and Results of Operations This section contains management's assessment of North Allantic Energy Corporation's (NAEC or the company) financial condition and the principal factors having an impact on the results of operations. The company is a wholly-owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with the company's financial statements and notes to financial statements.
FINANCIAL CONDITION Earnings Overview Public Service Company of New Hampshire (PSNH) and NAEC have entered into two power contracts that unconditionally obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook Unit 1 (Seabrook or the plant) for a period equal to the length of the Nuclear Regulatory Commission (NRC) full-power operating license for Seabrook (through 2026) whether or not Seabrook is operating and without regard to the cost of alternative sources of power (the Power Contracts) . In addition, PSNH will be obligated to pay decommissioning and project cancellation costs after the termination of the operating license. NAEC does not have any employees of its own and does not operate Seabrook. North Atlantic Energy Service Corporation (NAESCO) is the managing agent and represents the Seabrook joint owners, including NAEC, in the operation of the plant.
The company's cost-of-service includes all of its prudently incurred Seabrook-related costs, including operation and maintenance expense, fuel expense, property tax expense, depreciation expense, certain overhead and other costs and a phased-in return on its Seabrook investment.
The company's only assets are Seabrook and other Seabrook-related assets and its only source of revenues are the Power Contracts. PSNH's obligations under the Power Contracts are solely its own and have not been guaranteed by NU. The Power Contracts contain no provisions entitling PSNH to terminate its obligations. If, however, PSNH were to fail to perform its obligation under the Power Contracts, the company would be required to find other purchasers for Seabrook power.
A temporary restraining order issued by a U.S. District Court is currently blocking the New Hampshire Public Utilities Commission (NHPUC) from implementing a February, 1997 restructuring order that would have resulted in a write-off by PSNH of more than $400 million.
Management hopes to negotiate an alternative restructuring proposal in 1998 that will produce significant PSNH rate reductions and allow retail customers to choose their electric suppliers, but still give PSNH and NAEC an opportunity to maintain an adequate financial condition and earn fair returns on their investments.
NAEC had net income of approximately $30 million in 1997 compared to approximately $32 million in 1996. The decrease in net income for 26
1997 was primarily due to deferred tax benefits in 1996 associated with the proceeds from the sale of Seabrook Unit 2 steam generators, as well as lower earnings in temporary cash investments in 1997.
Liquidity and Capital Resources Cash provided from operations decreased by approximately $48 million in 1997, compared to 1996, as a result of the pay down of the 1996 year end accounts payable balance and proceeds in 1996 from the sale of the Seabrook Unit 2 steam generators. The year end accounts payable balance was relatively high due to purchases in preparation for the Seabrook outage that had been incurred but not yet paid by the i end of 1996. Cash used for financing activities decreased by approximately $51 million in 1997, compared to 1996, primarily due to lower reacquisitions and retirements of long-term debt, the utilization of the NU system money pool in 1997 and lower cash dividends on common stock. Cash used for investments decreased by approximately $5 million in 1997, compared to 1996, primarily due to lower 1997 nuclear fuel expenditures.
Each major subsidiary of NU finances its own needs. Neither The Connecticut Light and Power Company (CL&P) nor Western Massachusetts Electric Company (WMECO) has any financing agreements containing cross defaults based on financial defaults by NU, PSNH or NAEC. Similarly, neither PSNH nor NAEC has any financing agreements containing cross defaults based on financial defaults by NU, CL&P or WMECO. ;
Nevertheless, it is possible that investors will take negative operating results or regulatory developments at one company in the NU system into account when evaluating other companies in the NU System.
That could, as a practical matter and despite the contractual and legal separations among the NU companies, negatively affect each company's access to financial markets.
PSNH Restructuring In February, 1997, the NHPUC issued orders to restructure the state's electric utility industry and set interim stranded cost charges for PSNH. In the orders, the NHPUC announced a departure from cost-based ratemaking and adopted a market-priced approach to stranded cost recovery. PSNH, NU, NAEC and Northeast Utilities Service Company (NUSCO) filed for a temporary restraining order, preliminary and permanent injunctive relief and a declaratory judgment in the United States District Court of New Hampshire. The case subsequently was transferred to the United States District Court of Rhode Island (District Court) where a temporary restraining order was granted, staying, indefinitely, the enforcement of the NHPUC's restructuring orders as they affected PSNH. Certain appeals to the preliminary ruling have been denied and proceedings in the District Court are expected to resume.
The NHPUC conducted rehearing proceedings in 1997 to decide the appropriate methodology to be used to determine PSNH's interim stranded costs and to set PSNH's interim stranded cost charges utilizing the determined methodology. The NHPUC has not indicated when it will issue a decision in these proceedings. On December 15, 1997, the NHPUC officially announced that industry restructuring would not take place on January 1, 1998.
27
As part of the rehearing proceedings, PSNH proposed a new methodology to quantify its stranded costs. Under this proposal, PSNH would divest its owned generation and purchased power obligations via auction. To the extent that the auction fails to produce sufficient revenues to cover the net book value of owned generation and contractual payment obligations of purchased power, the difference would be recovered from customers through a non-bypassable distribution charge. The new proposal also relies upon securitization of certain assets to further reduce rates.
On February 20, 1998, PSNH forwarded a settlement offer to representatives from the state of New Hampshire that was consistent with PSNH's proposal in the rehearing proceedings, including among other things, a 20 percent rate reduction at the beginning of 1999, an auction of PSNH's non-nuclear generating units and securitization of approximately $1.15 billion of PSNH's stranded costs.
See the " Notes to Financial Statements", Note 7A, for the potential accounting impacts of restructuring.
Seabrook Performance Seabrook operated at a capacity factor of 78.3 percent through December 1997, compared to 96.8 percent for the same period in 1996.
The lower 1997 capacity factor is due primarily to the 50-day scheduled refueling and maintenance outage which began on May 10, 1997, and an unplanned outage which began on December 5, 1997. The unplanned outage occurred when the u. lit was shut down to repair leaks in a three inch stainless steel pipe in the residual heat removal system. The pipe was replaced, but problems were subsequently discovered in the control building air conditioning system. Design changes were implemented and the plant returned to service on January 16, 1998.
Seabrook Decommissioning NAEC's estimated cost to decommission its share of Seabrook is approximately $170 million in year end 1997 dollars. These costs are being recognized over the life of the unit with a portion currently being recovered through PSNH's rates. PSNH is obligated to pay NAEC's share of Seabrook's decommissioning costs even if the unit is shut '
down prior to the expiration of its license. As of December 31, 1997, the market value of the contributions already made to the decommissioning trusts, including their investment returns, was approximately $26 million.
See the " Notes to Financial Statements," Note 2, for further information on nuclear decommissioning.
Environmental Matters NAEC is potentially liable for environmental cleanup costs at a number of sites inside and outside its service territory. NAEC cannot estimate the potential liability for these costs or for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws and regulatory practices, management does not believe that these costs will have a 28
material effect on NAEC's financial position or future results of operations.
See the " Notes to Financial Statements" Note 7B, for further information on environmental matters.
Yonr 2000 Issue Tne Year 2000 issue exists because many computer systems and applications currently use two-digit date fields to designate a year.
As the change of the century occurs, date-sensitive systems may recognize the year 2000 as 1900, or not recognize it at all. This inabilie- recognize or properly treat the year 2000 may cause NU's systems .
?rocess critical financial and operational information incorrect 1, The company has assessed and continues to assess the impact of the Year 2000 issue on its operating and reporting systems.
The assessment of the nuclear operating systems is continuing and is expected to be completed in the summer of 1998.
The NU system will utilize both internal and external resources to reprogram, or replace, and test the software for Year 2000 modifications. The total estimated remaining cost of the Year 2000 project is estimated at $37 million and is being funded through operating cash flows. This estimate does not include any costs for the replacement or repair of equipment or devices that may be identified during the assessment process. The majority of these costs will be expensed as incurred over the next two years. To date, the NU system has incurred and expensed approximately $4 million related to the assessment of, and preliminary efforts in connection with, its Year 2000 project.
The costs of the project and the date on which the company plans to complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future ,
events including the continued availubility of certain resources, I third party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, and actual results could differ materially from those plans. If the NU System's remediation plan is not successful, there could be a significant disruption of the NU system's operation.
Rick Management Instruments The following discussion about the company's risk-management activities includes forward looking statements that involve risk and uncertainties. Actual results could differ materially from those projected in the forward looking statements.
! This analysis presents the hypothetical loss in earnings related to I
the interest rate market risks not covered by the risk-management i instruments at December 31, 1997. The company uses swaps to manage the market risk. The company does not use these risk-management instruments for speculative purposes.
NAEC holds a variable rate long-term note, exposing the company to interest rate risk. In order to hedge this risk, interest rate risk-management instruments have been entered into on NAEC's $200 million 29
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variable rate note, effectively fixing the interest on this note at 7.823 percent.
For further information on risk management instruments, see the " Notes I to Financial Statements," Note 8.
l RESULTS OF OPERATIONS l
Income Statement Variances Increase /(Decrease) :
Millions of Dollars 1997 over/ (under)1996 1996 over/ (under)1995 Amount Percent Amount Percent Operating revenues $30 19% $5 3%
Fuel Expense (2) (11) 3 25 Other operation and maintenance expense 20 45 (5) (12)
Amortization of Regulatory Assets, net 6 (a) - -
Federal and State Income Taxes 3 43 - -
Deferred Seabrook return (other and borrowed funds) (2) (9) (8) (27)
Other, net (2) (a) - -
Interest on Long-term Debt (2) (3) (10) (16)
Net income (2) (7) 8 31 (a) Percent greater than 100 Operating Revenues Operating revenues represent amounts billed to PSNH under the terms of the Power Contracts and billings to PSNH for decommissioning expense.
Operating revenues increased in 1997 primarily due to higher operation and maintenance expenses and the increased return associated wit".1 the phase-in of the final 15 percent of the Seabrook plant investment in May, 1996.
Operating revenues increased in 1996, primarily due to the increased return associated with the phase-in of the Seabrook investment, partially offset by a lower return due to lower debt costs.
Fuel Expense Fuel expenses decreased in 1997, primarily due to lower Seabrook capacity factors as a result of the Seabrook outages in 1997.
Fuel expenses increased in 1996, primarily due to higher Seabrook capacity factors.
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L .Other Operation and Maintenance Expense other operation 'and maintenance expenses increased in 1997 primarily i due to higher costs associated with the Seabrook outages in 1997.
Other operation and maintenance expenses decreased in 1996, primarily
.due to a planned refueling and maintenance outage in 1995.
l Amortization of Regulatory Assets, net Amortization of Regulatory Assets, net increased in 1997 primarily due l to the beginning of the amortization of the'Seabrook deferred return in December 1997.
Fsderal and State Income Taxes Federal and State income taxes increased in 1997 primarily due to )
deferred tax benefits in 1996 associated with proceeds from the sale i of.the Seabrook Unit 2 steam generators. j l
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l Daferred Seabrook Return, net l
i Deferred-Seabrook return, net decreased in 1997 primarily due to the .
final phase-in of Seabrook investment into rates in May, 1996. '
Deferred Seabrook return, net decreased in 1996, primarily due to the additional Seabrook investment phased into rates in May, 1996, and !
l . May ,' 1995, partially offset by a one-time adjustment in June, 1995, to .
the deferred Seabrook return balance.
i Other, net i Other, net decreased in 1997 primarily due to lower income from
. temporary' cash- investments and the amortization of the Seabrook deferred charges associated with the taxes on the purchased return. ,
Interest on Long-term Debt Although the change in 1997 was not significant, interest on long-term debt decreased in 1996 primarily due to the 1995 refinancing of its
$205 million 15.23-percent. variable-rate bank note. ;
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North Atlantic Energy Corporation SELECTED FINANCIAL DATA (a) 1997 1996 1995 1994 1993 (Thousands of Dollars)
Operating Revenues .... ... $ 192,381 $ 162,152 $ 157,1R3 $145,751 $125,408 Operating Income $ 57,061 $ 54,RR9 $ El,394 $ 42,950 $ ll,718 Net Income . .. ... . $ 29,953 $ 32,072 $ 24.441 $ 30,515 $ 25,99R Cash Dividends on Common Stock . . $ 2s,0nD $ 38,000 $ 24,000 $ 10,000 $ - l Total Assets .
$1,014,639 $1,017,3RR $1,014,649 $461,579 $900,821 1 1
1 Long-Term Debt (b)i. . . . $ 495,000 $ 915,000 $ 5s:0,000 $560,000 $560.000 STATISTICS 1997 1996 1995 1994 1993 Gross Electric Utility Plant at December 31, (Thousands of Dollars) $R11,140 $R16,446 $R06,R92 $792,RRO $ 7 8 9,12 7 kWh Sales (Millions) for the twelve month period ending December 31 ,
2,859 3.542 1,016 2,229 3,21R l
t STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Thousands of Dollars)
Quarter Ended (a) 1997 March 31 June 30 Sept. 30 Dec. 31 Opet ting Revenues . . $41,976 $50,128 $45,943 $54,334 Operating Income .
$14,406 $14,1 R 3 $14,124 $14,348 Net Income . $ 7,240 $ 6,95R $ 8,086 $ 7,669 1996 Operating Revenues $36,663 $19,107 $41,565 $44,R17 Operating Income $12,075 $17,786 $14,639 $14,389 i Net Income . . $ 7,1 3 $ 7,356 $ 9,91R $ 7,60R i
(a) Reclassifications of prior data have been made to conform with the current presentation.
(b) Includes portion due within one year.
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North Attontic Energy Corporation First MortgageBonds l- Tmstee and Interest Paying Agent United States Trust Company of New York I14 West 47th Street NewYork, New York 10036 4
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Address General Correspondence in Care of: l l Northeast Utilities Service Company .
l Investor Relations Department P.O. Box 270 i Hartford, Connecticut 06141-0270 Telephone: (860) 665-5000 l
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' Data contained in this AnnualReport are submitted
' for the sole purpose ofproviding irl formation to P.O. Box 330 1 l present security holders about the Cornpany. Manchester, New Hampshire 03105-0330 l l
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- Hugh C. MacKenzie:
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' Robert J. KoM . . . . ; O. Kaj Comendul .
