ML20195E344
| ML20195E344 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 11/16/1998 |
| From: | Weafer R BOSTON EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| BECO-2-98-148, NUDOCS 9811180319 | |
| Download: ML20195E344 (28) | |
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$% Boston Edison A SEC ENERGY COMPANY 800 Boylston Street Boston, Massachusetts 02199 Robert J. Weafer, Jr (617) 424-2463 I
Vice President, Controller i
and Chief Accounting Officer l
1 November 16,1998 BECo Ltr. 2-98-148 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 Docket No. 50-293 License No. DPR-35 D:ar Sir:
In accordance with 10CFR140.21 and the 1975 amendments to the Price Anderson Act (Public Law 94-97),
Boston Edison is submitting the following:
1.
Boston Edison Company Annual Report for 1997 2.
Boston Edison Company Form 10-Q for the quarter ended September 30,1998, as filed with the Securities and Exchange Commission 3.
Cash Flow Forecast for the Year 1999 4.
Narrative Statement of Curtailment of Capital Expenditures Very truly yours,
(
Enclosures cc:
Mr. Alan B. Wang, Project Manager Mr. Ira P. Dintz Project Directorate I-1 Insurance Indemnity Specialist
/
Office of Nuclear Reactor Regulation Office of Nuclear Reactor Regulation Mail Stop: 1482 Mail Stop: 10H5 j
i U. S. Nuclear Regulatory Commission U. S. Nuclear Regulatory Commission 1 White Flint North 1 White Flint North 11555 Rockville Pike 11555 Rockville Pike Rockville, MD 20852 Rockville, MD 20852
/
/19 V Regional Administrator, Region 1 Senior Resident inspector j
/
U. S. Nuclear Regulatory Commission Pilgrim Nuclear Power Station 475 Allendale Roade King of Prussia, PA 19406 9811180319 981116 v
PDR ADOCK 05000293 I
PDR l
o Y.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION i
Washington, D.C.
20549 FORM 10-0 l
[x] Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 1998 or
[ ]
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to Commission file number 1-2301 BOSTON EDISON COMPANY (Exact name of registrant as specified in its charter)
Massachusetts 04-1278810 (State or other jurisdiction of
( I.. R. S. Employer incorporation or organization)
Identification No.)
800 Boylston Street, Boston, Massachusetts 02199 (Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area code:
617-424-2000 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x
No Indicate the number of shares outstanding of each of the issuer's classes of l
common stock, as of the latest practicable date.
I Class outstanding at September 30, 1998 Common Stock, $1 par value 100 shares
-Part I - Financial Information t
Item 1.
Financial Statements Boston Edison Company Consolidated Statements of Income (Unaudited)
(in thousands)
Three Months Nine Months Ended September 30, Ended September 30, 1998 1997 1998 1997 i
Operating revenues
$476,226
$520,414
$1,256,767 $1,370,104 Operating expenses:
Energy supply 191,197 202,991 522,262 607,150 Operations and maintenance 85,902 103,569 269,099 301,321 Depreciation and amortization 22,329 29,089 69,453 71,273 Demand side management and renewable energy programs 10,102 7,463 27,144 21,560 Taxes - property and other 15,312 24,808 62,684 76,963 Income taxes 50,578 45,821 90,816 78,395 Total operating expenses 375,420 413,741 1,041,458 1,156,662 Operating income 100,806 106,673 215,309 213,442 i
Other income (expense), net 799 1,697 (4,318) 3,508 Operating and other income 101,605 108,370 210,991 216,950 Interest charges:
Long-term debt 19,457 23,049 63,489 69,436 Other 66 4,174 7,786 12,129 Allowance for borrowed funds used during construction (410)
(271)
(975)
(949)
Total interest charges 19,113 26,952 70,300 80,616 Net income S 82,492 S 81,418 S 140,691 S
136,334 Consolidated Statements of Retained Earnings (Unaudited)
(in thousands)
Balance at the beginning of the period
$262,116
$290,832 S 328,802 S 292,191 Net income 82,492 81,418 140,691 136,334 Dividends declared:
Dividends to common shareholders 0
(22,802)
(22,802)
(68,406)
Dividends to BEC Energy (23,000) 0 (116,000) 0 Preferred stock (1,486)
(2, 919)
(7,275)
(10,230)
Transfer of BETG to BEC Energy 0
0 (2,980)
O Subtotal 320,122 346,529 320,436 349,889 Provision for preferred stock redemption and issuance costs (7,459)
(157)
(7,773)
(3,517)
Balance at the end of the period S312,663
$346,372 S 312,663 S 346,372 Per share data is not relevant because Boston Edison Company's common stock is wholly owned by BEC Energy.
The accompanying notes are an integral part of the consolidated financial statements.
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i Boston Edison Company Consolidated Balance Sheets (Unaudited)
(in thousands)
September 30, December 31, 1998 1997 Assets Utility plant in service, at original cost
$2,689,406 S4,451,134 Less: accumulated depreciation 903,432 1,712,903 1,785,974 2,738,231 Generation-related regulatory asset, net 374,095 0
-Nuclear fuel, net 60,049 67,935 Construction work in progress 43,812 33,292 Net utility plant 2,263,930 2,839,458 Non-utility property G
14,669 Nuclear decommissioning trust 168,990 151,634 Equity investments 20,726 35,455 Other investments 9,063 7,107 Current assets:
Cash and cash equivalents 138,734 4,140 Accounts receivable 256,560 207,093 Accrued unbilled revenues 21,736 30,048 Fuel, materials and supplies, at average cost 16,175 60,834 Prepaid expenses and other
__ 67,276 31,283 Total current assets 500,481 333,398 Other regulatory assets:
Power contracts 62,534 71,445 Income taxes, not 51,876 51,096
' Redemption premiums 24,016 27,019 Postretirement benefits costs 21,804 22,441 Other 1,045 23,369 Total regulatory assets 161,275 195,370 Other-deferrei debits 28,201 45,256 Total assets
$3,152,666
$3,622,347 The accompanying notes are an integral part of the consolidated financial statements.
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l Boston Edison Company Consolidated Balance Sheets (Unaudited)
(in thousands)
September 30, December 31, 1998 1997 l
Capitalization and Liabilities Common stock equity:
Common stock and premium
$ 742,905
$ 744,652 1
Retained earnings 312,663 328,802 l
Total common stock equity 1,055,568 1,073,454 Cumulative preferred stock:
Nonmandatory redeemable series 43,000 83,000 Mandatory redeemable series 48,980 78,093 Total preferred stock 91,980 161,093 Long-term debt 955,638 1,057,076 Total capitelization 2,103,186 2,291,623 Current liabilities:
.Long-term debt / preferred stock due within one year 1,067 102,667
-Notes payable 0
137,013 Accounts payable 98,759 87,015 Transition contract payable 31,223 0
Taxes payable 33,018 (630)
Accrued interest 11,675 24,289 Dividends payable 23,993 24,748 Other 153,941 128,691 i
Total current liabilities 353,676 503,793 Deferred credits:
Accumulated deferred income taxes 350,569 485,738 Accumulated deferred investment tax credits 46,714 60,736 Nuclear decommissioning liability 172,423 155,182 Power contracts 62,534 71,445 Other 63,564 53,830 Total deferred credits 695,804 826,931 Commitments and contingencies Total capitalization and liabilities
$3,152,666 S3,622,347 l
l The accompanying notes are an integral part of the consolidated financial statements.
i
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Boston Edison Company Consolidated Statements of Cash Flows (Unaudited)
(in thousands) i Nine Months Ended September 30, i
1998 1997 l
Operating activities:
Net income
$ 140,691 S 136,334 Adjustments to reconcile net income to net l
cash provided by operating activities:
Depreciation and amortization 178,051 170,395 l
Deferred income taxes and investment i
tax credits (149,710)
(21,707) l Allowance for borrowed funds used during construction (975)
(949) j.
Net changes in:
Accounts receivable and accrued
[
untilled revenues (28,305) 3,704 Fuel, materials and supplies 28,667 (172)
Transition contract and other accour.ts payable 48,926 (45,242)
Other current assets and liabilities 9,423 27,841 Other, net 3,801 (4,590)
Net cash provided by operating activities 230,569 265,614 Investing activities:
Plant expenditures (excluding AFUDC)
(66,998)
(90,900)
Proceeds from sale of fossil assets 533,633 0
1 Nuclear fuel expenditures (11,141)
(2,811)
Investments (29,639)
(28,711)
Net cash provided by (used in) investing
~~~
activities 425,855 (122,422)
Financing activities:
Issuances:
Common stock 0
144 Long-term debt 0
'100,000 Redemptions:
Preferred stock (71 519)
(44,000)
Long-term debt (201,600)
(101,600; Net change in notes payable (101,878)
(17,164)
Dividends paid (146,833)
(79,234)
Net cash used in financing activities (521,830)
(141,854)
Net increase in cash and cash equivalents 134,594 1,338 Cash and cash equivalents at beginning of year 4,140 5,651 Cash _and cash equivalents at end of period 1_138,734 S
6,989 Supplemental disclosures of cash flow information:
Cash paid during the period for:
l Interest, net of amounts capitalized S 79,549
$ 87,916 Income taxes S 182,200 S 59,289 The accompanying notes are an integral part of the consolidated financial statements.
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Notes to Unaudited Consolidated Financial Statements A)
Basis of Presentation Boston Edison Company (Boston Edison) received final approval of its reorganization plan to form a holding company structure from the Securities and Exchange Commission on May 20, 1998.
Effective May 20 the holding company, BEC Energy (BEC), was formed with Boston Edison as a wholly owned subsidiary of BEC.
Unde-the new holding company structure the owners of Boston Edison's common stock became BEC common shareholders.
Existing debt and preferred stock of Boston Edison remained obligations of the regulated utility business.
Effective June 25, 1998, Boston Energy Technology Group (BETG) ceased being a subsidiary of Boston Edison and became a wholly owned i
subsidiary of BEC.
The accompanying consolidated financial statements reflect the results of operations and cash flows of Boston Edison prior to the reorganization.
BETG is excluded from the results of cperations and casn flows of Boston Edison in the third quarter of 1998.
The consolidated balance sheet at December 31, 1997 reflects the financial position of Boston Edison which also included BETG.
BETG is excluded from the consolidated balance j
sheet of Boston Edison at September 30, 1998.
i The accompanying unaudited consclidated financial statements should be read in conjunction with the Boston Edison 1997 Annual Report on Form 10-K and Forms 10-0 for the periods ended March 31, 1998 and June 30, 1998.
The financial information presented as of September 30 has been prepared from Boston Edison's books and records without audit by independent accountants.
Financial information as of December 31 has been derived from tne audited financial statements of Boston Edison, but does not include all disclosures required by generally accepted accounting principles (GAAP).
In the opinion of management, all adjustments (which are of a normal recurring nature) necessary for a fair presentation of the financial information for the periods indicated have been incluc.i.
Certain reclassifications have been made to the prior year data to conform with the current presentation.
Under the Boston Edison restructuring settlement agreement, which was approved by the Massachusetts Department of Telecommunications and Energy (DTE),
approximately 75% of the net assets of Pilgrim Nuclear Power Station are recoverable through a non-bypassable transition charge of the utility's distribution business.
The distribution business continues to be subject to rate-regulation.
The remaining 25% is collected under Pilgrim's wholesale power contracts with other utilities and municipalities.
Consistent with the guidance from accounting authoritative bodies regarding any impaired portion of utility plant assets identified for recovery in a legislative / rate order, the 1998 consolidated balance sheet reflects a reclassification of the Pilgrim net assets recoverable through the transition charge from utility plant to regulatory asset.
This Pilgrim regulatory asset, included in the generation-related regulatory asset on the consolidated balance sheet at September 30, 1998, continues to be grouped with utility plant for financial statement presentation.
Refer to Note C of Item 8 in the Boston Edison 1997 Annual Report on Form 10-K for more information on the accounting implications of the electric utility industry restructuring and the utility's related settlement l
agreement.
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Finalization of the sale of Boston Edison's fossil generating assets to Sithe Energies took place on May 15, 1998.
Boston Edison received proceeds from the sale of $655 million, including $121 million for a six-month transitional power purchase contract.
The amount received above net book value on the sale of these assets will be returned to Boston Edison's customers over the settlement period.
That amount is partially offset by certain costs recoverable through the transition charge due to the support of standard cffer s
service provided by Boston Edison's fossil generating assets prior to the fossil divestiture.
The net deferred gain is included as a reduction to the generation-related regulatory asset on the consolidated balance sheet at September 30, 1998.
In addition, Boston Edison received $19 million from Sithe for inventory and other closing adjustments.
Under the terms of Boston Edison's settlement agreement, generation and j
ourchased power costs are recovered from customers.
The settlement agreement allows for the deferral of the difference between these costs and the amounts b;.11ed to customers with a return for future recovery.
The net undercollection from the settlement recovery mechanisms at September 30, 1998 was more than offset by an overrecovery of approximately $36 million from the fuel and purchased power clause and is included in other regulatory assets on the consolidated balance sheet.
The fuel and purchased power clause ceased on March 1, 1998.
The inclusion of the over recovered fuel and purchased power clause costs as an offset to the settlement recovery mechanisns is consistent with Boston Edison's proposal made to the DTE.
Generation and purchased power costs recoverable under the settlement agreement have been separately reflected as energy supply expenses on the consolidated statements of income.
These costs include retail generation-related depreciation and amortization, decommissioning and other operating costs recovered through the transition charge.
The corresponding 1997 expenses have been reclassified for comparability.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
The results of operations for the three and nine-month periods ended September 30, 1998 and 1997 are not indicative of the results which may be expected for an entire year.
Kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions.
B)
Nature of Operations Within the newly restructured electric utility industry, BEC has announced its intention to focus its utility operations on the transmission and distribution of energy.
In April 1998, Boston Edison began soliciting expressions of interest for the sale of Pilgrim Nuclear Power Station as part of the l
previously announced strategy to exit the generation business.
Final bids for l
the purchase of Pilgrim were received on October 16, 1998.
Boston Edison is currently evaluating those bids and anticipates signing a purchase and sale agreement by year-end 1998. Boston Edison provides standard offer service to l
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all customers of record as of the retail access date, March 1, 1998.
Default service is provided to customers who are not eligible for standard offer service or who elect to not contract with a competitive energy supplier. As of September 30, 1903, 90% of customers are receiving standard offer service, while 10% are receiving default service.
No customers are receiving generation service from competitive suppliers.
Boston Edison delivers elect ricity at retail to an area of 590 square miles, including the City of i
Boste: and 39 surrounding cities and tcwns.
It also supplies electricity at wholeeele for resale to other utilities and municipal electric departments.
Bostc Edison is required to continue to develop and implement electric demand side agement programs as well as to provide funding for renewable energy proj oursuant to the Massachusetts electric industry restructuring legislh.
enacted in Novenber 1997.
1 C)
Contingencies
- 1. Hazardous Waste Boston Edison is an owner or operator of approximately 20 properties where oil or hazardous materials were spilled or released. As such, Boston Edison is required to clean up these remaining properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection.
There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics i
of the different sites.
Boston Edison continues to evaluate the cleanup costs of these sites.
It also faces possible liability as a potentially responsible party in the cleanup of five multi-party hazardous waste s..tes in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites.
Boston Edison is one of many potentially responsible parties and currently expects to have only a small percentage of the total potential liability for these sites.
Through September 30, 1998, Boston Edison had approximately $6 million accrued on its consolidated balance sheet related to its cleanup liabilities.
Management is unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, however based on its assessments of the specific site circumstances, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position.
However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
- 2. Generating Unit Performance Program Boston Edison's generating unit performance program ceased March 1, 1998.
Under this program the recovery of incremental purchased power costs resulting from generating unit outages prior to March 1, 1998 are subject to regulatory review.
Proceedings relative to generating unit performance remain pending l
before the DTE.
Management is unable to fully determine a range of reasonably l
possible disallowance costs in excess of amounts accrued, however based on its l
assessments of the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consclidated financial position.
However, it is reasonably possible that additional disallowance costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
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- 3. Connecticut Yankee Boston Edison is a 9.5% equity investor and power purchaser of Connecticut Yankee Atomic Power Company (CYAPC). The investment in CYAPC at September 30, 1998 is approximately $10 million and is included in equity investments on the consolidated balance sheet.
In December 1996, the Board of Directors of CYAPC, which owns and operates the Connecticut Yankee nuclear electric generating unit, unanimously voted to retire the unit.
The decision was based on an economic analysis of the costs of operating the unit through 2007, the period of the operating license, compared to the costs of closing the unit and incurring replacement power costs for the same period.
In December 1996, CYAPC filed for rate relief at the Federal Energy Regulatory j
Commission (FERC) seeking to recover certain post-operating costs, including decommissioning.
On August 31, 1998, the FERC Administrative Law Judge (ALJ) released an initial decision regarding CYAPC's filing. This decision celled for the disallowance of the common equity return on the CYAPC investment subsequent to the shutdown. The decision also stated that decommissioning collections should continue to be based on a previously approved estimate, with an adjustment for inflation, until a more reliable estimate is developed.
In October 1998, both CYAPC and Northeast Utilities, a 49% equity investor in CYAPC, filed briefs on exceptions to the ALJ decision.
If the initial decision is upheld, CYAPC could be required to write of f a portion of its investment in the generating unit and refund a portion of the'previously collected return on investment. Management is currently unable to determine the ultimate outcome of this proceeding, however, the estimate of u.e effect of the ALJ's initial decision does not have a material impact on its consolidated financial position or results of operations.
- 4. Industry and Corporate Restructuring Legal Proceedings / Referendum Campaign The DTE order approving the Boston Edison cottlement agreement and the DTE order approving the formation of BEC as a holiing company have been appealed by certain parties to the Massachusetts Supreme Judicial Court.
In addition, along with other Massachusetts investor-owned utilities, Boston Edison has l
been named as a dei sndant in a class action suit seeking to declare certain provisions of the Massachusetts electric industry restructuring legislation unconstitutional. Management is currently unable to determine the outcome of these proceedings or the impact the proceedings may have on its consolidated financial position or results of operations.
A referendum seeking repeal of the Massachusetts electric industry restructuring legislation that was enacted in November 1997 was overwhelmingly defeated by a better than 70% to 30% margin in a state-wide general election held on November 3, 1998. This outcome allows the comprehensive framework established for the restructuring of the electric industry to continue as l
intended under the enacted legislation.
- 5. Regulatory Proceeding In October 1997, the DTE opened a proceeding to investigate compliance with the 1993 order which permitted the formation of BETG and authorized Boston Edison to invest up to $45 million in unregulated activities.
The DTE has scheduled hearings on this matter for the fourth quarter. Management is 1
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- 6. Plymouth Lawsuit In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim Nuclear Power Station, filed suit against Boston Edison.
The town claims that Boston Edison has wrongfully failed to execute an agreement with the town for payments in addition to taxes due to the town under the recently enacted Massachusetts olectric industry restructuring legislation.
Boston Edison has disputed the town's claim and will' vigorously defend itself. Management is unable te determine the ultimate outcome of this action or the impact it may have on its consolidated financial position c r results of operations.
