UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1997
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 1-5139
CENTRAL MAINE POWER COMPANY
(Exact name of registrant as specified in its charter)
Incorporated in Maine 01-0042740
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
83 Edison Drive, Augusta, Maine 04336
(Address of principal executive offices) (Zip Code)
207-623-3521
(Registrant's telephone number including area code)
(Former name, former address and former fiscal year, if changed
since last report.)
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
the filing requirements for at least the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's
classes of Common Stock, as of the latest practicable date.
Shares Outstanding Class
as of July 31, 1997
Common Stock, $5 Par Value 32,442,752
Central Maine Power Company
INDEX
Page No.
Part I. Financial Information
Consolidated Statement of Earnings for the Three Months
Ended June 30, 1997 and 1996 1
Consolidated Statement of Earnings for the Six Months
Ended June 30, 1997 and 1996 2
Consolidated Balance Sheet - June 30, 1997 and
December 31, 1996:
Assets 3
Stockholders' Investment and Liabilities 4
Consolidated Statement of Cash Flows for the Six Months
Ended June 30, 1997 and 1996 5
Notes to Consolidated Financial Statements 6
Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Part II. Other Information 22
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Central Maine Power Company
CONSOLIDATED STATEMENT OF EARNINGS
(Unaudited)
(Dollars in Thousands Except Per Share Amounts)
For the Three Months
Ended June 30,
1997 1996
ELECTRIC OPERATING REVENUES $210,074 $216,358
OPERATING EXPENSES
Fuel Used for Company Generation 6,921 1,884
Purchased Power
Energy 94,837 95,253
Capacity 26,804 24,584
Other Operation 49,518 39,792
Maintenance 8,306 8,226
Depreciation and Amortization 13,520 14,551
Federal and State Income Taxes (3,677) 5,975
Taxes Other Than Income Taxes 7,108 6,825
Total Operating Expenses 203,337 197,090
EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 2,144 1,227
OPERATING INCOME 8,881 20,495
OTHER INCOME (EXPENSE)
Allowance for Equity Funds Used During Construction 256 198
Other, Net 824 1,789
Income Taxes Applicable to Other Income (Expense) (323) (605)
Total Other Income (Expense) 757 1,382
INCOME BEFORE INTEREST CHARGES 9,638 21,877
INTEREST CHARGES
Long-Term Debt 11,128 11,981
Other Interest 1,233 952
Allowance for Borrowed Funds Used During Construction (184) (152)
Total Interest Charges 12,177 12,781
NET INCOME (LOSS) (2,539) 9,096
DIVIDENDS ON PREFERRED STOCK 2,207 2,519
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ (4,746) $ 6,577
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 32,442,752 32,442,752
EARNINGS (LOSS) PER SHARE OF COMMON STOCK $ (0.15) $ 0.20
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $ 0.225 $ 0.225
The accompanying notes are an integral part of these financial statements.
Central Maine Power Company
CONSOLIDATED STATEMENT OF EARNINGS
(Unaudited)
(Dollars in Thousands Except Per Share Amounts)
For the Six Months
Ended June 30,
1997 1996
ELECTRIC OPERATING REVENUES $ 478,441 $ 490,497
OPERATING EXPENSES
Fuel Used for Company Generation 12,526 7,480
Purchased Power
Energy 218,774 212,981
Capacity 59,944 49,053
Other Operation 93,267 82,694
Maintenance 14,623 15,522
Depreciation and Amortization 26,994 28,019
Federal and State Income Taxes 5,877 23,936
Taxes Other Than Income Taxes 14,086 13,815
Total Operating Expenses 446,091 433,500
EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 4,044 3,099
OPERATING INCOME 36,394 60,096
OTHER INCOME (EXPENSE)
Allowance for Equity Funds Used During Construction 502 384
Other, Net 1,444 3,340
Income Taxes Applicable to Other Income (Expense) (571) (1,205)
Total Other Income (Expense) 1,375 2,519
INCOME BEFORE INTEREST CHARGES 37,769 62,615
INTEREST CHARGES
Long-Term Debt 22,342 24,014
Other Interest 2,301 1,948
Allowance for Borrowed Funds Used During Construction (362) (300)
Total Interest Charges 24,281 25,662
NET INCOME 13,488 36,953
DIVIDENDS ON PREFERRED STOCK 4,415 5,037
EARNINGS APPLICABLE TO COMMON STOCK $ 9,073 $ 31,916
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 32,442,752 32,442,752
EARNINGS PER SHARE OF COMMON STOCK $ 0.28 $ 0.98
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $ 0.45 $ 0.45
The accompanying notes are an integral part of these financial
statements.