~ Vice President-Western Region J Assistant Secretary.
j Kerry J. Kuhlmani . . - 1 Robert C. Aronson Vice President-Central Region L .. AssistantTreasurer -
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The Connecticut Light and Power Company and Subsidiaries Amended 1997 Annual Report Index Contents Pace Consolidated Balance Sheets (Restated) ..................... 2-3 Consolidated Statements of Income (Restated) ............... 4 Consolidated Statements of Cash Flows (Restated) ........... 5 Consolidated Statements of Common Stockholder's Equi t y ( Re s t a t e d ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Notes to Consolidated Financial Statements (Restated) ...... 7 Report of Independent Public Accountants................... 41 Management's Discussion and Analysis of Financial Condition and Results of Operations (Restated) ........... 42 Selected Financial Data (Restated) ......................... 54
. Statements of Quarterly Financial Data (Restated) .......... 54 Statistics ................................................. 55 Preferred Stockholder and Bondholder Information........... Back Cover
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PART I. FINANCIAL INFORMATION j THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS I l
l At Dtcember 31, 1997 1996 (Restated) (Restated)
(Thousands of Dollars) ;
ASSETS Utility Plant, at original cost: l Electric................................................. $ 6,411,018 $ 6,283,736 i Less: Accumulated provision for depreciation.......... 2,902,673 2,665,519 3,508,345 3,618,217 Construction work in progress............................ 93,692 95,873 Nuclear fuel, net. ...................................... 135,076 133,050 Total net utility plant.............................. 3,737,113 3,847,140 Other Property and Investments:
Muclear decommissioning trusts, at market................ 369,162 296,960 Investments in regional nuclear generating companies, at equity.................................... 58,061 56,925 Other, at cost........................................... 66,625 16,565 493,848 370,450 Current Assets:
Cash............................................... ..... 459 404 Notes receivable from affiliated companies............... -
109,050 Investments in securitizable assets...................... 205,625 Receivables, less accumulated provision for uncollectible accounts of $300,000 in 1997 and of $13,240,000 in 1996............................. 50,671 226,112 Accounts receivable from affiliated companies............ 3,150 3,481 Taxes receivable......................................... 70,311 40,134 Accrued utility revenues................................. -
78,451 Fuel, materials and supplies, at average cost............ 81,878 79,937 Recoverable energy costs, net--current portion...... .... 28,073 25,436 Frepayments and other.................................... 79,632 63,344 519,799 626,349 Diferred Charges:
Regulatory assets... .................................... 1,292,818 1,370,781 Unimortized debt expense................................. 19,286 17,033 Other........ ....... ................................... 18,359 12,283 1,330,463 1,400,097 i
l Total Assets...... .................................. $ 6,081,223 $ 6,244,036 l
The accompanying notes are an integral part of these financial statements.
2
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS At December 31, 1997 1996 (Restated) (Restated)
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES Capitalization:
Common stock.-$10 par value. Authorized 24,500,000 shares; outstanding 12,222,930 shares in 1997 and 1996................................ $ 122,229 $ 122,229 Capital surplus, paid in................................ 641,333 639,657 Retained earnings (Note 1). ............................ 419,972 580,779 Total common stockholder's equity.............. 1,183,534 1,342,665 Cumulative preferred stoex--
$50 par valve - authorized 9,000,000 shares; outstanding 5,424,000 shares in 1997 and 1996;
$25 par value - authorized 8,000,000 shares; outstanding no shares in 1997 and 1996 Not subject to mandatory redemption.................... 116,200 116,200 Subject to mandatory redemption.. .... .... ........... 151,250 155,000 Long-term debt..... .................................... 2,023,316 1,834,405 Total capitalization........................... 3,474,300 3,448,270 Minority Interest in Consolidated Subsidiary...... ....... 100,000 100,000 Obligations Under Capital Leases..... .................... 18,042 143,347 Current Liabilities:
Notes payable to banks.................................. 35,000 -
Notes payable to affiliated company.................. .. 61,300 -
Long-term debt and preferred stock--current portion...... ........ ................................ 23,761 204,116 Obligations under capital leases--current portion. .................... .............. ....... . 140,076 12,361 Accounts payable. .............. ............. . . . . . . . . . . 124,427 160,945 Accounts payable to affiliated companies. .. . .. ..... 92,963 78,481 Accrued taxes.. .... ............. .... ..... ...... 33,017 28,707 ,
' Accrued interest........ ...... ........... . ..... .. 14,650 31,513 Other.... ................ . ............ . .. ......... 23,495 34,433 548,689 550,556 Daferred Credits:
Accumulated deferred income taxes.................. .... 1,348,617 1,386,772 Accumulated deferred investment tax credits....... ..... 127,713 135,080 Deferred contractual obligations........................ 348,406 305,627 Other...... ................ .... ...................... 115,456 174,384 1,940,192 2,001,863 Commitments and Contingencies (Note 12)
Total Capitalization and Liabilities..... .. . $ 6,081,223 $ 6,244,036 The accompanying notes are an integral part of these financial statements.
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I THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES ,
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CONSOLIDATED STATEMENTS OF INCOME i 1
'For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) l
....................___ ............__................................................... t (Thousands of Dollars) #
Operating Revenues................................... $2,465,587 $2,397,460 $2,387,069 l q
Opsrating Expenses:
Operation --
Fuel, purchased and net interchange power....... 977,543 831,079 608,600 Other........................................... 726,420 727,674 614,382 l Maintenance........................................ 355,772 300,005 192,607 l
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Depreciation....................................... 238,667 247,109 242,496 Amortization of regulatory assets, net............. 61,648 57,432 54,217 Federal and state income taxes..................... (59,436) 957 178,346 Taxes other than income taxes...................... 172,592 174,062 172,395 Total operating expenses (Note 1) . . . . . . . . . . . . 2,473,206 2,338,318 2,063,043 Operating ( Los s ) / Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,619) 59,142 324,026 F
Other Income:
Equity in earnings of regional nuclear generating companies............................. 5,672 6,619 6,545 !
Other, net......................................... (1,856) 20,710 14,585 Minority interest in income of subsidiary.......... (9,300) (9,300) (8,732) l Income taxes.................................. ..... 7,573 160 (2,978) !
Other income, net............................ 2,089 18,189 9,420 t (Loss) / Income before interest charges. . . . . . . . (5,530) 77,331 333,446 Interest Charges:
Interest on long-term debt......................... 132,127 127,198 124,350 i Other interest. ................................... 1,940 1,001 3,880 ,
r Interest charges, net........................ 134,067 128,199 128,230 !
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' Net (Loss) / Income (Note 1)........................... $ (139,597) $ (50,868) $ 205,216 I
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The accompanying notes are an integral part of these financial statements.
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'IME CONNECTICUr LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATD4ENTS OF CASH FIDWS For the Years Ended December 31, 1997 1996 1995
{ (Restated) (Restated)
(Thousands of Dollars)
Operating Activities:
Ne t ( Los s ) / Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (139,597) $ (50,868) $ 205,216 Adjustments to reconcile to net cash from operating activities:
Depreciation.............................................. 238,667 247,109 242,496 Deferred income taxes and investment tax credits, net..... (10,400) (39,642) 49, ~J20 Deferred nuclear plants return, net of anortization. . . . . . . (281) 7,746 95,559 Amortization of deferred demand-side-management costs, net 38,029 26,941 (937)
Recoverable energy costs, net of amortization............. (9,533) (35,567) (16,169)
Amortization of ceferred cogeneration costs, net.......... 32,700 25,957 (55,341)
Deferred Other nuclearofrefuelin sources cash....g outage, net of amortization ... (45,333) 45,643 (20,712)
................................. 64,013 75,552 86,956 Other uses of cash........................................ (50,137) (23,862) (53,745)
Changes in working capital:
Receivables and accrued utilit 184,223 (22,378) (33,032)
Fuel, materials and su Accounts payable......pplies..y revenues.................. (22,036)
............................ (1,941) (11,455) (4,479) l 83,951
.................................... 9,605 Accrued taxes............................................. 4,310 (23,561) 25,855 Sale of receivables and accrued utility revenues.......... 70,000 - -
Investment in securitizable assets........................ (205,625) - -
Other working capital (excludes cash)..................... (74,266) (5,385) (1,869)
Het cash flows from operating activities (Note 1) . . . . . . . . . . . . . 72,793 300,131 528,923 Financing Activities:
Issuance of long-term debt.................................. 200,000 222,000 -
Issuance of Monthly Income Preferred Securities....................................... - -
100,000 Net increase /(decrease) in short-term debt.................. 96,300 (51,750) (127,000)
R: acquisitions and retirements of long-term debt............ (204,116) (14,329) (10,866)
Reacquisitions and retirements of preferred stock........... - -
(125,000)
Cash dividends on preferred stock........................... (15,221) (15,221) (21,185)
Cash dividends on cormen stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,989) (138,608) (164,154)
Net cash flows from/ (used for) financing activities. . . . . . . . . . . 70,974 2,092 (34B,205)
Investment Activities:
Investment in plant:
Electric utilit plant.................................... (155,550) (140,086) (131,858)
Nuclear fuel...y........................................... (702) 553 (1,543)
Net cash flows used for investments in plant........... .... (156,252) (139,533) (133,401)
Investment in NU system money pool.......................... 109,050 (109,050) -
Investment in nuclear decorrmissioning trusts . . . . . . . . . . . . . . . . (45,314) (50,998) (47,826)
Other investment activities, net............................ (51,196) (2,625) 581 Net cash flows used for investments........................... (143,712) (302,206) (180,646)
Net Increase In Cash For The Period........................... 55 67 72 Cash - beginning of period.................................... 404 337 265
' Cash - end of pe riod . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 459 $ 404 $ 337
==........ .......... ..........
Supplemental Cash Flow Information:
Cash paid /(refunded) during the year for:
Interest, net of arrounts capitalized. . . . . . . . . . . . . . . . . . . . . . . . $ 145,962 $ 114,458 $ 117,074 Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ ( 2 2 , 3 3 8 ) $ 77,790 $ 137,706 Increase in obligations:
Niantic Bay Fuel Trust and other capital leases............. $ 2,815 $ 2,855 $ 33,537 The accoupanying notes are an integral part of these financial statements.
5
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Capital Retained Common Surplus, Earnings (a) Total Stock Paid In (Note 1)
(Thousands of Dollars)
Balcnce at January 1, 1995............... $122,229 $632,117 $ 765,724 $1,520,070 Net income for 1995.................. 205,216 205,216 Cash dividends on preferred stock........ ..................... (21,185) (21,185)
Cash dividends on common stock....... (164,154) (164,154)
Loss on the retirement of preferred stock............... (125) (125)
Capital stock expenses, net....... .. 5,864 5,864 Balance at December 31, 1995............. 122,229 637,981 785,476 1,545,686 Net loss for 1996 (Note 1)........... (50,868) (50,868)
Cash dividends on preferred stock.............................. (15,221) (15,221)
Cash dividends on common stock....... (138,608) (138,608)
Capital stock expenses, net.......... 1,676 1,676 Balance at December 31, 1996 (Restated).. 122,229 639,657 580,779 1,342,665 Net loss for 1997 (Note 1)........... (139,597) (139,597)
Cash dividends on preferred stock.............................. (15,221) (15,221)
Cash dividends on common stock....... (5,989) (5,989) i Capital stock expenses, net.......... 1,676 1,676 Balance at December 31, 1997 (Restated).. $122,229 $641,333 $ 419,972 $1,183,534 (c) The company has dividend restrictions imposed by its long-term debt agreements.
At December 31, 1997, these restrictions totaled approximately $540 million.
Thn accompanying notes are an integral part of these financial statements.
6
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLTDATED FINANCIAL STATEMENTS
- 1. SECURITIES AND EXCHANGE COMMISSION INQUIRY In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC) inquired into Northeast Utilities' (NU) accounting for nuclear compliance costs. These costs are the unavoidable incremental costs associated with the current nuclear outages required to be incurred prior to restart of the units in accordance with correspondence received from the Nuclear Regulatory Commission (NRC) early in 1996. The SEC's view is that these unavoidable costs associated with nuclear outages and procedures to be implemented at nuclear power plants in response to regulatory requirements required prior to restart of the units should be expensed as incurred. During 1996 and 1997, NU and its wholly owned subsidiaries, The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO), reserved for these unavoidable incremental costs that they expected to incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred. While NU and its independent auditors, Arthur Andersen LLP, believed the accounting was required by, and was in accordance with, generally accepted accounting principles, the company has agreed to adjust its accounting for nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings. The financial statements in this report have been restated to reflect the change in accounting.
- 2.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES A. About The Connecticut Light and Power Company The Connecticut Light and Power Company and subsidiaries (the company or CL&P) , WMECO, Holyoke Water Power Company (HWP), PSNH and North Atlantic Energy Corporation (NAEC) are the operating subsidiaries comprising the Northeast Utilities system (the NU system) and are wholly owned by NU.
The NU system furnishes franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through CL&P, PSNH, WMECO and HWP. A fifth wholly owned subsidiary, NAEC, sells all of its entitlement to the capacity and output of the Seabrook nuclear power plant (Seabrook) to PSNH. In addition to its franchised retail service, the NU system furnishes firm and other wholesale electric services to various municipalities and other utilities, and participates in limited retail access programs, providing off-system retail electric service. The NU system serves about 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues.
Other wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies.
Northeast Nuclear Energy Company (NNECO) acts as agent for the 7
I The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NU system companies and other New England utilities in operating the Millstone nuclear generating facilities. North Atlantic Energy Service Corporation (NAESCO) acts as agent for CL&P and NAEC and has operational responsibilities for Seabrook. In addition, CL&P and WMECO each have established a special purpose I
subsidiary whose business consists of the purchase and resale of receivables.
B. Presentation The consolidated financial statements of CL&P include the accounts of all wholly owned subsidiaries. Significant intercompany transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform with the current year's presentation.
All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state
! regulatory agencies.
For more information on significant subsidiaries of CL&P, see Note 11, " Sale of Customer Receivables and Accrued Utility Revenues," and Note 14, " Minority Interest in Consolidated Subsidiary."
C. Public Utility Regulation NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act). NU and its subsidiaries, including CL&P, are subject to the provisions of the 1935 Act.
Arrangements among the NU system companies, outside agencies and
! other utilities covering interconnections, interchange of electric power and sales of utility property are subject to l regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. CL&P is subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions.
