ML20198G012
| ML20198G012 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 12/31/1997 |
| From: | Bailey L, Houston A NEW ENGLAND POWER CO. |
| To: | |
| Shared Package | |
| ML20198F859 | List: |
| References | |
| NUDOCS 9812280272 | |
| Download: ML20198G012 (37) | |
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4 Annual Report 1997 i New England Power Company 1
i i A Subsidiary of New England Electric System l 1
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I O p N ew England Power
" A M company 9812280272 981216 PDR ADOCK 05000443 ppR I [
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New Engl:nd Paw:r C mpany ,
25 Research Drive Westborough, Massachusetts 01582 Directors (As ofMarch I8,1998) i Lawrence E. Bailey Cheryl A. LaFleur l President ofthe Company Vice President and General Counsel of the Company and Senior Vice President, General Counsel, and Alfred D. Houston Secretary ofNew England Electric System Chairman of the Company and Executive Vice President ofNew England Electric System Richard P. Sergei President and ChiefExecutive ODicer ofNew England Electric System Officers (As ofMarch 18, I998)
Alfred D. Houston Arnold H. Tumer" Chairman ofthe Company and Executive Vice Vice President of the Company President ofNew England Electric System Jeffrey W. VanSant Lawrence E. Bailey Vice President ofthe Company President of the Company Robert King Wulff Clerk ofthe Company and ofcertain afliates, Andrew H. Aitken Seaesary or AssistcMink ofcertain afliates and Vice President of the Company Assistant Secretary ofan afliate Michael E. Hachey John G. Cochrane Vice President of the Company Treasurer of the Company and ofcertain apiliates, Vice President ofan affiliate, Assistant Treasurer of Michael E. Jesanis an abiliate and Treasurer ofNew England Electric Vice President of the Company and Senior Vice System President and ChiefFinancial Oficer ofNew England Electric System Kirk L Ramsauer Assistant Clerk of the Company and ofcertain Cheryl A.LaFleur abiliates, and Secretary, Assistant Secretary or clerk Vice President and General Counsel of the Company ofcertain affiliates and Senior Vice President, General Counsel, and Se:retary ofNew England Electric System Howard W. McDowell Assistant Treasurer and Controller of the Company John F. Malley and ofcertain abiliates Treasurer or Controller of Vice Preside nt of the Company certain affiliates and Assistant Secretary of an apiliate Masheed H. Rosenqvist*
Vice President of the Company
- Efective April 1,1998
- Mr. Turner plans to retire effective April I,1998.
Transfer Agent and Dividend Paying Agent of Preferred Stock Bank of Boston, Boston, Massachusetts Registrar ofPreferred Stock State Street Bank and Trust Company, Boston, Massachusetts This report is not to be L nsidered an ofer to sell or buy or solicitation of an ofer to sell or buy any security.
l N w Engl:nd Pswer Crmpany New England Power Company, (the Company) a wholly owned subsidiary of New England Electric System (NEES),is a Massachusetts corporation qualined to do business in Massachusetts, New Hampshire.,
Rhode Island, Connecticut, Maine, and Vennont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of these six states, the Securities and Exchange Commission (SEC),
l and the Federal Energy Regulatory Commission (FERC). The Company's business is currently that of I
generating, purchasing, transmitting, and selling electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates Granite State Electric Company (Granite State Electric),
l Massachusetts Electric Company (Massachusetts Electric), Nantucket Electnc Company (Nantucket Electric),
, and The Narragansett Electric Company (Narragansett Electric). In August 1997, the Company and l Narragansett Electric entered into an agreement to sell their nonnuclear generating business to an independent third party. See the " Divestiture of Generating Business" section of Financial Review.
In accordance with industry restructuring settlements in both Massachusetts and Rhode Island, the Company's wholesale contracts with its distribution affiliates have been amended. These amendments allow for termination of the all-requirements services under those contracts. They also allow the Company to recover the cost of its above-market generation commitments allocable to Massachusetts Electric and Narragansett Electric (95 percent of the total costs) through a transition access charge, which the distribution affiliates will collect from customers. In February 1998, a comprehensive settlement agreement was reached with parties in the state of New Hampshire, which, upon receipt of all required regulatory approvals, would provide for arrangements similar to those of the Massachusetts and Rhode Island settlements. Efforts are ongoing with unaffiliated customers to secure recovery of the balance of the Company's above-market commitments. See the " Industry Restructuring" section of Financial Review for further discussion.
Report of Independent Accountants New England Power Company, Westborough, Massachusetts: I We have audited the accompan,ing balance sheets of New EnFl and Power Company (the Company), a ,
wholly owned subsidiary of New England Electric System, as of December 31,1997 and 1996 and the related l statements of income, retained eamings, and cash flows for each of the three years in the period ended j December 31,1997. These financial statements are the responsibility of the Company's management. Our I responsibility is to express an opinion on these financial statements based on our audits.
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 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 the Company 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 mth generally l accepted accounting principles.
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I Boston, Massachusetts COOPERS & LYBRAND L.L.P.
March 2,1998 1
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Fin:nci:1 R vi;w !
Industry Restructuring On August 5,1997, the Company and its Rhode Island distribution affiliate, Nanagansett Electric, reached an agreement to sell their nonnuclear generating business to USGen New England, Inc. (USGen), an indirect wholly owned subsidiary of PG&E Corporation. The divestiture of the nonnuclear generating business is in connection with the restructuring of the electric utility industry.
Historically, electric utilities have provided their customers bundled electric service within exclusive franchise service territories. As the msult cf a number of trends, including a disparity in electric rates among regions of the country and new regulations and legislation intended to foster competition, retail customers are being allowed to choose their power supplier, with incumbent utilities required to deliver that electricity over their transmission and distribution systems. Because of legislation enacted in the states served by the NEES companies, most customers served by the NEES companies will have the ability to choose their power supplier by the first quarter of 1998.
When customers are allowed to choose their power supplier, utilities face the risk that market prices may not be sufficient to recover the costs of the commitments incurred to supply customers under a regulated structure. The amounts by which such costs exceed market prices are commonly referred to as " stranded costs." As described below, the Company has reached settlement agreements with all of its distribution affiliates and with parties representing the distribution customers of those affiliates. In each case, these settlements provide for recovery of stranded costs.
Massachusetts Legislation and Settlement Agreement In November 1997, legislation was enacted which provides customers of Massachusetts' investor-owned '
utilities with the ability to choose their power supplier beginning on March 1,1998. The legislation requires electric compames to provide customers who do not choose a power sepplier with a transition rate (or
" standard offer generation service") which results in a 10 percent rate reduction, with the discoui t increasing to 15 percent on or before September 1,1999. The legislation also provides a mechanism for the recovery of stranded costs resulting from the introduction of customer choice.
In December 1997, the Massachusetts Department of Telecommunications and Energy (MDTE) (formerly the Massachusetts Department of Public Utilities (MDPU)) found that a settlement agreement (the Massachusetts Settlement) previously reached among t' Gmpany, the Company's Massachusetts distribution affiliates, Massachusetts Electric and Nantucket Elech.c, and various govemmental agencies and other interested parties substantially complies with or is consistent with the Massachusetts statute. The Massachusetts Settlement was also conditionally approved by the FERC in November 1997, subject to a compliance filing to clarify the impact of the settlement on nonsettling parties.
In accordance with the Massachusetts Settlement, the Company's wholesale contracts with Massachusetts Electric and Nantucket Electric have been amended effective March 1,1998. The Massachusetts Settlement provides that Massachusetts Electric's and Nantucket Electric's share of the Company's stranded costs will be recovemd from distribetion customers through a transition access charge, which will be collected by these distribution con 2panies. Under the Massachusetts Settlement, the recovery of the Company's stranded costs is divided into several categories. Unrecovered costs associated with generating plants and regulatory assets would be recovered over 12 years and would earn a retum on equity of 9.4 percent. The above-market component of purchased power contracts and nuclear decommissioning costs would be recovered as incurred over the life of those obligations, a period expected to extend beyond 12 years. Initially, the transition access l charge was set at 2.8 cents per kilowatthour (kWh). The MDTE has approved a reduction of the initial
! transition access charge to 2.7 cents per kWh for Massachusetts Electric and Nantucket Electric, effective March 1,1998. The Company's filing with the FERC to approve this reduction is pending. The transition access charge would be reduced further upon completion of the sale of the Company's generating business, as described below. As the transition access charge declines, the Company would eam incentives based on successful mitigation of its stranded costs. These incentives would supplement the Company's return on l equity.
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New England Pow r Ccmpany Financizi R';vi:w (continued)
In addition to addressing customer choice and the recovery of stranded costs, the Massachusetts Settlement also required the NEES companies to divest their nonnuclear generating business. In August 1997, the Company and Narragansett Electric entered into an agreement to sell substantially all of their nonnuclear generating business to USGen. See " Divestiture of Generating Business" below. The net proceeds from the sale of the nonnuclear generating business to USGen will be ased to reduce the transition access charge to approximately 1.5 cents per kWh. In addition, the FERC accepted the NEES companies proposal in conjunction with their divestiture filing that the recovery of the remaining above-market nuclear generating plant investment and regulatory assets be completed by the end of the year 2000.
A referendum question which asks voters to n peal the Massachusetts statute is expected to be on the ballot in November 1998. The NEES companies are unabie to predict the outcome. While by itself, repeal of the statute is not expected to materially impair the effectiveness of the previously approved Massachusetts Settlement, the potential exists that following repeal, there could be legislative or regulatory actions which I
could be materially adverse to the NEES companies.
Rhode Island Legislation and Settlement Agreement lo August 1996, the state of Rhode Island enacted legislation that allows customers in that state the opportunity to choose their power supplier. Under the Rhode Island statute, state accounts, certain new customers, and the largest manufacturing customers were able to choose their power supplier beginning on July 1,1997, The balance of Rhode Island customers gained the ability to choose their power supplier on January 1,1998. The Rhode Island statute also provided utilities with the ability to recover stranded costs.
In November 1997, the FERC conditionally approved a settlement agreement among the Company, its Rhode Island distribution affiliate Narragansett Electric, the Rhode Island Public Utilities Commission and the Rhode Island Division of Public Utilities and Carriers, to implement the stranded cost recovery provisions of the Rhode Island statute, subject to a compliance filing to clarify the impact of the settlement on nonsettling parties. The terms of the Rhode Island Settlement are substantially the same as the Massachusetts Settlement.
New Hampshire Legislation and Settlement Agreement On February 3,1998, the Company and its New Hampshire distribution affiliate Granite State Electric reached a comprehensive settlement agreement with the Governor's office of the State of New Hampshire and a number of other interested parties on a plan to provide choice of power supplier to its customers by no later than July 1,1998. This settlement agreement was reached in response to a previously enacted New Hampshire statute which requires customer choice of power supplier. The principal terms of the New Hampshire settlement agreement, which require approval by state and federal regulators, are substantially simi'ar to the Massachusetts Settlement and the Rhode Island Settlement, including rate reductions for customers and the ability to recover stranded costs.
Unaffiliated Customers Agreements have not yet been reached with certain wholesale customers that represent less than 2 percent of the Company's stranded cost exposure. In March 1998, the largest of these customers, the Town c Norwood, Massachusetts, gave notice of its intent to terminate its contract with the Company, withcm accepting responsibility for its shan of the Company's stranded costs, and to begin taking power from another supplier. The Company has filed with the FERC for permission to charge Norwood a contract termination charge for its share of the Company's stranded costs.