- 7. Litigation In the normal course of its business Boston Edison is also involved in certain i
other legal matters.
Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued, however based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position.
However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
D)
Income Taxes The following table reconciles the statutory federal income tax rate to the annual estimated effective income tax rate for 1998 and the actual effective income tax rate for 1997.
1998 1997 Statutory tax rate 35.0%
55.0%
State income tax, net of federal income i
tax benefit 5.1 4.5 l
Investment tax credit amortization (6.8)
(3.3)
Other 0.8 0.1 Effective tax rate 34.1%
36.3%
3 The estimate of the 1998 effective tax rate declined by 5% as a result of the recognition in net income of the remaining unamortized investment tax credits related to Boston Edison's fossil generating assets at the time of their sale.
This shareholder benefit is included in other expense, not in the consolidated i
l statement of income for the nine-month period ended September 30, 1998.
E)
Financing Activity On May 15, 1998, Boston Edison closed the sale of its fossil generating assets and received total proceeds of $674 million in cash.
$202 million of these funds were used to retire short-term debt securities.
Boston Edison has no outstanding short-term debt on its September 30, 1998 consolidated balance sheet.
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i In June 1998, Boston Edison's $100 million 6.662% outstanding bank loan was redeemed.
Boston Edison also redeemed S2 million of mandatory and S2 million of the optional 7.27% sinking fund series preferred stock in May 1998.
In March 1998, $100 million of 5.95% debentures matured.
In July 1998, Boston Edison redeemed the remaining $32 million 7.27% sinking fund series preferred stock along with the S40 million 7.75% series preferred stock.
l F)
Related Party Transactions The September 30, 1998 consolidated balance sheet of Boston Edison includes a
$13 million receivable from BETG's telecommunications joint venture with RCN.
The receivable is for construction and construction management services provided by Boston Edison and its contractors to the joint venture for its fiber optic network.
G)-
Nuclear Decommissioning An update of Pilgrim Nuclear Power Station's decommissioning cost study was filed with the DTE in November 1998.
The updated study includes an estimate of decommissioning and fuel storage costs of approximately S600 million in 1997 dollars.
Item 2.
Management's Discussion and Analysis Results of Operations - Three Months Ended September 30, 1998 vs. Three Months Ended September 30, 1997 The decrease in earnings reflects the effect of the mandated 10% retail rate reduction which became effective March 1, 1998 under the Massachusetts Electric Utility Restructuring Law.
The decrease in earnings was partially offset by a decrease in operations and maintenance expense resulting from the fossil divestiture in May 1998 along with continued cost control efferts.
The results of operations for the quarter are not indicative of the results which may be expected for the entire year due to the seasonality of Boston Edison's kilowatt-hour (kWh. sales and revenues.
Refer to Note A to the Consolidated Financial Statements.
Operating revenues Operating revenues decreased 8.5% during the third quarter of 1998 as follows:
(in thousands)
Retail electric revenues S ( 3'i, 519 )
-Wholesale revenues (818)
Short-term sales and other revenues (5,851)
Decrease in operatina revenues S(44,188)
Retail electric revenues decreased due to the 10% retail rate reduction which became effective for electricity usage as of March 1, 1998.
The decrease from the rate reduction was partially offset by a 6.1% increase in kWh sales for i
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the quarter. The increase in kWh sales was due to warmer summer temperatures and continued streng economic conditions in the Boston area.
Operating expenses Energy supply expense includes fuel and purchased power, retail generation-related depreciation and amortization, decommissioning and otner operating costs recovered through the transition charge.
Energy supply expense decreased approximately $12 million. Total fuel and purchased power expenses decreased approximately $18 million. This decrease reflects lower company fuel costs and the timing effect of the fuel and purchased power and standard offsr cost collection mechanisms.
Lower fuel costs in the third quarter reflect the first full reporting period since the sale of Boston Edison's fossil generating assets to Sithe Energies in May 1998.
This decrease was partially offset by higher purchased power costs that include a six-month transitional power purchase cont et with Sithe that began in May.
Boston Edison received $121 million from Sithe to enter into the transition contract.
The capacity portion of the Sithe purchased power costs is offset by the recognition of the payment from Sithe and, therefore, has no net effect on earnings.
Operations and maintenance expense decreased $17.7 million.
The decrease is primarily due to the impact of the fossil divestiture.
The decrease in depreciation and amortization expense is due to an $8.7 million nonrecurring charge to depreciation expense in the third quarter of l
1997 to reflect the removal of specific nuclear-related intangible assets from
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the balance sheet.
This was partially offset by an increase in the composite distribution depreciation rate effective March 1, 1998 in accordance with the
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settlement agreement.
The increase in demand side management (DSM) and rerewable energy programs reflects an increase in the required spending for DSM programs in 1998.
In l
addition, the renewable energy programs expense is the result of a new state mandate for the funding of renewable energy that became effective March 1, 1998.
Renewable energy expenses are collected through distribution revenues and, therefore, have no net effect on earnings.
l The decrease in property and other taxes is due to a decrease in municipal property taxes as a result of the divestiture of the fossil generating stations in May 1998.
Other income (expense), net l
Other income in the third quarter of 1997 includes interest income from the favorable outcome of an IRS appeal related to investment tax credits.
Interest charges Interest charges on long-term debt decreased due to the maturing of $100 t
million of 5.95% debentures in March 1998 and the cessation of amortization of the associated redemption premiums along with the redemption of a $100 million 6.662% bank loan in June 1998.
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l Interest charges on short-term debt decreased due to the redemption of Boston Edison's outstanding short-term debt with the fossil divestiture proceeds.
Preferred stock dividends Preferred stock dividends decreased as a result of the redemption of 40,000 shares of 7.27% series cumulative preferred stock in May 1998, the remaining 320,000 shares of the 7.27% series in July 1998 and 400,000 shares of 7.75%
series cumulative preferred stock in July 1998.
Results of Operations - Nine Months Ended September 30, 1998 vs. Nine Months Ended September 30, 1997 Earnings in 1998 were positively impacted by decreases in operations and maintenance expense, municipal property taxes and interest expense resulting l
from the fossil divestiture in May 1998. Warmer summer weather and the l
continued strong local economy also had a positive impact on earnings.
These l
positive impacts were offset by the rate reduction mandated under Boston i
Edison's settlement agreement and an increase in unregulated subsidiary losses.
The results of operations for the nine months ended September 30, 1998 are not indicative of the results which may be expected for the entire year due to the seasonality of Boston Edison's kWh sales and revenues.
Refer to Note A to the Consolidated Financial Statements.
Qaerating revenues Operating revenues decreased 8.3% during the first nine months of 1998 as follows:
(in thousands) i Retail electric revenues
$(107,512)
Wholesale revenues (3,545)
Short-term sales and other revenues (2,280)
Decrease in operatina revenues
$(113,337)
Retail electric revenues decreased partly due to the timing effect of fuel and purchased power cost recovery.
Prior to its cessation as of March 1,
- 1998, the fuel clause charge was lower than the prior year as the 1997 charge reflected the recovery of substantial prior period undercollections.
Fuel clause revenues were offset by fuel and purchased power expenses and, therefore, had no net effect on earnings. Retail electric revenues also reflect the impact of the mandated 10% retail rate reduction.
The rate reduction partially offset the impact of the 2.7% increase in kWh sales in 1998. Warmer than usual summer weather and the strong economic conditions in 1998 offset the negative impacts from the mild winter weather.
Qperating expenses l
Energy supply expense includes fuel and purchased power, retail generation-related depreciation and amortization, decommissioning and other operating j
j costs recovered through the transition charge.
Energy supply expense i
decreased.approximately $85 million.
Total fuel and purchased power expenses i
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decreased approximately $93 million.
The decrease in company fuel costs resulting from the fossil divestiture in May 1998 was significantly offset by nn increase in purchased power subsequent to the divestiture.
Purchased power costs include the six-month transitional power purchase contract with Sithe Energies that began in May.
As the capacity portion of the Sithe purchased power costs is offset by the recognition of the payment from Sithe, those l
costs have no net effect on earnings.
The timing effect of the fuel and purchased power and standard offer cost collection mechanisms also contributed to the decrease.
Operations and maintenance expense decreased approximately $32 million.
The l
decrease reflects lower employee benefits costs, lower nuclear spending and the impact of the fossil divestiture.
The comparison of 1998 and 1997 is also positively impacted by the April 1997 Boston area storm.
l The decrease in depreciation and amortization expense is due to the $8.7 l
million nonrecurring charge in the third quarter of 1997 as discussed in the results of operations for the third quarter.
This was partially offset by the increase in the composite distribution depreciation rate in accordance with i
the settlement agreement.
As discussed in the results of operations for the third quarter, the increase in DSM and renewable energy programs expense reflects an increase in the required spending for DSM programs in 1998.
In addition, the renewable energy programs expense is the result of a new state mandate for the funding of renewable energy that became effective March 1, 1998.
Renewable energy expenses are collected through distribution revenues and, therefore, have no net effect on earnings.
l The decrease in property and other taxes is due to the decrease in municipal property taxes resulting from the fossil divestiture.
Other income (expense), net The increase in other expense, net reflects certain costs related to the fossil divestiture, net of the related tax benefits, including the recognition of previously deferred investment tax credits associated with the fossil generating stations. Also negatively impacting the comparison of 1998 to 1997 is the interest income from the favorable outcome of an IRS appeal related to investment tax credits received in the third quarter of 1997.
In addition, j
unregulated subsidiary losses were higher in 1998 as BETG's telecommunications l
joint venture with RCN began operations in the second quarter of 1997 l
Interest charges j
Interest charges on long-term debt decreased due to the maturing of $100 million of 5.70% debentures in March 1997, $100 million of 5.95% debentures in March 1998 and the cessation of amortization of the associated redemption premiums along with the redemption of a $100 million 6.662% bank loan in Jun; 1998.
Interest charges on short-term debt decreased due to the redemption of Boston Edison's outstanding short-term debt with the proceeds from the fossil a
divestiture.
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e Preferred stock dividends Preferred stock dividends decreased as a result of Boston Edison's redemption of 40,000 shares of 7.27% series cumulative preferred stock in May 1998 and l
1997, the remaining 320,000 shares of the 7.27% series and 400,000 shares of 7.75% series cumulative preferred stock in July 1998 and 400,000 shares of 8.25% series in June 1997 Electric Revenues Effective March 1, 1998, the retail access date, Boston Edison's electric delivery business provides its standard offer customers service at rates designed to give 10% savings from rates previously in effect.
These customers will realize an additional 5% average savings, after an adjustment for inflation, by September 1, 1999. The cost of providing standard offer service, which includes fuel and purchased power costs, is recovered from j
customers on a fully reconciling basis. New retail customers in the Boston Edison service territory and previously existing customers that are no longer eligible for the standard offer due to choosing a competitive supplier are on default service.
The price of default service is based on the average l
competitive market price for power.
Refer also to the Electric Revenues section of Item 7 of the Boston Edison 1997 Annual Report on Form 10-K.
As part of the restructuring settlement agreement, the annual performance adjustment charge ceased and the cost recovery mechanism for Pilgrim Station I
changed effective March 1, 1998. Approximately 25% of the operations and i
capital costs, including a return on investment, continues to be collected under wholesale contracts with other utilities and municipalities.
Refer to the Electric Revenues section of Item 7 of the Boston Edison 1997 Annual Report on Form 10-K for a description of Pilgrim's new cost recovery mechanism.
The rates of Boston Edison's distribution business will remain unchanged, subject to a minimum and maximum return on average common equity (ROE) until l
December 31, 2000.
Refer to the Electric Revenues section of Item 7 of the Boston Edison 1997 Annual Report on Form 10-K for detail regarding the minimum and maximum ROE.
Under the Boston Edison settlement agreement, the cost of providing transmission service to distribution customers is recovered on a l
fully reconciling basis.
l Liquidity l
Boston Edison supplements internally generated funds as needed, primarily through the issuance of short-term commercial paper and bank borrowings.
Boston Edison has authority from the Federal Energy Regulatory Commission to issue up to $350 million of short-term debt in addition to a $200 million revolving credit agreement and arrangements with several banks to provide additional short-term credit on an uncommitted and as available basis.
It also has authority to issue up to $220 million of equity and long-term debt securities under its approved long-term financing plan with the DTE which is available through 1998.
Proceeds from issuances under this plan are to be used to refinance short and long-term securities and to fund capital expenditures.
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Year 2000 Computer Issue l
I The year 2000 issue is the result of computer programs that were written using two digits rather than four to define an applicable year.
If computer programs with date-sensitive functions are not year 2000 compliant, they may I
recognize a date using "00" as the year 1900 rather than the year 2000.
This could result in system failures or miscalculations causing disruptions of i
l operations, including, among other things, a temporary inability to process transactions and engage in other normal business activities. Management has a year 2000 program in place that is addressing the risk of non-compliant internal business software, internal non-business software and embedded chip technology and external noncompliance of third parties.
L Management's plan to address the year 2000 issue includes modification of certain applications and replacement of systems that are not year 2000 compliant.
The cost associated with year 2000 compliance will be expensed as incurred.
In addition, a decision has been made to use this opportunity to upgrade some of the less efficient centralized business systems.
Replacement I
costs associated with these systems will be capitalized and amortized over i
future periods. Management estimates that it will expend approximately $30 l
million on these system modifications and upgrades.
For each system designated as " critical" (defined as being necessary to safely provide a reliable flow of electricity), management's year 2000 program requires system j
testing and a contingency plan to be developed.
l As part of the year 2000 program, significant suppliers, service providers and j
other vendors were contacted to determine year 2000 readiness. Many third parties have noted that they are already year 2000 compliant or in the process l
of becoming compliant.
In addition to the risk faced from its dependence on other third party suppliers, Boston Edison has a risk that power will not be available from the New England Power Pool (NEPOOL) for purchase and distribution to its customers.
Should NEPOOL fail to resolve its year 2000 issues as planned, there would be an adverse impact to Boston Edison.
To mitigate this risk, efforts are being coordinated with NEPOOL to establish l
inter-utility testing guidelines to determine year 2000 readiness.
Boston l
-Edison is also a participant in the ISO /NEPOOL New England Year 2000 Joint Oversight Committee which has been given responsibility for the operational l
reliability of NEPOOL.
l The year 2000 program remains on schedule with anticipated completion in the third quarter of 1999.
However, management believes it is not possible to determine with complete certainty that all potential year 2000 problems have been identified or will be corrected cue to the complexity and pervasiveness of the issue.
In the event that compliance is not completed as anticipated, it is reasonably possible that the year 2000 issue could have an adverse
- effect on operations.
New Accounting Standards In 1997, the Financial Accounting Standards Board (FASB) issued Statement of l
Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information (SEAS 131) which is effective in 1998.
This statement requires the reporting of certain additional information about operating segments as applicable within an enterprise.
SFAS 131 disclosure is l
16 l
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a not required for interim reporting in the initial year of application.
Management will include the selected financias information and disclosures as required in its 1998 Annual Report on Form 10 K and its future interim reports on Form 10-0 as appropriate.
In June 1998, the FASB issued SFAS 133, Accounting for Derivative Instruments and Hedging Activities which is effective in 2000.
Th4.s statement requires the recognition of all derivative instruments as either assets or 41 abilities in the statement of financial position and the measurement of those instruments at fair value. Management does not expect this statement to have a material impact on its consolidated financial position or results of operations.
The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use (SOP 98-1) in March 1998.
SOP 98-1, effective in 1999, provides specific guidance on whether to capitalize or expense costs within its scope. Management does not expect this SOP to have a material impact on its consolidated financial position or results of operations.
Safe Harbor Cautionary Statement Management occasionally makes forwt.rd-looking statements such as forecasts and projections of expected future performance or statements of its plans and objectives.
These forward-looking statements may be contained in filings with the Securities and Exchange Commi ssion, press releases and oral statements.
Actual results could potentially differ materially from these statements.
Therefore, no assurances can be tiven that the outcomes stated in such
-forward-looking statements and estimates will be achieved.
Refer also to the safe harbor cautionary statements included in the Boston Edison 1997 Annual Report on Form 10-K.
The preceding sections include certain forward-looking statements about environmental and legal issues and year 2000.
The impacts of various environmental and legal issues could differ from current expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than expected. The effects of changes in specific hazardous waste site conditions and cleanup technology could affect estimated cleanup liabilities.
The impacts of changes in available information and circumstances regarding legal issues could affect the estimated litigation costs.
The timing and total costs related to the year 2000 plan could differ from current expectations.
Factors that may cause such differences include the ability to locate and correct all relevant computer codes and the availability of personnel trained in this area.
In addition, management cannot predict the nature or impact on operations of third party noncompliance.
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l Part II -'Other Information Item 5.
Other Information Paul A. La Camera, age 55, was elected as a member of the Boston Edison Company Board of Directors, effectjve July 1, 1998. La Camera has been Presloent and General Manager of WCVB-TV Channel 5 since 1997.
From 1994 to i
1997 he was Vice President and General Manager of the station.
1 The following additional information is furnished in connection with the Registration Statement on Form S-3 of the Registrant (File No. 33-57840),
filed with the Securities and Exchange Commission on February 3, 1993.
l Ratio of earnings to fixed charges and ratio of earnings to fixed charges and preferred stock dividend requirements:
i Twelve months ended September 30, 1998:
Ratio of earnings to fixed charges 3.11 l
l Ratio of earnings to fixed charges and preferred stock dividend requirements 2.70 Item 6.
Exhibits and Reports on Form 8-K a)
Exhibits filed herewith:
l Exhibit 4 - Instruments Defining the Rights of Security holders, l
Including Indentures f
Boston Edison agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any agreements or instruments defining the rights of holders of any long-term debt whose authorization does not exceed 10% of Boston Edison's total assets.
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges 12.1 - Computation of ratio of earnings to fixed charges l
for the twelve months ended September 30, 1998 l
12.2 - Computation of ratio of earnings to fixed charges and preferred stock dividend requirements for the l
twelve months ended September 30, 1998 Exhibit 15 - Letter Re Unaudited Interim Financial Information l
15.1 - Report of Independent Accountants Exhibit '7 - Financial Data Schedule l
27,1 - Schedule UT l
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Exhibit 99 - Additional Exhibits 99.1 - Letter of Independent Accountants Form S-3 Registration Statement filed by Boston Edison Company on February 3, 1993 (File No.
33-57840) b)
No Form 8-K was filed during the third quarter of 1998.
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Signature Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
t BOSTON EDISON COMPANY (Registrant) j Date:
November 16, 1998
/s/ Robert J. Weafer, Jr.
Robert J. Weafer, Jr.
I Vice President-Finance, Controller and Chief i
Accounting Officer i
20
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Exhibit 12.1 Boston Edison Company Computation of Ratio of Earnings to Fixed Charges Twelve Months Ended September 30, 1998 (in thousands) i Net income from continuing operations
$148,999
-Income taxes 71,445 Fixed charges 104,679 Total S325.123 Interest expense
$ 95,394 1
Interest component of rentals 9,285-Total S104,673 Ratio of earnings to fixed charges 2211 l
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Exhibit 12.2 l
l Boston Edison Company Computation of Ratio of Earnings to Fixed Charges i
and Preferred Stock Dividend Requirements l ~
Twelve Months Ended September 30, 1998 l
(in thousands) l I-Net income from continuing operations
$148,999 Income taxes 71,445 Fixed charges 104,679 Total
$325,123 Interest expense.