For information regarding proposed changes in the nature of industry regulation, see Note 2H,. " Summary of Significant Accounting Policies - Regulatory Accounting and Assets," and Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A).
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l The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS D. New Accounting Standards The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS), SFAS 129,
" Disclosure of Information about Capital Structure," in February 1997. SFAS 129 establishes standards for disclosing information about an entity's capital structure. CL&P's current disclosures are consistent with the requirements of SFAS 129.
During June 1997, the FASB issued SFAS 130, " Reporting Comprehensive Income" and SFAS 131, " Disclosures about Segments of an Enterprise and Related Information." SFAS 130 establishes l
standards for the reporting and disclosure of comprehensive income. To date, CL&P has not had material transactions that would be required to be reported as comprehensive income. SFAS l 131 determines the standards for reporting and disclosing qualitative and quantitative information about a company's operating segments. This information includes segment profit or loss, certain segment revenue and expense items and segment :
assets and a reconciliation of these segment disclosures to corresponding amounts in the company's general purpose financial statements. CL&P currently evaluates management performance using a cost-based budget and the information required by SFAS 131 is not available. Therefore, these disclosure requirements are not applicable. Management believes that the implementation of SFAS 130 and SFAS 131 will not have a material impact on CL&P's current disclosures. ,
See Note 11, " Sale of Customer Receivables and Accrued Utility i Revenues," and Note 12C, " Commitments and Contingencies -
Environmental Matters," for information on other newly adopted :
accounting and reporting standards related to those specific areas. r t
E. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P owns common stock of four regional nuclear generating companies (Yankee companies). The Yankee companies, with CL&P's ownership interests are:
l l Connecticut Yankee Atomic Power Company (CYAPC) . . . . 34.5%
!' Yankee Atomic Electric Company (YAEC) . . . . . . . . . . . . . 24.5
Vermont Yankee Nuclear Power Corporation (VYNPC) .. 9.S
- CL&P's investments in the Yankee companies are accounted for on the equity basis due to the company's ability to exercise and significant influence over their operating financial policies.
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,,.,-r
The Connecticut Light and Power Company and Subsidiaries EOTES TO CONSOLIDATED FINA.NCIAL STATEMENTS CL&P's investments in the Yankee companies at December 31, 1997
- are:
(Thousands of Dollars)
CYAPC........................................ $38,358 YAEC......................................... 5,128 MYAPC........................................ 9,449 VYNPC........................................ 5.126
$58.061 Each Yankee company owns a single nuclear generating unit. Under the terms of the contracts with the Yankee companies, the shareholders-sponsors are responsible for their proportionate share of the costs of each unit, including decommissioning. The energy and capacity-costs.from VYNPC and nuclear decommissioning costs of the Yankee companies that have been shut down are billed as purchased power to CL&P.
The electricity produced by the. Vermont Yankee nuclear generating facility (VY) is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. YAEC's,. CYAPC's and MYAPC's nuclear power plants were shut down permanently on February 26, 1992, December 4, 1996, and August 6, 1997, respectively. Under ownership agreements with the Yankee companies, CL&P may be ' asked to provide direct or indirect financial support for one or more of the companies. For more information on the Yankee companies, see Note 4, " Nuclear Decommissioning," and Note .12F,
" Commitments and Contingencies - Long-Term Contractual Arrange-ments."
Millstone 1: CL&P has an 81.0 percent joint ownership interest in Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $387.7 million and $384.5 million, respectively, and the accumulated provision for depreciation included approximately $172.0 million and $159.4 million, respectively, for CL&P's share of Millstone 1. CL&P's share of Millstone 1
. expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income.
Millstone 2: CL&P has an 81.0 percent joint ownership interest in Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $694.7 million and $690.4 million, respectively, and the accumulated provision for depreciation included
. approximately $249.1 million and $224.1 million, respectively, for CL&P's share of Millstone 2. CL&P's share of Millstone 2 expenses is included in the corresponding operating expenses on-the accompanying Consolidated Statements of Income.
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The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Millstone 3: CL&P has a 52.93 percent joint ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $1.9 billion each year and the accumulated provision for depreciation included approximately $552.7 million and $504.1 million, respectively, for CL&P's share of Millstone
- 3. CL&P's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income.
The three Millstone units are out of service. NU hopes to return Millstone 3 to service in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 has been placed in extended maintenance status. Management is reviewing its options with respect to Millstone 1, including restart, early retirement and other options. In a draft ruling issued in February 1998, the Connecticut Department of Public Utility Control (DPUC) determined that Millstone 1 was no longer "used and useful" and ordered it removed from rate base.
In 1996, one of the joint owners of Millstone 3, Vermont Electric Generation and Transmission Cooperative, Inc. (VEG&T),
filed for bankruptcy. The subsequent liquidation resulted in the offering of VEG&T's 0.035 percent share of Millstone 3 for sale to the joint owners of Millstone 3. None of the non-NU joint owners accepted the offer. During 1998, CL&P expects to make the necessary regulatory filings to acquire ownership of VEG&T's share of Millstone 3.
For more information regarding the DPUC's action, see the MD&A.
For more information regarding the Millstone units see Note 4,
" Nuclear Decommissioning," and Note 12B, " Commitments and Contingencies - Nuclear Performance."
Seabrook 1: CL&P has a 4.06 percent joint ownership interest in Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $174.3 million and $173.7 million, respectively, and the accumulated provision for depreciation included approximately $33.9 million and $29.7 million, respectively, for CL&P's share of Seabrook 1. CL&P's share of Seabrook 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income.
F. Depreciation The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency.
Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in 11
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the severa] classes of electric plant-in-service are equivalent to a composite rate of 3.8 percent in 1997 and 4.0 percent in 1996 and 1995. See Note 4, " Nuclear Decommissioning,"
for information on nuclear decommissioning.
CL&P's nonnuclear generating facilities have limited service lives. Plant may be retired in place or dismantled based upon expected future needs, the economics of the closure and environmental concerns. The costs of closure and removal are incremental costs and, for financial reporting purposes, are accrued over the life of the asset as part of depreciation. At December 31, 1997 and 1996, the accumulated provision for depreciation included approximately $45.8 million and $43.0 million, respectively, accrued for the cost of removal, net of salvage for nonnuclear generation property.
( G. Revenues other than revenues under fixed-rate agreements negotiated with certain wholesale, commercial and industrial customers and limited retail access programs, utility revenues are based on authorized rates applied to each customer's use of electricity.
In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission.
Regulatory commissions also have authority over the terms and conditions of nontraditional rate making arrangements. At the end of each accounting period, CL&P accrues an astimate for the amount of energy delivered but unbilled.
For information on rate proceedings and their potential impact on CL&P, see the MD&A.
H. Regulatory Accounting and Assets The accounting policies of CL&P and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, " Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators also may reduce or ,
eliminate the value of an asset, or create a liability. If any portion of CL&P's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, CL&P would be required to write off all of its related regulatory assets and liabilities unless there is a formal transition plan which provides for the recovery, through established rates, for the collection of approved stranded costs and to maintain the cost-of-service basis for the remaining regulated operations. At the time of transition, CL&P would be 12
- . - - =- -
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS required to determine any impairment of the carrying costs of deregulated plant and inventory assets.
Management anticipates that a restructuring program will be implemented within Connecticut during the next few years. In a restructured environment, CL&P's generation business no longer will be rate regulated on a cost-of-service basis. The majority of CL&P's regulatory assets are related to its generation business.
1 The staff of the SEC has had concerns regarding the appropriateness of the utilities' ability to continue application of SFAS 71 for the generation portion of their business in a restructured environment. The SEC referred the issue to the Emerging Issues Task Force (EITF) of the FASB which reached a consensus and issued " Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101," (EITF 97-4). The EITF concluded:
(1) the future recognition of regulatory assets for the portion of the business that no longer qualifies for application of SFAS 71 depends on the regulators' treatment of the recovery of those costs and other stranded assets from cash flows of other portions of the business still considered to be regulated, and (2) a utility should discontinue the application of SFAS 71 when a legislative and regulatory plan has been enacted, which would include transition plans into a competitive environment, and when the stranded costs which are subject to future rate
, recovery are determined. EITF 97-4 became effective in August
- 1997.
. The Connecticut General Assembly is addressing a proposal for electric industry restructuring in the state of Connecticut during 1998. As the terms and conditions to be contained within the restructuring plan cannot be determined at this time,
, management believes that its use of regulatory accounting i
remains appropriate.
- CL&P expects that its transmission and distribution business will continue to be rate-regulated on a cost-of-service basis and, accordingly, CL&P will continue to apply SFAS 71 to this portion of its business.
For further information on CL&P's regulatory environment and the potential impacts ef restructuring, see Note 12A, " Commitments and Contingencica - Restructuring and Rate Matters" and the MD&A.
SFAS 121, " Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the evaluation of long-lived assets, including regulatory assets, for impairment when certain events occur or when conditions exist that indicate the carrying amounts of assets may not be recoverable. SFAS 121 requires that any long-lived assets which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If this 13
1 The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS revaluation is less than the book value of the asset, an impairment loss would be charged to earnings.
Management continues to -believe that it is probable that CL&P will recover its investments in long-lived assets through future revenues. This conclusion may change in the future as the implementation of restructuring plans in the state of Connecticut will generally require the formation of a separate generation entity that will be subject to competitive market conditions. As a result, CL&P will be required to assess the carrying amounts of its long-lived assets in accordance with SFAS 121.
The components of CL&P's regulatory assets are as follows:
At D_qcember 31, 1997 1996 (Thousands of Dollars)
Income taxes, net (Note 2I) .......... $709,896 $ 753,390 Recoverable energy costs, net (Note 2J) ...................... 104,796 97,900 Deferred demand-side management costs (Note 2K) .................... 52,100 90,129 Cogeneration costs (Note 2L) ......... 33,505 66,205 Unrecovered contractual obligations (Note 4) ............... 338,406 300,627 Other................................ 54,115 62,530
$1,292,818 $1,370,781 I. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. See Note 9, " Income Tax Expense" for the components of income tax expense.
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The Connecticut Light and Power Company and Subsidiaries
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The- tax effect of temporary differences, including timing l differences accrued under previously approved accounting standards ~, which give rise to the accumulated deferred tax ,
obligation is as follows:
i At December 31, 1997 1996 _
(Restated) (Restated)
(Thousands of Dollars)
Accelerated depreciation and other plant-related differences............ $1,056,690 $1,032,857 Regulatory assets - income tax gross up............................. 304,276 313,420 ;
Net operating loss carryforwards....... (7,670) -
Other.................................. (4,679) 40,495
$1,348,617 $1,386,772 At December 31, 1997, CL&P had a state of Connecticut net operating loss carryforward of approximately $131 million which can be used against CL&P and its affiliates' combined :
. Connecticut taxable income and which, if unused, expires in the '
year 2002.
J. Recoverable Energy Costs .
Under the Energy Policy Act of 1992 (Energy Act), CL&P is '
assessed for its. proportionate share of the costs of i decontaminating and decommissioning uranium enrichment plants
- owned' by the United States Department of Energy (D&D !
assessment). The Energy Act requires that regulators treat D&D ;
assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P is currently recovering these costs through rates. As of
' December 31, 1997, CL&P's total D&D deferrals were approximately ;
$50.1 million. ;
During 1997, CL&P implemented an energy adjustment clause (EAC) under which fuel prices above or below base-rate levels are ;
charged or credited to customers. The EAC replaced CL&P's fuel ;
adjustment and generation utilization adjustment clauses and is designed to reconcile and adjust the difference between actual
-fuel costs and the fuel revenue collected through base rates on a six-month basis.
L l For the ' period January 1, 1997 through June 30, 1997, CL&P agreed to a zero EAC rate. For the period July 1, 1997 through December-31, 1997, the DPUC approved an EAC rate through which CL&P recovered approximately $11.5 million of deferred fuel j costs. While this proceeding did not include provisions for the ;
I recovery of approximately $18 million of costs related to the early closing of CYAPC's nuclear generating unit, it did allow l 15 l
The Connecticut Light and Power Company and subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS I
for the recovery of costs, subject to refund, related to the closure .of MYAPC's nuclear generating unit'. CL&P has appealed the DPUC's ruling.related to CYAPC replacement power costs.
During . December 1997, the DPUC approved an EAC rate for the period January 1, 1998 through June 30, 1998. During this period, CL&P. will recover approximately $27.9 million of deferred fuel costs.
At December 31, 1997, CL&P's net recoverable energy costs, excluding . current net recoverable energy costs, were approximately $104.8 million.
For further information on recoverable energy costs, see the MD&A.
K. Demand-Side Management (DSM)
CL&P's' DSM costs are recovered in base 2.ates through a Conservation Adjustment Mechanism. CL&P is allowed to recover DSM costs in excess of costs reflected in base ' rates over periods ranging from approximately'four to ten years.
During April 1997, the DPUC approved CL&P's DS'M budget of $36 million for 1997. In October 1997, CL&P and other interested parties filed a stipulation with the DPUC requesting that the
.DPUC approve certain programs and establish a budget level of
$32.7 million for 1998 and $28.8 million for 1999. The $52.1 million of DSM costs on CL&P's books as of December 31, 1997, currently being collected, will be fully recovered by 2000, i L. Cogeneration Costs Beginning on July 1, 1996, the deferred cogeneration balance of approximately S86 million is being amortized over a five year period. An' additional $9 million of amortization was applied to the deferred balance in 1997, as required under a settlement agreement which CL&P reached with the DPUC. CL&P continues to apply any savings associated with the renegotiation of a certain ,
-contract with a cogeneration facility to the deferred balance.
Under current expectations, CL&P expects complete amortization !
of the deferred balance by December 31, 1998. At December 31, 1997, CL&P's deferred cogeneration costs balance was
.approximately'$23.5 million.
M._. Spent Nuclear Fuel Disposal Costs Under the Nuclear. Waste Policy Act of 1982, CL&P must pay the United States Department of Energy (DOE) for the disposal of spent nuclear ~ fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, .and the disposal of, spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the i DOE on a quarterly basi s . For nuclear fuel used to generate )
electricity prior to April 7, 1983 (prior-period fuel) , payment i must be.made. prior to the first delivery of spent fuel to the i 16
l The Connecticut Light and Power Company and Subsidiaries l
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS l DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill i Yield Rate. At December 31, 1997, fees due to the DOE for the l disposal of prior-period fuel were approximately $166.5 million, l including interest costs of $99.9 million.