Divestiture of Generating Business As described above, in August 1997, the Company and Narragansett Electric (collectively, the Sellers) reached an agreement to sell their nonnuclear generating business to USGen. The nonnuclear generating 3
New Engl:nd Power Company l Finrncial .ibviiw (continued)
I business includes three fossil-fueled generating stations and 15 hydroelectric generating stations, totaling approximately 4,000 megawatts (MW) of capacity, as well as NEES' interest in Narragansett Energy Resources Company (NERC), a 20 percent general partner in the Ocean State Power project, all of which has a book value of $1.1 billion. USGen will pay the Sellers $1.59 billion m cash, of which $225 million will be contingent upon the introduction of customer choice of power supplier in Massachusetts. Based on the enactment of the Massachusetts statute, the NEES companies believe that the conditions for payment of the full purchase price have been met. USGen will also reimburse the NEES companies for $85 million of costs associated with early retirement and special severance programs for employees affected by industry restructuring. USGen will assume responsibility for environmental conditions at the Sellers' nonnuclear generating stations. USGen will also assume the Sellers' obligations under long-term fuel and fuel transponation contracts and certain collective bargaining agreements for nonnuclear facilities.
In addition to the purchase of the generating stations, USGen will purchase the Company's entitlement to approximately 1,100 MW of power procured under long-term contracts. The Company will make a monthly fixed contribution toward the above-market cost of the purchased power of between $12.5 million and $14.2 million per month from closing through January 2008. USGen will be responsible for the balance of the costs under the purchased power contracts.
The sale is subject to approval by various state and federal regulatory agencies. Several panies have objected to the sale on various grounds, including allegations that following the sale, USGen would be able to exercise unlawful levels of market power. On February 25,1998, the FERC issued an order that rejected the market power allegations, approved the sale and conditionally approved most supporting filings. On Febmary 27,1998, the FERC approved the transfer of the hydroelectric generating licenses to USGen. While the timing of receipt of final regulatory approvals is uncenain, receipt of all approvals is unlikely before mid-1998. Closing is contingent upon all regulatory approvals being obtained by February 1999.
In order to meet the terms of the Company's mortgage indenture, the Company will be required, prior to the consummation of the sale, to either defease or call approximately $278 million ofits mortgage bonds. Any defeasance of bonds would be by deposit of cash representing principal and interest to the maturity date, or interest, principal, and general redemption premium to an earlier redemption date. In addition, the Company will retire approximately $372 million of mongage bonds securing the issuance of a like amount of pollution control revenue bonds (PCRBs) by various public agencies. However, the Company expects that substantially all of the underlying PCRBs will remain outstanding as unsecured obligations of the Company. In addition, the long-term debt of NERC will be retired prior to the closing.
Upon completion of the divestiture of the Company's nonnuclear generating business, the Company's stranded costs that will be recovered from distribution customers through a transition access charge, which will be collected by the Company's distribution affiliates, will be reduced from $4.5 billion to $2.1 billion.
As part of the divestiture plan, in February 1998, New England Energy Incorporated (NEEI) (a whoiiy owned subsidiary of NEES) sold its oil and gas propenies for approximately $50 million. NEEI's loss on the sale of approximately $120 million, before tax, has been reimbursed by the Company.
At the divestiture date, any gain or loss from the divestiture of nonnuclear generating assets and oil and gas assets will be recorded as a rrgulatory asset or liability to be recovered as part of the Company's stranded costs, through the ongoing transition access charge, consistent with the settlement agreements. The Company may be required to record a hability for the monthly fixed contribution towards the above-market cost of purchased power. In such an event, the Company would also record a regulatory asset consistent with the settlement agreements.
In addition, the Company will endeavor to sell, or otherwise transfer, its minority interest in three nuclear power plants and a 60 MW interest in a fossil-fueled generating station in Maine to nonaffiliates. Until such time as the nuclear interests are divested, the Company will share with customers 80 percent of the revenues and operating costs related to the units, with shareholders retaining the balance. In the event that the Company determines that it has an impairment of its nuclear plant balances under Statement of Financial Accounting Standards No.121, Accounting for Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (FAS 121), it will record any such impairment as a regulatory asset.
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New England Pow r Ccmpany Fin'ncial R:; view (continued)
Workforce Reduction The NEES companies expect to implement substantial workforce reductions beginning in 1998 as a result of industry restructuring and the sale of the nonnuclear generating business. The NEES companies are in the process of offering early retirement programs to their union and non-union employees, contingent upon the closing of the sale of the nonnuclear generating business to USGen. In addition, the NEES companies intend to offer enhimced severance benefits to affected employees. As previously described, the costs of the e.arly retirement and severance programs for all NEES companies are expected to be substantially recovered from the proceeds of the sale of the nonnuclear generating business. Since the early retirement program is contingent upon the divestiture, its cost will not be accrued until that time.
Risk Factors While the Company believes that the previously described settlements and legislation and the sale agreement with USGen and other developments, including the New Hampshire settlement, constitute substantial progress in reducing the impacts associated with industry restructuring, significant risks remain.
These include, but are not limited to: (i) the potential that ultimately the settlements will not be implemented in the manner anticipated by the Company, (ii) the possibility that a voter referendum in November 1998 could overtum the Massachusetts legislation, followed by mt terially adverse legislative or regulatory actions, (iii) the possibility of federal legislation that would increase the risks above those contained in the settlements and the Massachusetts and Rhode Island statutes, (iv) the potential for adverse stranded cost recovery decisions involving wholesale customers with whom settlements have not yet been reached and (v) the failure to complete the sa!e of the generating business to USGen.
This report contains statements that may be considered forward looking under the securities laws. Actual results may differ materially for the reasons discussed in this Financial Review. Upon the introduction of consuma choice, settlement agreements related to recovery of stranded costs will limit the Company's retum on equity to approximately 9.4 percent, before mitigation incentives, which is significantly lower than that camed by the Company in recent years. Following completion of the sale of the nonnuclear generating business, the Company's earnings will also be affected by the retum on the reinvestment of sale proceeds, which is expected, at least in the near term, to be considerably less than the return historically camed by the generating business.
Accounting implications Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general.
Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), requires regulated entities, in appropriate circumstances, to establish regulatory assets, and thereby defer the income statement impact of certain items of income and expense expected to be reflected in future rates. At December 31,1997, the Company had approximately $420 million in net regulatory assets in compliance with FAS 71. This amount excludes any effects related to the divestiture of NEEI's oil and gas properties discussed above.
In response to concems expmssed by the staff of the SEC, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board took under consideration how FAS 71 should be applied in light of recent changes within the regulated utility industry. In July 1997, the EITF concluded that a utility whose ongoing generation operations would not permit the application of FAS 71, but had otherwise received approval to recover stranded costs through regulated transmission and distribution rates, would be permitted to continue to apply FAS 71 to the recovery of the stranded costs.
The r-structuring settlements and statutes each provide for recovery of substantially all applicable stranded costs of generating assets and oil and gas related assets (including regulatory assets) not recoverable from the proceeds of the divestiture of the Company's generating business. The cost of these assets would be recovered 5
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New EngI::nd P w:r Campany Financi::l R;vi;w (continued)
! as part of a cost-based transition access charge imposed on all distdbution customers. Additionally, FERC l
Order No. 888 :nables transmission companies to recover their specific costs of providing transmission service.
Therefore, after the proposed divestiture, substantially all of the Company's business, including the recovery of its stranded costs, would remain under cost-based rate regulation. The Company believes these factors and I the EITF conclusion will allow it to continue to apply FAS 71. As a result of the FERC approval of the l restructuring settlements in November 1997, the Company was mquired to cease to apply FAS 71 to the 20 percent of its ongoing nuclear operations, as described under " Divestiture of Generating Business," the impact of which is expected to be immatedal.
. Despite the progress made to date, it is possible that future regulatory rules or other circumstances could cause the application of FAS 71 to be discontinued, which would result in a noncash write-off of previously established regulatory assets related to the affected operations. In addition, write-downs of plant assets under FAS 121 could be required, including a write-off of any gain or loss from the divestiture of the generating business.
! Overview of Financial Results Net income for 1997 decreased $8 million compared with 1996. The decrease was primarily due to
! increased operation and maintenance costs. The decrease was partially offset by a transmission rate increase, decreased purchased electric energy costs, excluding fuel, and decreased depreciation and amortization.
- Net income increased by $1 million in 1996. This increase reflected a reduction in purchased electric l energy, excluding fuel, and a reduction in operation and maintenance expense. Partially offsetting these increases were decreases in allowance for funds used durir.g construction (AFDC) and increased property taxes, both primarily due to the completion in the second half of 1995 of the Manchester Street generating station, as well as increased integrated facilities credits to the Company's affiliate, Narragansett Electric. The l Company also experienced reduced peak demand charge billings in 1996.
l Operating Revenue The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue (In _rnillions) 1997 1996 Sales growth, peak demand charges, and stranded investment recovery $ 2 $ (4)
Fuel recovery 55 48 Narragansett integrated facilities credit 5 (9)
Other, including transmission revenues 16 (5)
$ 78 5 30 Sales decreased in 1997 pdmarily due to a decrease in peak demand billing as a result of milder weather in the first quarter of 1997, as well as reduced load due to retail wheeling pilot programs instituted by Massachusetts Electric and Gratite State Electric. These decreases are more than offset by stranded investment recovery, which represents amouras being recovered in connection with these retail wheeling pilot programs, and with the first phase of retail competition by Narragansett Electric.
For a discussion of fuel recovery revenues, see the fuel costs discussion in the " Operating Expenses" section.
The entire output of Narragansett Electric's generating capacity is made available to the Company.
Narragansett Electdc receives a credit on its purchased power bill from the Company for its fuel costs and other generation and transmission related costs. The reduction in these credits in 1997 reflects a reduction in dismantlement costs being incurred by Narragansett Electric on a previously retired generating facility. TI'e increased credits in 1996 relate to costs associated with the dismantlement of the previously retired South 6
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, N:w England Power Company Financirl Revicw (continued)
Street generating facility and with Narragansett Electric's portion of costs associated with the repowered Manchester Street generating station that entered commercial operation in the second half of 1995.
The increase in other revenues in 1997 is primarily due to a transmission rate increase that went into effect in mid-1996.
Operating Expenses The following table summarizes the changes in operating expenses:
Increase (Decrease) in Operating Expenses (In millions) _ _ _ _
1997 1996
, Fuel costs $ 55 $ 52 Purchased energy excluding fuel (6) (28)
Other operation and maintenance 49 (22)
Depreciation and amostization (6) 1 Taxes (1) 8
$ 91 SI1 Fuel costs represent fuel for generation and the portion of purchased electric energy permitted in the past to be recovered through the Company's fuel adjustment clause. After the divestiture of the nonnuclear generating business, the Company will not require such a mechanism. The increase in fuel costs in 1997 and 1996 reflects increased power supply to other utilities, increased replacerrent power costs due to the reduced generation from panially owned nuclear units, and an increase in the cost of shon-term purchased power. The increase in 1996 is also due to fixed pipeline demand charges that, prior to the completion of the Manchester Street Station, were being panially deferred for amortization and recovery after the unit went into service in the second half of 1995.