Central Maine Power Company
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
June 30, Dec. 31,
1997 1996
(Unaudited)
ASSETS
ELECTRIC PROPERTY, at Original Cost $1,652,044 $1,644,434
Less: Accumulated Depreciation 616,466 598,415
Electric Property in Service 1,035,578 1,046,019
Construction Work in Progress 22,376 20,007
Net Nuclear Fuel 1,157 1,157
Net Electric Property and Nuclear Fuel 1,059,111 1,067,183
INVESTMENTS IN ASSOCIATED COMPANIES, at Equity 75,470 67,809
Net Electric Property, Nuclear Fuel and Investments in Associated
Companies 1,134,581 1,134,992
CURRENT ASSETS
Cash and Temporary Cash Investments 27,628 8,307
Accounts Receivable, Less Allowance for Uncollectible
Accounts of $2,526 in 1997 and $4,177 in 1996
Service - Billed 74,163 84,396
- Unbilled 33,412 45,721
Other Accounts Receivable 14,383 17,517
Prepaid Income Taxes 254 264
Inventories, at Average Cost
Fuel Oil 4,856 9,256
Materials and Supplies 11,953 12,172
Funds on Deposit With Trustee 61,694 59,512
Prepayments and Other Current Assets 5,968 9,500
Total Current Assets 234,311 246,645
DEFERRED CHARGES AND OTHER ASSETS
Recoverable Costs of Seabrook 1 and Abandoned Projects, Net 86,807 89,551
Regulatory Assets-Deferred Taxes 241,248 239,291
Yankee Atomic Purchase Power Contract 14,049 16,463
Connecticut Yankee Purchase Power Contract 40,884 45,769
Other Deferred Charges and Other Assets 215,107 238,203
Deferred Charges and Other Assets, Net 598,095 629,277
TOTAL ASSETS $1,966,987 $2,010,914
The accompanying notes are an integral part of these financial statements.
Central Maine Power Company
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
June 30, Dec. 31,
1997 1996
(Unaudited)
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION
Common Stock Investment $ 506,054 $ 511,578
Preferred Stock 65,571 65,571
Redeemable Preferred Stock 53,528 53,528
Long-Term Obligations 544,836 587,987
Total Capitalization 1,169,989 1,218,664
CURRENT LIABILITIES AND INTERIM FINANCING
Interim Financing 70,000 32,500
Sinking-Fund Requirements 16,209 9,375
Accounts Payable 78,870 93,197
Dividends Payable 9,512 9,512
Accrued Interest 11,357 11,610
Miscellaneous Current Liabilities 15,725 21,342
Total Current Liabilities and Interim Financing 201,673 177,536
COMMITMENTS AND CONTINGENCIES
RESERVES AND DEFERRED CREDITS
Accumulated Deferred Income Taxes 363,145 357,994
Unamortized Investment Tax Credits 31,254 31,988
Regulatory Liabilities-Deferred Taxes 53,025 52,616
Yankee Atomic Purchased Power Contract 14,049 16,463
Connecticut Yankee Purchased Power Contract 40,884 45,769
Other Reserves and Deferred Credits 92,968 109,884
Total Reserves and Deferred Credits 595,325 614,714
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $1,966,987 $2,010,914
The accompanying notes are an integral part of these financial statements.