, The DOE was originally scheduled to begin accepting delivery of l spent fuel in 1998. However, delays in identifying a permanent i
storage site have continually postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly
! alternatives. The company has primary responsibility for the interim storage of its spent nuclear fuel. Current capability l to store spent fuel at Millstone 1 and 2 are estimated to be l adequate until 2004 and at Seabrook until 2010. Storage j facilities for Millstone 3 are expected to be adequate for the projected life of the unit. Meeting spent fuel storage requirements beyond these periods could require new and separate storage facilities, the costs for which have not been determined.
In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its contractual obligation l to begin accepting spent nuclear fuel no later than January 31, l 1998. Currently, the DOE has not taken the spent nuclear fuel
! as scheduled and, as a result, may have to pay contract damages.
The ultimate outcome of this legal proceeding is uncertain at this time.
N. Market Risk-Management Policies CL&P utilizes market risk-management instruments, including swaps, collars, puts and calls, to hedge well-defined risks
! associated with changes in fuel prices. To qualify for hedge l treatment, the underlying hedged item must expose CL&P to risks and associated with market fluctuations the market-risk management instrument used must be designated as a hedge and must reduce the company's exposure to market fluctuations throughout the period.
Amounts receivable or payable under fuel-price management instruments are recognized in operating revenues when realized.
CL&P does not use market risk-management instruments for speculative purposes. For further information, see Note 13,
" Market Risk Management."
- 3. LEASES I CL&P and WMECO may finance up to $400 million of nuclear fuel for d
Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement which is scheduled to expire July 31, 1998. The NBFT capital lease agreement, which was amended in February 1998, requires CL&P and WMECO to secure their obligation to repay the 17
l The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NBFT with up to $90 million of first mortgage bonds. CL&P and WMECO will issue these bonds by May 1998.
CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-e production method at rates which reflect estimated kilowatt hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO.
CL&P has also entered into lease agreements, some of which are capital leases, for the use of data processing and off.4ce equipment, vehicles, gas turbines, nuclear centrol room simulat.rs and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to expense:
Year Capital Leases Operatino Leases 1997............. $10,457,000 $19,749,000 1996............. 17,993,000 22,032,000 1995........ .... 56,307,000 23,793,000 Interest included in capital leane rental payments was $9,948,000 in 1997, $10,144,000 in 1996 and $10,587,000 in 1995.
Future minimura renta) payments, excluding executory costs such as property taxes, state use taxes, insurance and maintenance, under long-term noncancelable leases as of December 31, 1997, are:
Year Capital Leases Operatino Leases (Thousands of Dollars) 1998................ $142,500 $ 22,700 1999................ 2,900 21,300 2000................ 2,900 19,900 2001................ 2,900 14,400 2002................ 3,000 6,200 After 2002.......... 54.300 22,800 Future minimum lease payments.......... 208,500 $107,300 aess amount representing interest.......... 50,400 Present value of future minimum lease payments.... $158,100 Rocky River Realty Company (RRR) provides real estate support services, including the leasing of properties and facilities, used by NU system companies, including CL&P. During 1997, RRR repurchased certain notes that were secured by real estate leases 18
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS between RRR as lessor and NUSCO as lessee. The repayment of these notes triggered the acceleration of rent and CL&P was subsequently billed by NUSCO and paid its proportionate share of the accelerated lease obligation. At December 31, 1997, CL&P has recorded long-term prepaid rent of approximately $11.1 million.
This asset is being amortized on a straight line basis and will be fully amortized in 2017,
- 4. NUCLEAR DECOMMISSIONING Millstone and Seabrook: CL&P's nuclear power plants have service lives that are expected to end during the years 2010 through 2026.
Upon retirement, these units must be decommissioned. Current decommissioning studies concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units and Seabrook 1. Decommissioning studies ar6 reviewed and updated pericolcally to reflect changes in decommissioning requirements, costs, technology and inflation.
The estimated cost of decommissioning CL&P's ownership share of Millstone 1 and 2, in year-end 1997 dollars, is $390.9 million and
$350.2 million, respectively. CL&P's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 in year-end 1997 dollars, is $294.0 million and $19.2 million, respectively. The Millstone units and Seabrook i decommissioning costs will be increased annually by their respective escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Consolidated Statements of Income.
Nuclear decommissioning costs amounted to $37.8 million each year in 1997 and 1996 and $30.5 million in 1995. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1997 and 1996, the balance in the accumulated reserve for depreciation amounted to $407.3 million and $329.1 million, respectively.
CL&P has established external decommissioning trusts through a trustee for its portion of the costs of decommissioning Millstone 1, 2 and 3. CL&P's portion of the cost of decommissioning Seabrook 1 is paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes levelized collections for the Millstone units and escalated collections for Seabrook 1 and after-tax earnings on the Millstone and Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent, respectively.
As of December 31, 1997, CL&P has collected through rates $277.9 million toward the future decommissioning costs of its share of the Millstone units, of which $240.3 million has been transferred to external decommissioning trusts. As of December 31, 1997, CL&P has paid approximately $2.9 million into Seabrook l's 19
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS decommissioning financing fund. Earnings on the decommissioning trusts and financing fund increase the decommissioning trust and the accumulated reserve for depreciation. Unrealized gains and losses associated with the decommissioning trusts and financing fund also impact the balance of the trusts and the accumulated reserve for depreciation.
Changes in requirements or technology, the timing of funding or dismantling or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. CL&P attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in CL&P's rates. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, CL&P expects that the decommissioning trusts and financing fund will be substantially funded when the units are retired from service.
Millstone 1 has been placed in extended maintenance status while management is reviewing its options with respect to the unit.
These include restart, early retirement and other options.
Relating to management's consideration of the option to immediately retire Millstone 1 are certain Connecticut state law issues. In its four-year rate review proceeding, the DPUC noted that CL&P may not be able to obtain its remaining investment in l Millstone 1 if it were to determine that the unit had been l prematurely shut down due to management imprudence. Additionally, there is a Connecticut statute which may limit CL&P's ability to collect future decommissioning charges related to Millstone 1 if Millstone 1 were to be terminated before the end of its expected life. J l
At December 31, 1997, CL&P's net unrecovered Millstone i plant costs were $215.7 million and the remaining unrecovered decommissioning costs were approximately $198 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. CL&P's ownership share of estimated costs, in year-end 1997 dollars, of decommissioning this unit is $48.0 million.
On August 6, 1997, the board of directors of MYAPC voted ,
unanimously to cease permanently the production of power at its j nuclear generating facility (MY). The NU system companies had '
relied on MY for approximately one percent of their capacitv.
During November 1997, MYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. During January 1998, the FERC accepted the amendments and proposed rates, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to approximately 20 l
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$867.2 million, of which CL&P's share was approximately $104.0 million.
On December 4, 1996, the board of directors of CYAPC voted unanimously to cease permanently the production of power a r. its nuclear generating plant (CY). During 1996, the NU system companies their capacity.
had relied on CY for approximately three percent of During late December 1996, CYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. On February 27, 1997, the FERC approved an order for hearing which, among other things, accepted CYAPC's contract amendment. The new rates became effective March 1, 1997, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to $619.9 million, of which CL&P's share was approximately $213.8 million.
YAEC is in the process of decommissioning its nuclear facility.
At December 31, 1997, the estimated remaining costs, incl.uding decommissioning, amounted to $124.4 million, of which CL&P's share was approximately $30.5 million.
Under the terms of the contracts with MYAPC, CYAPC and YAEC, the shareholder-sponsor companies, including CL&P, are responsible for their proportionate share of the costs of the units, including decommissioning. Management expects that CL&P will continue to be allowed CL&P to recover these costs from its customers. Accordingly, has recognized these costs as regulatory assets with corresponding obligations.
Proposed Accounting: The staff of the SEC has questioned certain current accounting practices of the electric utility industry, including CL&P, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in the financial statements. In response to these questions, the FASB has agreed to review the accounting for closure and removal costs, including decommissioning. If current electric utility industry accounting practices for nuclear power plant decommissioning are changed, the annual provision for decommissioning could increase relative to 1997, and the estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation) , with recognition of an increase in the cost of the related nuclear power plant. Management believes that CL&P will continue to be allowed to recover decommissioning costs through rates.
- 5. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the SEC under the 1935 Act or by the DPUC. SEC authorization allowed CL&P, as of January 1, 1998, to incur total short-term borrowings up to a maximum of $375 million.
21
l l The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS j Credit Agreements: In May 1997, because of the potential for NU and CL&P to violate their various financial ratio tests, NU l amended the three-year revolving credit agreement (Credit Agreement) with a group of 12 banks. Under the amended Credit Agreement, CL&P and WMECO are able to borrow, subject to the availability of first mortgage bond collateral, up to $313.75 i million and $150 million, respectively. At December 31, 1997,
! CL&P and WMECO have issued first mortgage bonds to enable j borrowings under this facility up to a maximum of $225 million and l
$90 million, respectively. NU, which cannot issue first mortgage bonds, will be able to borrow up to $50 million if NU consolidated, CL&P and WMECO each meet certain interest coverage j tests for two consecutive quarters. In addition, CL&P and WMECO each must meet certain minimum quarterly financial ratios to access the Credit Agreement. Both CL&P and WMECO satisfied these tests for the quarter ending December 31, 1997. The overall limit i
for all of the borrowing system companies under the entire Credit J
- Agreement is $313.75 million. The companies are obligated to pay 1 a facility fee of .50 percent per annum of each bank's total commitment under this Credit Agreement which will expire in November 1999. At December 31, 1997 and 1996, there were $50 million and $27.5 million, respectively, in borrowings under this Credit Agreement. Of these amounts, CL&P had $35 million borrowed in 1997 and nothing borrowed in 1996. ;
i l In addition to the Credit Agreement, NU, CL&P, WMECO, HWP and RRR have various revolving credit lines through separate bilateral l credit agreements. Under this facility, four banks maintain commitments to the respective companies totaling $56.25 million.
NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas HWP and RRR may borrow up to their SEC or board authorized short-term debt limit of $5 million and $22 million, respectively.
i Under the terms of this facility, the companies are obligated to pay a facility fee of .15 percent per annum of each bank's total commitment. These commitments will expire in December 1998. At December 31, 1997 and 1996, there were no borrowings and $11.3 million in borrowings, respectively, under this facility, all of which had been borrowed by other NU system companies.
l Under the credit facilities discussed above, CL&P may borrow funds l on a short-term revolving basis under its agreement, using either l fixed-rate loans or standby loans. Fixed rates are set using l competitive bidding. Standby loans are based upon several l alternative variable rates. The weighted average annual interest
! rate on CL&P's notes payable to banks outstanding on December 31, 1997 was 6.95 percent. CL&P had no borrowings under these facilities at December 31, 1996.
i Money Pool: Certain subsidiaries of. NU, including CL&P, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with l 22 1
, . . .. _ _ _ _ . _. .- -- _ _ . _ . _ . _. _. _.m._. .._ __. _ ._ _
The Connecticut Light-and Power Company and Subsidiaries l NOTES TO CONSOLIDATED FINANCIAL STATEMENTS i
! available funds of other member companies, including funds l borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the i terms of NU parent's original borrowing. At December 31, 1997, )
- l. CL&P had $61.3 million of borrowings outstanding from the. Pool. At December 31, 1996, CL&P had no borrowings outstanding from the Pool. The interest rate on borrowings from the Pool on December 31, 1997 was 5.8 percent.
l Maturities of short-term debt obligations were for periods of l l three months or less. For further information on short-term debt, including the ability to access these agreements, see the MD&A.
l 6. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION l
Details of preferred stock not subject to mandatory redemption are. ,
i l December 31, Shares l' 1997 Outstanding Redemption December 31, December 31, l Descriotion Price 1997 1997 1996 1995 l
(Thousands of Dollars) I
$1.90 Series of 1947 $52.50 163,912 $ 8,196 $ 8,196 $ 8,196
$2.00 Series of 1947 54.00 336,088 16,804 16,804 16,804
$2,04 Series of 1949 52.00 100,000 5,000 5,000 5,000 l
$2.06 Series E of 1954 51.00 200,000 10,000 10,000 10,000
$2.09 Series F of 1955 51 00 100,000 5,000 5,000 5,000
$2.20 Series of 1949 S2.50 200,000 10,000 10,000 10,000
$3.24 Series G of 1968 51.84 300,000 15,000 15,000 15,000 3.90% Series of 1949 50.50 160,000 8,000 8,000 8,000 4.50% Series of 1956 50.75 104,000 5,200 5,200 5,200 4.50% Series of 1963 50.50 160,000 8,000 8,000 8,000 ,
4.96% Series of 1958 50.50 100,000 5,000 5,000 5,000 5.28% Series of 1967 51.43 200,000 10,000 10,000 10,000 6.56% Series of 1968 51.44 200,000 10,000 10,000 10,000 l Total preferred stock i
not subject to mandatory redemption $116,200 $131 1 200 $116,200 l .'All or any part of each outstanding series of such preferred stock .
may be redeemed by CL&P at any time at established redemption prices plus accrued dividends to the date of redemption.
i t
i i i a
23
The Connecticut Light and Power Company and Subsidiaries i NOTES TO CONSOLIDATED FINANCIAL STATEMENTS i 7. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION ,
{- l l
Details of preferred stock subject to mandatory redemption are: i December 31, Shares )
, 1997 Outstanding j Redemption December 31, December 31, Descriotion Price
- 1997 1997 1996 1995 (Thousands of Dollars) l 7.23% Series of 1992 $52.41 1,500,000 $ 75,000 $ 75,000 $ 75,000 l
- 5. 3 0%- Series of 1993 51.00 1,600,000 80,000 80,000 80,000 155,000 155,000 155,000 Less prefe ered stock to be redeemed within one year'.... 75,000 3,750 - -
Total preferred stock subject to mandatory redemption......... $151,250 $155,000 $155,000 l
- Each of these series is subject to certain refunding limitations
- for the first five years after they were issued. Redemption prices reduce in~ future years.