The decrease in purchased power costs, excluding fuel, during 1997 reflects reduced charges from the Connecticut Yankee nuclear power plant, which was permanently closed in December 1996. This decrease was panially offset by increased charges from the Maine Yankee nuclear power plant, which was permanently closed in mid-1997. The decrease in 1996 reflected the expiration of certain purchased power contracts.
The decrease in depreciation and amonization expense reflects the completion of the amonization of the Company's pre-1988 investment in the Seabrook i nuclear unit and the Company's investment in the canceled Seabrook 2 nuclear unit. In accordance with the 1995 settlement agreement, upon completion of the amortization of Seabrook 1 and Seabrook 2, the Company agreed to accelerate its amonization of previously deferred costs associated with postretirement benefits other than pensions (PBOPs). Upon completion of the PBOP amonization, which occurred in July 1997, the Company was required to accelerate its depreciation of its investment in the Millstone 3 nuclear unit. This accelerated depreciation is recorded as a regulatory liability.
The increase in other operation and maintenance expens:s in 1997 is due to an increase of $8 million in transmission wheeling costs, increased maintenance costs of $14 million at the partially owned Millstone 3 and Seabrook i nuclear facilities, an $11 million increase in deferred PBOP amortization mentioned above, an overall increase in general and administrative costs, start-up costs associated with the new regional transmission control organization, and the Company's share of costs associated with the restoration to service of previously idled facilities throughout New England in response to a tightening regional power supply. The decrease in operation and maintenance in 1996 reflected reduced thermal and hydro generating plant overhaul activity, partially offset by $13 million of costs to conect deficiencies at the Millstone 3 nuclear unit, in which the Company has a 12 percent ownership interest. The Company also experienced a reduction in transmission wheeling costs, pension costs, PBOPs, and other general and administrative costs.
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New Engl:nd Psw:r C mpany l Fin ncial R:;vi';w (continued) i Allowance for Funds Used During Construction (AFDC) 1 The decrease in AFDC in 1996 is due to the completion of the Manchester Street plant repowering project. i Nuclear Units Nuclear Units Permanently Shut Down Three of the four regional nuclear generating companies in which the Company has a minority interest own nuclear generating units which have been p:rmanently shut down. These three units are as follows:
NEP's Investment Future Estimated Unit Percent Amount Date Retired Billings to NEP($)
Yankee Atomic 30 7 million Feb 1992 44 million Connecticut Yankee 15 17 million Dec 1996 92 million Maine Yankee 20 16 million Aug 1997 164 million in the case of each of these units, the Company has recorded an estimate of the total future payment obligation as a liability and an offsetting regulatory asset, reflecting estimated future billings from the companies. In a 1993 decision, tne "ERC allowed Yankee Atomic to recover its undepreciated investment in the plant as well as unfunded nuclear decommissioning costs and other costs. Connecticut Yankee and Maine Yankee have both filed similar requests with the FERC. Several panies have intervened in opposition to both filings. The Company's stranded cost settlements allow it to recover all costs that the FERC allows the Yankee companies to bill to the Company.
In October 1997, the Citizer/s Awareness Network and Nuclear Information and Resource Service filed a petition with the Nuclear Regulatory Commission (NRC) that would require formal NRC approval of a plant decommissioning plan for the Connecticut Yankee and Maine Yankee plants. In 1998, the petitioners indicated their intention to file a request with the NRC designed to overturn a current NRC rule on decommissioning. The Company cannot predict what impact, if any, these activities will have on the cost of decommissioning the plants.
At Maine Yankee, the NRC has identified numerous apparent violations of its regulations, which may result in the assessment of significant civil penalties.
In the 1970s, the Company and several other shareholders (Sponsors) of Maine Yankee entered into 27 contracts (Secondary Purchase Agreements) under which they sold portions of their entitlement to Maine Yankee power output through 2002 to various entities, primarily municipal and cooperative systems in New England (Secondary Purchasers). Virtually all of the Secondary Purchasers have ceased making payments under the Secondary Purchase Agreements and have demanded arbitration, claiming that such agreements excuse further payments upon plant shutdown. The Company has notified the Secondary Purchasers that the shutdown does not relieve them of their obligation to make payments under the Secondary Purchase Agreements and that they are in default of such agreements. The Company has asked the FERC to enforce the Company's rights under the agreements. In the event that no funher payments are forthcoming from Secondary Purchasers, the Company, as a primary obligor to Maine Yankee, would be required to pay an additional $9 million of future shutdown costs. These costs are not included in the $164 million estimate disclosed in the table above. Shutdown costs are recoverable from customers under the stranded cost settlements.
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New Engl:nd Pow r Ccmpany Financi:1 R;vi:w (continued)
A Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay for the plant decommissioning, the owners of Maine Yankee are jointly and severally liable for the shortfall.
Operating Nuclear Units The Company has minority interests in three other nuclear generating units, Vermont Yankee, Millstone 3, and Seabrook 1. In October 1996, the NRC issued letters to operators of nuclear power plants requiring them to document that the plants are operated and maintained within their design and licensing bases, and that any deviations are reconciled in a timely manner. The Seabrook I and Vermont Yankee nuclear power plants responded to the NRC letters in February 1997. Millstone 3 is currently shut down and has been placed on the NRC " Watch List," signifying that its safety performance exhibits sufficient weakness to warrant increased NRC attention. Millstone 3 may not restart without NRC approval.
Uncertainties regarding the future of nuclear generating stations, particularly older units, such as Vermont Yankee, are increasing rapidly and could adversely affect their service lives, availability, and costs. These uncertainties stem from a combination of factors, including the acceleration of competitive pressures in the power generation industry and increased NRC scrutiny. The Company performs periodic economic viability reviews of operating nuclear units in which it holds ownership interests.
Millstone 3 In April 1996, the NRC ordered Millstone 3, which has experienced numerous technicai mi nontechnical problems, to remain shut down pending verification that the unit's operations are in accordance with NRC regulations and the unit's operating license. Millstone 3 is operated by a subsidiary of Nonheast Utilities (NU).
The Company is not an owner of the Millstone 1 and 2 nuclear generating units, which are also shut down under NRC orders.
7 A number of significant prerequisites must be fulfilled prior to restart of Millstone 3, including certification by NU that the unit adequately conforms to its design and licensing bases, an independent verification of corrective actions taken at the unit, an NRC assessment concluding a safety conscious work environment exists, public meetings, and a vote of the NRC Commissioners. The Company cannot predict when Millstone 3 will be allowed by the NRC to restart, but believes restart of the unit is unlikely prior to the summer of 1998.
Since April 1996, the Company has incuned an estimated $35 million in incremental replacement power costs, which it has been recovering from customers through its fuel clause. During the outage, the Company is incurring incremental replacement power costs of approximately $2 million per month.
Several criminal investigations related to Millstone 3 are ongoing. In December 1997, the NRC assessed civil penalties totaling $2.1 million for numerous violations at the three Millstone units. The Compaay's share of this fine was less than $100,000. The Connecticut Department of Environmental Protection and Connecticut Attomey General have filed suit against NU for alleged wastewater discharge violations at the Millstone units, which may result in the assessment of substantial civil penalties.
In August 1997, the Company filed suit against NU in Massachusetts Superior Court for damages resulting from the tonious conduct of NU relating to Millstone 3. The Company is seeking compensation for the losses it has suffered, including the costs of lost power and costs necessary to assure that Millstone 3 can safely retum to operation. The Company also seeks punitive damages. NU has filed for dismissal of the suit and sought to consolidate it with suits filed by other joint owners in Massachusetts Superior Court.
The Company also sent a demand for arbitration to Connecticut Light & Power Company and Westem Massachusetts Electric Company, both subsidiaries of NU, seeking damages resulting from their breach of obligations under an agreement with the Company and others regarding the operation and ownership of Millstone 3.
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N;w England Pow:r Ccmpany Fin:nci:1 R3vi:w (continued)
Brayton Point
- In October 1996, the Environmental Protection Agency (EPA) announced it was beginning a process to determine whether to modify or revoke and reissue the Company's water discharge permit for its Brayton Point 1,576 MW power plant. This action came two years before the permit expiration date. The EPA stated it took this step in response to a request fmm the Rhode Island Department of Environmental Management (RIDEM).
A RIDEM report asserted a statistical correlation between the decline in the fish population in Mount Hope i Bay and a change in operations at Brayton Point that occmred in the mid-1980s.
In April 1997, the Company signed a memorandum of agreement negotiated with the various federal and l state environmental agencies under which the Company will voluntarily operate under more stringent l conditions than under its existing permit. The agreement was in lieu of any immediate action on the permit, j and will remain in effect until a renewal permit is issued. On January 16,1998, the Company applied for a l new water discharge permit with both the EPA and the Massachusetts Department of Environmental Protection. The Company cannot predict at this time what permit changes will be required or the impact on Brayton Point's operations and economics. However, permit changes may substantially impact the plant's capacity and ability to produce energy and/or require substantial capital expenditures to construct equipment to address the concerns raised by the environmental agencies.
Year 2000 Computer issues In the next two years, most large companies will face a potentially serious information systems (computer) problem because most software applications and operational programs written in the past will not properly recognize calendar dates beginning in the year 2000. This could force computers to either shut down or lead to incorrect calculations. The NEES companies began the process of identifying the changes required to their computer programs and hardware during 1996. The necessary modifications to the NEES companies' centralized financial, customer, and operational information systems are expected to be completed by the end of 1998. Noncentralized systems are also being reviewed for Year 2000 problems. The NEES companies believe total costs associated with making the necessary modifications to all centralized and noncentralized systems will be approximately $25 million, of which approximately $8 million has been incurred as of December 31,1997. Most of the remaining costs are expected to be incurred prior to December 31,1998.
The Company's share of the total costs is expected to be approximately $10 million.
Utility Plant Expenditures and Financing Cash expenditures for utility plant totaled $70 million for 1997. The funds necessary for utility plant expenditures during the period were provided by net cash from operating activities, after the payment of dividends. Cash expenditures for utility plant for 1998 are estimated to be $55 million, principally related to transmission functions. Internally generated funds are expected to fully cover the Company's capital expenditures in 1998.
In 1997, the Company retired $3 million of maturing long-term debt. The Company also retired $35 million of mortgage bonds prior to maturity and incurred premiums of $2.2 million associated with the early retirement.
At December 31,1997, the Company had $111 million of short-term debt outstanding including $108 million of commercial paper borrowings and $3 million of borrowings from affiliates. At December 31,1997, the Company had lines of credit and bond purchase facilities with banks totaling $580 million which are available to provide liquidity support for commercial paper borrowings and for $372 million of the Company's outstanding variable rate mortgage bonds in tax-exempt commercial paper mode and for other corporate purposes. There were no borrowings under these lines of credit at December 31,1997.
10
Nsw England Power Company Financial Rsvisw (continued)
New Accounting Standards in 1997, the Financial Accounting Standards Board released two new Statements of Financial Accounting Standards (FAS), FAS 130 and FAS 131, both of which will go into effect in 1998. FAS 130, Reporting Comprehensive Income, requires the reporting in financial statements of a new additional item called comprehensive income, which will incorporate amounts not previously included in reported net income. FAS 131, Disclosure about Segments of an Enterprise and Related Information, requires the reporting in financial statements of certain new additional information about operating segments of a business. The Company is currently evaluating the impact that these new accounting standards will have on its future reporting requiremerts.