Central Maine Power Company
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (Dollars in Thousands)
(Note 1)
For the Six Months
Ended June 30,
1997 1996
CASH FROM OPERATIONS
Net Income $ 13,488 $ 36,953
Items Not Requiring (Not Providing) Cash:
Depreciation 22,033 22,139
Amortization 16,992 18,050
Deferred Income Taxes and Investment Tax Credits, Net 1,752 5,323
Allowance for Equity Funds Used During Construction (502) (384)
Changes in Certain Assets and Liabilities:
Accounts Receivable 25,676 26,188
Prepaid Accrued Income Taxes 10 1,195
Other Current Assets 3,532 3,825
Inventories 4,619 (1,665)
Accounts Payable (12,151) (35,029)
Accrued Interest (253) (324)
Miscellaneous Current Liabilities (5,617) 4,629
Deferred Energy-Management Costs (267) (409)
Maine Yankee Outage Accrual (10,350) 4,140
Purchased-Power Contracts (75)
Other, Net 5,019 (2,020)
Net Cash Provided By Operating Activities 63,981 82,536
INVESTING ACTIVITIES
Construction Expenditures (18,028) (18,773)
Investments in Associated Companies (5,205) (11,685)
Changes in Accounts Payable - Investing Activities (2,176) (905)
Net Cash Used by Investing Activities (25,409) (31,363)
FINANCING ACTIVITIES
Issuances:
Short Term Revolving Credit Agreement 12,500
Redemptions:
Preferred Stock (14,000)
Mortgage Bonds (11,500)
Medium Term Notes (10,000)
Long-Term Debt (545)
Funds on Deposit with Trustee (2,182) (29,200)
Dividends:
Common Stock (14,609) (14,611)
Preferred Stock (4,415) (5,037)
Net Cash Used by Financing Activities (19,251) (74,348)
Net Increase (Decrease) In Cash 19,321 (23,175)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 8,307 57,677
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 27,628 $ 34,502
The accompanying notes are an integral part of these financial statements.
Central Maine Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Certain information in footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting
principles has been condensed or omitted in this Form 10-Q pursuant to the
rules and regulations of the Securities and Exchange Commission. However, the
disclosures herein should be read with the Annual Report on Form 10-K for the
year ended December 31, 1996 (Form 10-K), and are adequate to make the
information presented herein not misleading.
The consolidated financial statements include the accounts of Central Maine
Power Company (the Company) and its 78 percent-owned subsidiary, Maine
Electric Power Company, Inc. (MEPCO). The Company accounts for its investments
in associated companies not subject to consolidation using the equity method.
The Company's significant accounting policies are contained in Note 1 of Notes
to Consolidated Financial Statements in the Company's Form 10-K. For interim
accounting periods the policies are the same. The interim financial statements
reflect all adjustments that are, in the opinion of management, necessary for
a fair statement of results for the interim periods presented. All such
adjustments are of a normal recurring nature.
The adoption of the Alternative Rate Plan (ARP), effective January 1, 1995,
eliminated the reconcilable fuel clause used under traditional rate-of-return
regulation to account for and collect fuel and purchased-power energy costs.
Fuel revenues are now recorded as they are billed rather than deferred and
reflected in revenues over time periods established by the Maine Public
Utilities Commission (MPUC). The elimination of the fuel-clause results in
higher revenues in the winter months.
For purposes of the statement of cash flows, the Company considers all highly
liquid instruments purchased having maturities of three months or less to be
cash equivalents.
Supplemental Cash Flow Disclosure - Cash paid for the six months ended June
30, 1997 and 1996 for interest, net of amounts capitalized, amounted to $22.7
million and $24.3 million, respectively. Income taxes paid, net of amounts
refunded, amounted to $4.8 million and $18.7 million for the six months ended
June 30, 1997 and 1996. The Company incurred no new capital lease obligations
in either period.
2. Commitments and Contingencies
Maine Yankee Atomic Power Company. As previously reported, the Maine Yankee
Atomic Power Company (Maine Yankee) nuclear generating plant at Wiscasset,
Maine (the Plant) has been shut down since December 6, 1996, and was expected
to remain off-line at least until August 1997. On May 27, 1997, the Board of
Directors of Maine Yankee voted to reduce maintenance-and-repair spending at
the Plant and announced that Maine Yankee was considering permanent closure
based on economic concerns and uncertainty about operation of the Plant; and
on the same day the Maine Yankee Board indicated that it had also been
exploring a sale of the Plant to PECO Energy Company (PECO). For a detailed
discussion of the background of the current shutdown, including events leading
to the Plant's being placed on the "watch list" by the Nuclear Regulatory
Commission (NRC) and other significant regulatory and operational issues,
management changes, and investigations of Maine Yankee by the NRC and the
United States Department of Justice, see the Company's Annual Report on Form
10-K for the year ended December 31, 1996, its Quarterly Report on Form 10-Q
for the quarterly period ended March 31, 1997, and its Current Reports on Form
8-K dated May 15, 1997, and August 1, 1997.