S 95,394 Interest component of rentals 9,285 1
Subtotal 104',679 Preferred stock dividend requirements 15,622 Total
$120,301 i
Ratio of earnings to fixed charges and preferred stock dividend requirements 2.70 i.
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Exhibit 15.1 Report of Independent Accountants To the Directors of Boston Edison Company f
We have reviewed the accompanying consolidated balance sheet of Boston Edison I
Company (Boston Edison) as of September 30, 1998 and the related statements of income for the three and nine-month periods ended September 30, 1998 and 1997 and cash flows for the nine-month periods ended September 30, 1998 and 1997.
These financial statements are the responsibility of Boston Edison's management.
We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial l
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that l
should be made to the acenmpanyi..g financial statements in order for them to be in conformity with generally accepted accounting principles.
l Boston, Massachusetts PricewaterhouseCoopers LLI' l
October 22, 1998 l
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Exhibit 99.1 Securities and Exchange Commission 450 Fifth Street, N.W.
Washington, D.C.
20549 l
Re:
Boston Edison Company l
Registration on Form S-3 We are aware that our report dated October 22, 1998 on our review of the l
interim financial information of Boston Edison Company (Boston Edison) for the l
period ended September 30, 1998 and included in this Form 10-0 is incorporated by reference in Boston Edison's registration statement on Form S-3 (File No.
33-57840).
Pursuant to Rule 436(c) under the Securities Act of 1933, this f
report should not be considered a part of the registration statement prepared or certified by us within the meaning of Sections 7 and 11 of that Act.
Boston, Massachusetts PricewaterhouseCoopers LLP October 22, 1998 l
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i 24
-.. -. =
l BOSTON EDISON COMPANY 1999 INTERNAL CASH FLOW PROJECTION FOR PILGRIM UNIT #1 NUCLEAR POWER STATION (DOLLARS IN THOUSANDS) i i
i 12 Months Ended Projected Year f
9/30/98 1999 Net income After Taxes 148,999 150,000 Less Dividends Paid (A)
(102,555)
(99.000)
{
i Retained Eamings 46,444 51,000 l
Adjustments Depreciation and Amortization 231,185 225,000 l
Deferred Taxes and ITC (149,668)
(120,000) l AFUDC (1.215)
(1.400)
Total Adjustments 80.302 103.600 j
Intemal Cash Flow 126.746 154.600 Average Quarterly Cash Flow 31.687 38.650 i
Percentage Ownership in All Operating Nuclear Units Pilgrim Unit #1 = 74.27%
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Maximum Total Contingency Liability 10,000 1
(A) Excludes special dividend of $70 Million dollars paid to BEC Energy upon divestiture of the Company's Fossil Generation Units, j
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ITEM (4) NARRATIVE STATEMENTS OF CURTAILMENT OF CAPITAL EXPENDITURES:
The Boston Edison Company would be able to curtail $10 million of capital expenditures l
within any three month period of the next twelve months if it becomes necessary to pay j
retrospective premiums.
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Earnings Per Share Return On Equity 13.0%
$2.75
$2.71
$2.61 I
12.5%
12.4% 12.4%
$2.52*
$2.50 12.2%*
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$2.25 11.5%
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$2.00 1993 1994 1995 1996 1997 1993 1994 1995 1996 1997
- 1995 amount excludes a
- 1995 percentage excludes a
$0.44 restructuring charge.
$0.44 restructuring charge.
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FINANCIAL HIGHLIGHTS years ended December 31, 1997 1996 Operating revenues (000)
$ 1,776,233
$ 1,666,303 Earnings available for common (000)
$ 131,493 126,181 Weighted average common shares outstanding (000) 48,515 48,265 Common stock data:
Earnings per share 2.71 2.61 Dividends declared per share 1.88 1.88 Payout ratio 69 %
72 %
Book value per share 22.13 21.37 Return on average common equity 12.4 %
12.4 %
Fixed charge coverage (SEC) 2.95 2.91 l
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1 i
CONTENTS Letter to ShareholJers 2
Commitment To Customers 4
lihat Customers Can Expect from Elect >ic Utility Deregulation 6
Strengthening The Economy and The Community - Equally Important 7
The Arrival ofCompetition and Customer Choice 8
Exiting The Power Generation Business After 11i kars 10 New A]fsliations.. New Directions i2 1he Future 14 Financial Section I6 4
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NIYIYIM'N DEAR SHAREHOLDER Dramatic and succesful. Strong norJs, but ihey accurately reflect ihe results <f1997.
f or the past two y cars, in my annual letter to you, I have discussed changes expected in the j
industry and the company as a result of deregulation of energy supply. Now it has happened. Your I
company has emerged from the uncertainty of the past in a strong position for future success. Ilut 1997 l
was more, much more, than the culmination of the anticipated changes in energy markets. It marked, as well, a significant. mge in our core business of generating electricity, with the decision to sell our oil and natural gas power plants.
Perhaps most importantly, as it relates to our future, our employees went the extra mile throughout the ycar for our customers and for you, our shareholders. The results speak li>r themsches:
lhtal sharehohler return was 51 percent as the company's share price climbed 41 percent.
Earnings per share increased to 52.71.
Iicld operations were redesigned around customer expectations, resulting in significant pnxiucti'.;i,ty and sersice improsements.
Nearly a do b new customer services were introduced.
l cgislation passed that assures tustomers of energy sasings and thoice of energy suppliers, w hile pnniding ihr full recmcry of stranded costs.
Sale of our oil and gas fired poner plants attracted a 50 percent premium.
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l These results alone are impressive. lioneser, hv themsches they mask the fact that the sale of our power plants makes us a smaller comnam. While ne base exited the electric generation business, l
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ue are in an excellent position to pursue new opportututies for grouth. We base adopted an ambitious sision of the future. We see a company with two million customers in the year 2000, a three fold increase in three scars. That gnmth will come fnim a combination of geographic expansion io electricity delisery, and possibly gas delisery, and from our joint sentures.
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Ours is a sision that capitalizes on the restructuring of energy markets, as well as their convergence with telecommunications markets. That vision, and steps already taken to achiese it, prompted McGraw-liill Publishing's Ekaricallibrid magazine to award your company the 1997 James 11.
McGraw Award for Corporate Excellence. The award was presented because of "the companv's sisionary I
restructuring and disersification cI[ orts"and"its groundbreaking corporate strategy." ds the award notes, t
the strategy " continues to strengthen the compant's commitment to the end user."
This report is about that commitment and about the employees who make it real.
Thomas J. May Chairman, President and Chief Executisc Officer YbhIYIN
~
COMMITMENT TO CUSTOMERS
.\\lcGraw.lldi, in selecting the companyfor the 1997 James H.
.ticGraw.harJfr Corporate thccIlence, reccyjnited itpr its
" commitment to the end user" Ours is the last major industry to ge :hrough Jeregulation, after ihe airhnes, tcIccommunications, truding and naturalgas. The public pohcy initiatis es producing competition in the cIcctric utihty industry are driven by a combination ofnew technolopes, and customers who expect anJ l
want to have choices.
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Peopic and technology are wming together to change public policy and create competition I
in what had been a completely regulated monopoly industry. At iloston Edison, people and technology are also coming together -- working together -- to make a difference in delis ering comfort, comenience and efficiency to customers. Itoston Edison and the reliable delisery of electricity will be the core of the new I
holding company, llEC Energy.
t in 199'7, all aspects of the electric delisery business underwent transliarmation. Key business actisities, such as electric system construction and senices, asset management, metering and all aspects of j
customer care, were restructured around customer requirements and the processes necessary to meet them.
i The new business processes capture the best practices of world-class companies, domestic and foreign.
l This transformation is the result of a highly disciplined, customer-focused, strategic assessment of process, people and technological needs for a high perfi>rming " delivery" business.
Ti> make the processes work, multi-disciplined teams are in place throughout Bmton l
Edison. Separatch, an asset management team focuses on imestment planning and technology selection to ensure that the delivery network prmides a high level of performance to achiese customer satisfaction j
and financial return.
Meann hile, new customer senice initiatives base been built around the principle of case of doing business.These initiatives gise customers options, and provide accurate and timely inli>rmation and personalized service. New senices introduced in 1997 included direct payment, Internet access to account information, appointment scheduhng, and consolidated billing for customers with multiple accounts. Also A new look introduced was a new storm response management and information system.This new ssstem will shorten for the restorttion time and provide customers with better information about restoration progress.
Boston As the changes described abme were being implemented, major work continued to Edison bill upgrade the existing distribution system in and around the City oflioston. We also introduced a major s
provides expansion of our automated meter reading system and further imprmement in our remote monitorinoo customers and switching capabilities. Iloth significantiv imprme productisity and customer information.
with more detailed infor-mation in an easier to read format.
5
- /
NNlb WHAT CUSTOMERS CAN EXPECT FROM ELECTRIC UTILITY DEREGULATION Thefollowing is some basic informatw.~ Boston Edison has been providmg its customers about deregulatwn, which started. Starch 1, i 998.
Why was March I impor+ ant?
That was when the production of electricity was omcially " deregulated." That means that power plants will no longer be part of the regulated monopoly customers have known for decades. The electric utility, such as Boston Edison, will still deliver the electricity. But it will act more like Federal Express -- delivering the package of power you will purchase from among an array of producers. March I was also the date w hen electric utility rates - the cent-per-kilowatt hour price - went down 10 percent.
Does that mean the bill will go down 10%?
The price per kilow att-hour will go down. Customers w ho use the same amount in March as during an earlier month, will see a 10 percent reduction. But consumption saries due to many factors, including weather, which alTects the total bill. It is important to k>ok at both the rate and the usage.
Will customers actually have to decide where to buy their electricity?
No, not initially. They may choose to do nothing, to just continue getting power --
customers will be able to production and deliscry - from the utility. The utility may not be producing it, but it will buy it for choose the customers during the transition from monopoly to full competition.
company that After March 1, who will customers call if the lights go out?
produces Customers will continue to call their local utility that delisers their electricity. That will not change.
power.
Who will be responsible for ensuring a reliable supply of electricity?
Boston Edison will The electric utility - the delivery company -- will continue to be responsible for a reliable c ntinue to deliver transmission and distribution system. But making sure there is enough production capacity will be the thct power.
result of market forces - supply and demand. Already, in anticipation of pending competition, power prmlucers have announced new plants to meet anticipated demand for lower priced power.
6
4 STRENGTHENING THE ECONOMY AND THE COMMUNITY -- EQUALLY IMPORTANT i
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Civic inrohement and environmental stenarJship remain an important aspect ofBoston Edison l
Company's aainities. The changes occurring in the electric unhty industry Jo not Jimmish the importance of a nbrant cconomy, a ilean environment and heahhy commumiies to the u cil bemg ofthe company, its customers and its employ ees.
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Over the years, the company has been actise in programs to help the economy and the I
I communities in w hich it does business. In 1997, the company continued to work u ith state and local governments on quality oflife issues. For example, Chairman, President and CEOTom May chairs the Governor's Council on Economic Grow th and Technology.The focus last year was on three issues -
business support for quality education, continued progress on reducing the cost of doing business in
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continued to help attract employers such as Sun Microsystems to the service area.
-4 On the environmental front, the j
company worked closely with various interests to attract alternative fuel vehicle manufacturers to the area 1
i and to establish incenthes for tchicle purchases. It helped attract federal funding for Ocet operators to offset incremental costs of clean fuel technologies.
Finally, the company's philanthropic efforts were concentrated in the areas of education, the emironment, health and human services, community development and the arts. it continued to help Boston MayorTom Menino implement the Kids Compute 2001 program, w hich is ahead of schedule as more and more companies step foruard to participate.
Y IN N '\\INI N 7
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THE ARRIVAL OF COMPETITION AND CUSTOMER CHOICE For the past halfdecaJc,pilowmg passage gf the hational Energy Act qf I 992, government, business, utihty industry, consumer, academic and environmental leaders have been l
collaborating to restructure the electric utihty mJustry. Ihc i
parties representcJ many interests and often opposing vicupoints.
Out ofthis process, a set qfprinciples emerged in i993 and 1996 nhich Boston Edison has supported.
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l In July 1997 lbston Edison finalized its deregulation settlement agreement with the Massachusetts Attorney General, the Massathusetts Disision of Energy Resources and various customer and j
environmental groups. Implementation of the settlement required state legislation and approval by the i
Massachusetts Department of Tilecommunications and Energy (DTE). Ibth have been achiesed. The Massachusetts Legislature passed, by overu helming majorities in both llouses, legislation that implements customer choice and competition for energy supply beginning in March 1998. Lndmark may be an I
merused word to describe significant esents. In this case,it seems appropriate.
t The legislation is a well-balanced approach to meeting the needs of customers, stockholders, communities hosting power plants and our employees. It assures all customers of a 10 percent rate reduction in 1998 followed by a further lhe percent reduction by September 1,1999. It provides for full recovery of stranded costs u hile providing incentises for mitigating those costs. This is discussed more fully in the section on disestiture. Communit;es with power plant sites are protected against property tax losses as power plants are revalued. Additionally, the legislation maintains the state's commitment to those customers in need of assistance and to the deployment of energy conser ation measures and the use of renewable energy.
The steps necessary to implement the legislation are now being taken. The company worked toward that end for much of 1997. By year-end, sirtually all internal systems and infrastructure needed to implement customer choice were in place.
These internal changes were moving in concert with regulatory pniceedings before the DTE.
Employees worked The DTE considered specilic filings from ik>ston Edison on the settlement and establishment of the through-holding company, HEC Energy. It also had to consider and act on new terms and conditions for out 1997 customers and for energy suppliers and registration icquirements for supplier.s and marketers. The DTE to pre-Pare for has been able to keep to an aggressise schedule and meet the legislatise requirements for compctition electric and approval of settlements reached by Boston Edison and other utilities.We are awaiting a decision utility from the DTE regarding our reorganization plan to form BEC Energy.
deregulation.
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As a result, the company set an ambitious schedule in 1997 to sell its oil and natural gas power plants. This was based on the belief that plants soki carly wouhl be the most attractise and wouhl command the Sithe Energies best price, as potential buyers jockesed to gain a presence in this emerging market. We were correct.
t ps the competi-liy spring, letters seeking expressions ofinterest had been sent to 1,500 organi/ations tive considered potential buyers. By summer, plant sisits and meetings had begun as those interested were bidding being qualified. Mming in parallel with debate mer the restructuring legislation, the company narrowed with an the list of bidders, uith bids due December 3,1997, just tuo necks after the legislation was passed.
Mfer of We had urged law makers to act in 1997, arguing that it nouhl alh>w our customers to benellt 5657 mil-from the intense market interest. This wouhllead to a higher purchase price and reduce rates charged to lion for five our customers.
generating plants When the bids were opened and the winner announced on December 10, the aggressise and a transitional pur-strategies to push for House and senate sotes in support of the legislation - and to sell the oil and natural chase power contract.
gas poner plants -- were validated.
Sithe Energies won the bidding, paying a total of s657 million. Against a book value of s450 million, Sithe's bid prmided s5 36 million for the assets at the generating sites in and near Boston and s 121 million for a transition purchase power contract.
Sithe cited compttition and the recentiv passed legislation as the reasons for its interest in Massachusetts. Indicatise of how it siews the neu market, sithe also announced that it would imest more than s I billion at the sites to build 2,800 megawatts of new, highly cilicient generating capacity w hile keeping the 2,000 megawatts it purchased operating. This is testimony to our employees and to the position Massachusetts has staked out in restructuring. It bodes util for Boston Edison since the Massachusetts and New England economics should benefit from the energy price impacts of competition.
The sale is expected to be completed by the middle of May.
Next to be addressed is the future of the Pilgrim Nuclear Power Station. In 1997, Pilgrim completed its shortest refueling outage in historv. The plant continued to perform ucll, as it has throughout the 1990s. Under the settlement agreement w hi( h led to the sale of the oil and gas-fired plants, the company will recmer transition costs associated uith Pilgrim, including decommissioning costs.
Boston Edison is required to develop and file bv January 1,1999 with the Department of Telecommunications and Energy a plan for saluing Pilgrim. Among the options are creation of a regional or national alliance of nudcar plants or outright sale. In am case, the plant's phpit al conAnon is good, the
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NEW AFFILIATIONS... NEW DIRECTIONS i
The company 's new insolvement in telecommunicatwns got cjf to a i
strong start in i997. The telecommunicatwns joint senture nah RCN attracicJ a lot of national mcJia interest - and many new customers.
RCNI.1fasabusetts,in ubich Baston EJiwn is a 49 percent vuner is s sencJ as a natwnal moJcIpr utshiy entry into telewmmumcatwns markets. RCN n afacuhtics hased telecommunicatwns company offering bunJIed icIcphone. cable and Internet aacsspr Jchtery oser jiber optic netnorks.
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SbNxbNN RCN's oserall customer count totaled approximately 20,00) by the end of 1997. It has attracted intense interest from communities throughout Greater Boston and around the state, especiallt regarding its cable television service. This is largely because for the first time established cahic telesision companies are running into direct competition. An often-cited example is the City of Somenille, next to Ikiston. In that city, Time Warner chose not to impose a 10 percent rate increase last fall, simply because of the competition from RCN. Other cities and tmtns are taking notice, and RCN is signing sideo agreements with communities at the rate of one per month.
EnergyVision, an energy marketing joint senture withThe Williams Companies ofTulsa, Oklahoma, showed modest growth in 1997, primarily in the natural gas market. The electricity market in New England did not develop as cuickly as anticipated. This is expected to change, h<meser, as states such i
j as Massachusetts open their markets, and independent generating companies such as Sithe Energies deselop l
new projects.
At another company afliliate, Northuind Ik>ston, construction began on its first district cooling plant located atThe First Church of Christ, Scientist in Boston. The plant will be readv to serve customers in Boston's Back Bay District in June,1998. Northwind is 75 percent owned by Boston Edison and 25 percent owned by UnicomThermal of Chicago.
Coneco, a w holly-owned energy senices company, signed signi6 cant contracts in New brk and Florida and several other states during the ycar. While it continued to gnm, the pace shmed somew hat in late Customers have 1997 due to energy consenation funding cutbacks for New York State schools.
already begun to real-ize the bene-fits of competi-tior. in the cable industry through our relationship with RCN.
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THE FUTURE Our success in i 997 was built arounJ people, processes and technolqjies working together to serve customers. The company was faturcJ in pubhcations such as TI.llE maganne, thclibil Sircet Journal, the New York Turnes and Ivrbes because of uspcus on strategicsfor success under compctriion. The usion, and the strate-u giesfor accomphshing it, are n cil JefuncJ and being impicmented.