The following table details redemption and sinking fund activity for preferred stock-subject to mandatory redemption: ;
Minimum l Annual i Sinking-Fund _
Shares Reaccuired i Series. Reauirement 1997 1996 1995 (Thousand of Dollars)
.9.00% Series of 1989 $- - -
3,000,000 7.23% Series of 1992 (1) 3,750 - - -
5.30% Series of 1993 (2) 16,000 - - -
1 (1) Sinking fund requirements commence September 1, 1998.
(2) Sinking fund requirements commence October 1, 1999.
The minimum sinking-fund provisions of the series subject to mandatory redemption, for the years 1998 through 2002, aggregate approximately $3.8 million in 1998, and $19.8 million for 1999 through 2002. There were no minimum sinking-fund provisions in 1997. In case of default on sinking-fund payments, no payments I may he made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If CL&P is in arrears in the payment of ' dividends on any outstanding shares of preferred stock, CL&P would be .
prohibited from . redeeming or purchasing less than all of the preferred stock outstanding. All or part of each of the series named above may be -redeemed by CL&P at any - time at established 24
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATBD FINANCIAL STATEMENTS redemption prices plus accrued dividends to the date of redemption, subject to certain refunding limitations.
- 8. LONG-TERM DEBT Details of long-term debt outstanding are:
December 31, 1997 1996 First Mortgage Bonds:
(Thousands of Dollars) 7 5/8% Series UU due 1997............. $ -
$ 193,288
.6 1/2% Series T due 1998............. 20,000 20,000 7.1/4% Series VV due 1999............. 99,000 99,000 5 1/2% Series A due 1999............. 140,000 140,000 5 3/4% Series XX due 2000............. 200,000 200,000 7 7/8% Series A due 2001............. 160,000 160,000 7 3/4% Series C due 2002............. 200,000 -
6 1/8% Series B due 2004............. 140,000 140,000 7 3/8% Series TT due 2019............. 20,000 20,000
' 7 1/2% Series YY due 2023............. 100,000 100,000 8 1/2% Series C due 2024............. 115,000 115,000 7 7/8% Series D due 2024............. 140,000 140,000 7 3/8% Series ZZ- due 2025............. 125,000 125,000 Total First Mortgage Bonds...... 1,459,000 1,452,288 Pollution Control Notes:
Variable rate, due 2016-2022.......... 46,400 46,400 Variable tax exempt, due 2028-2031.... 377,500 377,500 Fees and interest due for spent fuel disposal costs (Note 2M)......... 166,458 157,968 Other................................... 86 10,915 Less amounts due within one year........ 20,011 204,116 Unamortized premzum and discount, net... (6,117) (6,550)
Long-term debt,, net................... 1 023,316 $1,834,405 Long-term debt and cash sinking-fund requirements on debt outstanding at December 31, 1997 for the years 1998 through 2002 are approximately $20.0 million, $239.0 million, *';00.0 million,
$160.0 million and $200.0 million, respectively. Tne one-percent sinking- and improvement-fund requirements for CL&P first mortgage bonds are no longer required, as of 1997, as determined by a majority of bondholders.
All or any part of each outstanding series of first mortgage bonds may be redeemed by CL&P at any time at established redemption prices plus accrued interest to the date of redemption, except
! certain series which are subject to certain refunding limitations during their respective initial five-year redemption periods.
J Essentially all of CL&P's utility plant is subject to the lien of its first mortgage bond indenture. As of December 31, 1997 and 1996, CL&P has secured $315.5 million of pollution control notes with second mortgage liens on Millstone 1, junior to the ..ien of 25 l
i
'The Connecticut Light and Power' Company and Subsidiaries l
WOTES TO CONSOLIDATED FINANCIAL STATEMENTS ,
its first mortgage bond indenture. The average effective interest rate on the variable-rate pollution control notes ranged from 3.6 t percent to 3.7 percent for 1997 and from 3.4 percent to 3.6 percent for 1996. -
I CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds
~
I with a bond' insurance and liquidity facility secured by First Mortgage Bonds.
l l
- 9. INCOME TAX EXPENSE The components or the federal and state income tax provisions l
. (credited) / charged to operations are:
For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated)
(Thousands of Dollars)
Current-income taxes:
Federal..................... $(53,339) $ 30,650 $ 93,906 State....................... (3,270) 9,789 37,898 Total current............. (56,609) 40,439 131,804 Deferred income taxes, net: l Federal..................... 8,436 (22,866) 52,075 i State....................... (11,470) (9,409) 5,085 !
Total deferred............ (3,034) (32,275) 57,160 Investment tax credits, net... (7.366) (7.367) (7,640)
Total income tax (credit)/ expense.......... $ (67,009) $ 797 $181,324 The components.of total income tax expense are classified as follows:
Income taxes charged to l
operating expenses.......... $(59,436) $ 957 $178,346 Other income taxes............ (7,573) _ (160) 2,978 Total ineome tax (cred t ) / expense . . . . . . . . . . . . . , $(67,009) $ 797 $181,324
{
l l
l' l
4 l
26
The Connecticut Light and Power Company and Subsidiaries
' NOTES'TO CONSOLIDATED FINANCIAL STATEMENTS Deferred income taxes are comprised of the tax effects of temporary differences as follows:
For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated)
(Thousands of Dollars)
Depreciation, leased nuclear fuel, settlement credits and disposal costs................ $ 11,991 $ 3,981 $44,278 Energy adjustment clauses....... (14,039) (1,654) 23,302 Demand-side management.......... (12,408) (17,099) 1,310 Nuclear plant deferrals......... 14,007 (18,861) (8,055)
Bond redemptions................ (1,339) (1,789) (2,255)
Contractual settlements......... 1,754 2,513 (9,496)
Pension accruals................ 6,524 2,944 5,382 State net operating loss carryforwards........... .... (7,670) - -
Other..~........................ (1,854) (2,310) 2,694 Deferred income taxes, net...... $ ( 3 , Q{,) $ (32,275) $57,160 A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows:
For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated)
(Thousands of Dollars)
Expected federal income tax at 35 percent of pretax income... $ ( 72,312 ) $ (18,257) $135,289 Tax effect of differences:
State income taxes, net of federal benefit............. (8,966) 248 27,939 Depreciation.......... ....... 19,701 21,313 23,517 Deferred nuclear plants return (30) (444) (1,639)
Amortization of regulatory assets .......... 3,901 8,601 20,218 Property tax.................. - -
(159) .
Investment tax credit amortization................ (7,366) (7,367) (7,640)
Adjustment for prior years' l
taxes....................... (10) -
(10,442)
Othe1, net.................... (1,927) (3,297) (5,759)
Total income tax (credits)/ expense............. $ (67,009) $ 797 $181,324 10 . - EMPLOYEE BENEFITS A. Pension Benefits t
l L The NU system's subsidiaries participate in a uniform
- noncontributory defined benefit retirement plan covering all l regular NU system employees. Benefits are based on years of j service and the employees' highest eligible compensation .
l l 27 l
I J
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-during 60 consecutive months of employment. CL&P's direct pcrtion of the NU system's pension credit, part of which was c.redited to utility plant, approximated $22.5 million in 1997, $8.8 million in 1996 and $10.4 million in 1995. The company's pension (credit) / costs for 1997, 1996 and 1995 included approximately $ (949) thousand, $2.8 million and $0.1 million, respectively, related to wor cforce reduction programs.
Currently, CL&P annually funds an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code.
Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds.
The components of net pension credit for CL&P are:
For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars)
Service cost.................. $ 7,888 $ 11,896 $ 7,543 Interest cost................. 37,939 37,226 37,110 Return on plan assets......... (148,830) (103,248) (138,582)
Net amortization.............. 80,507 45,300 83,516 Net pension credit............ $(22,496) $ (8.826) $ (10,413 )
For calculating pension cost, the following assumptions were used:
For the Years Ended December 31, 1997 1996 1995 Discount rate................. 7.755 7.50% 8.25%
Expected long-term rate of return.............. 9.25 8.75 8.50 Compensation / progression rate........................ 4.75 4.75 5.00 7
28
-l The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets:
At December 31, 1997 1996
, (Thousands of Dollars)
Accumulated benefit obligation, including vestad benefits at -
December 31, 1997 and 1996 of
$ (4 2 0,4 99,000) and $ (405,340,000)
. respectively.....................,. $ (4 51, 8 02 ) $ (434,473 )
Projected benefit obligation........ $ (531,564 ) $ (514, 989 )
Market value of plan assets......... 846,366 736.448 Market value in excess of projected
-benefit cbligation................ 314,802 221,459 Unrecognized transition amount...... (6,445) (7,365)
Unrecognized prior service costs.... 3,524 3,818 Unrecognized net gain............... (269,560) (198,088)
Prepaid pension asset............... $ 42,321 $ 19,824 The following actuarial assumptions were used in calculating the plan's year-end funded status:
At December 31, 1997 1996 Discount rate....................... 7.25% 7.75%-
Compensation / progression rate....... 4.25 4.75 B. Postretirement Benefits Other Than Pensions The NU system's subsidiaries provide certain health care benefits, prim'arily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the NU system who have met specified service requirements. For current employees and certain retirees, the total SEAS 106 benefit is limited to two times the 1993 per-retiree health care cost. The SEAS 106 obligation has been calculated based on this assumption. CL&P's direct portion . of SFAS 106 costs, part of which were deferred or charged to utility plant, approximated $12.8 million in 1997,
$17.9 million in 1996 and $20.7 million in 1995.
During 1997 and 1996, CL&P funded SEAS 106 postretirement costs through external trusts. CL&P is funding, on an annual basis, amounts that have been rate-recovered and which also are tax deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds.
29
Tho' Connecticut Light and Power Company and Subsidiaries j NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The components of health care and life insurance cost are:
i' For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars)
Service cost.................... $ 1,692 $ 2,270 $ 2,248 Interest cost................... 9,152 10,211 13,510 Return on plan. assets........... (7,755) (2,904) (1,015) ,
Amortization of unrecognized transition obligation......... 7,344 7,344 7,344 Other amortization, net......... .
2,370 956 602 Net health care and life insurance cost................ $12,803 $17,877 $20,689 For calculating SFAS 106 benefit costs, the following assumptions were used:
For the Years Ended December 31, 1997 1996 1995 Discount rate................... 7.75% 7.50% 3.00%
Long-term rate of return -
Health assets, net of tax..... 6.00 5.25 5.00
, Life assets................... 9.25 8.75 8.50 i
l The following table represents the plan's funded status L
reconciled to the Consolidated Balance Sheets: ;
At December 31, 1997 1996 (Thousands of Dollars)
Accumulated postretirement benefit obligation of:
Retirees.......................... $ (102,282) $ (109,299) !
l Fully eligible active employees... (219) (165) >
Active employees not eligible to retire....................... (24.075) (27,913)
Total accumulated postretirement benefit obligation............... (126,576) (137,377) ,
Market value of plun assets........ 46,055 38,783 I
Accumulated postretirement benefit obligation in excess of plan assets............s ........ (80,521) (98,594)
Unrecognized-transition amount..... 110,162 117,506 l
! Unrecognized net gain.............. (29,641) (18,912)
L ' Accrued postretirement benefit l liability........................ $ -
30 i
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following actuarial assumptions were used in calculating the plan's year-end funded status:
At December 31. 1997 1996 Discount rate...................... 7.25% 7.75%
Health care cost trend rate (a) .... 5.76 7.23 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 4.40 percent by 2001.
The effect of increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1997, by $7.3 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $563 thousand. The trust holding the health plan assets is subject to federal income taxes at a 39.6 percent tax rate. CL&P currently is recovering SFAS 106 costs through rates.
- 11. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES During 1996, CL&P entered into an agreement to sell up to $200 million of undivided ownership interests in eligible customer receivables and accrued utility revenues (receivables).
The FASB issued SFAS 125, " Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," in June 1996. SFAS 125 became effective on January 1, 1997, and establishes, in part, criteria for concluding whether a transfer of financial assets in exchange for consideration should be accounted for as a sale or as a secured borrowing. During October 1997, CL&P restructured its sales agreement to comply with the conditions of SFAS 125 and account for transactions occurring under this program as sales of assets. CL&P has established a special purpose, wholly owned subsidiary whose business consists of the purchase and resale of receivables. For receivables sold, CL&P has retained collection responsibilities as agent for the purchaser under CL&P's agreement.
As collections reduce previously sold receivables, new receivables may be sold. At December 31, 1997, approximately $70 million of receivables had been sold to a third-party purchaser by CL&P through the use of CL&P's special purpose, wholly owned subsidiary, CL&P Receivables Corporation (CRC). All receivables transferred to CRC are assets owned by CRC and are not available to pay CL&P's creditors.
For CRC's sales agreement with its third-party purchaser, the receivables are sold with limited recourse. CRC's sales agreement provides for a formula-based loss reserve in which additional receivables may be assigned to the third-party purchaser for costs 31 l
l
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS such as . bad debt. The third-party _ purchaser absorbs the excess amount in the event that actual loss experience exceeds the loss reserve. At December 31, 1997, approximately $7.2 million of assets had been designated as collateral by CRC. This amount represents the formula-based amount of credit exposure at December 31, 1997.
Historical losses for bad debt for- CL&P have been substantially less.
CL&P's accounts receivable program could be terminated if its senior secured debt is downgraded two more steps from its current ratings.
Concentrations of credit risk to the purchaser under the company's agreement with respect to the receivables are limited due to CL&P's diverse customer base within'its service territory.
For additional information on the accounts receivable program and CL&P's ability to utilize this program, see the MD&A.
- 12. COMMITMENTS AND CONTINGENCIES A. Restructuring and Rate Matters Although CL&P continues'to operate under cost-of-service based regulation, legislative restructuring initiatives during 1997 and 1998 in its jurisdiction has created some uncertainty with respect to future rates and the recovery of strandable investments and certain future costs such as purchase power obligations. Management is unable to predict the ultimate '
outcome of restructuring initiatives, however, it continues to believe that it is probable that CL&P will fully recover its prudently incurred costs, including regulatory assets and strandable investments based on the general nature of public ,
utility cost-of-service regulation.
For further information on restructuring, see Note 2H, " Summary of Significant Accounting Policies - Regulatory Accounting and ,
Assets," and the MD&A.
The DPUC is required to review a utility's rates every four years if there had not been a rate proceeding during such i period. The DPUC has conducted such a review. For information regarding this review and other rate matters, see the MD&A.