11
New Engl:nd Pow:r C:mpany Statements of Income Year ended December 31, (In thousands) 1997 1996 1995 Operating revenue, principally from affiliates $ 1,677,903 $ 1,600,309 $ 1,570,539 Operating expenses:
Fuel for generation 372,734 342,545 279,849 Purchased electric energy 527,647 508,910 547,926 Other operation 241,506 203,456 211,872 Maintenance 89,820 79,118 92,954 Depreciation and amonization 98,024 104,209 102,758 Taxes,other than income taxes 67,311 66,416 58,716 income taxes 90,009 91,894 91,051 Total operating expenses 1,487,051 1,396,548 1,385,126 Operating income 190,852 203,761 185,413 Other income:
Allowance for equity funds used during construction - - 7,746 Equity in income of nuclear power companies 5,189 5,159 5,721 Otherincome (expense), net (3,404) (1,85l) (1,610)
Operating and other income 192,637 207,069 197,270 Interest:
Interest on long-term debt 42,277 45,111 46,797 Other interest 7,055 10,066 10,525 Allowance for borrowed funds used during construction - credit (1.238) (591) (11,479)
Totalinterest 48,094 54,586 45,843 Net income $ 144,543 $ 152,483 $ 151,427 Statements of Retained Earnings Year ended December 31, (In thousands)_ _ _ _ _ _ _ _ _ _ _ __ 1997 1996 __ _
1995 Retained earnings at beginning of year $ 400,610 $ 385,309 $ 372,763 Net income 144,543 152,483 151,427 Dividends declared on cumulative preferred stock (2,075) (2,574) (3,433)
Dividends declared on common stock, $21.00,
$20.80, and $21,00 per share, respectively (135,448) (134,158) (135,448)
Premium on redemption of preferred stock -
(450) -
Retained eamings at end of year $ 407,630 $ 400,610 $ 385,309 The accompanying notes are an integral part of these financial statements.
12
New England Power C mpany 1 Balance Sheets At December 31, (In thousands) 1997 1996 Assets Utility plant, at original cost $ 3,057,749 $ 2.991,797 Less accumulated provisions for depreciation and amortization 1,1 % ,972 1,118,340 1,860,777 1,873,457 Constmetion work in progress 29,015 36.836 Net utility plant 1,889,792 1,910,293 investments:
Nuclear power companies, at equity (Note D-1) 49,825 47,902 NonutHity property and other investments 34,723 30.591 Total investments 84,548 78,493 Current assets:
Cash 1,643 3,046 Accounts receivable:
Affiliated companies 233,308 201370 Accrued NEEl revenues (Note D-3) 11,419 21,648 Others 26,638 23,219 Fuel, materials, and supplies, at average cost 47,492 58,709 Prepaid and other current assets 17,837 25,050 Total current assets 338,337 333,042 Accrued Yankee nuclear plant costs (Note D-2) 299,564 166,413 Deferred charges and other assets (Note B) 150,851 159,474
$ 2,763,092 $ 2,647.715 Capitalization and Liabilities Capitalization:
Common stock, par value $20 per share, authorized and outstanding 6,449,896 shares $ 128,998 $ 128,998 Premium on capital stock 86,779 86,779 Other paid-in capital 289,818 289,818 Retained eamings 407,630 400,610 Unrealized gain on securities, net 34 0 Total common equity 913,259 906,205 Cumulative preferred stock, par value $ 100 per share (Note II) 39,666 39,666 Long-term debt 647,720 733,006 Total capitalization 1,600,645 1,678,877 Current liabilities:
Long-term debt due in one year 50,000 3,000 Short-term debt (including $3,125 and $5,275 to affiliates) 111,250 93,600 Accounts payable (including $14,373 and $25.301 to affiliates) 109,121 127,226 Accrued liabilities:
Taxes 39 8,158 Interest 8,905 9,668 Other accrued expenses (Note G) 23,554 16,577 Dividends payable 35,474 27,412 Total current liabilities 338,343 285,641 Deferred federal and state income taxes 369,757 382,164 Unamortized investment tax credits 53,463 55,486 Accrued Yankee nuclear plant costs (Note D-2) 299,564 166,413 Other reserves and deferred credits 101,320 79,134 Commitments and contingencies (Note D)
$ 2.763,092 $ 2,647,715 The accompanying notes are an integral part of these financial statements.
13
New England Pow r C::mpany
' Statements of Cash Flows . _. _
Year ended December 31. (In thousands) 1997 1996 . _ _
1995 Operating activities:
s i 14,543 $ 152,483 $ 151,427 j Net income Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 101,186 108,338 108,384 Deferred income taxes and investment tax credits, net (12,728) (7,458) 25,683 Allowance for funds used during construction (1,238) (591) (19,225)
Decrease (increase) in accounts receivable (25,128) 19,629 1,321 Decrease (increase) in fuel, materials, and supplies 11,217 (4,045) 18,697 Decrease (increase) in prepaid and other current assets 7,213 2,936 5,743 Increase (decrease) in accounts payable (18,105) (36,565) (15,970)
Increase (decrease) in other current liabilities (1,905) 9,640 (2,150)
Other, net 19,919 28.582 (28,244)
Net cash provided by operating activities $ 224,974 $ 272,949 $ 245,666 Investing activities:
Plant expenditures, excluding allowance for funds used during construction $ (69,863) $ (65,981) $(162,766)
Other investing activities (4,040) (3,878) (3,614)
Net cash used in investing activities $ (73,903) $ (69,859) $(166,380)
Financing activities:
Dividends paid on common stock $ (127,386) $(138,995) $(103,198)
Dividends paid on preferred stock (2,075) (2,574) (3,433)
Changes in short-term debt 17,650 (31,550) (20,425)
Long-term debt -issues - 47,850 60,000 Long-term debt - retirements (38,500) (57,850) (10,000)
Preferred stock - retirements - (20,900) -
Premium on reacquisition oflong-term debt (2,163) - -
Gain on redemption of preferred stock - 1,368 -
Net cash used in financing activities $ (152,474) $ (202,651) $ (77,056) l Net increase (decrease) in cash and cash equivalents $ (1,403) $ 439 $ 2,230 Cash and cash equivalents at beginning of year 3,046 2,607 377 Cash and cash equivalents at end of year $ 1,643 $ 3,046 $ 2,607 !
Supplementary information:
Interest paid less amounts capitalized $ 46,033 $ 51,212 $ 41,557 ,
Federal and state income taxes paid $ 109,109 $ 96.006 $ 57.948 l Dividends received from investments at equity $ 3,267 $ 4,313 $ 5,014 l
l The accompanying notes are an integral part of these financial statements. l l4
New England P:wcr Ccmpany N:t:s 13 Financi:1 St t:m:nts Note A- Significant Accounting Policies
- 1. Nature of operations:
The Company, a wholly owned subsidiary of New England Electric System (NEES), is a Massachusetts corporation and is qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of these six states, the Securities and Exchange Commission (SEC), and the Federal Energy Regulatory Commission (FERC). The Company's business is currently that of generating, purchasing, transmitting, and selling electric energy in wholesale quantities to other electric utilities, principally its affiliates Granite State Electric Company (Granite State Electric), Massachusetts Electric Company (Massachusetts Electric), Nantucket Electric Company (Nantucket Electric), and The Narragansett Electric Company (Narragansett Electric). See Note B for a discussion of industry restructuring and Note C for a discussion of the Company's planned divestiture of its nonnuclear generating business.
- 2. System of accounts:
The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction.
In preparing the financial statements, management is required to make estimates that affect the reported i
amounts of assets and liabilities and disclosures of asset recovery and contingent liabilities as of the date of the balance sheets, and revenues and expenses for the period. These estimates mry differ from actual amounts
! if future circumstances cause a change in the assumptions used to calculate these estimates.
l 3. Allowance for funds used during construction (AFDC):
l l
l The Company capitalizes AFDC as part of construction costs. AFDC represents the composite interest and equity costs of capital funds used to f'mance that portion of construction costs not yet eligible for inclusion in rate base. AFDC is capitalized in " Utility plant" with offsetting noncash credits to "Other income" and
" Interest." This method is in accordance with an established rate-making practice under which a utility is permitted a retum on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 5.9 percent,5.8 percent, and 7.5 percent,in 1997,1996, and 1995, respectively.
15
New Engl:nd Pow:r C mpany N tes 13 Financi;l Stat:ments (continued)
Note A-Significant Accounting Policies (continued)
- 4. Depreciation and amortization:
The depreciation and amortization expense included in the statements of income is composed of the following:
Year ended December 31. (In thousands) 1997 1996 1995 ,
Depreciation $ 80,260 $ 78,187 $ 66,309 Nuclear decommissioning costs (Note D-2) 2,638 2,629 2,629 Amortization:
Investment in Seabrook I pursuant to rate settlement - 15,210 23,074 Oil Conservation Adjustment (OCA) - - 4,467 ,
Seabrook 2 property losses 113 6,279 6,279 Millstone 3 additional amortization, pursaant to rate settlement 15,013 1.904 -
Total depreciation and amortization expense $ 98,024 S 104.209 $ 102,758 Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable propeny was 2.9 percent in 1997 and 1996, and 2.7 percent in 1995.
Revenues from the OCA were used to accelerate the amortization of expenditures for coal conversion facilities at the Company's Salem Harbor Station. In addition, Seabrook I costs under the 1988 rate settlement were fully amortized at December 31,1996. Property losses associated with the Company's investment in the canceled Seabrook 2 nuclear unit were fully amortized by March 31,1997.
- 5. Cash:
The Company classifies short-term investments with a maturity of 90 days or less at time of purchase as cash.
- 6. New accounting standards:
In 1997, the Financial Accounting Standards Board released two new Statements of Financial Accounting Standards (FAS), FAS 130 and FAS 131, both of which will go into effect in 1998. FAS 130, Reporting Comprehensive Income, requires the reporting in financial statements of a new additional item called comprehensive income, which will incorporate amounts not previously included in reponed net income. FAS 131, Disclosure about Segments of an Enterprise and Related Information, requires the reporting in financial statements of certain new additional information about operating segments of a business. The Company is l
currently evaluating the impact that these new accounting standards will have on its future reporting requirements.
l Note B -Industry Restructuring As the result of legislation enacted in the states served by the NEES companies, most customers served by the NEES companies will have the ability to choose their power supplier by the first quaner of 1998. When customers are allowed to choose their power supplier, utilities face the risk that market prices may not be sufficient to recover the costs of the commitments incurred to supply customers under a regulated structure.
The amounts by which such costs exceed market prices are commonly referred to as " stranded costs." As described below, the Company has reached settlement agreements with all of its distribution affiliates and with panies representing the distribution customers of those affiliates. In each case, these settlements provide for 16
New Engl:nd Pow;r C::mpany N: tis 13 Fin:nci:1 St:t:m:nta (continued)
Note B - Industry Restructuring (continued) recovery of stranded costs. See the " Industry Restructuring" section of Financial Review for a more in-depth discussion of current developments in this area.