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There has neser been a more exciting time in the electric utility industry. And with the "
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(hallenges of deregulation come opportunities for growth. In 1998, ne expect to see the beginning of Edison dramatic c hanges in the structure of the utility industry in New England. Now that the rules of received competition and restructuring are becoming clear, consolidation appears inevitable. The company expects national to be part of that consolidation as the territorial maps of utility sersice areas are redrawn. Geographic recogni. 'I " expansion is a major part of the company's strategy for growth. from The ycar 1998 will base its challenges. The rate reduction of 10 percent, as wc!! as the McGraw infrastructure necessary to achieve customer choice, will challenge our employees. The strict cost control Hiii for measures and productisity imprmements that base been implemented in the recent past will continue. Corporate Excellence. Yet, the company is in a good position ihr grow th because ofimestments in technology, improvements in operations and a highly skilled workforce. The strong management tearn that produced the results of the last few years, especially the results of 1997,is well positioned to lead lloston Edison. We will continue to balance the ongoing, day-to-day needs of the company u hile embracing cach opportunity to grow and prosper. " Boston Edison is being recognized for its ground breaking corporate strategy that was initiated wellin advance of state regulatory mandates and continues to strengthen the company's commitment to the end user" Mariel Leone Electrical World Editor-in chief Commenting on Boston Edison's selection for McGraw Hill's Corporate ExceIIence Award b 15
NNsisNxisN l 4 FINANCIAL SECTION Dividends Paid Per Share Capital Expenditures (in millions) $255 '$247 $230- $1.88 $1.88 $1.82 $205 $199 $1.76 $180 $1.75 $155- $145 $130 $114 r $1 $1.50 8 I I $80 I I 1993 1994 1995 1996 1997 1993 1994 1995 1996 1997 Retail Customer Sales Mix GResident Commercial 60% { l l Industrial & Other 13% i6 .~
l: M nagemsnt's Discussion and Analysis them will be derived. Net generating assets recoverable from the Proceeds of the fossil divestiture and through the non-bypassable Electric Utility industry Restructuring transition charge of our distribution business which continues to l The traditionally rate-regulated electric utility industry is rapidly be subject to rate-regulation, therefore, remain on our consolidat-l changing in response to the continuing market pressures for ed balance sheet at December 31,1997. In addition, approxi-lower-priced electric energy. These pressures have resulted in mately 25% of the operations and capital costs, including a regulatory and legislative proceedings at both federal and state return on investment, of Pilgrim Nuclear Power Station will con-levels designed to foster competition in the industry. On tinue to be collected under wholesale life of the unit contracts. january 28,1998, the Massachusetts Department of These contracts continue to be regulated by the Federal Energy l Telecommunications and Energy (DTE), formerly the Regulatory Commission (FERC) and are not impacted by our Department of Public Utilities (DPU), approved our restructur-settlement agreement. ing settlement agreement that was fded in July 1997. The DTE i found that the settlement agreement substantially complied or Divestiture of Fossil Generating Assets was consistent with key provisions of a Massachusetts law enact. Our restructuring settlement agreement includes a provision for ed in November 1997 establishing a comprehensive framework the divestiture of our fossil generating assets no later than six for the restructuring of our industry. Major provisions of our raonths after the retail access date. On December 10,1997,we settlement agreement include the ability for retail electric cus-entered into a purchase and sale agreement with Sithe Energies, tomers to choose their electricity supplier (referred to as retail Inc., a privately-held company headquartered in New York, to access) as of March 1,1998 (the retail access date). Customers purchase our non-nuclear generating assets. The proceeds from l who choose not to participate in retail access will have the the sale of these assets will be $657 million. The net book value l option of continuing to buy power from our electric delivery of these assets at December 31,1997 is approximately $450 mil-I business at " Standard Offer" prices. Upon the retail access date, lion. Included in the purchase price, Sithe Energies will pay customers that continue to buy electricity under the Standard $121 million to us in connection with a six-month transitional Offer will realize an average 10% savings from the rates in effect power sales agreement under which we will buy power from the l during 1997. Under the new legislation, Standard Offer cus-generating plants. Sithe Energies will also be responsible for tomers will realize another 5% savings in electricity rates, after obligations resulting from the recently enacted utility restructur-an adjustrnent for inflation, by September 1,1999. We expect ing legislation for property tax payments to communities with l to be able to meet this additional rate reduction as a result of the non. nuclear power plants. Net proceeds from the divestiture divestiture of our fossil generating assets which is discussed will be used to reduce the distribution transition charge. l below. As part of our settlement agreement, the retail delivery Implementation of the divestiture plan is subject to certain rates of our retained distribution business include a non-bypass-regulatory approvals including those of the DTE and the FERC. j able transition charge designed to recover certain costs incurred We anticipate finalization of the divestiture in mid-1998. ) by our generation business under the traditional electric In July 1997, we reached an agreement with our field ser-l ratemaking structure which cannot be otherwise recovered in a vice tmion that requires the buyer of our fossil generating assets l competitive environment. The rates of our distribution bus'nees to recognize and continue to honor the provisions of the union's will continue to be regulated by the DTE based on the cost of current collective bargaining agreement through the end ofits providing distribution service. term, May 2000. As part of a package offered to employees In 1997 the Emerging Issues Task Force (EITF) reached con-affected by the fossil divestiture, all eligible fossil and designated sensus on specific issues raised related to the application of fossil support employees age 55 or older with at least 10 years of l Statement of Financial Accounting Standards No. 71, Accounting service, or age 65 by July 1,1998, were offered unreduced for the Effects of Certain Types of Regulation (SFAS 71). As pan retirement and transition benefits under a voluntary early retire- . ofits consensus, the EITF determined that when deregulation ment program (VERP). Under this program,40 people elected j legislation is passed and regulatory actions have taken place pro-to retire. Retirement dates are expected to be the first of the viding sufficient detail for an enterprise to reasonably determine month following the transfer of ownership of our fossil generat-how the transition plan will affect the separable portion ofits ing assets. Severance programs were offered to management business being deregulated, the enterprise should stop applying and field service union employees affected by the fossil divesti-SFAS 71 to that portion ofits business. As a result of the recent-ture that did not elect or were ineligible to retire under the ly passed Massachusetts electric industry restructuring legislation VERP. These severance benefits include salary payments, edu-and the DTE order regarding our related settlement agreement, cation / retraining allowances and outplacement services. It is we have determined that, as of December 31,1997, the provi-anticipated that 48 employees will receive severance benefits sions of SFAS 71 no longer apply to the generation portion of under these programs. 1 our business. The EITF further determined that book values of The estimated costs associated with the VERP and sever-assets and liabilities originating in the separable portion of the ance programs is approximately $21 million including the business no longer subject to rate-regulation should be evaluated effects on the retirement, life and dental plans. Severance and f on the basis ofwhere the regulated cash flows to realize and settle employee retraining costs related to the divestiture are recover-1 17
able through the distribution transition charge under our settle-Company (WESCO), a subsidiary ofThe Williams Companies, ment agreement. Therefore, we have established an offsetting Inc. This LLC, EnergyVision, markets electricity, natural gas and regulatory asset for these obligations on our consolidated bal-energy-related services to retail customers in the six New England ance sheet at December 31,1997. states and began operations in February 1997 BETG and Nuclear Asset impairment Results of Operations As part of the settlement agreement, we recover our net invest-ment in Pilgrim as of December 31,1995 (adjusted for deprecia-7 m sus N tion through 1997) through the distribution transition charge. Under the terms of the settlement agreement, we must perform Earnings per share of common stock were $2.71 in 1997 com-a market valuation of Pilgrim by 2002. Upon acceptance of the pared to $2.61 in 1996, a 3.8% increase as described below. valuation by the DTE, the resulting dollar amount, net of pru. Operating revenues dently incurred post-1995 investments in the plant, will reduce emounts collectible through the transition charge. If the valua. Operating revenues increased 6.6% over 1996 as follows: (in thousands) tion is not sufficient to allow for the recovery of these invest, Retail electric revenues $ 87,252 ments, we will seek their recovery through the transition charge. Due to the market pressures facing us, the ultimate recovery of Demand side management revenues 1,232 these assets is not certain. Therefore, we reduced our investment Wholesale revenues (765) in Pilgrim by the $13 million invested in the plant since Short-term sales and other revenues 22,211 January 1,1996 as an impairment loss. An after tax charge of increase in operating revenues $109,930 approximately $8 million due to this reduction was recorded to non-operating expense on our consolidated statement ofincome Retail base revenues, consistent with the 0.8% increase in in the fourth quarter of1997. A similar uncertainty does not kilowatt-hour (kWh) sales in 1997, were relatively flat com-exist for the ultimate recovery of the fossil generating assets as pared to 1996. Increases due to warmer than normal tempera-the sale proceeds agreed to in the purchase and sale agreement tures in June and July, cooler temperatures in October and with Sithe Energies exceeds the net book value of these assets. December and the stronger local economy were offset by milder BEC Energy than normal winter conditions during the first quarter of 1997 and lower industrial sales. Industrial sales continue to be We are currendy awaiting a decision from the DTE regarding adversely affected by the decline in manufacturing activity in our reorgamzanon plan to form a holding company structure. A our service territory. In addition, revenues in 1996 reflect one decm..on from the Secun.. ties and Exchange Commission is also more day of sales due to the leap year. Total retail electric rev-pending. Approval from the Nuclear Regulatory Comm.. issmn enues increased $87.3 milh.on pnmanly fue to the u.mmg effect i was received on February 11,1998. Th.is plan was appnwed by of fuel and purchased power cost recovery. The increase in fuel i the FERC and our shareholders m. 1997. This new stru mre and purchased power clause revenues reflect the current recov-wdl clearly separate our regulated and unregulated operations. It ery of prior year undercollecu.ons. These higher revenues are t wd. l provide us wn. h greater organizatenal flexibih.ty allowing us l offset by higher fuel and purchased power expenses and, there-to take advantage of nonutility business opportunities in a more fore, have no net effect on earnings. Pilgn.m performance rev-l I umely manner. The holding company structure is a well-estab-enues, which vary annually based on the operating performance lished form of organization for companies conducting multiple gnm Stan n, decreased due to a lower annual capacity fac-lines of business. In fact, all other investor-owned Massachusetts tor effecuve November 1996 reflectmg the refuehng and main-electnc unh..ues are currently organized m. this manner. Through tenance utage n the 6rst quanu oM7. our holding company, BEC Energy, we will seek ways to expand Short-term sales revenues.mcreased approximately $16 m l-i our customer base. l lion. This is due to the continued reduction in available nuclear Joint Ventures energy supply in New England combined with a 42% increase in ur f ssil generati n all wing f r incre sed sales to the power We continue to conduct unregulated activities through our whol. ly owned subsidiary, Boston Energy Technology Group (BETG). exchange. Revenues from short-term sales result in a corre-During 1997, BETG entered into two joint venture agreements. SPonding reduction to future fuel and purchased power billings ret il cust mers and, therefore, have no net effect on earnings. t BETG has a joint venture agreement with RCN Telecom Services, Inc. (RCN). The fmal closing on this joint venture Operating expenses occurred in June 1997. This limited liability company (LLC) Fuel and purchased power expenses m. creased $90.2 million. competes directly with local and long-distance telephone, v.deo i This increase reflects $57 milh.on related to the n.mmg effect of and Intemet access companies for telecommum. canons-related services. BETG owns 49% of the LLC while RCN owns 51% fuel and purchased power cost recovery. In addition, company fuel expense mcreased $50 million primarily due to the 42% and mam. tams day-to-day management responsibih.ty. BETG also has an energy marketing venture with Williams Energy Serv. mcrease m fossil generation. These increases were partially offset ices 18
by a $22 million decrease in power exchange purchases. Fuel 1996 versus 1995 and purchased power expenses are substantially recoverable Earnings per share of common stock were $2.61 in 1996 com-through fuel and pu thased power revenues. pared to $2.08 in 1995. Earnings in 1995 reflect a nonrecurring Operanons and maintenance expense decreased $2.6 mil-before tax charge of $34 million ($20.7 million after tax, or lion from 1996. The decrease is the result oflower spending 50.44 per share) associated with our corporate restructuring. due to overall cost control efforts and significantly less overhaul The restructuring is discussed further in Note F to the activity at our fossil generating units. These decreases were par-Consolidated Financial Statements. Excluding the nonrecurring tially offset by an approximately $5 million incremental impact restructuring charge, earnings per common share increased 3.6% associated with service restoration efforts resulting froa a severe over 1995 as described below. snow storm in April 1997 that struck the greater Boswn area. The increase in depreciation and amortization expense is due Operating revenues to the net impact of two depreciation adjustments. We recorded Operating revenues increased 2.3% over 1995 as follows: an $8.7 million nonremtring charge to depreciation expense in (in thousands) the third quarter of IW = ;.flect the removal of specific Retail electric revenues $48,649 nuclear-related intangible assets from our balance sheet. In 1996 Demand side management revenues (20,545) we recorded a $5.2 million adjustment to correct the accumulat-Wholesale revenues (2,072) ed depreciat on balance of certain large computer equipment. Short-term sales and other revenues 11,768 Income taxes increased as a result of higher net income off-set by a lower effective tax rate. The effective tax rate for 1997 Increase in operating revenues $37,800 reflects the impact of the favorable outcome of an Internal Revenue Service (IRS) appeal received in the third quarter relat-Retail electric revenues increased $48.6 million. Fuel and ed to investment tax credits (lTC). This also resulted in an Purchased power clause revenues increased approximately $36 increase in unamortized ITC which will be reflected as a reduc _ million. These higher revenues are offset by higher fuel and tion to income tax expense over the life of the related assets. purchased power expenses and, therefore, have no net effect on Refer to Note D to the Consolidated Financial Statements for earnings. Performance revenues increased $14.5 million as more information on income taxes. Pilgrim Station operated at a higher capacity in 1996. Retail kWh sdes increased 2.8% in 1996, primarily due to the posi-Oth:r expense tive economic impacts on our commercial customers. Other expense, net in 1997 reflects the charge of approximately Demand side management (DSM) revenues decreased pri- $8 million, after tax, from the nuclear asset impairment which is marily due to a decline in current DSM program expenditures. further discussed in Note C to the Consolidated Financial The primary reason for the decrease in wholesale revenues Statements in addition to BETG equity losses. These decreases is due to Pilgrim contract customer revenues. These revenues were partially offset by approximately $3 million, after tax, in decreased despite increased kWh sales due to lower operations interest income from the IRS appeal. and maintenance expense related to Pilgrim Station. Pilgrim contract customers are billed for their proportionate share of the intrrest charges unit's costs. Total interest charges on long-term debt decreased due to the Net short-term sales and other revenues increased $11.8 maturing of $100 million of 5.70% debentures in March 1997 million. Despite lower kWh sales, short-term sales revenues and the cessation of amortization of the associated redemption increased approximately $6 million due to higher fuel prices, premiums. This was partially offset by the March 1997 issuance Revenues from short-term sales result in a corresponding reduc-of $100 million of 6.662% bank debt due in 1999. The tion to future fuel and purchased power billings to retail cus-decrease also reflects the maturity of $100 million of 51/8% tomers and, therefore, have no net effect on earnings. This debentures in March 1996. increase also reflects an increase in revenue from non-electric Allowance for borrowed funds used during construction sources in 1996. (AFUDC), which represents the financing costs of construction, decreased primarily due to a lower average construction work in Operating expenses progress (CWIP) balance in 1997. The 1996 average CWIP bal-Fuel and purchased power expenses increased $53.1 million. ance included nuclear fuel purchased in anticipation of Pilgrim Fuel expense increased, despite a slight decrease in company gen. Station's scheduled refueling outage in the first quarter of 1997. eration, due to significantly higher oil and natural gas prices. Purchased power expense reflects a higher volume of energy pur-Pr;ferred stock dividends chases and an overall increase in energy prices. These increases The decrease in preferred stock dividends is the result of the were partially offset by the timi:.g effect of feel and purchased redemption of 20,000 of mandatory and 20,000 of optional power cost recovery. Fuel and purchased power expenses are sub-shares of 7.27% series cumulative preferred stock in May 1997 stantially recoverable through fuel and purchased power revenues, and 400,000 shares of 8.25% series in June 1997. Refer to Note Operations and maintenance expense decreased $40.8 million I to the Consolidated Financial Statements. primarily due to lower labor costs resuhing from our 1995 restruc-19
turing and the continuing cost control effons of each of our busi-9% of our electric operating revenues. Total kWh sales increased ness units. In addition, the amortization of deferred nuclear out-3.1% as a result of the continued reduction in available nuclear age costs decreased $9 million. As discussed in Note B to the energy supply in New England. This reduction, combined with Consolidated Financial Statements, in the third quarter of 1995 an increase in our fossil generation allowed for increased sales to we made a retroactive change to the amortization period of these the power exchange. deferred costs from five years to two years, consistent with the The 2.8% increase in 1996 retail kWh sales was primarily two-year cycle between refueling outages at Pilgrim Station. due to the positive effect on commercial customers of the The 1995 operating expenses reflect a $34 million nonre-stroag economy in our retail service territory. Residential sales curring charge related to our corporate restructuring. Refer to decreased slightly primarily due to overall milder than normal Note F to the Consolidated Financial Statements for.;dditional weather conditions. Industrial sales remained relatively flat. information regarding our 1995 restructuring. Total kWh mes, including wholesale, increased 3.3%. The Depreciation and amortization increased $32.2 million. The increase m wholesale sales was primar:ly due to higher sales to increase is primarily the result of a change in the estimated remain-our Pilgrim contract customers as the plant was operating for ing emnomic lives of our Mystic 4, 5 and 6 fossil generating units substantially all of 1996. In addition, sales to our municipal in the second qu.rter of 1996, retroactive to the beginning of the customers increased due to a reduction in available energy year, and an increase in the depreciable plant balance. The change supply in New England. in estimated economic lives of Mystic 4, 5 and 6 resulted in a $22 Electric revenues million increase in depreciation expense for the year. The decrease in DSM programs expense reflects the decline As discussed in the Electric Utility Industry Restructuring sec-in current DSM program expenditures. tion, our delivery business will provide Standard Offer customers The increase in income taxes is due to higher net income service at rates designed to give an average 10% savings upon the and a higher effective tax rate in 1996. The effective tax rate in retail access date. As pan of the recently passed restructuring .1996 is 38.2% versus 37.1% in 1995, legislation in Masscchusetts, these customers are to realize an additional 5% average savings, after an adjustment for inflation, intzrest charges by September 1,1999. We expect to meet this additional rate Interest on long-term debt decreased due to the maturity of reduction as a result of the proceeds received from the divestiture $100 million 8 7/8% debentures in December 1995 and $100 of our fossil generating assets and potential securitization or refi-million 51/8% debentures in March 1996. These decreases nancing of our stranded costs. Under our settlement agreement, were partially offset by the issuance of $125 million 7.80% the aggregate amount of our transition charge is reduced by the debentures in May 1995 which were outstanding for all of 1996. net proceeds from fossil divestiture. Other interest charges increased due to an increase in interest on Under the settlement agreement, the annual performance shon-term debt caused by the higher average shon-term debt adjustment charge ceases and our cost recovery mechanism for level partially offset by a lower average short-term borrowing Pilgrim Station changes as of the retail access date. Approximately rate. The short-term debt balance increased as a result of the 25% of the operations and capital costs, including a return on debenture maturities and the redemption of $4 million of pre-investment, will continue to be collected under wholesale life of ferred stock in 1996. AFUDC decreased due to lower overall the unit contracts. The remaining output will be sold in the construction activity during 1996, shorter construction periods, competitive energy market. Through December 31,2000, we and lower short-term interest rates. will share 25% of any profit or loss from the sale of Pilgrim's n cust men thmugh tk transidon " *P " *
- t u Electric Sales and Revenues charge. In addm.on, we wdl obtain transition payments up to a Electric sales maximum of $23 million per year depending on the level of Retail kWh sales increased 0.8% in 1997. This was primarily mst5 incurred f r Property taxes, insurance, regulatory fees and attributable to the commercial sector. The commercial increase secunty requaements.