For information regarding the FERC rate proceedings for CYAPC l
and MYAPC, see Note 4, " Nuclear Decommissioning."
l B. Nuclear Performance Millstone: The three Mil' one units are managed by NNECO.
Millstone 1, 2 and 3 have 1 out of service since November 4, 1995, February 21, 1996, an( iarch 30, 1996, respectively, and l are on the Nuclear Regulatory Commission's (NRC) watch list. NU l has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units.
l l-32
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Subsequent to its January 31, 1996 announcement that Millstone had been placed on its watch list, the NRC stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 is currently in extended maintenance status.
Management cannot predict when the NRC will allow any of the Millstone units to return to service and thus cannot precisely estimate the total replacement power costs CL&P will ultimately incur. Replacement power costs incurred by CL&P attributable to the Millstone outages averaged approximately $23 million per month during 1997, and for 1998 are projected to average approximately $7 million per month for Millstone per month for Millstone 2 and $5 million per $7 million 3,
month for Millstone 1 while the plants remain out of service. CL&P will continue to expense its replacement power costs in 1998.
Based dates, on the current estimates of expenditures and restart management believes the NU system has sufficient resources related to fund power replacement the restoration costs. of the Millstone units and If the return to service of Millstone restart 3 or 2 is delayed substantially beyond the present estimates, if some financing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if CL&P and WMECO encounter . additional significant costs or if any other significant deviations from management's assumptions occur, CL&P and WMECO could be unable to meet their cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and attempt to obtain additional sources of funds. The availability of these funds would be dependent upon general market conditions and CL&P's and WMECO's respective credit and financial conditions at that time.
For information regarding Millstone restart costs, see the MD&A.
For information concerning the ability of CL&P to access its borrowing facilities, see the MD&A.
Li tiga tion: CL&P and WMECO, th.cugh NNECO as agent, operate Millstone 3 at cost, and without profit, under a sharing agreement that obligates them to utilize good utility operating practice and requires the joint owners to share the risk of employee negligence and other risks of operation and maintenance pro-rata in accordance with their ownership shares. This agreement also provides that CL&P and WMECO would be liable only 33
.. - . . - .- - ~ . - - - - - . . , - . . . - _ - . . . . - - - - - -
I The Connecticut Light and Power Company and Subsidiaries l NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1 for damages to the non-NU owners for a deliberate violation of -
the agreement pursuant to authorized corporate action.
On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims arising out of the operation of ,
Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two-thirds of the non-NU interests in Millstone 3 claimed compensatory damages in excess of $200 million. In addition, one of the lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP, pending the outcome of the lawsuit.
Management cannot estimate the potential outcome of these suits but believes there is no legal basis for the claims and intends to defend against them vigorously. To date, no reserves have been established for this litigation. At December 31, 1997, the NU system's costs related to this litigation were estimated to be approximately $100 million for incremental O&M costs and approximately $100 million for replacement power costs. These costs are likely to increase as long as Millstone 3 remains out .
I of service.
The Connecticut Municipal Electric Energy Cooperative (CMEEC) and CL&P have been negotiating since May 1996 over issues related to the operation of Millstone 1 and 2. CMEEC has failed to make payments on its accrued obligations since October 1996, claiming that CL&P materially breached its contractual obligations. CL&P has denied the allegations and requested payment. The matter has gone to arbitration which has been scheduled for July 1998.
CL&P has filed an application with the Connecticut Superior Court in Hartford requesting the court to grant interim relief to CL&P. CL&P has asked the court to enforce the contract provisions by ordering CMEEC to pay the outstanding obligations under the contract (approximately $25 million) and to continue
' making payments (approximately $1.8 million per month) during the arbitration process.
On December 9, 1997, the Superior Court judge issued a decision denying CL&P's request for an interim payment order. Management cannot predict the outcome of this litigation and has taken steps to assert its legal rights. CL&P has requested '
reargument, in order to present evidence, and has requested that the Connecticut Superior Court vacate its order. CL&P is prepared to appeal to a higher court, if necessary, after the reargument.
C. Environmental Matters The NU system is subject to regulation by federal, state and local authorities with respect to air and water quality, the ,
34
The Connecticut Light and Power Company and Subsidiaries
~
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS handling and - disposal of toxic substances and hazardous and. i solid wastes, and the handling and use of chemical products.
The NU system has an-active environmental auditing and training '
program and believes that it is in substantial compliance with current environmental laws and regulations. However, the NU system is subject to certain pending enforcement actions and governmental investigations _in the environmental area.
Management cannot predict the outcome of these enforcement actions and investigations.
Environmental requirements-could hinder the construction of new generating units, transmission and distribution lines, substations and other facilities. Changing environmental requirements could also require extensive and costly modifications to CL&P's existing generating units and transmission and distribution systems, and could raise operating costs significantly. As a result, CL&P may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation and disposal of byproducts and wastes. CL&P may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot be estimated accurately.
CL&P has recorded a liability based upon currently available information for what it believes are its estimated environmental remediation costs that it expects to incur for waste disposal sites. In most cases, additional future l environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 1997, the net liability recorded by CL&P for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $6.4 million, which management has determined to be the most probable amount within the range of $6.4 million to $16.4 million.
During 1997, CL&P adopted . Statement of Position 96-1,
" Environmental Remediation Liabilities" (SOP) . The principal objective of the SOP is to improve the manner in which existing authoritative accounting literature is applied by entities to specific situations of recognizing, measuring and disclosing environmental remediation liabilities. The adoption of the SOP resulted in an increase of approximately $395 thousand to CL&P's )
environmental reserve in 1997.
CL&P cannot estimate the potential liability for future claims, l including environmental remediation costs, that may be brought l against it. However, considering known facts, existing laws and 35
i l
l The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS l
regulatory practices, management does not believe the matters disclosed above will have a material effect on CL&P's financial position or future results of operations.
D. Nuclear Insurance Contingencies Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities in the country covered by the federal government's third-party liability indemnification program, an owner of a nuclear unit could be assessed in proportion to its ownership interest in each of its nuclear units up to $75.5 million. Payments of this assessment would be limited to $10.0 million in any one year per nuclear incident based upon the owner's pro rata ownership interest in each of its nuclear units. In addition, the owner would be subject to an additional five perecnt or $3.8 million, in proportion to its ownership interests in cach of its nuclear units, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection. Based upon its ownership interests in Millstone 1, 2 and 3 and in Seabrook 1, CL&P's maximum liability, including any additional assessments, would be $173.6 million per incident, of which payments would be limited to $21.9 million per year. In addition, through power purchase contracts with MYAPC, VYNPC, and CYAPC, CL&P would be responsible for up to an additional $44.4 million per incident, of which payments would be limited to $5.6 million per year.
Insurance has been purchssed to cover the primary cost of repair, replacement or decontamination of utility property resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against CL&P with respect to losses arising during the current policy year is approximately $11.5 million under the primary property insurance program.
l Insurance has been purchased to cover certain extra costs incurred in obtaining replacemen power during prolonged accidental outages and the excess cosc of repair, replacement or decontamination or premature decommissioning of utility property resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against CL&P with respect to losses arising during current policy years are approximately $9.5 million under the replacement power policies and $15.6 million under the excess property damage, decontamination and decommissioning policies.
The cost of a nuclear incident could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating i reactor operators insured under this coverage are subject to retrospective assessments of $3 million per reactor. The maximum potential assessment against CL&P with respect to losses 36
J The Connecticut Light and Power Company end subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS arising during the current policy period is approximately $8.9 million. Effective January 1, 1998, a new worker policy was ;
purchased which is not subject to retrospective assessments.
E. Construction Program ,
The construction program is subject to periodic review and l revision by management . CL&P currently forecasts construction j expenditures of approximately $1.3 billion for the years 1998-2002, including $164.9 million for 1998. In addition, CL&P estimates that nuclear fuel requirements, including nuclear fuel i financed through the NBFT, will be approximately $247.7 million for the years 1998-2002, including $37.6 million for 1998. See i Note 3, " Leases," for additional information about the financing of nuclear fuel.
F. Long-Term Contractual Arrangements Yankee Companies: CL&P, WMECO and PSNH rely on VY for approximately 1.7 percent of their capacity under long-term contracts. Under the terms of their agreements, the NU system companies pay their ownership (or entitlement) shares of costs which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning and a return on invested capital. These costs are recorded as purchased power expense and are recovered through the company's rates. CL&P's total cost of purchases ;
under contracts with VYNPC amounted to $14.1 million in 1997, l
$14.8 million in 1996 and $14.7 million in 1995.
The other Yankee generating facilities, MY, CY and Yankee Rowe, were permanently shutdown as of August 6, 1997, December 4, 1996 and February 26, 1992, respectively. See Note 2E, " Summary of Significant Accounting Policies - Investments and Jointly Owned Electric Utility Plant , " for further information on the Yankee companies, and Note 4, " Nuclear Decommissioning," regarding the related decommissioning obligations.
Nonu tili ty Generators: CL&P has entered into various arrangements for the purchase of capacity and energy from nonutility generators (NUGs). These arrangements have terms from 10 to 30 years, currently expiring in the years 2001 through 2028, and require CL&P to purchase energy at specified prices or formula rates. For the 12-month period ending December 31, 1997, approximately 14 percent of NU system electricity requirements wan met by NUGs. CL&P's total cost of purchases under these arrangements amounted to $283.2 million in 1997,
$279.5 million in 1996 and $282.2 million in 1995. These costs may be deferred for eventual recovery through rates.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities.
37
The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Estimated Annual Costs: The estimated annual costs of CL&P's significant long-term contractual arrangements are as follows:
1998 1999 2000 2001 2002_
(Millions of Dollars)
VYNPC............. $ 16.8 $ 16.9 $ 16.2 $ 17.7 $ 18.4 NUGs.............. 281.0 291.5 290.9 295.5 299.6 Hydro-Quebec...... 18.5 17.9 17.6 17.1 16.7 For additional information regarding the recovery of purchased power costs, see Note 2J, " Summary of Significant Accounting Policies -
Recoverable Energy Costs."
- 13. MARKET RISK MANAGEMENT CL&P uses swap, collar, put and call instruments with financial institutions to hedge against some of the fuel price risk created by long-term negotiated energy contracts and nuclear replacement power generation and fuel purchases. These agreements minimize exposure associated with rising fuel prices by managing a portion of CL&P's cost of fuel for these negotiated energy contracts and nuclear replacement power generation and fuel purchases. As of December 31, 1997, CL&P had outstanding agreements with a total notional value of approximately $327 million, and a negative mark-to-market position of approximately $21 million.
The terms of the agreements require CL&P to post cash collateral with its counterparties in the event of negative mark-to-market positions and lowered credit ratings. The amount of the collateral is to be returned to CL&P when the mark-to-market position becomes positive, when CL&P meets specified credit ratings or when an agreement ends and all open positions are properly settled. At December 31, 1997, cash collateral in the amount of $15.4 million was posted under these terms, which is included in other, at cost, on the accompanying Consolidated Balance Sheets.
These agreements have been made with various financial institutions, each of which is rated "Al" or better by Moody's rating group. CL&P will be exposed to credit risk on its fuel price management instruments if the counterparties fail to perform their obligations.
However, management anticipates that the counterparties will be able to fully satisfy their obligations under the agreements.
- 14. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY CL&P Capital LP (CL&P LP., a subsidiary of CL&P) had previously issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent- to the MIPS issuance, CL&P LP 38
The Connecticut Light and Power company and Subsidiaries NOTES TO CONSOLIDATBD FINANCIAL STATEMENTS loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the unsecured debenture. form of an CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is elin.inated interests.
and the MIPS securities are accounted for as minority
- 15. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Cash and nuclear decommissioning trusts: The carrying amounts approximate fair value.
SFAS 115,
" Accounting for Certain Investments in Debt and Equity securities," requires investments in debt and equity securities to be presented at fair value. As a result of this requirement, the investments held in CL&P's nuclear decommissioning trusts were adjusted to market by approximately $49.2 million as of December 31, 1997, and $22.3 million as of December 31, 1996, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 1997 and 1996 represent cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for both 1997 and 1996.
Preferred stock and long-term debt: The fair value of CL&P's fixed rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value.
The carrying amounts of CL&P's financial instruments and the estimated fair values are as follows:
Carrying Fair At December 31. 1997 Amount Value (Thousands of Dollars)
Preferred stock not subject to mandatory redemption................ $ 116,200 $ 62,889 Preferred stock subject to mandatory redemption................... 155,000 135,600 Long-term debt -
First Mortgage Bonds................... 1,459,000 1,435,772 Other long-term debt................... 590,443 590,443 MIPS..................................... 100,000 100,760 39
. . - . . .. -- .. . . . _ ~ . - . , . _ _ , - - . - ... .-
The Connecticut' Light and Powsr Company and Subsidiaries NOTES TO CONSOLIDATED' FINANCIAL STATEMENTS Carrying Fair At December 31. 1996 Amount Value (Thousands of Dollars)
. Preferred stock not subject
.to mandatory redemption'................ $ 116,200 $ 111,845 t
Preferred stock subject to mandatory redemption................... 155,000 120,900 ,
Long-term debt -
First Mortgage Bonds................... 1,452,288 1,410,665 Other long-term debt................... 592,783 592,783 MIPS...................................... 100,000 108,520 The fair values shown above have been reported to meet disclosure requirements and do not . purport to represent the amounts at which those obligations would be settled.
d 40
\
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l The Connecticut Light and Power Company and Subsidiaries ,
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of The Connecticut Light and Power Company: ;
l We have audited-the accompanying consolidated balance sheets, as j restated - See Note 1, of The Connecticut Light and Power Company l and Subsidiaries (a Connecticut corporation and a wholly owned l subsidiary of Northeast Utilities) as of December 31, 1997 and
! 1996, and the related consolidated statements of income, common l stockholder's equity and cash flows, as restated - see Note 1, for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the ,
Company's management. Our responsibility is to express an l
opinion on these financial statements based on our audits.
l.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether l the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An l audit also includes assessing the accounting principles used and
- significant estimates made by management, as well as evaluating :
the overall- financial statement presentation. We believe that I our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above l
present fairly, in all material respects, the financial' position of The Connecticut Light and Power Company and Subsidiaries as of I
'ecember 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted l accounting principles.