On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently
cease power operations at the Plant and begin the process of decommissioning
the Plant. The formal vote followed an announcement by the Maine Yankee Board
on August 1, 1997, that Maine Yankee and PECO, after two months of intensive
negotiations, had been unable to arrive at "a mutually beneficial framework
for agreement" on a sale of the Plant to PECO. The decision to shut down the
Plant was based on an economic analysis of the costs, risks and uncertainties
associated with operating the Plant compared to those associated with closing
and decommissioning the Plant.
Prior to the shutdown vote the Company had been incurring substantial costs as
its 38-percent share of Maine Yankee costs, as well as additional costs for
replacement power while the Plant has been out of service. During the first
half of 1997 such costs amounted to approximately $67.4 million for the
Company: $31.8 million due to basic operations and maintenance costs, $25.7
million due to replacement power costs and $9.9 million associated with
incremental costs of operations and maintenance. The Maine Yankee Board's
decision to close the Plant should mitigate the costs the Company would
otherwise incur in 1997 through a phasing down of Maine Yankee's operations
and maintenance costs, but will not reduce the need to buy replacement energy
and capacity. The amount of costs for replacement power and energy will vary
during the year based on the Company's power requirements and market
conditions, but the Company expects such costs to be within a range of
approximately $4.5 million to $6 million per month during the remainder of
1997, based on current energy and capacity needs and market conditions. Under
the electric-utility restructuring legislation enacted by the Maine
Legislature in May 1997 the Company's obligation to provide replacement power
will terminate on March 1, 2000, with its other power-supply obligations. In
the interim, the previously reported termination of a major non-utility
generator contract should result in savings to the Company at an annual rate
of approximately $25 million commencing November 1, 1997.
The impact of the nuclear-related costs on the Company will be a major
obstacle to achieving satisfactory results in 1997, despite the approximately
$75 million in annual Maine Yankee-related costs imbedded in the current
determination of the Company's required revenues for ratemaking purposes and
despite success in controlling other operating costs. The higher costs
incurred to date associated with nuclear plant investments and the costs
anticipated to replace energy and capacity needs for the remainder of the
year, as a result of the permanent shutdown of Maine Yankee, will reduce
current year earnings to a level that will trigger the low-earnings bandwidth
provision of the Company's Alternative Rate Plan (ARP). That provision is
activated if actual earnings for 1997 are outside a bandwidth of 350 basis
points above or below a 10.68-percent rate-of-return allowance. A return below
the low end of the range provides for additional revenue through rates equal
to one-half the difference between the actual earned rate of return and the
7.18-percent (10.68 minus 350 basis points) low end of the bandwidth. While
the Company believes the mechanism will be triggered in 1997, it cannot
predict the amount of additional revenues that may ultimately result. In any
case, under the ARP the Company would not be likely to start to receive any
additional revenues before July 1, 1998. In addition, the Company has publicly
stated that it would strive to limit its electricity price increases under the
ARP to a level at or below the rate of inflation through 1999, the last year of
the term of the ARP, in order to attain its goal of price stability. The
Company believes stable prices are essential to its ability to retain and
promote electricity sales.
The Company's 38-percent ownership interest in Maine Yankee's common equity
amounted to $28.3 million as of June 30, 1997, and under Maine Yankee's Power
Contracts and Additional Power Contracts the Company is responsible for 38
percent of the costs of decommissioning the Plant. Maine Yankee has been
collecting decommissioning costs in advance pursuant to a 1994 Federal Energy
Regulatory Commission ("FERC") rate order. Maine Yankee's most recent estimate
of the total costs of decommissioning was $316.6 million (in 1993 dollars), of
which approximately $183 million had been collected as of June 30, 1997. Maine
Yankee is in the process of developing an updated decommissioning cost
estimate, which the Company anticipates will be higher than the 1993 estimate,
and expects to file the revised decommissioning cost study with the FERC in
the fall of 1997 as part of a rate filing reflecting the permanent shutdown of
the Plant. Recent legislation enacted in Maine associated with industry
restructuring provides for recovery of decommissioning expense in the rates of
the transmission and distribution entity as required by federal law, rule or
order. Therefore, the Company will record a liability for its estimated share
of decommissioning costs and a corresponding regulatory asset in the third
quarter.