reflects the impact of a continued strong economy in the Boston Beginning upon the retail access date, the rates of our dis-area and very warm temperatures in June and July and cooler tribution business will remain unchanged through than normal temperatures in the fourth quarter. Hotel occupan-December 31,2000, subject to a minimum and maximum rerum n average comnion equity (ROE). We will be required cy rates and non-manufacturing employment continued to increase in 1997. The commercial sector represents approxi-m file with the DTE a computation supponing the ROE of our mately 50% of our electric operating revenues. Residential rev-distribution business after each calendar year. The ROE is sub-enues, which represent 27% of electric revenues, were also posi-ject to a floor of 6% and a ceiling of 11.75% If the ROE is tively impacted by the weather. These positive impacts were off-below 6%, we are authorized to add a surcharge to distribution rates in order to achieve the 6% floor. If the ROE is above set by milder winter weather in the first quarter of 1997 and declines in manufacturing employment affecting the industrial 11% we are required to adjust distribution rates by an amount sector. In addition, revenues in 1996 reflect one more day of necessary to reduce the calculated ROE between 11% and sales due to the leap year. The industrial sector represents only 12.5% by 50% and a return above 12.5% by 100% No 20
_ = - adjustment is made if the ROE is between 6% and 11%. The expcased as incurred. In addition, we have made a decision to cost of providing transmission service to distribution customers use this opportunity to upgrade some of our less efficient cen-will be recovered on a fully reconciling basis. tralized business systems. The full replacement costs asscciated with these systen, will be capitalized and amortized over future ' Uquidity periods. The total cost of the year 2000 project is expected to be We ordinarily meet most of our cash requirements for plant funded through internally generated funds. We anticipate com-expenditures with internally generated funds. These funds are pletion of the year 2000 project in the third quarter of 1999. cash flows from operating activities, adjusted to exclude changes Other Matters in working capital and the payment of dividends. Durit. 1997, 1996 and 1995 our internal generation of cash provided 211%, Environmental 177% and 102% respectively of our plant expenditures. The We are subject to numerous federal, state and local standards with capital spending level, excluding nuclear fuel, forecasted for respect t waste disposal, air and water quality and other environ-1998 is $265 million which includes amounts for utility plant mental e nsiderations. These standards can require that we mod-and the capital requirements of our nonutility ventures. This ify ur existing facilities r incur increased operating costs. spending level also includes the 1998 portion of business systern
- wremly own r puate appr ximately 30 propernes j
replacements discussed below. The capital spending level over where od. or hazardous materials were previously spdled or the next five years is forecasted to be approximately $940 mil-released. We also continue to face possible liability as a poten-lion. In addition to capital expenditures, we have debt and pre-nally resp nsible party m the cleanup of six multi-party haz-ferred stock payment requirements of $103.6 million in 1998 ard us waste sues in Massachusetts and other states where we and 1999, $168.6 million in 2000, $53.6 million in 2001 and are alleged t have generated, transported or disposed of haz- $3.6 million in 2002. ardous waste at the sites. Refer to Note L6. to the We supplement our internally generated funds as needed, C ns lidated Financial Statements for more information regard-primarily through the issuance of short-term commercial paper ing hazardous waste issues. and bank borrowings. We have authority from the FERC to The Accounting Standards Executive Committee of the I issue up to $350 million of short-term debt. We also have a American Institute f Certified Public Accountants issued $200 million revolving credit agreement and arrangements with Statement f Position 96-1, Environmental Remediation several banks to pmvide additional short-texm credit on a com-Liabiht es (SOP 96-1), effective in 1997. This statement con. mitted as well as on an uncommitted and as available basis. At rains authontanve guidance ou specific accounting issues related December 31,1997, we had $137 million of short-term debt m the recognition, measurement, display and disclosure of envi-outstanding, none of which was incurred under the revolving mnmental remedianon liabihties. It requires that an accrual for credit agreement. We have $220 million remaining under our envir nmental liabihnes mclude estimates of the costs of com-approved long-term financing plan with the DTE whi-h is pensati n and benefits for those employees expected to devote a available through 1998. Proceeds from issuances unr this sigmficant amount of time directly to that effort. SOP 96-1 plan are to be used to refinance short and long-term securities had no material effect on our financ,al position or resuhs of i and to fund capital expenditures. Refer to Notes I and J to the Consolidated Financial Statements for additional information perat ns during 1997. Uncertainties continue to exist with respect to the disposal relating to our financm.g acovmes. of both spent nuclear fuel and low-level radioactive waste (LLW) At December 31,1997, BETG had $7.5 m. h.d on outstand-resulting from the operation of Pilgn.m Stanon.The Um. d te mg credit agreement. The purpose of th. mg under a revolv. States Department of Energy (DOE) is responsible for the ulu.- is Im.e is to fund u.s capital requirements above our $45 m. h.d on m te mate disposal of spent nuclear fuel; however, uncertainties
- h.. d investment. This debt wdl be refinanced upon the for-regarding the DOE,s schedule of acceptance of spent fuel for d.is-m2 tion of BEC Energy.
posal continue to exist. In 1995 we regained access to the LLW We anticipate using the sale proceeds from our pending disposal facility located in Barnwell, South Caroh.na. Refer to fossil divestiture to adj.ust our capual structure. Note E to the Consolidated Financial Statements for further dis-l . Year 2000 Computer issue cussion regarding nuclear decommissioning and waste disposal. The 1990 Clean Air Act Amendments (CAAA) requi,re a The year 2000 computer issue is the result of programs written using two digits instead of four to define an applicable year. significant reduction in nationwide emissions of sulfur dioxide Consequently, these programs will not properly recognize calen-fmm f ssil generating units. Other provisions of the CAAA mvolve limitations on emissions of nitmgen oxides from exisung dar dates beginning in the year 2000. This could cause comput-ers to shut down or yield incorrect results. generating units. As discussed in the Divestiture of Fossil We have developed a plan to address the year 2000 issue Generating Assets section, we have signed an agreement with that includes modification of certain applications and replace. Sithe Energies for the sale of our fossil generating assets. If regu-ment of systems that are not year.2000 compliant. The cost latory approval is not obtained or is delayed, we could continue associated with modification of existing applications will be m oper te these units subject to the provisions of these amend-21 I
ments. We currently meet the standards of the CAAA and, tutional. We are currently unable to determine the outcome of depending on the outcome of certain Massachusetts Department these proceedings or their impact on us. of Environmental Protection air quality modeling studies, our Opponents of the electric industry restructuring legislation generating units could continue to operate through at least 1999 that was enacted in November 1997 have mounted a referen-before additional emission reductions would be required. dum campaign to repeal that law. A coalition of business, Public concern continues regarding electromagnetic fields industry and public interest groups that supported the legisla-(EMF) associated with electric transmission and distribution tion, along with the electric utility industry, is opposed to the facilities and appliances and wiring in buildings and homes. referendum and is prepared to mount an aggressive campaign to Such concerns have induded the possibility of adverse health defeat it. We are currently unable to predict the eventual out-effects caused by EMF as well as perceived effects on property come of this referendum or its impact ou us. values. Some scientific reviews conducted to date have suggest-Safe harbor cautionary statement ed associations between EMF and potential health e& cts, while other studies have not substantiated such associations. The We occasionally make forward-looking statements such as fore-J National Research Council previously reported that there is no casts and projections of expected future performance or state-conclusive evidence that exposure to EMF from power lines and ments of our plans and objectives. These forward-looking state-appliances presents a health hazard. The panel of scientists, ments may be contained in filings with the Securities and working with the National Academy of Sciences, report that Exchange Commission, press releases and oral statements. Actual more than 500 studies over the last several years have produced results could potentially di&r materially from these statements. no proof that EMF causes leukemia or other cancers or harms Therefore, no assurances can be given that the outcomes stated in human health in other ways. We continue to support research such forward-looking statements and estimates will be achieved. into the subject and are participating in the funding ofindus-The preceding sections include certain forward-looking try-sponsored studies. We are av are that public concern regard. statements about the e& cts of the industry restructuring I ing EMF in some cases has resulted in litigation, in opposition process and our related settlement agreement, the divestiture of to existing or proposed facilities in proceedings before regulators our fossil generating assets, operating results, year 2000 and or in requests for legislation or regulatory standards concerning environmental and legal issues. EMF levels. We have addressed issues relative to EMF in vari. The e& cts of electric utility industry restruc:uring could ous legal and regulatory proceedings and in discussions with differ from our expectations. This could occur as regulatory customers and other concerned perons; however, to date we decisions and negotiated settlements between utilities and inter-have not been significantly affected oy these developments. We venors are finalized. In addition, the development of a compet-i continue to monitor all aspects of the EMF issue. itive electric generation market, the impacts of actual electric supply and demand in New England and further kgislative Litigat, ion action may a&ct the ultimate results of the industry restructur-In October 1997, the DTE opened a proceeding to investigate ing and our settlement agreement. our compliance with the 1993 order which permitted the forma-The divestiture plan could differ from our expectations. I tion of BETG and authorized us to invest up to $45 million in This could occur if required regulatory approvals are delayed or unregulated activities. We are unable to determine the ultimate not obtained. outcome of this proceeding or its impact on our operations. The impacts of our continued cost control procedures on We were named as a party in lawsuits by Subaru of New our operating results could di&r from our expectations. The England, Inc. and Subaru Distributors Corporation. The plain-effects of changes in economic conditions, tax rates, interest tiffs claimed certain automobiles stored on lots in South Boston rates, technology and the prices and availability of operating su& red pitting damage caused by emissions from our New supplies could materially affect our projected operating results. Boston Station generating unit. In 1997 we settled both law-The timing and total costs related to our year 2000 plan suits. Neither settlement had a material impact on our consoli-could differ from cur expectations. Factors that may cause such dated results of operations or financial position. differences include the ability to locate and correct all relevant Refer to Note L8. to the Consolidated Financial Statements for computer codes and the availability of personnel trained in this more information on other legal matters in which we are invohed. area. In addition, we cannot predict the nature or impact on operations of third party noncompliance. Industry restructuring legal proceedings / referendum The impacts of various environmental and legal issues l crmpaign could differ from our expectations. New regulations o ;.haaiges The DTE order approving our settlement agreement has been to existing regulations could impose additional operating appealed by certain parties to the Massachusetts Supreme requirements or liabilities caer than expected. The effects of Judicial Court, in addition, along with other Massachusetts changes in specific hazardous waste site conditions and cleanup investor owned utilities, we have been named as a defendant in a technology could affee our estimated cleanup liabilities. The l class action suit seeking to declare certain provisions of the impacts of changes in 1.vailable information and circumstances j Massachusetts electric industry restructuring legislation unconsti-regarding legal issues could affect our estimated litigation costs. 22
' Consolidated Statsmants of Income' years ended December 31, l(in thousands, except earnings per share) 1997 1996 '1995 Operating revenues $ 1,776,233 $ 1,666,303 $ 1,628,503
- Operating expenses
Fuel and purchased power - 679,131 588,893_ 535,806. Operations and maintenance 414,779 417,372 458,196 Restructuring costs 0 0 34,000 Depreciation and amortization 188,687 185,494 -153,339 Demand side management programs 29,790 30,825 45,125 - Taxes-property and other 107,975 107,086-106,361 income taxes 95,021 88,703 68,276 Total operating expenses 1,515,383 1,418,373 1,401,103 Operating income 260,850 247,930 227,400 Other income (expense), net (10,498) 698 (575) Opsrating and other income ' 250,352 248,628 226,825 Interest charges: Long-term debt 92,489 94,823 106,640 Other 14,410 14,551 12,642 ~ Allowance for borrowed funds used during construction (1,189) (2,292) (4,767) Total interest charges 105,710 107,082 114,515 I Nst income 144,642 141,546 112,310 Preferred stock dividends 13,149 15,365 15,571 Earnings available for common shareholders $ 131,493 $ 126,181 96,739 ) . Weighted average common shares outstanding 48,515 48,265 46,592 1 Eamings per share of common stock-basic and diluted 2.71 2.61 2.08 Consolidated Statements of Retained Earnings years ended December 31, L (in thousands) 1997 1996 1995 Balance at the beginning of the year $ 292,191 $ 257,749 $ 247,409 Net income 144,642 141,546 112,310 Subtotal 436,833 399,295 359,719 Dividends declared: Preferred stock 13,149 15,365 15,571 Common stock 91,208 90,834 86,399 Subtotal 104,357 106,199 101,970 Provision for preferred stock redemption and issuance costs (a) 3,674 905 0 LBilance at the end of the year $ 328,802 $ 292,191 $ 257,749 (a) Refer to Note B.7. to the Consolidated Financial Statements.
- The accompanying notes are an integral part of the consolidated financial statements.
_ m Censolid:t:d Bil:nca Shaats December 31, (in" thousands) 1997 1996 Assets Utility plant in service, at original cost $ 4,457,868. $ 4,387,887 Less: accumulated depreciation 1,713,079 $ 2,744,789 1,550,317 $ 2,837,570 Nuclear fuel - 351,722 351,453 Less:' accumulated amortization - 283,787 67,935 268,509 82,944 Construction work in progress 41,403-30,376 Net ut;lity plant - 2,854,127 2,950,890 l Nuclear decommissioning trust 151,634 132,076 Equity investments 35,455 28,752 Oth rinvestments 7,107 7,630 Currsnt assets: Cash and cash equivalents 4,140 5,651. Accounts receivable 192,220 233,024 Accrued unbilled revenues. 30,048 34,922 Fuel, materials and supplies, at average cost 60,834 57,075 Prepaids and other 31,283 318,525 - 45,146 375,818 . Dsferred debits: Regulatory assets 220,403 202,026 - Other' 35,096 32,099 Total assets $ 3,622,347 $ 3,729,291 Crpitalization and Liabilities Common stock equity 5 1,073,454 $ 1,036,424 i Cumulative preferred stock 161,093 201,419 Long-term debt 1,057,076 1,058,644 Current liabilities: Long-term debt / preferred stock due within one year 5 102,667 $ 102,667 Notes payable 137,013 201,454 Accounts payable 87,015 134,083 Accrued interest 24,289 24,378 Dividends payable 24,748 25,343 Other 128,061 503,793 115,812 603,737 -- Deferred credits: Accumulated deferred income taxes 485,738 498,718 Accumulated deferred investment tax credits 60,736 58,899 Nuclear decommissioning liability 155,182 133,388 Power contracts 71,445 88,963 Other 53,830 49,099 - Commitments and contingencies Total capitalization and liabilities $ 3,622,347 $ 3,729,291 l i The accompanying notes are an integral part of the consolidated financial statements. 24
.Consolid:tsd Statsmants of Cash Flows years ended December 31, ' (in thousands) 1997 1996 1995 Operating activities:- L ~ ' l Net income $ 144,642 $ 141,546 $ 112,310 L Adjustments to reconcile net income to net. ~ - cash provided by operating activities: . Depreciation and amortization : 223,529 228,259 202,294 - Defe'rred income taxes and investment tax credits ' (21,664) (4,057) (25,193) Allowance for borrowed funds used during construction (1,189). (2,292) (4,767). L Net changes in: l I Accounts receivable and accrued unbilled revenues 45,678 (11,719) (34,626) .i Fuel, materials and supplies (5,486) (2,171) 7,202 Accounts payable. - (47,068) ' 609 2,978 i Other current assets and liabilities 25,428 (44,514) 26,485 L Other, net (4,640) 50,815 26,993 Net cash provided by operating activities 359,230 356,476 313,676
- Invasting activities:
Plant expenditures (excluding AFUDC) (114,110) (145,347) .(180,822) Nuclear fuel expenditures (4,089) (52,967) (13,621) Investments in joint ventures (7,859) (5,698) 0 1 Other investments (19,830) (28,616) (19,005) N:t cash used In investing activities (145,888) .(232,628) (213,448) Fintncing activities: Issuances: ( . Common stock ' 144 12,559 64,888 Long-term debt 100,000 0 125,000 ' Redemptions:~ l l Preferred stock (44,000) (4,000) (2,000) Long-term debt (101,600) (101,600) (100,600) ~ Net change in notes payable (64,441) 75,013 .(88,345) ~ Dividends paid -(104,956) (106,010) (100,152) - Net cash used in financing activities (214,853) (124,038) .(101,209) Ntt decrease in cash and cash equivalents (1,511) (190) (981)
- Cash and cash equivalents at the beginning of the year 5,651 5,841 6,822 Cash and cash equivalents at the end of the year 4,140 5,651 5,841
. Supplemental disclosures of cash flow information-l [ Cash paid during the year for: interest, net'of amounts capitalized ' $ 100,795 $ 100,810 104,011 l Income taxes 99,326 98,668 96,180 l~ [ t The accompanying notes are an integral part of the consolidated financial statements. I 1 2J
Notes to Consolidated Financial Statements Note A. Nature of Operations Boston Edison Company (the Company) is an investor-owned regulated public utility operating in the energy, energy services and telecommunications business. This includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side management programs. A portion of our generation is produced by our wholly owned nuclear generating unit, Pilgrim Nuclear Power Station. We supply electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. We also supply electricity at wholesale for resale to other utilities and municipal electric departments. Electric operating revenues were 88% retail and 12% wholesale in 1997. We also conduct unreg-ulated activities through our wholly owned subsidiary, Boston Energy Technology Group (BETG). Through BETG and its subsidiaries,,ve are engaged in certain nonutility businesses, including energy utilization and conserva-tion, construction management and district rgy. BETG has a joint venture with RCN Telecom Services, Inc. (RCN) that provides certain telecommunications-related services.. limited liability company (LLC) formed from this joint venture is owned 51% by RCN and 49% by BETG, with RCN having the day-to-day management responsibility. BETG also has a joint venture with Williams Energy Services Company (WESCO). This joint venture markets electricity, natural gas and energy-related services to retail customers in the six New England states. BETG and WESCO each own 50% of this LLC, EnergyVision. We are currently awaiting a decision from the Massachusetts Department of Telecommunications and Energy (DTE), formerly the Department of Public Utilities, regarding our plan to form a holding company structure. This structure will clearly separate our regulated and unregulated lines of business. Through our holding company, BEC Energy, we will seek ways to expand our customer base. After the corporate reorganization, Boston Edison will be a wholly owned subsidiary of BEC Energy. BETG will cease being a subsidiary of Boston Edison and become a wholly owned subsidiary of BEC Energy. The common shareholders of Boston Edison will become shareholders of BEC Energy. The existing debt and preferred stock of Boston Edison will remain obligations of the regu-lated utility business. Refer also to Note C to these Consolidated Financial Statements for changes in the nature of our operations as a result of the electric utility industry restructuring and our related settlement agreement. Note B. Significant Accounting Policies
- 1. B: sis of Consolidation and Accounting The consolidaed Gnancial statements include the activities of our wholly owned subsidiaries, Harbor Electric Energy Company (HEEC) and BETG. All signifcant intercompany transactions have been eliminated. Certain reclassi6 cations have been made to the prior year data to conform with the current presentation.