As explained in Note 1 to the consolidated financial statements, the company has given retroactive effect to the change in accounting for nuclear compliance costs.
/s/ ARTHUR ANDERSEN LLP i ARTHUR ANDERSEN LLP Hartford, Connecticut
. February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998).
4 4
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f The Connecticut' Light and Power Company l
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OTERATIONS I
This section contains management's assessment of CL&P's (the company) financial condition and the principal factors having an impact on the results of operations. The company is a wholly-owned subsidiary of ;
Northeast Utilities (NU). This discussion should be read in conjunction I with the company's consolidated financial statements and footnotes.
FINANCIAL CONDITION i
Overview The length of the ongoing outages at the three Millstone nuclear plants (Millstone) and the high costs of the recovery efforts weakened i CL&P's 1997 net income, balance sheet and cash flows and will continue I to have an adverse impact on the company's financial condition until !
the units are returned to service.
CL&P had a net loss of approximately $140 million in 1997, compared to a net loss of approximately $51 million in 1995. The poorer financial results in 1997 were due primarily to the fact that all three Millstone units were off line for the entire year in 1997 and spending associated with the recovery efforts was significantly higher in 1997 than it was in 1996. Millstone 3 operated for nearly three months in 1996 and Millstone 2 for nearly two months. As a result, the cost of replacing power ordinarily generated by the Millstone units rose by approximately $65 million in 1997. The total operation and maintenance (O&M) costs at Millstone were approximately $173 million higher in 1997. {
The higher Millstone costs have caused CL&P to focus closely on maintaining adequate liquidity and reducing nonnuclear O&M costs. In June 1997, CL&P successfully sold $200 million in first mortgage bonds. CL&P's access to $225 million of revolving credit lines was j renegotiated in the first half of 1997. Also helping to maintain liquidity was the renegotiation in early 1998 of a $100 million credit line used by Niantic Bay Fuel Trust (NBFT) to purchase nuclear fuel for Millstone. Additionally, nonnuclear O&M expenses in 1997 were reduced by about $30 million from 1996.
The SEC has advised CL&P to adjust for certain costs associated with the ongoing Millstone outages as they are incurred. For the past two j years, CL&P has been reserving for the unavoidable costs they expected I to incur to meet NRC requirements. These annual staterants have been !
adjusted in accordance with the SEC's directive. Manageaent does not expect implementation of this accounting change to affect the ability i of CL&P and Western Massacnusetts Electric Company (WMECO) to meet )
their financial covenants contained in their $313.75 million revolving i credit arrangement. j i
I 42 !
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_ ._ __ _ . _ . _ . _ . _ _ _ _ _ . . - m... __.~_.__.-._-.m _._._.m_._ _
In 1998, management expects Millstone-related expenses to fall significantly, assuming Millstone 3 and Millstone 2 are returned to service at dates close to current estimates, although the o&M expenses at Millstone 3 and 2 will be considerably higher than before the station was placed on the . Nuclear Regulatory Commission's (NRC's) watch list. The actual level of 1998 nuclear spending at Millstone will depend on when the units return to operation and the cost of restoring them to service. The company hopes to restart Millstone 3, the newest and largest unit at the site, in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. The company cannot restart the Millstone units until it receives formal approval from the NRC. As part of an effort to reduce spending in 1998, Millstone 1 has been placed in extended maintenance status. Management l
will review its options with respect to Millstone 1 in 1998, including restart, early retirement and other options.
Rate reductions to customers served by CL&P are likely to offset a portion 1998, of the. benefit of lower Millstone-related costs. On March 1, CL&P's rates were reduced by approximately 1.4 percent to reflect the removal of Millstone 1 from rates, and additional non cash l
' reductions were made to revenue requirements as a result of an interim ,
rate order issued by the Connecticut Department of Public Utility Control (DPUC). A pending CL&P rate case may result in additional
! rate adjustments later in 1998. CL&P's revenues could be further reduced if substantial-delays in restarting Millstone 3 and Millstone 2 result in a DPUC decision to remove those' units from rates.
In addition to focusing on maintaining liquidity, management also must i attend to industry restructuring efforts in Connecticut. Restructuring i legislation is being considered in the Connecticut legislative session that began in February 1998.
l In 1997, CL&P experienced modest economic growth in its retail sales that was offset by the effects of mild winter weather. In 1998, management expects that the Connecticut economy will continue to experience modest growth.
Millstone Outages
- CL&P has an 81-percent ownership interest in Millstone units 1 and 2 l l and a 52.93-percent ownership interest in Millstone unit 3.
Millstone 1, 2 and 3 have been out j
! of service since November 4, 1995, February 21, 1996, and March 30, 1996, respectively. ;
i I Subsequent to its January 31, 1996, announcement that Millst- 'e had {
been placed on its watch list, the NRC has stated that thu units cannot return to service until independent, third-party verification !
! teams have reviewed the actions taken to improve the design, l
configuration and employee concern issues that prompted the NRC to i place the units on its' watch list. The actual date of the return to l service for each of the units is dependent upon the completion of f
- independent inspections, reviews by the NRC and a vote by the NRC j Commissioners. t 43
In January 1998, NU declared Millstone 3 physically ready for restart, which meant that almost all of the restart-required physical work had been completed in the plant. The NRC currently is conducting a series of inspections to determine, among other things, whether the plant has effective leadership and corrective action and employee concerns programs. .The Independent Corrective Action Verification Program, an NRC-ordered independent review of the plant's design and licensing bases, is expected to be completed in March 1998.
In 1997, CL&P's share of nonfuel O&M costs expensed for Millstone increased to approximately $445 million, compared to approximately
$272 million in 1996.
CL&P's portion of replacement power costs attributable to the Millstone outages totaled approximately $281 million in 1997 compared to $216 million expensed in 1996. These costs for 1998 are forecasted to average . approximately $7 million per month for Millstone 3, $7 million per month for Millstone 2 and $5 million per month for Millstone 1 while the plants are out of service.
CL&P has been, and will continue to be, expensing all of the costs to restart the units including replacement power and nonfuel O&M l expenses. See " Rate Matters" for issues related to the recovery of Millstone 1 costs.
NU.and its subsidiaries are involved in several class action lawsuits l- and other litigation in connection with their nuclear operations. See the " Notes to Consolidated Financial Statements," Note 12B, for further information on this litigation.
Millstone 1 i
Management will review its options with respect to Millstouc 1 during i 1998. The issues that management will consider in evaluating its options include the costs to restart the unit, the economic benefits of the unit's continued operation and certain Connecticut state law l issues. In the CL&P four year rate review proceeding, (discussed in l
detail under " Rate Matters"), the DPUC noted that CL&P may not be able l
to recover its remaining investment in Millstone 1 if the DPUC were to
! determine ~ that the unit. had been prematurely shut down due to l management imprudence- . Additionally, there is a Connecticut statute l which may limit CL&P's ability to collect decommissioning charges in l the future if Millstone 1 were to be prematurely retired. -
! r CL&P's net unrecovered Millstone 1 plant cost and the unrecovered decommissioning costs at December 31, 1997, were approximately $216 million'and $198 million, respectively.
Capacity 4
During 1996 and continuing into 1997, CL&P ' took measures to improve 1 its capacity position, including obtaining additional generating
. capacity, improving the availability of CL&P's generating units and l improving its transmission capability. During 1997, CL&P spent f approximately $48 million to ensure availability of adequate generating capacity in Connecticut, of which $35 million was expensed.
44 l
In 1998, CL&P does not anticipatc the need to take additional measures to ensure adequate generating capacity.
CL&P. could incur up to an additional $50 million in 1998 for incremental capacity purchres to meet NEPOOL requirements as a result j of the Millstone outages.
Liquidity and Capital Resources
(
Cash provided from operations decreased approximately $227 million in 1997, compared to 1996, primarily due to higher cash expenditures related to the Millstone outages, and the pay down in 1997 of the 1996 year end accounts payable balance. The 1996 year end accounts payable balance was relatively high due to costs related to a severe December storm and costs ' associated with the Millstone outages that had been incurred but not yet paid by the end of 1996. Net cash from financing activities increased approximately $69 million, primarily due to an increase in short-term borrowings and lower cash dividends on common i shares, partially offset by higher long-term debt retirements. Cash used for investments decreased approximately $158 million, primarily due to lower investments in the NU system Money Pool, partially offset by higher capital expenditures and an increase in special deposits.
CL&P established facilities in 1996 under which it may sell, from time to time, up to $200 million of its account.a receivable and accrued utility revenues. As of December 31, 1997, CL&P sold approximately
$70 million of receivables to third-party purchasers.
NU's, CL&P's and WMECO's three-year revolving credit agreement was amended in May 1997 (the Credit Agreement). Under the Crecit Agreement, CL&P and WMECO are able to borrow up to approximately $225 million and $90 million, respectively, subject to a total borrowing limit of $313. '5 million for all three borrowers. NU will be able to borrow up to $50 million when NU, CL&P and WMECO have each maintained a consolidated operating income to consolidated interest expense ratio of at least 2.50 to 1 for two consecutive fiscal quarters. Currently, the companies cannot meet this requirement. At December 31, 1997, CL&P had $35 million outstanding under the Credit Agreement.
Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has any financing agreements containing cross defaults based on financial defaults by NU, Public Service Company of New Hampshire (PSNH) or North Atlantic Energy Corporation (NAEC). Nevertheless, it is possible that investors will take negative operating results or regulatory developments for one subsidiary of NU into account when evaluating the other NU subsidiaries. That could, as a pract.ical matter and despite the contractual and legal separations among NU and its subsidiaries, negatively affect the company's access to financial markets.
In December 1997 and January 1998, Moody's Investors Service (Moody's) and Standard & Poor's (S&P), respectively, downgraded the senior secured debt of CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO. This was the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since the Millstone units went on h the NRC watch list in 1996. All of NU system's securities are rated 45
below investment grade and remain under review for further downgrade.
CL&P's accounts receivable program could be terminated if its senior secured debt is downgraded two more steps from its current ratings.
Although CL&P does not have any plans to issue debt in the near term, rating agency downgrades generally increase the future cost of borrowing funds because lenders will want to be compensated for increased risk. Additionally, this could affect the terms and ability of the company to extend existing agreements.
CL&P's ability to borrow under the financing arrangements is dependent on the satisfaction of contractual borrowing conditions. The financial covenants that must be satisfied to permit CL&P and WMECO to borrow under the credit Agreement are particularly rectrictive and become more restrictive throughout 1998. Spending levels in 1998, particularly for the first half of the year while the Millstone units are expected to be out of service, will be constrained to levels intended to assure thz.t the financial covenants in CL&P's and 't!MECO's Credit Agreement are satisfied. However, there is no assurance that these financial covenants will be met as the system may encounter additional unexpected costs from such areas as storms, reduced revenues from regulatory actions or the effect of weather on sales levels.
If the return to service of Millstone 3 or Millstone 2 is delayed substantially beyond the present restart estimates, if some borrowing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if the system encounters additional significant costs, or any other significant deviations from management's current assumptions, the currently available borrowing facilities could be insufficient to meet all of CL&P's cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and would attempt to take other actions to obtain additional sources of funds. The availability of these funds would be dependent upon the general market conditions and CL&P's credit and financial condition at that time.
Restructuring CL&P continues to operate under cost-of-service based regulation, however, future rates and the recovery of strandable costs are issues that are being considered as part of broad restructuring legislation in the current Connecticut legislative session. Strandable costs are expenditures or commitments that have been made to meet public service obligations with the expectation that they would be recovered from customers in the future. CL&P has exposure to strandable costs for its investments in high-cost nuclear generating plants, state-mandated purchased power obligations and significant regulatory assets. The company's exposure to strandable investments and purchased power obligations exceeds its shareholder's equity. CL&P's financial strength and resulting ability to compete in a restructured environment will be negatively affected if the company is unable to recover its past investments and commitments. Even if the company is given the opportunity to recover a large portion of its strandable costs, earnings prospects in a restructured environment will be affected in ways which cannot be estimated at this time.
46 l
The company is seeking to mitigate the impacts of restructuring by l proposing stable, lower rates, while pursuing customer choice options i
and full recovery of its strandable costs. The company's strategy to recover strandable costs includes efforts to promote state legislation that will authorize the issuance of rate reduction bonds that would refinance these investments and which would be repaid through non-bypassable charges to customers. Management is unable to predict the ultimate outcome of these initiatives which will be subject to regulatory and legislative approvals. Management believes it is l entitled to full recovery of its prudently incurred costs, including '
regulatory assets and other strandable costs. See the " Notes to
- Consolidated Financial Statements," Note 2H, for the potential accounting impacts of restructuring.
Rote Matters In July 1996, the DPUC approved a rate settlement agreement with CL&P (the Settlement). Under the Settlement, CL&P froze base rates until at least December 31, 1997, and agreed to accelerate the amortization of regulatory assets during the period that the rate freeze remains in effect. The Settlement provided that CL&P's target return on equity (ROE) would be 10.7 percent but did not alter CL&P's allowed ROE of 11.7 percent. If CL&P's actual ROE for a calendar year exceeds 10.7 percent after the target regulatory asset amortization ($68 million in 1997) and after adjustment for any incremental NRC billings and any rate disallowances for nuclear operations, then CL&P shall retain two-thirds of any surplus and use the remaining one-third to provide a reduction in bills. CL&P's actual ROE, as adjusted, fell below the target ROE for 1996 and 1997 and, therefore, the accelerated amortization of regulatory assets was reduced to the minimum amounts l allowed under the Settlement ($73 million in 1996 and $54 million in '
1997) For each full year that the rate freeze remains in effect, CL&P agreed to amortize an additional $44 million of regulatory assets.
On July 30, 1997, the DPUC issued a decision in its prudence review of nuclear cost recovery issues disallowing CL&P's recovery of all of the l replacement power costs associated with the ongoing outages at l Millstone. CL&P has expensed, and will continue to expense, replacement power costs for the Millstone outages as they are incurred.