The settlements generally provide for the following:
a introduction of choice of power supplier in Rhode Island, Massachusetts, and New Hampshire by January 1,1998, March 1,1998, and July 1,1998, respectively; e a transition rate, or " standard offer generation service," resulting in rate reductions of approximately 10 percent at the date of commencement of retail choice; a termination of all-requirements contracts be' ween the Company and its distribution affiliates on terms which allow the Company to recover its stranded costs through a transition access charge, which the distribution affiliates will collect from customers; e adjustments to stranded cost recovery to reflect the market value of fossil-fueled and hydroelectric generating assets, determined through divestiture of such assets.
Under the various settlements, the recovery of the Company's stranded costs is divided into several categories.
Unrecovered costs associated with generating plants and regulatory assets would be recovered over 12 years and would eam a retum on equity of approximately 9.4 percent. The above-market component of purchased power contracts and nuclear decommissioning costs would be recovered as incurred over the life of those obligations, a period expected to extend beyond 12 years. Initially, the transition access charge was set at 2.8 cents per kilowatthour (kWh). The MDTE has approved a reduction of the initial transition access charge to 2.7 cents per kWh for Massachusetts Electric and Nantucket Electric, effective March 1,1998. The Company's filing with the FERC to approve this reduction is pending. The transition access charge would be reduced further upon completion of the sale of the Company's generating business, as described below. As the transition access charge declines, the Company would eam incentives based on successful mitigation of its stranded costs. These incentives would supplement the Company's retum on equity. The Massachusetts and Rhode Island settlements were approved by the FERC in November 1997, subject to a compliance filing to clarify the impact of the settlements on nonsettling parties. The Massachusetts Settlement was also found by the Massachusetts Department of Telecommunications and Energy (formerly the Massachusetts Department of Public Utilitiu) to be in substantial compliance with or consistent with the Massachusetts restructuring statute. The New Hampshire settlement is pending before the New Hampshire Public Utilities Commission arf' the FERC.
In August 1997, the Company and Narragansett Electric entered into an agreement to sell substantially all of their nonnuclear generating business to USGen New England, Inc. (USGen), an indirect wholly owned subsidiary of PG&E Corporation. The net proceeds from the sale of its nonnuclear generating business to USGen will be used to reduce the transition access charge to approximately 1.5 cents per kWh. In addition, the FERC accepted the NEES companies proposal in conjunction with their divestiture filing that the recovery of the remaining above-market nuclear generating plant costs and regulatory assets be fully recovered by the end of the year 2000. See Note C for a discussion of the Company's planned divestiture ofits nonnuclear generating business.
Account'ng implications Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71),
requires regulated entities, in appropriate circumstances, to establish regulatory assets, and thereby defer the income statement impact of certain items of income and expense expected to be reflected in future rates.
17
New Engl:nd Pcw:r Ccmpany N:t:a to Fin:ncial St tsm:nts (continued)
Note B - Industry Restructuririg (continued)
In response to concems expressed by the staff of the SEC, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board took under consideration how FAS 71 should be applied in light of recent changes within the regulated utility industry. In July 1997, the EITF concluded that a utility whose ongoing generation operations would not permit the application of FAS 71, but had otherwise received appmval to recover stranded costs through regulated transmission and distribution rates, would be pennitted to continue to apply FAS 71 to the recovery of the stranded costs.
The restructuring settlements and statutes each provide for recovery of substantially all applicable stranded costs of generating assets and oil and gas related assets (including regulatory assets) not recoverable from the proceeds of the divestiture of the Company's generating business. The cost of these assets would be recovered as part of a cost-based transition access charge imposed on all distribution customers. Additionally, FERC Order No. 888 enables transmission companies to recover their specific costs of providing transmission service.
Therefore, after the proposed divestiture, substantially all of the Company's business, including the recovery ofits stranded costs, would remain under cost-based rate regulation. The Company believes these factors and the EITF conclusion will allow it to continue to apply FAS 71. As a result of the FERC approval of the industry restructuring settlements, the Company was required to cease to apply FAS 71 to the 20 percent of its ongoing nuclear operations, as described in Note C, the impact of which is expected to be immaterial.
Despite the progress made to date, it is possible that future regulatory rules or other circumstances could cause the application of FAS 71 to be discontinued, which would result in a noncash write-off of previously established regulatory assets related to the affected operations. In addition, write-downs of plant assets under Statement of Financial Accounting Standards No.121, Accounting for the Impairment of Long-Lived Assets and for long-Lived Assets to Be Disposed Cf (FAS 121) could be required, including a write-off of any gain or loss from the divestiture of the generating business. At December 31, 1997, the Company had approximately $420 million in regulatory assets in compliance with FAS 71, as detailed in the table below.
This amount excludes any effects related to the divestiture of New England Energy Incorporated's (NEEI) (a sholly owned subsidiary of NEES) oil and gas properties, discussed in Note C.
The :omponents of regulatory assets are as follows:
At december 31. (In thousands) 1997 1996 Rrgulatory assets included in current assets and liabilities:
Accrued NEEl losses (see Note D-3) $ 11,419 $ 21,648 Rate adjustment mechanisms (6,957) (4,790) 4,462 16,858 Regulatory assets included in deferred charges and other reserves and deferred credits:
Accrued costs - Yankee nuclear plants (see Note D-2) 299,564 166,413 Unamortized losses on reacquired debt 31,197 31,353 Deferred FAS No.106 costs (see Note E-2) - 13,680 Deferred FAS No.109 costs (see Note F) 25,738 27,461 Purchased power contract termination costs 15,662 19,578 Deferred gas pipeline charges (see Note D-6) 52,570 59,733 Accelerated amortization - Millstone 3 (16,917) (1,904)
Other 4,837 4,884 412,651 321,198
$ 417,113 5 338.056 t
18
New Engl nd P:wcr Comp:ny l Nat:s t3 Fin:nci:1 St t:m:nts (continued)
)
Note C - Divestiture of Generating Business As described above, in August 1997, the Company and Narragansett Electric (collectively, the Sellers) reached an agreement to sell their nonnuclear generating business to USGen. The nonnuclear generating business includes three fossil-fueled generating stations and 15 hydroelectric generating stations, totaling approximately 4,000 megawatts (MW) of capacity, as well as Narragansett Energy Resources Company's (NERC) pannership interest in the Ocean State Power project, all of which has a book value of $1.1 billion. USGen will pay the Sellers $1.59 billion in cash, of which $225 million will be contingent upon the introduction of customer choice of power supplier in Massachusetts. Based on the enactment of the Massachusetts statute, the NEES companies believe that the conditions for payment of the full purchase price have been met. USGen will also reimburse the NEES companies for $85 mill:on of costs associated with early retirement and special severance programs for employees affected by industry restructuring. Since the early retirement program is contingent upon the divestiture, its cost will not be accrued until that time. USGen will assume responsibility for environmental conditions at the Sellers' nonnuclear generating stations. USGen will also assume the Sellers' obligations under long-term fuel and fuel transponation contracts and certain collective bargaining agreements for nonnuclear facilities.
In addition to the purchase of the generating stations, USGen will purchase the Company's entitlement to approximately 1,100 MW of power procured under long-term contracts. The Company will make a monthly fixed contribution toward the above-market cost of the purchased power of between $12.5 million and $14.2 million per month from closing through January 2008. USGen will be responsible for the balance of the costs under the purchased power contracts.
The sale is subject to approval by various state and federal regulatory agencies. Several parties have objected to the sale on various grounds, including allegations that following the sale, USGen would be able to exercise unlawful levels of market power. On February 25,1998, the FERC issued an order that rejected the market power allegations, approved the sale and conditionally approved most supponing filings. On Febmary 27, 1998, the FERC approved the transfer of the hydroelectric generating licenses to USGen. While the timing of receipt of final regulatory approvals is uncertain, receipt of all approvals is unlikely before mid-1998.
Closing is contingent upon all regulatory approvals being obtained by February 1999.
In order to meet the terms of the Company's mortgage indenture, the Company will be required, prior to the consummation of the sale, to either defease or call approximately $278 million of its mortgage bonds. Any defeasance of bonds would be by deposit of cash representing principal and interest to the maturity date, or interest, principal, and general redemption premium to an earlier redemption date. In addition, the Company will retire approximately $372 million of mortgage bonds securing the issuance of a like amount of pollution control revenue bonds (PCRBs) by various public agencies. However, the Company expects that substantially all of the underlying PCRBs will remain outstanding as unsecured obligations of the Company. In addition, the long-term debt of NERC will be retired prior to the closing.
As pan of the divestiture plan, in February 1998, NEEI sold its oil and gas properties for approximately $50 million. NEEI's loss on the sale of approximately $120 million, before tax, has been reimbursed by the Company.
At the divestiture date, any gain or bss from the divestiture of nonnuclear generating assets and oil and gas assets will be recorded as a regulatory asset or liability to be recovered as part of the Company's stranded costs, through the ongoing transition access charge, consistent with the settlement agreements. The Company may be required to record a liabihty for the monthly fixed contribution towards the above-market cost of purchased power. In such an event, the Company would also record a regulatory asset consistent with the settlement agreements.
19
New Engirnd Pow:r C mpany N:tr> 19 Fin:ncl:1 Stat:ments (continued)
Note C - Divestiture of Generating Business (continued)
In addition, the Company will endeavor to sell, or otherwise transfer, its minority interest in three nuclear power plants and a 60 MW interest in a fossil-fueled generating station in Maine to nonaffiliates. Until such time as the nuclear interests are divested, the Company will share with customers 80 percent of the revenues !
I and operating costs related to the units, with shareholders retaining the balance. In the event that the Company determines that it has an impairment of its nuclear plant balances under FAS 121, it will record any such impairment as a regulatory asset.
Note D - Commitments and Contingencies
- 1. Yankee Nuclear Power Companies (Yankees):
The Company has minority interests in four Yankee Nuclear Power Companies. These ownership interests are accounted for on the equity method. The Company's share of the expenses of the Yankees is accounted for in " Purchased electric energy" on the statements of income.
A summary of combined results of operations, assets, and liabilities of the four Yankees is as follows:
- (In thousands) 1997 1996 1995 Operating revenue $ 660,742 $ 697.054 5 695.781 Net income $ 29,959 $ 27.567 $ 31.657 Company's equity in net income $ 5,189 $ 5.159 5 5.721 Net plant $ 204,689 5 401,049 $ 443,967 Other assets 3,100,589 2,031,336 1,418,681 Liabilities and debt (3,036,845) (2,177,068) (1.612,843)
Net assets $ 268,433 $ 255.317 $ 249.805 Company's equity in net assets $ 49,825 $ 47.902 $ 47.055 Company's purchased electric energy $ 107.140 $ 110.778 $ 115.647 At December 31,1997, $16 million of undistributed eamings of the Yankees were included in the Company's retained eamings.
2, Nuclear Units Nuclear Units Permanently Shut Ibwn Three of the four regional nuclear generating companies in which the Company has a minority interest own nuclear generating units which have been pennanently shut down. These three units are as follows:
NEP's Investment Future Estimated Unit Percent Amount Date Retired Billings to NEP($)
Yankee Atomic 30 7 million Feb 1992 44 million Connecticut Yankee 15 17 million Dec 1996 92 million Maine Yankee 20 16 million Aug 1997 164 million in the case of each of these units, the Company has recorded an estimate of the total future payment obligation as a liability and an offsetting regulatory asset, reflecting estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant as well 20 i
New England Pow;r C:mpany Notes ta Financi;l Stat;ments (continued)
Note D - Commitments and Contingencies (continued) as unfunded nuclear decommissioning costs and other costs. Connecticut Yankee and Maine Yankee have both filed similar requests with the FERC. Several panies have intervened in opposition to both filings. The Company's stranded cost settlements allow it to recover all costs that the FERC allows the Yankee companies to bill to the Company.