We follow accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the DTE. We are also sub-ject to the accounting and reporting requirements of the Securities and Exchange Commissic.n. The consolidated financial statements conform with generally accepted accounting principles (GAAP). As a rate-regulated company we have been subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), under GAAP. The application of SFAS 71 resuhs in differences in the timing of recognition of certain expenses from that of other businesses and indus-tries. As a result of the recently passed Massact usetts electric industry restructuring legislation and the DTE order regarding our related settlement agreement, as of December 31,1997, we are no longer applying the provisions of SFAS 71 to our generation busi-ness. Our distribution business remains subject to rate-regulation and continues to meet the criteria for application of SFAS 71. Refer to Note C to these Consolidated Financial Statements for more information on the accounting implications of the electric utili-ty industry restructuring. The preparation of fmancial statements in c onformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
- 2. Revenues We record estimates of retail base revenues for el:ctricity used by our customers but not yet bdled at the end of each accounting period.
- 3. Forecasted Fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and purchased power costs which are not included in our base rates to be billed to customers using a forecasted rate. The difference between actual costs and the amounts billed to cus-tomers is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable on the consolidated balance sheet until subsequent rates are adjusted.
26
~.-
- 4. Utility Pirnt Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation.
- 5. Depreciation and Nuclear Fuel Amortization Depreciation of our utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the r
various classes of property. Excluding the effect of the adjustment discussed below, the overall composite depreciation rates were 3.30%,3.33% and 3.28% in 1997,1996 and 1995, respectively. a Upon the completion of a review of our electric generating units, we determined that our oldest and least efficient fossil units 1 (Mystic 4,5 and 6) were unlikely to provide competitively-priced power beyond the year 2000. Therefore we revised the estimated remaining economic lives of these units to five years in 1996. The cost of decommissioning Pilgrim Station is excluded from our depreciation rates. Refer to Note E to these Consolidated Financial Statements for a discussion of nudear decommissioning. The cost of nudear fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense also includes an amount for the estimated costs of ultimately disposing of spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are recovered from our customers through fuel rates.
- 6. Deferred Nudear Outage Costs We defer the incremental costs associated with nudear refueling outages when incurred and amortize them over Pilgrim Station's oper-
. ating cyde in 1995 we changed the amortization period from five years to two years. The two-yea amortization period is consistent with the two-year cyde between nudear refueling outages at Pilgrim Station. ' 7. Costs Associated with Issuance and Redemption of Debt and Preferred Stock Consistent with our recovery in electric rates, we defer discounts, redemption premiums and related costs associated with the redemp-tion and issuance oflong-term debt and preferred stock. The costs related to long-term debt are recognized as an addition to interest expense over the life of the original or replacement debt. Beginning in 1996, consistent with an accounting order received from the FERC, we reflect costs related to preferred stock redemptions and issuances as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable.
- 8. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is induded as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form ofincreased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1997,1996 and 1995 were 6.04%,5.87% and 6.35%, respectively, and represented only the cost of short-term debt.
- 9. Cash and Cash Equivalents Cash and cash equivalents are comprised of highly liquid securities with maturities of 90 days or less when purchased. Outstanding checks are included in cash and accounts payable until they are presented for payment.
- 10. Allowance for Doubtful Accounts Our accounts receivable are substantially recoverable. This recovery occurs both from customer payments and from the portion of cus-tomer charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.
- 11. Regulatory Assets I
Regulatory assets represent costs incurred which are expected to be collected from customers through future charges e accordance with agreements with our regulators. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. The majority of these costs is currently being recovered from customers over varying time periods. Refe-to Note C to these Consolidated Financial Statements for information regarding the recovery of regulatery assets related to our geners tion business. i 17
Regulatory assets consisted of the following: ' December 31, 1997 1996 -. Fossil divestiture $ 21,248 -0 71,445 88,963 Power contracts 51,096 47,483 . Income taxes, net 27,019 31,052 Redemption premiums Postretirement benefits costs 22,441 15,009 1 Decontamination and decommissioning 12,282 13,190-Nuclear outage costs 10,160 3,432 Other 4,712 2,897 I $ 220,403 $ 202,026
- 12. Earnings Per Share of Common Stock Basic earnings per share (EPS) of common stock is calculated by dividing net income, after the payment of preferred stock dividends, by the weighted average common shares outstanding during the year. Statement of Financial Accounting Standards No.128, Earnings per Share, requires the disclosure of diluted EPS effective for periods ending after December 15,1997. Diluted EPS is similar to the computation of basic EPS except that the weighted average common shares is increased to include the number of dilutive potential common shares. Diluted EPS, which includes the effect of deferred (nonvested) shares and stock options granted under the Stock Incentive Plan in the calculation of weigined average common shares, is the same as basic EPS displayed on the consolidated statement ofincome.
Note C. Electric Utility Industry Restructuring
- 1. Accounting Implications Under the traditional revenue requirements model, our electric rates have been based on the cost of providing electric service. As such, we have been subject to cenain accounting standards that are not applicable to other businesses and industries in general. The applica-tion of SFAS 71 requires us to defer the recognition of cenain costs when incurred if future rate recovery of these costs is expected.
Based on a consensus reached by the Emerging Issues Task Force (EITF) regarding specific issues raised related to the application of SFAS 71, we have determined that, as of December 31,1997, the provisions of SFAS 71 no longer apply to the generation portion of our busi- . ness. In its consensus, the EITF determined that when deregulation legislation is passed and regulatory actions have taken place provid-ing sufficient detail for an enterprise to reasonably determine how the transition plan will affect the separable portion ofits business being deregulated, the enterprise should stop applying SFAS 71 to that portion ofits business. On January 28,1998, the DTE approved our restructuring settlement agreement that was filed in July 1997. The DTE found that the settlement agreement substantially com-plied or was consistent with key provisions of a Massachusetts law enacted in November 1997 establishing a comprehensive framework . for the restructuring ofour industry. The EITF further determined that book values of assets and liabilities originating in the separable portion of the business no longer subject to rate-regulation should be evaluated on the basis of where the regulated cash flows to realize l , and settle them will be derived. Net utility plant and other related assets on our consolidated balance sheet as of December 31,1997 indude approximately $700 million related to nudear generation and approximately $450 million related to fossil generation. As pan of j; our settlement agreement, approximately 75% of these nudear assets are fully recoverable through the non-bypassable transition charge of our distribution business which continues to be subject to rate-regulation. The remaining 25% will be collected under Pilgrim's j, wholesale life of the unit contracts. These contracts continue to be regulated by the FERC and are not impacted by our settlement agree-j ment. These fossil assets will be recovered from the proceeds from their sale as discussed in pan 2 below. i The implementation of our approved settlement agreement has certain accounting implications. The highlights of these include: Drprsciation ' The composite depreciation rate for distribution utility plant increases from 2.38% to 2.98% as of March 1,1998 (the retail access date). I Gsnsration related plant and regulatory assets t --Plant and regulatory assets related to our generation business, except for those related to Pilgrim's wholesale life of the unit contracts, will be recovered through the transition charge. This recovery, which includes a return, will occur over a twelve-year period. 28 l
Storm fund Under the settlement agreement, we are authorized to establish a storm contingency fund to use for the incremental costs of any major storm (in excess of $1 million). The settlement required that we initially establish the fund with $8 million of proceeds received from the sale of Clean Air Act emission allowances. As costs are charged against the fund, the balance will be restored to the original level from distribution charges up to a maximum of $3 million per year. Fust and purchased power charge The fuel and purchased power charge ceases as of the retail access date. Net remaining over or under collection of fuel and purchased power costs will be reflected in future customer billings. Standard offer charge Customers will have the option of continuing to buy power from our electric delivery business at ' Standard Offer" prices as of the retail access date. The Standard Offer charge begins at 2.8 cents at retail access and increases to 5.1 cents by 2004. The cost of provid-ing Standard Offer service, which includes fuel and purchased power costs, will be recovered from Standard Offer customers on a fully reconciling basis. Distribution and transmission charges Distribution rates will be subject to a minimum and maximum return on averae common equity (ROE) through December 31,2000. The ROE is subject to a floor of 6% and a ceiling of 11.75%. If the ROE is below 6%, we are authorized m add a surcharge to distri-bution rates in order to achieve the 6% floor. If the ROE is above 11%, we are required to adjust distribution rates by an amoum nec-essary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by 100% No adjustment is made if the ROE is between 6% and 11%. In addition, distribution rates will be adjusted for any changes in tax laws or accounting principles th2t result in a change in our costs of more than $1 million. The cost of providing transmission service to distribution customers will be recovered on a fully reconciling basis. Nuclear generation Under the settlement agreement, the armual performance adjustment charge ceases and our cost recovery mechanism for Pilgrim Station i changes as of the retail access date. Approximately 25% of the operations and capital costs, including a return on investment, will continue to be collected under wholesale life of the unit contracts. The remaining output will be sold in the competitive energy market. Through ~ December 31,2000, we will share 25% of any profit or loss from the sale of Pilgrim's output with distribution customers through the transi-tion charge. In addition, we will obtain transition payments up to a maximum of $23 million per year depending on the level of costs incurred for property taxes, insurance, regulatory fees and security requirements. Nuclear decommissioning Appre, ately 25% of Pilgrim's decommissioning costs will continue to be collected under wholesale life of the unit contracts. The remaining portion will be recovered through the transition charge. Amounts collected for decommissioning will be adjusted as decom-missioning cost studies are updated. Refer to Note E to these Consolidated Financial Statements for more information on nuclear decommissioning costs.
- 2. Divestiture of Fossil Generating Assets included in our settlement agreement is a provision for the divestiture of our fossil generating assets. On December 10,1997,we entered into a purchase and sale agreement with Sithe Energies, Inc., a privately-held company headquartered in New York, to purcitase our non-nuclear generating assets. The proceeds from the sale of these assets will be $657 million. The net book value of these assets at December 31,1997 is approximately $450 million. Included in the purchase price, Sithe Energies will pay $121 million to us in connection with a six-nionth transitional power sales agreement under which we will continue to buy power from the generating plants. Sithe Energies will also be responsible for obligations resulting from the recently enacted utility restructuring legislation for property tax payments to communities with non-nuclear power plants.
In July 1997, we reached an agreement with our field service union that requires the buyer of our fossil generating assets to rec-ognize and continue to honor the provisions of the union's current collective bargaining agreement through the end ofits term, May 2000. As part of a package offered to employees affected by the fossil divestiture, all eligible fossil and designated fossil support i employees age 55 or older with at least 10 years of service, or age 65 by July 1,1998, were offered unreduced retirement and transi-tion benefits under a voluntary early retirement program (VERP) Under this program,40 people elected to retire. Retirement dates are expected to be the first of the month following the transfer of ownership of our fossil generating assets. Severance programs were offered to management and field service union employees affected by the fossil divestiture that did not elect or were ineligible to retire under the VERR These severance benefits include salary payments, education / retraining allowances and outplacement services. It is anticipated that 48 emplcyees will receive severance benefits under these programs. 29
The estimated costs associated with the VERP and severance programs is approximately $21 million including the effects on the retirement, life and dental plans. Severance and employee retraining costs related to the <iivestiture are recoverable through the distri bution transition charge under our settlement agreement. Therefore, we have established an offsetting regulatory asset for these oblig ations on our consolidated balance sheet at December 31,1997.
- 3. Nuclear Asset impairment As part of ae settlement agreement, we recover our net investment in Pilgrim Station as of December 31,1995 (adjusted for deprec tion through 1997) through the distribution transition charge. Under the terms of the settlement agreement, we must perform a mar-ket valuation of Pilgrim by 2002. Upon acceptance of the valuation by the DTE, the resulting dollar amount, net of prudently incurred post-1995 investments in the plant, will reduce amounts collectible through the transition charge. If the valuation is not suffi-cient to allow for the recovery of these investments, we will seek their recovery through the transition charge. Due to the market pres-sures facing us, the ultimate recovery of these assets is not certain. Therefore, we reduced our investment in Pilgrim by the $13 million invested in the plant since January 1,1996 as an impairment loss under Statement of Financial Accounting Standards No.121, Accounting for the impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of(SFAS 121). An after tax charge of approximately $8 million due to this reduction was recorded to non-operating expense on our consolidated statement ofincome in the fourth quarter of 1997. A similar uncertainty does not exist for the ultimate recovery of the fossil generating assets as the sale proc :ds agreed to in the purchase and sale agreement with Sithe Energies exceeds the net book value of these assets.
Note D. Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No.109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recognition ofdeferred tax assets and liabilities for the future tax effects of temporary differ-ences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded net regulatory assets of $51.1 million and $47.5 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1997, and December 31,1996, respectively. The regulatory assets represent the additional future revenues to be collected from cus-tomers for deferred income taxes. Accumulated deferred income taxes consisted of the following: December 31, (in thousands) 1997 1996 Deferred tax liabilities: Plant-related $ 535,460 $ 532,390 Other 79,930 95,642 615,390 628,032 Deferred tax assets: Plant-related 11,926 8,406 Investment tax credits 33,125 38,005 Other 84,601 82,903 l 129,652 129,314 Net accumulated deferred income taxes $ 485,738 $ 498,718 No valuation allowances for deferred tax assets are deemed necessary. Previously deferred investment tax credits are amortized over the estimated lives of the property giving rise to the credits. l l l 30
Components ofincome tax expense were as follows: years ended Decemb:r 31, (in thousands) 1997 1996 1995 Current income tax expense $ 116,685 $ 92,760 $ 93,469 D:ferred income tax expense (14,104) 14 (21,115) Investment tax credit amortization (7,560) (4,071) (4,078) Income taxes charged to operations 95,021 88,703 68,276 Taxes on other income: Current (12,566) (721) (1,729) Total income tax expense 82,455 $ 87,982 $ 66,547 The efTective income tax rates reflected in the consolidated fmancial statements and the reasons for their difTerences from the statutory federal income tax race were as follows: 1997 1996 1995 Statutory tax rate 35.0 % 35.0% 35.0% State income tax, net of federal income tax benefit 4.5 4.3 4.3 Investment tax credit amortization (3.3) (1.8) (2.3) Other 0.1 0.7 0.1 Effective tax rate 36.3 % 38.2% 37.1 % The 1997 effective tax rate declined by 0.8% as a result of the favorable outcome of an Internal Revenue Service appeal related to investment tax credits. Note E. Nuclear Decommissioning and Nuclear Waste Disposal
- 1. Nuclear Decommissioning l
When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. Decommissioning means to remove nuclear facilities from service safely and reduce residual radioactivity to a level that permits termination of the Nudear Regulatory Commission (NRC) license and release of the property for unrestricted use. We record an estimate of decommissioning costs in depreciation expense on the consolidated statements ofinco te over Pilgrim's expected service life. Decommissioning expense is approximately $14 million per year. The estimate used to determine our annual expense is based on a 1991 study that documents a cost of approximately $328 million to decommission the plant using the " green field" method, which provides for the plant site to be com-l pletely restored to its original state. The cost estimate was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense through charges to our retail customers and from other utility companies and municipalities which purchase a con-tracted amount of Pilgrim's electric generation. The funds we collect from decommissioning charges are deposited in an external trust and are restricted to use for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted, increase the nudear decommissioning trust balance, thus reducing the amount to be collected from customers. l The 1991 decommissioning study was partially updated for internal planning purposes in order to evaluate the potential impact of long-term spent fuel storage options resulting from delays in the United States Department of Energy (DOE) spent fuel removal pro-gram. Refer to part 2 for a discussion of spent fuel removal. The partial update indicated an estimated decommissioning cost of $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology. We are in the process of updating this study. No fmal cost estimste is currently available; however, we continue to monitor DOE spent fuel removal schedules and developments in spent fuel storage techno!ogy along with their impact on the decommissioning estimate. Certain financial reporting considerations related to nudear decommissioning costs have not been fully resolved. In 1996 the Financial Accounting Standards Board (FASB) issued proposed new rules for accounting for liabilities related to dosure and removal of long-lived assets, which include decommissioning of nuclear generating facilities. If these proposed rules are adopted we would be required to retroactively recognize the entire estimated liability for decommissioning costs on the balance sheet, offset by an addition to utility plant. The plant addition would be depreciated over Pilgrim's remaining expected service life. The liability would be mea-sured based on the present value of estimated future cash flows. The cumulative effect of adoption of these proposed rules could result in the recognition of a regulatory asset to be recovered from customers to the extent that the present value difference in the liability between when the liability was incurred and when the rules are adopted exceeds the depreciation expense previously recognized for j decommissioning. In addition, trust fund earnings would be reported on the income statement. The FASB recently resumed its delib-erations on this project. No date has been set for the issuance of either a final statement or revised proposed rules. 31 1
i
- 2. Spent Nuclur Full The spent fuel storage facility at Pilgrim Station is expected to provide storage capacity through approximately 2003. We have a license amendment from the NRC to modify the facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any further modifications are subject to review by the DTE. We are actively exploring th feasibility of other spent fuel storage facilities and technologies.
Delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site for spent nuclear fuel. The DOE's current estimate for an available site is 2010. In November 1997, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its con-tract obligation to begin accepting spent nuclear fuel no later than January 31,1998. This decision was in response to petitions filed by us and other interested parties seeking declaratory rulings concerning enforcement and remedies for the DOE's failure to accept spent fuelin a timely manner. The court directed the plaintiffs to pursue relief under terms of their contracts with the DOE. Based on this ruling, the DOE may have to pay contract damages ifit does not take the spent nuclear fuel as scheduled. Under the Nuclear Waste Policy Act of 1982, it is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel. We currently pay a fee of $1.00 per net megawarthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges. We cannot predict at this time whether or on what schedule the DOE will eventually construct a spent fuel repository or what the effect will be of any delays in such construction. The DOE recently denied our petition to suspend payments made to the Nuclear Waste Fund based on its interpretation of the U.S. Court of Appeal's decision made in November 1997. The DOE has, however, made an offer to consider amendments to exist-ing contracts to address the hardships the anticipated delay in accepting spent fuel may cause individual contract holders. We contin-ue to monitor this situation and consult with legal counsel as to our next course of action.
- 3. Low-Level Radioactive Waste We regained access to low-level radioactive waste (LLW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currently the only disposal facility available to us. legislation has been enacted in Massachusetts establishing a regulatory process for managing LLW, including the possible siting, licensing and construction of a disposal facility within the state, or, alternatively, an agree-ment with one or more other states. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management procedure, we will continue to monitor the situation and investigate other available options.