The DPUC is required to review a utility's rates every four years if there has not been a rate proceeding during such period. In 1997, the DPUC conducted such.a review of CL&P's rates, including an analysis of the possibility of removing one or more of the Millstone nuclear units from CL&P's rate base. On December 31, 1997, the DPUC issued its ruling in this matter. The decision did not effect a change in CL&P's rates, but set forth findings and conclusions that could be used to do
- so in additional proceedings. The most significant conclusion was j that Millstone 1 should be removed from CL&P's rate base, which would l cause an annual revenue reduction of approximately $30.5 million. The
- decision stated that the DPUC would open an interim rate case l immediately to remove Millstone 1 from CL&P's rates and simultaneously l
to remove an additional $110.5 million of other expenses from rates related to perceived overearnings. On February 25, 1998, the DPUC 47
issued a decision reducing CL&P's rates by approximately 1.4 percent to reflect the removal of Millstone 1 from rates. This reduction reflects the removal from rates of O&M, depreciation and investment l return related to Millstone 1, net of replacement power costs. In addition, the decision requires CL&P to accelerate the amortization of regulatory assets by $110.5 million, which includes the $44 million from the 1996 Settlement. The interim rate reduction became effective on March 1, 1998.
CL&P also was directed to file a full rate case on June 1, 1998, to address potential overearnings amounting to an additional $150 million in 1998. The effective date of any rate order will be September 28, 1998. In addition, the DPUC has scheduled hearings for April 1, 1998
! to determine the status of Millstone 3 and Millstone 2. If the units are not operating by that date, the DPUC will consider their removal from rates. A similar restart status hearing is anticipated for
! June 1, 1996.
The DPUC also will consider CL&P's analyses of the economic benefits
- of the continued operation of Millstone 1 and 2 in the context of
( CL&P's next integrated resource planning proceeding, which begins in April 1998.
Nuclear Decommissioning l
l Connecticut Yankee CL&P has a 34.5 percent ownership interest in the Connecticut Yankee nuclear generating facilit; (CY or the plant). On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease permanently the production of power at the
! plant. The decision to retire CY from commercial operation was based
! on an economic analysis of the costs of operating it compared to the i costs of closing it and incurring replacement power costs over the remaining period of the plant's operating license, which would have expired in 2007. The economic analysis showed that closing the plant and incurring replacement power costs produced substantial savings.
CY has undertaken a number of regulatory filings intended to implement the decommissioning. In late December 1996, CY filed an amendment to its power contracts with the FERC to clarify the obligations of its purchasing utilities following the decision to cease power production.
At December 31, 1997, CL&P's share of these obligations was approximately $214 million, including the cost of decommissioning and the recovery of existing assets. Management expects that the company will continue to be allowed to recover such FERC approved costs from its customers. Accordingly, CL&P has recognized its share of the estimated costs as a regulatory asset, with a corresponding obligation, on its balance sheets.
Maine Yankee CL&P has a 12 percent ownership interest in the Maine Yankee (MY) nuclear generating facility. On August 6, 1997, the Board of Directors of Maine Yankee Atomic Power Company (MYAPC) voted 48
unanimously to retire MY. On January :.4, 1998, FERC released a draft l order on the MYAPC application to amend its power contracts with the i
owner / purchasers and revise its decommissioning and other charges.
l FERC has accepted the proposed application for filing and made the amendments and the proposed charges under the contracts effective on l January 15, 1998, subject to refund after hearings. At December 31, !
1997, CL&P's share of the estimated remaining obligation, including decommissioning, terms amounted to approximately $104 million. Under the of the contracts with MYAPC, companies, including CL&P, the shareholders' sponsor are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects customers.
that CL&P will be allowed to recover these costs from it's Accordingly, CL&P has recognized these costs as a regulatory asset, with a corresponding obligation on its balance sheet.
l Millstone and Seabrook l
CL&P's estimated cost to decommission its shares of the Millstone plants and Seabrook is approximately $1.1 billion in year end 1997 dollars. These costs are being recognized over the lives of the ;
1 i
respective units with a portion currently being recovered through rates. As of December 31, 1997, CL&P's share of the market value of the contributions already made to the decommissioning trusts, including their investment returns, was ,5 proximately $369 million.
See the " Notes to Consolidated Financial Statements," Note 4, for further information on nuclear decommissioning, including the CL&P's share units.
of costs to decommission the other regional nuclear generat.ing Environmental Matters CL&P is potentially liable for environmental cleanup costs at a number of sites inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of CL&P. At December 31, 1997, CL&P had recorded an environmental reserve of approximately $6.4 million. See the " Notes to Consolidated Financial Statements," Note 12C, for matters.
further information on environmental Year 2000 Issue The Year 2000 issue exists because many computer systems and applic tiens As currently use two-digit date fields to designate a year.
change of the century occurs, date-sensitive systems may reco: i z- the year 2000 as 1900, or not recognize it at all. This inab: y to recognize or properly treat the year 2000 may cause NU's l
systems to process critical financial and operational information incorrectly. The NU system has assessed and continues to assess the impact of the Year 2000 issue on its operating and reporting systems.
The assessment of the nuclear operating systems is continuing and is expected to be completed in the summer of 1998.
49
The NU system will utilize both internal and external resources to reprogram or replace, and test the software for Year 2000 modifications. The total estimated remaining cost of the Year 2000 project for the NU system is $37 million and is being funded through operating cash flows. This estimate does not include any costs for the replacement or repair of equipment or devices that may be identified during the assessment process. The majority of these costs will be expensed as incurred over the next two years. To date, the NU system has incurred and expensed approximately $4 million related to the assessment of and preliminary efforts in connection with its Year 2000 project.
The costs of the project and the date on which the NU system plans to complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, and actual results could differ materially from those plans. If the NU system's remediation plan is not successful, there could be a significant disruption of the company's operations.
Risk-Management Instruments The following discussion about the company's risk-management activities includes forward-looking statements that involve risk an uncertainties. Actual results could differ materially from those projected in the forward-looking statements.
l This analysis presents the hypothetical loss in earnings related to the fuel price and interest rate market risks not covered by the risk-management instruments at December 31, 1997. The company uses swaps, i
collars, puts, and calls to manage the market risk exposures associated with changes in fuel prices and variable interest rates.
l The company does not use these risk-management instruments for speculative purposes. For more information on CL&P's use of risk management instruments, see the " Notes to Consolidated Financial Statements," Notes 13.
l l In the generation of electricity, the most significant variable cost
, component is the cost of fuel. Typically, most of CL&P's fuel purchases are protected by a regulatory fuel price adjustment clause.
However, for a specific, well-defined volume of fuel that is excluded l from the fuel price adjustment clause (unprotected volume), CL&P l employs fuel price risk-management instruments to protect itself i against the risk of rising fuel prices, thereby limiting fuel costs j and protecting its profit margins. These risks are created by the sale of long-term, fixed-price electricity contracts to wholesale customers and the purchase or generation of replacement power related to the ongoing Millstone nuclear outages.
At December 31, 1997, CL&P had outstanding agreements with a tota 2 notional value of approximately $327 million. The settlement amounts associated with the instruments reduced fuel expense by approximately
$7.8 million.
50
_- _ m ._. . _ _ _ _ _ _ _ _ _ _ _ . _ _ - _ - _._. _ . _ . _ _ _ _ _ _
i l CL&P has had experience using various fuel price risk-management instruments since 1994, most of which have been in the form of fuel price swaps. At December 31, 1997 approximately 30 percent of the unprotected volume was covered by fuel price risk-management instrument (hedge ratio) for 1997. This effectively fixed or bounded the fuel cost and thus eliminated the market price risk for this covered volume of fuel. At December 31, 1997, the company had a hedge ratio of 44 percent for 1998.
At December 31, 1997, the 56 percent uncovered. volume of fuel for 1998, as a result of-not being hedged, is subject to changes in actual market prices. Therefore, assuming a hypothetical 10 percent increase in the average 1997 price of fuel in 1998, the result would be a negative pre-tax impact on' earnings of approximately $12.4 million.
This analysis is based on the broad assumption that the entire uncovered volume of fuel remains constant and will be purchased the spot market. This assumption is subject to change as the uncovered volume of fuel likely will change during the next year. Other assumptions used in this analysis, projections of the fuel mix, the ,
l amount of long-term sales contracts or the projected Millstone restart '
dates, also are subject to change. 1 i
l RESULTS OF OPERATIONS !
Income Statement Variances (Millions of Dollars) '
1997 over/ (under) 1996 1996 over/ (under) 1995 i
l Amount Percent Amount Percent I Operating revenues $68 3% $ 10 -%
Fuel, purchased and net 1
interchange power 146 18 222 37 l Other operation (1) 0 113 18 Maintenance 56 19 107 56 Amortization of regulatory assets, net 4 7 3 6 Federal and state income
- j. taxes (68) (a) (181) (100)
Other income, _ net (23) (a) 6 42 Net incoma (89) (a) (256) (a )
(a) Percentage greater than 100 l
Oparating Revenues Total operating revenues increased in 1997, primarily due to higher fuel recoveries and higher conservation recoveries. Fuel recoveries
- . increased $33' million, primarily due to a higher fuel adjustment
'. clause-rate in 1997. Conservation recoveries increased by $17 million l primarily due to a 1996 reserve for over-recoveries of demand-side-4- management costs. Retail kilowatt hour sales were essentially unchanged in 1997.
51 ,
l l
Total operating revenues increased in 1996, primarily due to higher retail sales and regulatory decisions, partially offset by lower fuel recoveries and lower wholesale revenues. Retail sales increased 1.8 percent ($29 million) primarily due to modest economic growth in 1996.
Regulatory decisions increased revenues by $15 million primarily due to the mid-1995 retail rate increase, partially offset by 1996 reserves for over-recoveries of demand-side management costs. Fuel recoveries decreased $24 million primarily due to lower average fossil fuel prices. Wholesale revenues decreased $18 million primarily due to higher recognition in 1995 of lump-sum payments for the termination of a long-term contract and capacity sales contracts that expired in 1995.
Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 1997, primarily due to replacement power costs associated with the Millstone outages and the expensing in 1997 of replacement power costs incurred in 1996.
Fuel, purchased and net interchange power expense increased in 1996, primarily due to replacement power due to the nuclear outages and the 1996 write-off of the generation utilization adjustment clause (GUAC) balances under the settlement, partially offset by lower nuclear generation and the timing of the recognition of costs under the cot.pany's fuel clauses.
Other Operation and Maintenance other operation and maintenance expenses increased in 1997, primarily due to higher costs associated with the Millstone restart effort ($173 million), higher charges from Maine Yankee ($9 million), partially offset by lower recognition of nuclear refueling outage costs primarily as a result of the 1996 Rate Settlement ($72 million), lower capacity charges from Connecticut Yankee as a result of a property tax refund ($27 million), lower administrative and general expenses ($23 million) primarily due to lower pensions and benefit costs and lower storm expenses, i
Other operation and maintenance expenses increased in 1996, primarily due to higher costs associated with the Millstone restart effort
($93 million) and higher 1996 costs to ensure adequate generating capacity ($39 million). In addition, 1996 costs reflect higher storm and reliability expenditures, higher recognition of conservation expenses and higher marketing costs.
Ac.ortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in 1997, primarily due to the completion of cogeneration deferrals in 1996 and increased amortization in 1997, partially offset by the completion of CL&P's i Seabrook amortization in 1996. l l
Amortization of regulatory assets, net increased in 1996, primarily due to lower cogeneration deferrals and the accelerated amortization 1
52 i
- l. ;
l of regulatory assets as a result of'the Settlement, partially offset
[ by the completion of the Millstone 3 phase-in amortization in 1995.
l lJ ,Fcderal and State Inconne Taxes k I-L Federal and state income taxes decreased in 1997 and 1996, primarily !
due to lower book taxable income.
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1 53
The Connecticut Light and Power Company and Subsidiaries SELECTED FINANCIAL DATA
1997 1996 1995 1994 1993 (Restated) (Restated)
(Thousands of Dollars)
Operating Revenues....... .. 32,465,587 $2,397,460 $2,387,069 S2,328,052 $2,366,050
~ Operating (Loss)/ Income..... (7,619) 59,142 324,026 286,948 241,655 Net (Loss)/ Income.... .. . . (139,597) (50,868) 205,216 198,288 191,449*'
Cash Dividends on
-Common Stock............. 5,989 138,608 164,154 159,388 160,365 Total Assets.............. . 6,081,223 6,244,036 6,045,631 6,217,457 6,397,405 Long-Term Debt "' . . . . . . ... 2,043,327 2,038,521 1,822,018 1,823,690 2,057,280 Preferred Stock Not Subject to Mandatory Redemption.. .. ... ..... 116,200 116,200 116,200 166,200 166,200 Preferred Stock Subject to Mandatory Redemption"'. .... . . .. 155,000 155,000 155,000 230,000 230,000 Obligations Under capital Leases"'..... .... 158,118 155,708 172,264 175,969 177,418 GTATEMENTS OF QU'ARTERLY FINANCIAL DATA (Unaudited) (Restated)
Quarter Ended" 1997 March 31 June 30 September 30 December 31 (Thousands of Dollars)
Operating Revenues ((jjajgj $ 574.841 $ 627.712 $ 638,126-Operating Income /(Loss) M I 111M) d1.fl S 732
. Net Loss $(19.636) $ (50.161) $ (33.160) $ (36.640) 1996 Operating Revenues $659.355 $542.999 $599.505 $ 595.601 l
_ Operating Income /(Loss) $ 77.641 $ 19.895 $ (3.051) $ (35.343)
Net Income /(Loss) 1_1Q,.111 $ (6.002) $(30.582) $ (64.799)
'*' Reclassifications of prior data have been made to conform with the current presentation.
- ' Includes the cumulative effect of change in accounting for municipal preperty tax expense, which increased earnings for common shares by $47.7 million.
"' Includes portion due within one year.
54
The Connecticut Light and Power Company and Subsidiaries STATISTICS Gross Electric Average Utility Plant Annual December 31, Use Per Electric (Thousands of kWh Sales Residential Customers Employees Dollars) (Millions) Customer (kWh) ( Averacre) (December 31) 1997 $6,639,786 26,766 8,526 1,103,309 2,163 1996 6,512,659 26,043 8,639 1,099,340 2,194 1995 6,389,190 26,366 8,506 (a) 1,094,527 2,270 1994 6,327,967 26,975 8,775 1,086,400 2,587 1993 6,214,401 26,107 8,519 1,078,925 2,676 (a) Effective January 1, 1996, the amounts shown reflect billed and unbilled sales. 1995 has been restated to reflect this change.
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