In October 1997, the Citizen's Awareness Network and Nuclear Information and Resource Service filed a petition with the Nuclear Regulatory Commission (NRC) that would require formal NRC approval of a plant decommissioning plan for the Connecticut Yankee and Maine Yankee plants. In 1998, the petitioners indicated their intention to file a request with the NRC designed to ovenum a current NRC rule on decommissioning. The Company cannot predict what impact, if any, these activities will have on the cost of decommissioning the plants.
At Maine Yankee, the NRC has identified numerous apparent violations of its regulations, which may result in the assessment of significant civil penalties.
In the 1970s, the Company and several other shareholders (Sponsors) of Maine Yankee entered into 27 contracts (Secondary Purchase Agreements) under which they sold portions of their entitlement to Maine Yankee power output through 2002 to various entities, primarily municipal and cooperative systems in New England (Secondary Purchasers). Virtually all of the Secondary Purchasers have ceased making payments under the Secondary Purchase Agreements and have demanded arbitration, claiming that such agreements excuse funher payments upon plant shtdown. The Company has notified the Secondary Purchasers that the shutdown does not relieve them of their obligation to make payments under the Secondary Purchase Agreements and that they are in default of such agreements. The Company has asked the FERC to enforce the Company's rights under the agreements. In the event that no further payments are fonhcoming from Secondary Purchasers, the Company, as a primary obligor to Maine Yankee, would be required to pay an additional $9 million of future shutdown costs. These costs are not included in the $164 million estimate disclosed in the table above. Shutdown costs are recoverable from customers under the stranded cost settlements.
A Maine statute provides that if both Maine Yankee and its decommissioning trust fund htme insufficient assets to pay for the plant decommissioning, the owners of Maine Yankee are jointly and sever ally liable for the shortfall.
Operating Nuclear Units The Company has minority interests in three other nuclear generating units, Vermont Yankee, Millstone 3, and Seabrook 1. In October ? 996, the NRC issued letters to operators of nuclear power plants requiring them to document that the plants are operated and maintained within their design and licensing bases, and that any deviations are reconciled in a timely manner. The Seabrook 1 and Vermont Yankee nuclear power plants responded to the NRC letters in February 1997. Millstone 3 is currently shut down and has been placed on the NRC " Watch List," signifying that its safety performance exhibits sufficient weakness to warrant increased NRC attention. Millstone 3 may not restart without NRC approval.
Uncenainties regarding the future of nuclear generating stations, panicularly older units, such as Vermont Yankee, are increasing rapidly and could adversely affect their service lives, availability, and costs. These uncertainties stem from a combination of factors, including the acceleration of competitive pressures in the power generation industry and increased NRC scrutiny. The Company performs periodic economic viability reviews of operating nuclear units in which it holds ownership interests.
21
New Engl nd Pcwcr C mpany N:t:s to Fin:nci:1 St t:m:nts (continued)
Note D - Commitments and Contingencies (continued)
Millstone 3 In April 1996, the NRC ordered Millstone 3, which has experienced numerous technical and nontechnical problems, to remain shut down pending verification that the unit's operations are in accordance with NRC ,
regulations and the unit's operating license. Millstone 3 is operated by a subsidiary of Northeast Utilities (NU).
The Company is not an owner of the Millstone 1 and 2 nuclear generating units, which are also shut down under NRC orders.
A number of significant prerequisites must be fulfilled prior to restart of Millstone 3, including cenification by NU that the unit adequately conforms to its design and licensing bases, an independent verification of corrective actions taken at the unit, an NRC assessment concluding a safety conscious work environment exists, public meetings, and a vote of the NRC Commissioners. The Company cannot predict when Millstone 3 will be allowed by the NRC to restart, but believes restart of the unit is unlikely prior to the summer of 1998.
Since April 1996, the Company has incurred an estimated $35 million in incremental replacement power costs, which it has been recovering from customers through its fuel clause. During the outage, the Company is incurring incremental replacement power costs of approximately $2 million per month.
Several criminal investigations related to Mi!! stone 3 are ongoing. In December 1997, the NRC assessed civil penalties totaling $2.1 million for numerous violations at the three Millstone units. The Company's share of this fine was less than $100,000. The Connecticut Department of Environmental Protection and Connecticut Attorney General have filed suit against NU for alleged wastewater discharge violations at the Millstone units, which may result in the assessment of substantial civil penalties.
In August 1997, the Company filed suit against NU in Massachusetts Superior Court for damages resulting from the tortious conduct of NU relating to Millstone 3. The Company is seeking compensation for the losses it has suffered, including the costs oflost power and costs necessary to assure that Millstone 3 can safely retum to operation. The Company also seeks punitive damages. NU has filed for dismissal of the suit and sought to consolidate it with suits filed by other joint owners in Massachusetts Superior Court.
The Company also sent a demand for arbitration to Connecticut Light & Power Company and Westem Massachusetts Electric Company, both subsidiaries of NU, seeking damages resulting from their breach of obligations under an agreement with the Company and others regarding the operation and ownership of Millstone 3.
Decommissioning Trust Funds Each nuclear unit in which the Company has an ownership interest has established a decommissioning trust fund or escrow fund into which payments are being made to meet the projected costs of decommissioning.
Listed below is information on each operating nuclear plant in which the Company has an ownership interest.
The Company is liable for its share of decommissioning costs for Millstone 3, Seabrook 1, and all of the Yankees. Decommissioning costs include not only estimated costs to decontaminate the units as required by the NRC, but also costs to dismantle the uncontaminated portion of the units. The Company records decommissioning costs on its books consistent with its rate recovery. The Company is recovering its share of I projected decommissioning costs for Millstone 3 and Seabrook I through depreciation expense. In addition, l the Company is paying its portion of projected decommissioning costs for all of the Yankees through purchased power expense. Such costs reflect estimates of total decommissioning costs approved by the FERC.
1 22
New England Pow:r C:mpany Notes 13 Financial Stat; ment](continued)
Note D - Commitments and Contingencies (continued)
NEP's shart of(millions of dollars)
NEP's Estimated Decommissioning Ownership Net Decommissioning Fund License Unit Interest (c7c) Plant Assets Cost (in 1997 $) Balances
- Expiration Vetmont Yankee 20 35 77 34 2012 Millstone 3 12 366 66 18 " 2025 Seabrook 1*** 10 54 47 9** 2026
- Certain additional amounts are anticipated to be available through tax deductions.
Fund balances are included in "Other investments" on the balance sheets. Any differences from market value are not material.
- Proposed legislation in New Hampshire would make owners of Seabrook I proportional guarantors for decommissioning costs in the event that an owner without a franchise territory fails to fund its share of decommissioning costs.
There is no assurance that decommissioning costs actually incurred by Vermont Yankee, Millstone 3, or Seabrook I will not substantially exceed these amounts. For example, decommissioning cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste; those repositories do not currently exist. If any of the units were shut down prior to the end of their operating licenses, which the Company believes is likely, the funds collected for decommissioning to that point would be insufficient.
Under the settlement agreements discussed in Note B, the Company will recover decommissioning costs through transition access charges.
The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the Department of Energy (DOE)) is responsible foi the disposal of spent nuclear fuel. The federal government requires the Company to pay a fee based on its share of the net generation from the Millstone 3 and Seabrook I nuclear units. The Companyis recovering this fee through its fuel clause. Similar costs are incurred by the Vermont Yankee nuclear generating unit. These costs are billed to the Company and also recovered from customers through the Company's fuel clause. In November 1997, ruling on a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the Court of Appeals for the District of Columbia (Court) held that the DOE is obligated to begin disposing of utilities' spent nuclear fuel by January 31,1998. The DOE failed to meet this deadline. The utilities, including the operators of the units in which the Company has an obligation, are assessing their future options. In February 1998, Maine Yankee petitioned the Court to compel the DOE to remove Maine Yankee's spent fuel from the site.
Nuclear insurance The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident at a nuclear plant to $8.9 billion (based upon 110 licensed reactors). The maximum amount of commercially available insurance coverage to pay such claims is $200 million. The remaining $8.7 billion would be provided by an assessment of up to $79.3 million per incident levied on each of the participating nuclear units in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. The maximum assessment, which was most recently adjusted in 1993, is adjusted for inflation at least every five years. The Company's current interest in the Yankees (excluding Yankee Atomic),
Millstone 3, and Seabrook I would subject the Company to a $58 million maximum assessment per incident.
The Company's payment of any such assessment would be limited to a maximum of $7.3 million per incident per year. As a result of the permanent cessation of power operation of the Yankee Atomic plant, Yankee 23
New Engl:nd Psw:r Ccmpany Notn 13 Fin:ncini Stat:ments (continued)
Note D - Commitments and Contingencies (continued)
Atomic has received from the NRC a panial exemption from obligations under the Price-Anderson Act.
However, Yankee Atomic must continue to maintain $100 million of commercially available nuclear insurance coverage. Connecticut Yankee and Maine Yankee have filed with the NRC for similar exemptions.
Each of the nuclear units in which the Company has an ownership interest also carries nuclear property insurance to cover the costs of propeny damage, decontamination or premature decommissioning, and workers' claims resulting from a nuclear incident. These policies may require additional premium assessments if losses relating to nuclear incidents at units covered by this insurance occurring in a prior six-year period exceed the accumulated funds available. The Company's maximum potential exposure for these assessments, either directly, or indirectly through purchased power payments to the Yankees, is approximately $8 million per year.
- 3. Oil and gas operations:
The Company's affiliate, NEEI, participated in a rate-regulated domestic oil and gas exploration, development, and production program through a partnership with a nonaffiliated oil company. Losses from this program, calculated under the full cost method of accounting, have been charged to the Company, and ultimately to distribution customers, in accordance with SEC and FERC approvals. Such losses were $11 million, $22 million, and $44 million in 1997,1996, and 1995, respectively. In February 1998, after a competitive bidding process, NEEI sold all ofits remaining oil and gas properties held as of December 31,1997 to its partner for
$50 million. The loss on such disposition, approximately $120 million, before tax, has been charged to the Company. The settlements provide for the recovery of the NEEIloss as part of the Company's stnnded costs.
See Note B for a discussion of industy restructuring and Note C for a discussion of the Company's planned divestiture of its nonnuclear generating business.
- 4. Plant expenditures:
The Company's utility plant expenditures are estimated to be approximately $55 million in 1998. At December 31,1997, substantial commitments had been made relative to future planned expenditures.
- 5. Hydro-Quebec Interconnection and arbitration:
l l
The Company is a participant in both the Hydro-Quebec Phase I and Phase II projects. The Company's l participation percentage in both projects is approximately 18 percent. The Hydro-Quebec Phase I and Phase
! II projects were established to transmit power from Hydro-Quebec to New England. Three affiliates of the Company were created to construct and operate transmission facilities related to these projects. The participants, including the Company, have entered into support agreements that end in 2020, to pay monthly their proportionate share of the total cost of constructing, owning, and operating the transmission facilities.
The Company accounts for these support agreements as capital leases and accordingly recorded approximately
$65 million in utility plant at December 31,1997. Under the support agreements, the Company has agreed, in conjunction with any Hydro-Quebec Phase Il project debt financings to guarantee its share of project debt.