Note F.1995 Corporate Pestructuring In 1995 we streamlined the corporate organization and reorganized the company into separate business units in order to strengthen our cnmpetitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retirement pro-grams and implemented a special severance program to reduce employee staffing levels. Under the enhanced retirement programs 330 employees elected to retire, and 149 employees whose positions were eliminated became eligible for benefits under the special severance program. These programs resulted in a $34 million pre-tax charge ($20.7 million after tax) over the third and fourth quarters of 1995. The charge consisted of $24 million for the retirement programs and $10 million for the severance program. Note G. Pensions and Other Postretirement Benefits
- 1. Pensions We have a defined benefit funded retirement plan with certain contributory features that covers substantially all employees. Benefits are based upon an employee's years of service and highest eligible average compensation during the last ten years of credited employ-ment. Our funding policy is to contribute an amount each year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. The retirement plan assets consist of equities, bonds, money market funds, insurance contracts and real estate funds.
We also have an unfunded supplemental retirement plan for certain management employees. Benefits under this plan are based upon an employee's years of service and highest eligible average compensation during years of credited employment. 31
Net pension cost consisted of the following components: years ended December 31, (in thousands) 1997 1996 1995 Current service cost - benefits earned $ 12,625 13,452 $ 11,339 Interest cost on projected benefit obligation 31,537 32,325 31,789 Actual return on plan assets (60,602) (40,335) (72,192) Net amortization and deferral 33,912 17,064 49,557 Net pension cost $ 17,472 22,506 $ 20,493 In accordance with our 1992 retail rate setdement agreement we deferred the difference tinween the net pension cost of the retirement . plan and its annual funding amount through 1995. Net pension cost recognized in 1995 was $28 million. We experienced a high number of employee retirements from 1994 to 1996. A large number of these retirements were as a direct result of our 1995 corporate restructuring. In 1997, a review of the accounting for the pension expense related to the retirements ,j ' revealed that an adjustment to the pension costs related to these employees was necessary. Therefore, we increased our pension regula-j- tory asser by $8.6 million in 1997 for the adjustment related to the period of our 1992 settlement agreement. The remaining adjust- } ment did not have a material impact on our consolidated results of operations or financial position. We used the following assumptions for calculating pension cost: 1997 1996 1995 . Discount rate 7.75% 7.25% 8.25 % Expected long-term rate of return on assets 10.00 % 10.00 % 10.00 % Compensation increase rate 3.90% 3.90% 3.90% The plans' funded status were as follows: December 31, . (in thousands) 1997 1996 Supplemental Supplemental Retirement Retirement Retirement Retirement Plan Plan Plan Plan Actuarial present value of accumulated benefit obligation: Vested $ 361,484 8,571 $ 316,101 7,576 Non-vested 10,578 1,192 10,867 943 Total $ 372,062 9,763 $ 326,968 8,519 Plan assets at fair value $ 401,182 0 $ 331,299 0 Projected obligation for service rendered to date (446,360) (11,076) (400,561) (9,199) Projected benefit obligation in excess of plan assets (45,178) (11,076) (69,262) (9,199) Unrecognized prior service cost 9,385 9,736 11,238 9,436 Unrecognized net loss /(gain) 50,673 (27) 78,853 (1,141) . Unrecognized net obligation 5,704 0 7,130 0 . Additional minimum liability (a) 0 (8,396) 0 (7,615) ' Net pension prepayment /(liability)(b) $ 20,584 $ (9,763) 27,959 $ (8,519) (a) Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SFAS 87), requires the recognition of an additional minimum liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accor-dance with SFAS 87 we recorded additional minimum liabilities and corresponding intangible assets of $8.4 million and $7.6 million on our consolidated balance sheets at December 31,1997 and 1996, respectively. (b).The prepaid pension amount at December 31,1997 reflects the impact of $8 million related to the fossil workforce reduction as dis-cussed in Note C to these Consolidated Financial Statements. 33
We used the following assumptions for calculating the plans' year-end funded status: 1997 1996 7.25% 7.75% Discount rate 4.25% 3.90 % Compensation increase rate We also provide defined contribution 401(k) plans for substantially all of our employees. We match a portion of employ, i vol-untsy contributions to the plans. We made matching contributions of $8 million in 1997 and 1996 and $9 million in 19b.
- 2. Other Postretirement Benefits in addition to pension benefits, we also provide health care and other benefits to our retired employees who meet certain age and y service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accordance with i
Statement of Financial Accounting Standards No.106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). Our 1992 retail rate settlement agreement provided us with a phase-in to full expense of the PBOP costs incurred under SFAS 106. This settlement agreement allowed us to defer any costs in excess of the specified phase-in amounts to the extent that we funded an external trust. Our funding policy is to generally contribute 100% of PBOP costs to external trusts. Therefore, we recognized $23 mil-lion of PBOP costs in 1995 in accordance with the 1992 settlement agreement. Beginning in 1996 we recognized the ftdl PBOP costs incurred under SFAS 106. The net deferred PBOP costs of $15 million resulting from the delayed phase-in are included in regulatory assets as these costs will be recovered from customers in future periods. Net postretirement benefits cost consisted of the following components: i years ended December 31, (in thousands) 1997 1996 1995 Current service cost - benefits earned 3,543 4,616 3,408 Interest cost on accumulated benefit obiigation 17,006 16,815 13,521 Actual return on plan assets (18,852) (9,584) (7,151) Amortization of transition obligation 9,151 9,151 9,151 Net other amortization and deferral 12,417 5,209 3,017 Net postretirement benefits cost $ 23,265 26,207 $ 21,946 - We used the following assumptions for calculating postretirement benefits cost: 1997 1996 1995 Discount rate 7.75% 7.25% 8.25% Expected long-term rate of return on assets 9.00 % 9.00% 9.00% i Health care cost trend rate 6.00 % 7.00% 7.00% The health care cost trend rate is assumed to decrease by 1% in 1998 and to remain at 5% in years thereafter. Changes in the health care cost trend rate will affect our cost and obligation amounts. A 1% increase in the assumed health care cost trend rate would increase the total service and interest cost components by 7A% and would increase the accumulated benefit obligation at December 31,1997 by 6.6%. t b I J 34 l
= -..- The PBOP program's funded status was as follows: December 31, (in thousands) 1997 1996 Trust assets at fair value $ 103,989 $ 72,702 Accumulated obligation for service rendered to date from: Retirees $ (166,035) $ (156,694) Active empSyees eligible to retire (16,484) (12,644) Active employees not eligible to retire (55,097) (237,616) (61,567) (230,905) Accumulated benefit obligation in excess of trust assets (133,627) (158,203) Unrecognized prior service cost (14,128) (16,274) Unr: cognized net loss 12,916 26,663 Unrecognized transition obligation 127,107 146,413 Net postretirement benefits liability (a) $ (7,732) $ (1,401) (a) The postretirement benefits liability at December 31,1997 reflects an $8 million additional PBOP obligation related to the fossil workforce reduction as discussed in Note C to these Consolidated Financial Statements. The weighted average discount rates used to measure the program's year-end funded status were 7.25% in 1997 and 7.75% in 1996. The trust assets consist of equities, bonds and money market funds. i Note H. Stock-Based Compensation In 1997, we initiated a Stock Incentive Plan (the Plan) which was adopted by the Board of Directors and approved by our stockholders. The Plan permits a variety of stock and stock-based awards, induding stock options and deferred (nonvested) stock to be granted to cer-tain key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of shares of common stock that may be delivered under the Plan is 2,000,000, including shares issued in lieu of or upon reinvestment of dividends arising from awards. During 1997, we granted 73,820 shares of deferred stock and 298,400 ten-year non-qualified stock options under the Plan. The weighted average grant date fair value of the deferred stock is $27.26. The options were granted at the full market price of the stock on the date of the grant. Both awards vest ratably over a three-year period. We recognize compensation cost for our stock-based awards under the provisions of APB Opinion 25, which requires compensation cost to be measured by the quoted stock market price at the measurement date less the amount, if any, an employee is required to pay. 35
l I The required fair value method disclosures related to our stock-based compensation are as follows: 1997 l (in thousands, except per share amounts) N;t income $ 144,642 Actual $ 144,572 Pro forma Etrnings per share 2.71 j Actual 2.71 Pro forma Stock option activity of the Plan was as follows: 0 Options outstanding at January 1,1997 Options granted 298,400 l Options forfeited (25,400) Options outstanding at December 31,1997 ~ 273,000 l Summarized information regarding stock options outstanding at December 31,1997: Weighted Range of Average Remaining Weighted Average Exercise Prices Contractual Life (Years) Exercise Price $25.75-$26.00 9.44 $25.84 j No stock options were exercisable at December 31,1997. l The stock options were granted with a weighted average grant date fair value of $2.22. The fair value was estimated using the Black-Scholes option pricing model with the following weighted average assumptions: Expected life (years) 4.0 l Risk-free interest rate 6.44% Volatility 16% Dividends 7.28% Compensation cost recognized in income for our stock-based compensation awards in 1997 was $275,000. 36 L
I I Note 1. Capital Stock December 31, j (doll rs in thousands, except per share amounts) 1997 1996 Common stock equity: Common stock, par value $1 per share, 100,000,000 shirts authorized; 48,514,973 and 48,509,537 shares issued and outstanding: 48,515 48,510 Prrmium on common stock 696,137 695,723 l R:tained earnings 328,802 292,191 Total common stock equity $ 1,073,454 5 1,036,424 Dividends declared per share of common stock were $1.88 in 1997 and 1996 and $1.835 in 1995. Cumulative preferred stock: Par value $100 per share,2,890,000 shares authorized; issued and outstanding: Nonmandatory redeemable series: Current Shares Redemption Series Outstanding Price / Share l 4.25% 180,000 $103.625 18,000 18,000 4.78 % 250,000 $102.800 25,000 25,000 7.75% 400,000 40,000 40,000 8.25 % 0 40,000 83,000 123,000 Less: redemption and issuance costs 0 (3,046) l Total nonmandatory redeemable series 83,000 119,954 Mandatory redeemable series: Cunent Shares Redemption Series Outstanding Price / Share 7.27 % 360,000 $102.420 36,000 40,000 8.00 % 500,000 50,000 50,000 86,000 90,000 Less: redemption and issuance costs (5,907) (6,535) due within one year (2,000) (2,000) Total mandatory redeemable series 78,093 81,465
- 1. Common Stock Common stock issuances in 1995 through 1997 were as follows:
Number Total Premium on (in thousands) of Shares Par Value Common Stock Balance at December 31,1994 45,535 45,535 $ 622,803 Dividend reinvestment plan 468 468 11,404 New issuances 2,000 2,000 49,479 Balance at December 31,1995 48,003 48,003 683,686 Dividend reinvestment plan 507 507 12,037 Bal:nce at December 31,1996 48,510 48,510 695,723 Dividend reinvestment plan 5 5 414 Balance at December 31,1997 48,515 48,515 $ 696,137 i 37 l
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- 2. Cumulative M;ndat:ry Redeemibla Pr:f;rred Stock The 360,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $102.420. The redemption price dedines annually each May to par value in May 2002. The stock is subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. We also have the noncumulative option each May to redeem additional shares, not to exceed 20,000, through the sinking fund at $100 per share plus accrued dividends. We redeemed, at par value,40,000 shares in 1997 and 1996 and 20,000 shares in 1995.
We are not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 e $100 per share plus accrued dividends. Noto J. Indebtedness December 31, (in thousands) 1997 1996 Long-term debt: Debentures: 5.700%, due March 1997 0 100,000 5.950%, due March 1998 100,000 100,000 6.800%, due February 2000 65,000 65,000 6.050%, due August 2000 100,000 100,000 6.800%, due March 2003 150,000 150,000 7.800%, due May 2010 125,000 125,000 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8.250%, due September 2022 60,000 60,000 7.800%, due March 2023 200,000 200,000 Total debentures 1,015,000 1,115,000 Less: due within one year (100,000) (100,000) Net long-term debentures 9157600 1,015,000 Sewage facility revenue bonds 32,500 34,100 Less: due within one year (667) (667) Less: funds held by trustee (4,757) (4,789) Net long-term sewage facility revenue bonds 27,076 28,644 Massachusetts Industrial Finance Agency bonds: 5.750%, due February 2014 15,000 15,000 6.662% bank loan, due 1999 100,000 0 Total long-term debt $ 1,057,076 $ 1,058,644 ~ Short-term debt: Notzs payable: Bank loans 94,013 129,631 Commercial paper 43,000 71,823 Total notes payable $ 137,013 $~201,454 38
1.- Long-tsrm Dabt l t The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption price of 104.483%, the 9 3/8% series due 2021 are l ' first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the i 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. No other series are redeemable prior to maturity. There is no sinking fund requirement for any ti. ries of our debentures. Sewage facility revenue bonds were issued by HEEC. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. In both May 1996 and 1997, we redeemed $1.6 million as scheduled. The f weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds is in reserve with the trustee. If HEEC should have insufficient fund., tu pay for extraordinary expenses, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 million. The 5.75% tax-exenipt unsecured bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006. In March 1997, we obtained $100 million of 6.662% notes in the form of a bank loan. This note matures in 1999. The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2002 are $101.6 million in 1998 and 1999, $166.6 million in 2000 and $1.6 million in 2001 and 2002,
- 2. Short-term Debt We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have regulatory authority to issue up to $350 million of short-term debt.
We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount. Information regarding our utility short-term borrowings, comprised of bank loans and commercial paper, is as follows: (dollars in thousands) 1997 1996 1995 Maximum short-term borrowings $ 316,100 $ 272,500 $ 327,769 . Weighted average amount outstanding $ 212,663 $ 208,914 165,720 Weighted average interest rates excluding commitment fees 5.85% 5.65% 6.21 % In addition, at December 31,1997. BETG had $7.5 million outstanding under a revolving credit agreement. Note K. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value: Nuclear decommissioning trust: The cost of $151.6 million approximates fair value based on quoted market prices of securities held. Cash and cash equivalents: ' The carrying amount of $4.1 million approximates fair value due to the short-term nature of these securities. Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt: The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31,1997, are as follows: Carrying Fair . (in thousands) Amount Value Mandatory redeemable cumulative preferred stock 80,093 91,720 1 Sewage facility revenue bonds 32,500 35,084 Unsecured debt $ 1,030,000 $ 1,073,982 1 i i 39
Note L Commitments and Contingencies
- 1. Ccntractual Commitments At December 31,1997, we had estimated contractual obligations for plant and equipment of approximately $18 million.
We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both transmission agreements and noncancellable leases for the years after 1997 are as follows: + (in thousands) 1998 21,938 1999 18,958 2000 16,738 2001 12,356 2002 11,194 Y:ars thereafter 91,874 Total 173,058 Amounts above include $2.7 million which is expected to be assumed by Sithe Energies as part of our pending fossil divestiture discussed in Note C to these Consolidated Financial Statements. The total of future minimum rental income to be received under noncancellable subleases related to the above leases is $300,921. We will capitalize a portion of these lease rentals as part of plant expenditures in the future. The total expense for both lease rentals and transmission agreements was $27.5 million in 1997, $26.3 million in 1996 and $24.5 million in 1995, net of capitalized expenses of $1.2 million in 1997, $2.9 million in 1996 and $2.7 million in 1995. We previously entered into various take or pay and throughput agreements, primarily to supply our New Boston fossil generating station with natural gas. The fixed and determinable portions of the obligations associated with these agreements are $19.5 million in 1998 and 1999 and $14.6 million in 2000. As part of our fossil divestiture agreement, Sithe Energies has agreed to assume these l obligations. The total expense under these agreements was $47.1 million in 1997, $49.5 million in 1996 and $13.9 million in 1995. t l
- 2. Electric Company Investments We have an approximately 11% equity investment in two companies which own and operate transmission facilities to import electricity l
from the Hydro-Quebec system in Canada. As an equity participant we are required to guarantee, in addition to our own share, the l total obligations of those participants who do not meet certain credi: criteria. At December 31,1997, our portion of these guarantees was $16.6 million. I We have a 9.5% equity investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992 the board of directors of Yankee Atomic decided to discontinue operations of the Yankee Atomic nuclear generating station perma-nendy and decommission the facility. Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approximately $13 million as of December 31,1997. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset. We also have a 9.5% equity investment in Connecticut Yankee Atomic Power Company (CYAPC) of approximately $11 million. In December 1996, the board of directors of CYAPC, which owns and operates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the unit. The decision was based on an economic analysis of the costs of operating the unit through 2007, the period ofits operating license, compared to the costs of closing the unit and incurring replace-ment power costs for the same period. The current estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee is approximately $615 million. Our share of these remaining estimated costs is $58 million. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset similar to Yankee Atomic. In early 1997, CYAPC filed a rate case at the FERC seeking to recover certain post-operating costs, including decommissioning. The Connecticut Department of Public Utility Control (DPUC) has raised concerns to the FERC regarding CYAPC's estimate of these costs and the plant operator's prudency prior to the shutdown decision. The FERC set CYAPC's request for hearing before an Administrative Law Judge. The DPUC subsequently filed testimony in the proceeding asserting the position that the FERC should deny recovery of substantial post-operating costs, including a significant amount related to decommissioning and the return on CYAPC's undepreciated investment. We are currently unable to determine the ultimate outcome of this proceeding or its impact. i l 1 40 = _ - -
- 3. Nucinr Insurancs The federal Price-Anderson Act currently provides $8.9 billion of fmancial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nudear liability insurance up to $8.7 billion is'provided by a retrospective assessment of up to $79.3 million per incident levied on each of the 110 nuclear generating units currently licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year.
We have purchased insurance from Nuclear Electric insurance Limited (NEIL) to cover some of the costs to purchase replace-ment power during a prolonged accidental outage and the cost of repair, replacement, decontamination or decommissioning of our utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assessment for losses which occur during current policy years is $10A million under both the replacement power and excess property damage, decontamination and decommissioning policies.
- 4. Hazardous Waste We are an owner or operator of approximately 30 properties where oil or hazardous materials were spilled or released. As such, we are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection. We continue to evaluate the costs associated with site cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and he particular characteristics of the different sites. We also contin-ue to face possible liability as a potentially responsible party in the cleanup of six multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. We are one of many potentially responsible parties and currently expect to have only a small percentage of the potential liability. Through December 31, 1997, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of reason-ably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not believe that it is probable that any such additional costs will have a material impact on our fmancial condition. However, it is rea-sonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
- 5. Generating Unit Performance Program Our recovery of the incremental purchased power costs resulting from outages at our generating units occurring through the retail access date is subject to review by the DTE. We are unable to fully determine a range of reasonably possible disallowance costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reasonably possible that additional disallowance costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
4 l
- 6. Litigation In October 1997, the DTE opened a proceeding to investigate our compliance with the 1993 order which permitted the formation of BETG and authorized us to invest up to $45 million in unregulated activities. We are unable to determine the ultimate outcome of this proceeding or its impact on our operations.
In the normal course of our business we are involved in certain other legal matters. We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reason-ably possible that additionallitigation costs that may result from a change in estimates could have a material impact on the results of a reporting period in the ricar term.