Maine Yankee has entered into agreements with the holders of over 80 percent
of its outstanding First Mortgage Bonds and its lender banks under which those
bondholders and banks agreed that they would not assert that the voluntary
shutdown of the Plant constituted a covenant violation under the Company's
First Mortgage Indenture or two bank credit agreements and agreed to continue
to maintain Maine Yankee's level of bank borrowings at $67 million, out of
aggregate commitments of $85 million, which Maine Yankee considers adequate
for its needs. The agreements terminate October 31, 1997, by which date Maine
Yankee must reach agreement on restructured debt arrangements reflecting its
decommissioning status. At the same time, Maine Yankee and its sponsors,
including the Company, agreed to amend Maine Yankee's Power Contracts and
Additional Power Contracts, effective upon approval by the FERC, to clarify
and confirm the sponsors' obligations to continue to pay their shares of Maine
Yankee's costs during the decommissioning process. Under the agreements Maine
Yankee must also file the contract amendments with the FERC as part of a rate
proceeding by October 15, 1997.
Higher nuclear-related costs are affecting other stockholders of Maine Yankee
in varying degrees. Bangor Hydro-Electric Company, a Maine-based 7-percent
stockholder, has cited its "deteriorating" financial condition, suspended its
common-stock dividend, and sought expedited rate relief. Maine Public Service
Company, a 5-percent stockholder, cited problems in satisfying financial
covenants in loan documents and reduced its common-stock dividend
substantially in early March 1997. Northeast Utilities (20-percent stock
ownership through three subsidiaries), which is also adversely affected by the
substantial additional costs associated with the three shut-down Millstone
nuclear units and the permanently shut-down Connecticut Yankee unit, as well
as an unfavorable utility deregulation plan in New Hampshire currently under
appeal, announced on March 25, 1997, an indefinite suspension of its quarterly
common-stock dividends, commencing with the dividend that would have been
payable for the quarter ending June 30, 1997. A default by a Maine Yankee
stockholder in making payments under its Power Contract or Capital Funds
Agreement could have a material adverse effect on Maine Yankee, depending on
the magnitude of the default, and would constitute a default under Maine
Yankee's bond indenture and its two major credit agreements unless cured within
applicable grace periods by the defaulting stockholder or other stockholders.
The Company cannot predict, however, what effect, if any, the financial
difficulties being experienced by some Maine Yankee stockholders will have on
Maine Yankee or the Company.
Connecticut Yankee and Millstone - On December 4, 1996, the Board of Directors
of Connecticut Yankee Atomic Power Company voted to permanently shut down the
Connecticut Yankee plant, for economic reasons, and to decommission the unit,
which had not operated after July 22, 1996. The Company has a 6 percent equity
interest in Connecticut Yankee, totaling approximately $6.8 million at June
30, 1997. The Company incurred replacement power costs of approximately $2.5
million in the first half of 1997. The Company estimates its share of the cost
of Connecticut Yankee's continued compliance with regulatory requirements,
recovery of its plant investments, decommissioning and closing the plant to be
approximately $40.9 million and has recorded a regulatory asset and a
liability on its consolidated balance sheet. The Company is currently
recovering through rates an amount adequate to recover these expenses.
The Company has a 2.5 percent ownership interest in Millstone Unit No. 3,
which is operated by Northeast Utilities. This facility has been off-line
since April 1996 due to NRC concerns regarding license requirements and the
Company cannot predict when it will return to service. Millstone Unit No. 3,
along with two other units at the same site owned by Northeast Utilities, is
on the NRC's "watch list" in "Category 3," which requires formal NRC action
before a unit can be restarted. The Company incurred replacement power costs
related to Millstone Unit No. 3 of approximately $2.4 million for the first
half of 1997. For a discussion of a lawsuit and arbitration claim filed by the
Company and other minority owners of Millstone Unit No. 3 against the
operators of the unit, see "Legal and Environmental Matters", below.
Legal and Environmental Matters - The Company is a party in legal and
administrative proceedings that arise in the normal course of business.