At December 31,1997, the Company had guaranteed approximately $25 million of project debt. In the event any Interconnection facilities are abandoned for any reason, each panicipant is contractually committed to pay its pro-rata share of the net investment in the abandoned facilities. The Company's rights and obligations under l its support agreements will be transferred to USGen upon completion of the sale of the Company's nonnuclear i generating business.
In 1996, various New England utilities which are members of the New England Power Pool, including the Company, submitted a dispute to arbitration regarding their Finn Energy Purchased Power Contract with Hydro-Quebec. In June 1997, Hydro-Quebec presented a damage claim of approximately $37 million for past 24 I
1 New Engirnd Powcr Csmpany l Notes to Fin:nci:1 Stat;ments (continued)
Note D - Commitments and Contingencies (continued) damages, of which the Company's share would have been approximately $6 to $9 million. The claims involved a dispute over the components of a pricing formula and additional costs under the contract. With respect to on-going claims, the Company had been paying Hydro-Quebec the higher amount (additional costs of approximately $3 million per year) since July 1996 under protest and subject to refund. In October 1997, an arbitrator mied in favor of the New England utilities in all respects. The Company has made a demand for
. refund. Hydro-Quebec has not yet refunded any monies and has appealed the decision. On November 9, 1937, the Company and the other utilities began a second arbitration to enforce the first decision. Refunds received from Hydro-Quebec will be passed on to customers.
- 6. Natural gas pipeline capacity:
In connection with serving the Company's gas-fueled electric generation facilities, the Company has entered into several contracts for nabral gas pipeline capacity and gas supply. These agreements require minimum fixed payments that are currently estimated to be $59 million to $62 million per year from 1998 to 2002.
Under these agreements, r~naining fixed payments from 2003 through 2014 total approximately $501 million.
In connection with managing its fuel supply, the Company uses a portion of this pipeline capacity to sell natural gas. Proceeds f om the sale of natural gas and pipeline capacity of $41 million, $50 million, and $71 million in 1997,1996, and 1995, respectively, have been passed on to customers through the Company's fuel clause. These proceeds have been reflected as an offset to the related fuel expense in " Fuel for generation" in the Company's statements of income. Natural gas sales decreased in 1996 as a result of the Manchester Street plant entering commercial operation in the second half of 1995.
See Note C for a discussion of the Company's planned divestiture of its nonnuclear generating business.
- 7. Hazardous waste:
The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similarlaws.
The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The Company currently has in place an intemal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for six sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other sites, and may in the future become aware of additional sites, that it may be held responsible for remediating.
Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult.
There are also significant uncenainties as to the portion,if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be bome by the Company. The NEES companies have 25
New Engl:nd P wcr Ccmpany Nat:s t3 Fin:nci;l Stat:ments (continued)
Note D - Commitments and Contingencies (continued) recovered amounts from certain insurers, and, where appropriate, the Company intends to seek recovery from its insurers and from other PRPs, but it is uncertain whether, and to what extent, such effons will be successful.
The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial position.
In October 1996, the American Institute of Certified Public Accountants issued new accounting rules for Environmental Remediation Liabilities which became effective in 1997. These new rules did not have a material effect on the Company's financial position or results of operations.
- 8. Long-term contracts for the purchase of electricity:
The Company purchases a portion of its electricity requirements pursuant to long-term contracts with owners of various generating units. These contracts expire in various years from 1998 to 2029.
Cenain of these contracts require the Company to make minimum fixed payments, even when the supplier is unable to deliver power, to cover the Company's proportionate share of the capital and fixed operating costs of these generating units. The fixed portion of payments under these contracts totaled $114 million in 1997,
$127 million in 1996, and $150 million in 1995, excluding contracts with Yankee Atomic, Connecticut Yankee, and Maine Yankee (see Note D-2) for all periods presenteJ. Thew contracts have minimum fixed payment requirements of $110 million annually from 1998 through 2001, $120 million in 2002, and approximately $950 million thereafter. Approximately 97 percent of the payments under these contracts are to Vermont Yankee and OSP, entities in which NEES subsidiaries hold ownership interests.
The Company's other contracts, principally with nonutility generators, require the Company to make payments only if power supply capacity and energy are deliverable from such suppliers. The Company's payments under these contracts amounted to $265 million in D97, $230 million in 1996, and $245 million in 1995.
See Note C for a discussion of the Company's planned divestiture of its nonnuclear generating business.
- 9. Town of Norwood dispute:
In April 1997, the Town of Norwood, Massachusetts filed a lawsuit against the Company in the United States District Court for the District of Massachusetts. The Company is a wholesale power supplier for Norwood pursuant to rates approved by the FERC. Norwood alleges that the Company's proposed divestiture of its power generation assets would violate the terms of a 1983 power contract which settled an antitrust lawsuit brought by Norwood against the Company. Norwood also alleges that the Company's proposed divestiture plan and recovery of stranded investment costs contravene federal antitrust laws. Norwood seeks an injunction enjoining the divestiture and an unspecified amount of treble damages (a specific claim for $450 million was withdrawn). Norwood's motion for a preliminary injunction of the divestiture was denied on September 8, 1997. On November 21,1997. Norwood filed an amended complaint n aking new allegations relating to the sale of the Company's generating assets and naming as additional defendants, NEES, USGen and USGen's affiliate, PG&E. The Company continues to believe that its divestiture plan will promote competition in the wholesale power generation market and that it has met and will continue to meet its contractual commitments to Norwood. On January 9,1998, the defendants, including NEES and the Company, filed a motion to dismiss the lawsuit. In March 1998, Norwood gave notice of its intent to terminate its contract with the Company, without accepting responsibility for its share of the Company's stranded costs, and to begin taking power from another supplier. The Company has filed with the 1 ERC for permission to charge Norwood a contract termination charge for its share of the Company's stranded costs.
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New Engl nd Pow:r C:mp ny i Nat:s 13 Fin:ncial Stat:ments (continued)
Note E - Employee Benefits
- 1. Pension plans:
The Company participates with other subsidiaries of NEES in noncontributory, defined-benefit plans covering substantially all employees of the Company. The plans provide pension benefits based on the employee's compensation during the five years prior to retirement. The Company's funding policy is to contribute each ;
year the net periodic pension cost for that year. However, the contribution for any year will not be less than I the minimum contribution required by federal law or greater than the maximum tax deductible amount.
The Company's net pension cost for 1997,1996, and 1995 included the following components:
Year ended December 31, (In thousands) 1997 1996 1995 Service cost - benefits earned during the period $ 2,887 $ 2,769 $ 2,231 1
1 Plus (less):
Interest cost on projected benefit obligation 7,003 6,669 6,406
)
l Return on plan assets at expected long-term rate (7,842) (7,204) (6,488)
Amortization 61 270 131 Net pension cost $ 2,109 $ 2.504 $ 2.280 Actual retum on plan assets $ 18,362 $ 12.672 $17.108 Year ended December 31. 1998 1997 1996 1995 Assumptions used to determine pension cost: l Discount rate 6.75 % 7.25 % 7.25 % 8.25 %
Average rate of increase in future compensation levels 4.13 % 4.13 % 4.13 % 4.63 % l Expected long-term rate of return on assets 8.50 % 8.50% 8.50 % 8.75 %
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New England Psw:r Campany Notes 13 Financi"J Stat:ments (continued)
Note E - Employee Benefits (continued) l The funded status of the plans cannot be presented separately for the Company as the Company participates !
in the plans with other NEES subsidiaries. The following table sets forth the funded status of the NEES l companies' plans at December 31:
At December 31. (In millions) 1997 1996 Benefits earned Actuarial present value of accumulated benefit liability:
Vested $647 $640 Non-vested 18 19 Tom] $665 $ 659 Reconciliation of funded status Actuarial present value of projected benefit liability $757 $753 Unrecognized prior service costs (8) (9)
FAS No. 87 transition liability not yet recognized (amortized) (1) (1)
Net gain (loss) not yet recognized (amortized) 61 40 809 783 Pension fund assets at fair value 834 812 FAS No. 87 transition asset not yet recognized (amonized) (10 (10) 826 802
- Accmed pension /(prepaid) payments recorded on books y17) $ (19)
The plans' funded status at December 31,1997 and 1996 were calculated using the assumed rates from 1998 and 1997, respectively, and the 1983 Group Annuity Mortality table.
l Plan assets are composed primarily of corporate equity, debt securities, and cash equivalents.
l l 2. Postretirement Benefit Plans Other Than Pensions (PBOPs):
l The Company provides health care and life insurance coverage to eligible retired employees. Eligibility is l based on certain age and length of service requirements and in some cases retirees must contribute to the cost
! of theircoverage.
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New Engl::nd Pow;r C:mpany N:tes t3 Financirl Stat:m:;nts (continued)
Note E - Employee Benefits (continued)
The Company's total cost of PBOPs for 1997,1996, and 1995 included the following components:
. . _ . _ _ . _ _ _ . . . ~ _ _ _ . . . _ . _ . _ _ _ _ _ _ _ _
Year ended December 31. (In thousands) 1997 1996 1995 Service cost - benefits camed during the period $ 1,363 $1.407 $1,344 Plus (less):
Interest cost on accumulated benefit obligation 3,545 3,580 4,013 Retum on plan assets at expected long-term rate (2,343) (1,832) (1,374) l Amortization 1,581 1.867 2.079 Net postretirement benefit cost S 4,146 $ 5.022 .$ 6.062 l Actual retum on plan assets $5.387 $ 3.572 $ 4.137 Year ended December 31 1998 1997 ,1996 1995
==
Assumptions used to determine postretirement benefit cost: ;
Discount rate 6.75 % 7.25 % 7.25 % 8.25 % 1 Expected long-tenn rate of return on assets 8.25 % 8.25 % 8.25 % 8.50% l Health care cost rate - 1995 to 1999 5.25 % 8.00 % 8.00 % 8.50%
Health care cost rate - 2000 to 2004 5.25 % 6.25 % 6.25 % 8.50%
Health care cost rate - 2005 and beyond 5.25 % 5.25 % 5.25 % 6.25 %
The following table sets forth the Company's benefits eamed and the plans' funded status:
At December 31. (In millions) 1997 1996 Accumulated postretirement benefit obligation:
Retirees $ 29 $ 32 Fully eligible active plan participants 2 2 Other active plan participants 20 20 Total benefits earned 51 54 Unrecognized transition obligation (38) (41)
Unrecognized net gain 21 13 34 26 Plan assets at fair value 34 29 Prepaid postretirement benefit costs recorded on books $ -
$ 3 The plans' funded status at December 31,1997 and 1996 were calculated using the assumed rates in effect for 1998 and 1997, respectively.
The assumptions used in the health care cost trends have a significant effect on the amounts reported.
Increasing the assumed rates by 1 percent in each year would increase the accumulated postretirement benefit obligation as of December 31,1997 by approximately $6 million and the net periodic cost for 1997 by approximately $0.8 million.
The Company funds the annual tax-deductible contributions. Plan assets are invested in equity and debt securities and cash equivalents.
I 29
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New England P;w:r C:mpany Not:s to Financial Stat;ments (continued)
Note F -Income Taxes j l
The Company and other subsidiaries panicipate with NEES in filing consolidated federal income tax returns.