- 7. Industry Restructuring Legal Proceedings / Referendum Campaign The DTE order approving our settlement agreement has been appealed by certain parties to the Massachusetts Supreme Judicial Court.
In addition, along with other Massachusetts investor owned utilities, we have been named as a defendant in a class action suit seeking to declare certain provisions of the Massachusetts electric industry restructuring legislation unconstitutional. We are currently unable to determine the outcome of these proceedings or their impact on us. Opponents of the electric industry restructuring legislation that was enacted in November 1997 have mounted a referendum campaign to repeal that law. A coalition of business, industry and public interest groups that supported the legislation, along with the electric utility industry, is opposed to the referendum and is prepared to mount an aggressive campaign to defeat it. We are cur-rently unable to predict the eventual outcome of this referendum or its impact on us. 41
~ Note M. Long-Term Power Contracts - 1. Long-Term Contracts for the Purchase of Electricity We purchase electric power under several long-term contracts for which we pay a share of a generating unit's capital and fixed operating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense on our consolidated income statements. Information relating to these contracts as of December 31,1997, is as follows: proportionate share (in thousands) Units of Debt Contract Capacity Minimum Outstanding Expiration Purchased (a) Debt Through Cont. Annual Generating Unit Date MW Service Exp. Date Cost Canal Unit 1 - 2002 25.0 141 $ 1,475 $ 5,172 997 2,166 Mass. Bay Transportation Authority - 1 2005 100.0 34 Ocsan State Power - Unit 1 2010 23.5 72 4,256 17,962 21,778 Ocean State Power - Unit 2 2011 23.5 72 3,592 15,951 23,969 134,023 Northeast Energy Associates (b) (b) 219 L'Energia (c) 2013 73.0 63 21,902
- MissPower 2013 44.3 117 11,227 70,660 54,215 577 Mass. Bay Transportation Authority - 2 2019 100.0 34
.. Total 752 $ 20,550 $109,745 $ 287,627 (a) The Northeast Energy Associates contract represents 6.5% ofour total system generation capability, The remaining units listed ' above represent approximately 16% in total. (b) We purchase 75.5% of the energy output of this unit under two contracts. One contract represcrits 135MW and expires in the year 2015. The other contract is for 84MW and expires in 2010. We pay for this energy based on a price per kWh actually received. We do not pay a proportionate share of the unit's capital and fixed operating costs. (c) We pay for this energy based on a price per kWh actually received. Our total fixed and variable costs associated with these contracts in 1997,1996 and 1995 were approximately $288 million, $281 million and $262 million, respectively. Our minimum ftxed payments under these contracts for the years after 1997 are as follows: (in thousands) ' 1998 88,406 1999 88,501 2000-89,853 2001 90,365 2002 92,768 L Years thereafter 959,981 Total $ 1,409,874 Total present value. 783,975 Under our settlement agreement, by July 1998 we are required to file a plan with the DTE describing the actions we intend to take to sell, assign or otherwise dispose of our purchased power contracts. I 42
- 2. Long Tzrm PowIr S:lis Contracts In addition to other wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities and municipalities under long-
- term contracts. Information relating to these contracts is as follows: Contract Expiration Units of Capacity Sold Contract Customer Date MBT Commonwealth Electric Company 2012 11.0 73.7 Montaup Electric Company 2012 11.0 73.7 Various municipalities 2000 (a) 3.7 25.0 Total 75.7 172.4 (a) Subject to certain adjustments. Under these contracts, the utilities and municipalities pay their proportionate shart of the costs of operating Pilgrim Station and associated transmission facilities. These costs include operation and maintenance expenses, insurance, local taxes, depreciation, decom-missioning and a return on investment. Raport ofIndependent Accountants To the Stockholders and Directors of Boston Edison Company We have audited the accompanying consolidated balance sheets of Boston Edison Company and subsidiaries (the Company) as of December 31,1997 and 1996, and the related consolidated statements ofincome, retained earnings and cash flows for each of the three years in the period ended December 31,1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion 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 per-form 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 state-ment presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated 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 consolidated results ofits operations and its cash flows for each of the three years in the period ended December 31,1997, in conformity with generally accepted accounting principles. Boston, Massachusetts January 22,1998 43
S:l:ctsd Consolidated Quartsrly Financial Data (Unaudited) ' (in thousands, except earnings per share) Earnings Available Earnings Operating Operating Net ' for Common Per Average Revenues income income Shareholders Common Share (a) i .T997 ~ First quarter $ 422,725 $ 47,589 $ 20,935 $ 17,118 - $ 0.35 Second quarter ' 426,735 60,487 33,978 30,484 0.63 Third quarter 519,513 108,060 81,418 78,499 1.62 - i Fourth quarter 407,260 44,714 8,311 5,392 0.11 1996 . First quarter $. 387,849 $ 52,093 $ 25,203 $ 21,313 $' O.44 l . Second quarter - 389,756 55,232 27,926 24,086 0.50 Third quarter 497,968 105,353 80,011 76,194 1.58 Fourth quarter 390,730 35,252 8,406 4,588 0.09 (a) Based on the weighted average number of common shares outstanding during each quarter. f Salscted Quarterly Common Stock Data (Unaudited) i The reported high and low market value per share of our common stock as reported in the WallStrrctfournaland the dividends declared ' per share for each of the quarters in 1997 and 1996 was as follows: 1997 1996 High Low Dividends High Low Dividends First quarter $27 3/8 26 $0.470 $301/8 $261/4 $0.470 Srcond quarter 26 5/8 24 5/8 0.470 27 1/8 23 5/8 0.470 . Third quarter 30 7/8 26 1/2 .0.470 25 3/8 21 3/4 0.470 i Fourth quarter 38 3/8 30 1/4 0.470 27 21 3/4 0.470 i h f E P a 1 t 44 l.. ....J-
S:Iscted Consolidated Operating Statistics (Unaudited) 1997 1996 1995 1994 1993 Capicity.- MW: Pilgrim Station 670 670 669 669 670 Nzw Boston Station 760 730 760 760 760 Mystic Station 994 994 1,005 1,006 1,006 i ' W.F. Wyman Unit 4 37 37 36 36 36 Jst turbines 276 278 284 287 283 i Total (a) 2,737 2,709 2,754 2,758 2,755 f Contract purchases 941 1,237 1,274 1,035 938 l Contract sales (281) (333) (340) (373) (283) Net capability at year-end 3,397 3,613 3,688 3,420 3,410 N;t capability at peak - MW 3,444 3,385 3,466 3,484 3,663 Crpibility responsibility ] to NEPOOL at peak - MW 3,312 3,256 3,306 3,306 3,190 S
- d. Company territory:
/ Hourly peak - MW 2,835 2,703' 2,785 2,798 2,662 I, - Load factor 61.0 % 63.4 % 60.0 % 58.9 % 60.5 % [d f Crpibility(net kW): } Fcssil 85 % 86 % 85 % 84 % 84 % (j Nuclear 15 % 14 % 15 % 16 % 16 % ? j ~ ' Fossil 80 % 69 % 73 % 75 % 68 % [ .Genaration (system kWh excluding interchange): Nuclear 20 % 31 % 27 % 25 % 32 % 4 i j. Utility plant ($ in 000's): f, Expenditures $ 114,110 $ 145,347 $ 180,822 $ 198,771 $ 246,774 V!j. Rstirements 21,449 68,688 48,111 45,673 34,147 hj ' Accumulated depreciation 1,713,079 1,550,317 1,439,996 1,344,452 1,258,359 T D:preciable plant 4,375,391 4,317,028 4,235,347 3,994,212 3,841,752 7 3 Number of utility employees
- at y:ar-end 3,227 3,362 3,812 4,026 4,397 (a); Ba' sed upon winter capability audit results.
45 =
S:l:ct:d Consolidat:d Sales Statistics (Unaudited) 1997 1996 1995 1994 1993 El:ctric energy (kWh in thousands): Sources (system output): Generated 11,686,810 10,531,745 10,537,114 9,428,931 9,787,092 Purchased 6,014,208 5,680,194 5,446,542 5,920,065 5,326,224 New England Power Pool 887,250 1,842,732 1,513,467 1,535,335 1,575,310 Total 18,588,268 18,054,671 17,497,123 16,884,331 16,688,626 Disposition: Commercial 7,991,349 7,821,371 7,454,684 7,478,631 7,263,358 Residential 3,566,405 3,549,899 3,563,626 3,534,372 3,477,870 Industr:al 1,467,600 1,547,630 1,538,218 1,539,385 1,580,969 Other (a) 131,187 130,678 131,626 130,721 145,242 Total retail sales 13,156.541 13,049,578 12,688,154 12,683,109 12,467,439 Wholesale and contract sales (a) 2,674,283 3,127,087 2,805,777 2,367,589 2,272,669 New England Power Pool 1,610,860 741,390 884,336 725,439 877,978 Total system 17,441,684 16,918,055 16,378,267 15,776,137 15,618,086 Miscellaneous usage 1,146,584 1,136,616 1,118,856 1,108,194 1,070,540 Total 18,588,268 18.054,671 17,497,123 16,884,331 16,688,626 Kilowatthour sales - annual growth: Commercial 2.2 % 4.9 % (0.3)% 3.0 % 1.2 % Residential 0.5 (0.4) 0.8 1.6 1.9 Industrial (5.2) 0.6 (0.1) (2.6) (5.4) Other 0.4 (0.7) 0.7 (10.0) (50.3) Total retail sales (a) 0.8 2.8 1.7 (0.7) Wholesale and contract sales (14.5) 11.5 18.5 4.2 (9.7) New England Power Pool 117.3 (16.2) 21.9 (17.4) (53.7) Total system 3.1 % 3.3 % 3.8 % 1.0 % (8.0)% Electric operating mvenues by class: Commercial 51 % 50 % 50 % 50 % 49 % Residential 27 % 27 % 28 % 28 % 28 % industrial 9% 9% 9% 9% 10 % Other 1% 2% 2% 2% 1% Wholesale and contract 12 % 12 % 11 % 11 % 12 % Average number of customers 662,354 657,487 653,757 655,707 651,141 (a) Effective in both November 1995 and February 1993, a former retail customer became a wholesale customer as allowed under Massachusetts state law. t 46
..m_. Offic2rs Dirsctors i Thomas J, May, Chairman of the Board, President and Chief a,d Gary L Countryman, Chairman of the Board and Chief Executive OGcer Executive O$cer, Liberty Mutual Insurance Company . Ronald A. Ledgett, Executive Vice President a,e Thomas G. Dignan, Jr., Partner, Ropes & Gray f, Alison Alden, Senior Vice President - Sales, Services and Human Resources d,e Richard J. Egan, Chairman of the Board, EMC L. Carl Gustin, Senior Vice President - Corporate Relations Corporation (storage-related computer system products) b,c,d Charles K. GitTord, Chairman and Chief Executive l Douglas S. Horan, Senior Vice President - Strategy and Law and General Counsel Omcer, BankBoston Corporation j (bank holding company) and BankBoston, N.A. j James J. Judge, Senior Vice President - Corporate Services and a,b Nelson S. GifTord, Principal, Fleetwing Capital Treasurer - (venture investments) ) William N. Dimoulas, Vice President - Information a,b,c Matina S. Horner, Executive Vice President, Teachers j Technology Insurance and Annuity Association and College Philippe A. Frangules, Vice President - Strategic Planning and Retirement Equities Fund j Business Development a,c Thomas J. May, Chairman of the Board, President and ' Richard S. Hahn, Vice President - Technology Chief Executive OGcer, Boston Edison Company - Leon J. Olivier, Vice President - Nuclear Operations and b,d Sherry H. Penney, Chancellor, University of j - Station Director Massachusetts at Boston David M. Samuel, Vice President - Customer Care b,e Herb-rt Roth, Jr., Former Chairman of the Board and Chief Executive OGcer, LFE Corporation (traGc and j Robert J. Weafer, Jr., Vice President - Finance, Controller and ndustrial process control systems) ChiefAccounting OGcer b,e Stephen J. Sweeney, Former Chairman of the Board, l Theodora S. Convisser, Clerk of the Corporation . President and Chief Executive O$cer, Boston Edison [ ' Donald Anastasia, Assistant Treasurer Ccmpany .) i a Member of Executive Committee 4 b Member of Audit, Finance and Risk Management Committee Member of Pricing Committee c d Member of Executive Personnel Committee Member of Nuclear Oversight Committee e s l i i I i 48 l
..m. ^S11;ctrd Consolidat:d Financial Statistics (Unauditsd) 1997 1996 1995 1994 1993 Operating revenues (000) $ 1,776,233 $ 1,666,303 $ 1,628,503 $ 1,544,735 $ 1,482,159 Earnings available for common (000) $ 131,493 $ 126,181 96,739 (a) 109,257 $ 102,513 Per common share: - Earnings 2.71 2.61 2.08 (a) 2.41 2.28 Dividends declared 1.880 1.880 1.835. 1.775 1.715 3 Dividends paid .1.88 1.88 1.82 1,76 1.70 Book value - 22.13 21.37 20.61 20.11 19.42 ' Payout ratio ' 69 % 72 % 88 %(a) 73 % 75 % Return on average common equity - 12.4 % 12.4 % 10.0 %(a) 12.1 % 11.9 % Year-end dividend yield 5.0 % 7.0 % 6.4 % 7.6 % ' 5.9 % FixS charge coverage (SEC) 2.95 2.91 2.38 2.46 2.22 Capitalization: Total debt - 51 % 52 % 54 % 56 % 57 % Preferred equity 7% 8% 8% 9% 9% . Common equin 42 % 40 % 38 % 35 % 34 % Long-tsrm debt (000) - $ 1,057,076 $ 1,058,644 $ 1,160,223 $ 1,136,617 $ 1,272,497 Mandatory redeemable prefsrred stock (000) $ ' 80,093 83,465 86,837 88,837 90,837 Total assets (000) $ 3,622,347 $ 3,729,291 $ 3,637,170 $ 3,608,699 $ 3,468,724 I Internal generation after dividends (000) $ 240,362 $ 257,446 $ 184,492 217,030 194,209 Plant expenditures (000) 114,110 $ 145,347 $ 180,822 198,771 $ 246,774 - Intsrnal generation 211 % 177 % 102 % 109 % 79 % Common shares outstanding: Weighted average 48,514,958 48,264,734 46,591,662 45,337,661 44,959,050 t Year-end. 48,514,973 48,509,537 48,003,178 45,535,477 45,129,227 Stock price: - High 38 3/8 30 1/8 29 1/2 29 7/8 32 5/8 Low 24 5/8 21 3/4 23 1/8 21 1/2 26 3/8 Year-end 37 7/8 26 7/8 29 1/2 24 29 3/4 Year-end market value (000) $ 1,837,505 $ 1,303.694 $ 1,416,094 5 1,092,851 $ 1,342,595 Trading volume (shares) 37,732,900 41,105,700 23,078,900 25,095,100 18,729,400 Market / book ratio (year-end) 1.71 1.26 1.43 1.19 1.53 - Price / earnings ratio (year-end) .14.0 10.3 14.2 (a) 10.0 13.0 (a) Amounts excluding $34 million pre-tax restructuring charge: Earnings available for common (000) 117,403 Earnings .2.52 Payout ratio 72 % i Return on average common equity 12.2 % Price / earnings ratio 11.7 % L Certain redassifications and recalculations were made to the data reported in prior years to conform with the method of presentation used 'in 1997. i 47
Important Shareholder Information Automatic Monthly Investment Program Shareholder Inquiries Shareholders who are participants in the Dividend ' Ifyou have questions concerning your dividend payments, the Reinvestment and Common Stock Purchase Plan may now Dividend Reinvestment and Common Stock Purchase Plan, direct make automatic monthly investments of a specified amount deposit service, transfer procedures or other stock account matters, (not less than $50 per month) through an Automated Clearing please contact our stock transfer agent at the following address: House ("ACH") withdrawal from their savings or checking Boston EquiServe account. Once automatic monthly deductions are initiated, + Shareholder Services Division funds will be drawn from your designated bank account on the 25th of each month and will be invested in common stock on P.O. Box 8040 the next investment date. For more information on the Boston, MA 02266-8040 Autometk Monthly investment Program, or an enrollment Toll Free Phone: 1-800-338-8446 form, contact our stock transfer agent. / Telecommunication Device for the Deaf (TDD)
- 1-800-952-9245.
Safekeeping Program Dividend Payment Dates Shareholders who are participants in the Dividend Reinvestment and Common Stock Purchase Plan can transfer their common Common and Preferred stock certificates into their plan account for safekeeping. ~ 1st of February, May, August and November Dividends on those shares will be reinvested automatically like 3 Tan Status of 1997 Dividends any other shares held in the plan. To continue receiving cash dividends, you must hold your shares in certificate form. For Generally, unless you are subject to certain exemptions, all divi-additional information, contact our stock transfer agent. dends on our common or preferred stock are to be considered 100% taxable. SEC Form 10-K Stock Symbol and Exchange Listings Stockholders may obtain a copy of our annual report to the Securities and Exchange Commission on Form 10-K, by con-Ticker Symbok BSE tacting our Investor Relations Department. New York (NYSE) and Boston stock exchanges Quarterly Report to Shareholders 1998 Annual Shareholders Meeting Beneficial owners of our stock whose shares are registered in All shareholders are invited to attend our Annual Meeting on names other than their own may obtain copies of our Quarterly Tuesday, May 5.1998, at i1:00 A.M. at the Boston Back Bay Reports to Shareholders by contacting our Investor Relations Hilton, Second Floor, Belvidere Ballroom,40 Dalton Street, Department. Note that the Annual Report will continue to be Boston, Massachusetts. mailed to beneficial owners directly by their bank or broker. Dividend Payments - Direct Deposit Service investor & Shareholder Contacts Shareholders receiving dividend checks can arrange for electron-Philip J. Lembo ic direct deposit. Transfers are made on the dividend payment Director, Investor Relations dates and confirmation statements are mailed to shareholders. (617) 424-3562 To take advantage of this convenient program, contact our or i stock transfer agent as noted above. Jean M. Carella Dividend Reinvestment and Common Stock Investor Relations Specialist Purchase Plan (617) 424-2658 Our Dividend Reinvestment and Common Stock Purchase Plan Email Address . (the plan) is available to our common and preferred shareholders, ir@bedison.com our residential electric customers and employees. Participants do not pay brokerage fees or commissions related to the purchase of Internet Address [i shares. Some important features of the plan are as follows: www.bostonedison.com h - Optional cash payments invested monthly ( - $50 per month minimum not to exceed $40,000 Company Contact per calendar year Theodora S. Convisser p - Safekeeping of common stock certificates Clerk of the Corporation Beneficial owners of our stock whose shares are registered in Gewal Owes , names other than their own (e.g., a broker or bank nominee) must arrange participation with the record holder. If for any 800 Boylston Street j reason you are unable to arrange participation with your broker Boston, MA 02199-8003 J q or bank nominee, you must become a record holder by having (617) 424-2000 ] I ' the shares transferred to your own name. r.f,
h 'd i & Boston Edison 800 Boylston Street Boston, Massachusetts 02199-8003}}