The Company's income tax provision is calculated on a separate retum basis. Federal income tax retums have been examined and reported on by the Internal Revenue Service through 1993.
Total income taxes in the statemerts of income are as follows:
)
Year ended December 31, (In thousands) 1997 1996 1995 Income taxes charged to cprrations $ 90,009 $ 91,894 $ 91,051 l Income taxes cl.arged (credited) to "Other income" (373) 555 353 S 89,636 $ 92,449 $ 91,404 Totalincome taxes Total income taxes, as shown above, consist of the following components:
Year ended December 31, (In thousands) 1997 1996 1995 Current income taxes $102,364 $ 99,907 $ 653'21 Deferred income taxes (10,705) (5,435) 27,188 Investment tax credits, net (2,023) (2,023) (1,505)
Totalincome taxes $ 89,636 $ 92,449 $ 91,404 Investment tax credits have ban deferred and are being amortized over the estimated lives of the property giving rise to the credits.
Total income taxes, as shown above, consist of federal and state components as follows:
' Year ended December 31, (In thousands) 1997 1996 1995 Federalincome taxes $ 73,077 $ 76,656 $ 74,590 State income taxes 16,559 15,793 16,814 Total income taxes $ 89,636 $ 92,449 $ 91,404 With regulatory approval from the FERC, the Company has adopted comprehensive interperiod tax allocation (nornialization) for temporary book / tax differences.
Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows:
Year ended December 31, (In thousands) 1997 1996 1995 Computed tax at statutory rate $ 81,963 $ 85,726 $ 84,991 l Increases (reductions) in tax resulting from:
Amortization ofinvestment tax credits (2,023) (2,023) (2,227)
State income taxes, net of federal income tax benefit 10,763 10,265 10,929 All other differences (1,067) (1,519) (2,289)
Total income taxes $ 89,636 $ 92,449 $ 91,404 l 30
New England Pow:r C:mpany Notes t3 Fin:ncial Stat:ments (continued)
Note F - Income Taxes (continued)
The following table identifies the major components of total deferred income taxes:
At December 31,(In millions) 1997 l996 Deferred tax asset:
Plant related $ 87 $ 97 Investment tax credits 22 23 All other 44 46 153 166 Deferred tax liability-Plant related (418) (415)
Equity AFDC (43) (45)
All other (62) (88)
(523) (548)
Net deferred tax liability $(370) $ (382)
Note G - Short-term Borrowings and Other Accrued Expenses At December 31,1997, the Company had $111 million of shon-term debt outstanding including $108 million in commercial paper borrowings and $3 million of borrowings from affiliates. NEES and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside shon-term borrowings.
Companies which invest in the pool share the interest camed on a basis proponionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.
At December 31,1997, the Company had lines of credit and standby bond purchase facilities with banks totaling $375 million which are available to provide liquidity support for commercial paper borrowings and for $372 million of the Company's outstanding variable rate mongage bonds in tax-exempt commercial paper mode (see Note I) and for other corporate purposes. There were no borrowings under these lines of credit at December 31,1997. Fees are paid on the lines and facilities in lieu of compensating balances.
The weighted average rate on outstanding short-term borrowings was 5.7 percent at December 31,1997. The fair value of the Company's shon-term debt equals carrying value.
The components of other accrued expenses are as follows:
At December 31,(In thousands) 1997 1996 Accrued wages and benefits $ 9,838 $ 7,190 Capital lease obligations due within one year 4,333 4,328 Rate adjustment mechanisms 6,957 4,790 Other 2,426 269
$23,554 $ 16,577 i
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New Engl::nd Pcwcr Company Not:s to Fin ncitt Stat:ments (continued)
Note H - Cumulative Preferred Stock
( A summary of cumulative preferred stock at December 31,1997 and 1996 is as follows (in thousands of dollars except for share data):
l Shares Authorized Dividends Call l
and Outstanding Amount Declared Price l _
1997 1996 1997 1996 1997 1996
$100 Par value 6.00% Series 75,020 75,020 $ 7,502 $ 7,502 $ 451 $ 451 (a) 4.56% Series 100,000 100,000 10,000 10,000 456 456 $ 104.08 4.60% Series 80,140 80,140 8,014 8,014 368 368 $ 101.00 I i
l 4.64% Series 41,500 41,500 4,150 4,150 192 328 $ 102.56 )
6.08% Series 100,000 100,000 10,000 10,000 608 608 $ 102.34 l l 7.24% Series - - - - - 363 $ 103.06 l Total 3 % ,660 396,660 $ 39,666 $ 39,666 $ 2,075 $2,574 i
(a) Noncallable.
The annual dividend requirement for total cumulative preferred stock was $2,075,000 for 1997 and for 1996.
During 1997, the Company's parent, NEES, purchased preferred stock of the Company with a par value of $29 l million.
In August 1996, the Company repurchased $6 million of its 4.64 percent series of cumulative preferred stock.
In May 1996, the Company redeemed all ($15 million) of its 7.24 percent series of cumulative preferred stock.
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New Engl:nd Pow:r Campany Not:s to Fin:ncial Stit:ments (continued)
Note 1 - Long-term Debt A summary of long-term debt is as follows:
At December 31, (In thousands)
Series Rate % Maturity 1997 1996 General and Refunding Mongage Bonds:
Y(94-3) 8.10 December 22,1997 $ 3,000 W(93-2) 6.17 February 2,1998 $ 4 300 4,300 W(93-4) 6.14 February 2,1998 1,300 1,300 W(93-5) 6.17 February 3,1998 5,000 5,000 W(93-7) 6.10 February 4,1998 10,000 10,000 W(93-9) 6.04 February 4,1998 29,400 29,400 Y(94-4) 8.28 December 21,1999 10,000 10,000 W(93-6) 6.58 February 10,2000 5,000 5,000 Y(95-1) 7.94 February 14,2000 5,000 5,000 Y(95-2) 7.93 February 14,2000 10,000 10,000 Y(95-3) 7.40 March 21,2000 10,000 10,000 Y(95-4) 6.69 June 5,2000 25,000 25,000 W(93-1) 7.00 February 3,2003 25,000 25,000 Y(94-2) 8.33 November 8,2004 10,000 10,000 K 7.25 October 15,2015 38,500 38,500 X variable March 1,2018 79,250 79,250 R variable November 1,2020 135,850 135,850 S variable November 1,2020 50,600 50,600 U 8.00 August 1,2022 134,500 170,000 V variable October 1,2022 106,150 106,150 Y(94-1) 8.53 September 20,2024 5,000 5,000 Unamonized discounts (2,130) (2.344)
Total long-term debt 697,720 736.006 Long-term debt due in one year (50,000) (3,000)
$ 647,720 $ 733.006 Substantially all of the propenies and franchises of the Company are subject to the lien of the mortgage indentures under which the general and refunding mongage bonds have been issued.
The Company will make cash payments of $50 million in 1998, $10 million in 1999, and $55 million in 2000 to retire maturing mongage bonds. There are no cash payments required in either 2001 or 2002.
The terms of the $372 million of variable rate PCRBs collateralized by the Company's mongage bonds at December 31,1997 require the Company to reacquire the bonds under certain limited circumstances. At December 31,1997, interest rates on the Company's variable rate bonds ranged from 3.70 percent to 4.85 percent. See Note C for information on potential bond defeasance.
At December 31,1997, the Company's long-term debt had a carrying value of $700,000,000 and had a fair value of approximately $721,000,000. The fair value of debt that reprices frequently at market rates approximates canying value. For all other debt, the fair market value of the Company's long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the Company for debt of the same remaining maturity.
33
New Engl:nd Pow:r Osmpany N:t:0 ta Fin;ncial Stattm:nts (continued)
Note J - Restrictions on Retained Earnings Available for Dividends on Comrnon Stock Pursuant to the provisions of the Articles of Organization and the By-Laws relating to the Dividend Serics Preferred Stock, certain restrictions on payment of dividends on common stock would come into effect if the
" junior stock equity" was, or by reason of payment of such d.:vidends became, less than 25 percent of ' Total capitalization." However, the junior stock equity at December 31,1997 was 55 percent of total capitalization, including long-term debt due in one year, and, accordingly, none of the Company's retained eamings at December 31,1997 were restricted as to dividends on common stock under the foregoing provisions.
Under restrictions contained in the indentures relating to general and refunding mortgage bonds (Series K),
none of the Company's retained eamings at December 31,1997 were restricted as to dividends on common i
stock. However, a portion of the Company's retained eamings (less than $30 million) may be restricted due to regulatory requirements related to hydroelectric licensed projects.
Note K - Supplementary income Statement Information Advertising expenses, expenditures for research and development, and rents were not material and there were l
no royalties paid in 1997,1996, or 1995. Taxes, other than income taxes, charged to operating expenses are set forth by classes as follows:
Year ended December 31, (In thousands) 1997 1996 1995 l $ 58,942 $ 49,807 Municipal property taxes $ 59,102 l
Federal and state payroll
! and other taxes 8,209 7,474 8,909
$ 67.311 $ 66,416 $ 58,716 New England Power Service Company, an affiliated service company operating pursuant to the provisions of ,
l Section 13 of the Public Utility Holding Company Act of 1935, fumished services to the Company at the cost of such services. These costs amounted to $91,985,000, $85,124,000, and $1%,411,000, including capitalized construction costs of $24,347,000, $19,412,000, and $24,671,000, for each of the years 1997,1996, and 1995, respectively, i
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New England Pow r C:mpany i Not:3 to Financial Statim:;nts (continued)
Selected FinancialInformation Year ended December 31, (In millions) 1997 1996 1995 1994 1993 Operating revenue:
Electric sales (excluding fuel cost recovery) $ 921 $ 918 $ 941 $ 942 $ 939 Fuel cost recovery 6% 642 594 563 576 Other 61 40 36 36 34 Tott.] operating revenue $ 1,678 $1,600 $1,571 $1,541 $ 1,549 Net income $ 145 $ 152 $ 151 $ 149 $ 141 Total assets $2,763 $ 2,648 $ 2,648 $ 2,613 $ 2,441 Capitalization:
Common equity $ 913 $ 906 $ 889 $ 877 $ 850 Cumulative preferred stock 40 40 61 61 61 Long-term debt 648 733 735 695 667 Total capitalization $ 1,601 $1,679 $1,685 $ 1,633 $1,578 Preferred dividends declared $ 2 $ 3 $ 3 $ 3 $ 5 Common dividends declared $ 135 $ 134 $ 135 $ 119 $ 111 Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth (in thousands) Quarter Quarter Quarter Quaner 1997 Operating revenue $ 438,048 $ 396,049 $ 443,774 $ 400,032 Operating income $ 50,652 $ 30,028 $ 64,535 $ 45,637 Net income $ 37,945 $ 19,515 $ 52,019 $ 35,064 1996 Operating revenue $ 400,460 $ 375,001 $ 431,420 $ 393,428 Operating income $ 55,277 $ 39,628 $ 63,782 $ 45,074 Net income $ 40,973 $ 26,768 $ 52,559 $ 32,183 Per share data is not relevant because the Company's common stock is wholly owned by New England Electric System.
A copy of New England Power Company's Annual Repon on Form 10-K to the Securities and Exchange Commission for the year ended December 31,1997 will be available on or about April 1,1998, without charc., upon written request to New England Power Company, Shareholder Services Department,25 Research Drive, Westborough, Massachusetts 01582.
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