Effective January 1, 1997, the Company adopted Statement of Position 96-1,
Environmental Remediation Liabilities. The statement provides requirements and
guidance on specific accounting for recognition, measurement, display and
disclosure of environmental remediation liabilities. As discussed in Note 4 of
Notes to Consolidated Financial Statements in the Company's Form 10-K, in
connection with one such proceeding, the Company has been named a potentially
responsible party (PRP) and has been incurring costs to determine the best
method of cleaning up an Augusta, Maine, site formerly owned by a salvage
company and identified by the Environmental Protection Agency (EPA) as
containing soil contaminated by polychlorinated biphenyls (PCBs) from
equipment originally owned by the Company.
In 1995, the EPA approved a remedy to adjust the soil cleanup standard to a
more easily attainable ten parts per million, after the cleanup method using
solvent extraction was found to be technically infeasible. On July 30, 1996,
the EPA approved the off-site disposal of the contaminated soil at an EPA
licensed secure landfill.
The Company believes that its share of the remaining costs of the cleanup
under the approved remedy could total approximately $2.4 million to $4.2
million. This estimate is net of an agreed partial insurance recovery and the
1993 court-ordered contribution of 41 percent from Westinghouse Electric
Corp., but does not reflect any possible contributions from other insurance
carriers the Company has sued or from any other parties. The Company has
recorded an estimated liability of $2.4 million and an equal regulatory asset,
reflecting an accounting order to defer such costs and the anticipated
ratemaking recovery of such costs when ultimately paid. In addition, the
Company has deferred, as a regulatory asset, $6.2 million of costs incurred
through June 30, 1997.
Other Environmental Sites - The Company has been notified by the Maine
Department of Environmental Protection (MDEP) that it may be a potentially
responsible party at other sites in Maine. The Company has recorded an
estimated liability of $1,155,000 associated with various feasibility studies
and other remedial activities for these other environmental sites.
The Company cannot predict with certainty the level and timing of the cleanup
costs, the extent they will be covered by insurance, or their ratemaking
treatment, but believes it should recover substantially all of such costs
through insurance and rates.
Millstone Unit No. 3 Litigation - On August 7, 1997, the Company and other
minority owners of Millstone Unit No. 3 filed suit in Massachusetts Superior
Court and initiated an arbitration claim against Northeast Utilities, its
trustees, and two of its subsidiaries, alleging mismanagement of the unit by
the defendants. The minority owners are seeking to recover their additional
costs resulting from such mismanagement, including their replacement power
costs. The Company cannot predict the outcome of the litigation and
arbitration.
3. Regulatory and Legislative Matters
Alternative Rate Plan - The MPUC approved the Company's Alternative Rate Plan
(ARP) effective January 1, 1995. Please refer to Note 3 of Notes to
Consolidated Financial Statements included in the Company's Form 10-K for the
year ended December 31, 1996 for a detailed description. The ARP was
established in response to an order by the MPUC to develop a five-year plan
containing price-cap, profit-sharing, and pricing-flexibility components.
Although the ARP is a major reform, the MPUC will continue to regulate the
Company's operations and prices, provide for continued recovery of deferred
costs, and specify a range for its rate of return.
The Company believes, as stated in the MPUC's order approving the ARP, that
operation under the ARP continues to meet the criteria of Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS No. 71). In its order, the MPUC reaffirmed the
applicability of previous accounting orders allowing the Company to reflect
amounts as deferred charges and regulatory assets. As a result, the Company
will continue to apply the provisions of SFAS No. 71 to its accounting
transactions and in its future financial statements.
The ARP contains a mechanism that provides price-caps on the Company's retail
rates to increase annually on July 1, commencing July 1, 1995, by a percentage
combining (1) a price index, (2) a productivity offset, (3) a sharing
mechanism, and (4) flow-through items and mandated costs. The price cap
applies to all of the Company's retail rates, including the Company's
fuel-and-purchased power cost, which previously had been treated separately.
Under the ARP, fuel expense is no longer subject to reconciliation or specific
rate recovery, but is subject to the annual indexed price-cap changes.
The Company believes the ARP provides the benefits of needed pricing
flexibility to set prices between defined floor and ceiling levels in three
service categories: (1) existing customer classes, (2) new customer classes
for optional targeted services, and (3) special-rate contracts. The Company
believes that the added flexibility will position it more favorably to meet
the competition from other energy sources that has eroded segments of its
customer base. Some price adjustments can be implemented upon 30-days' notice
by the Company, while certain others are subject to expedited review by the
MPUC. The Company has utilized this feature in providing new rates to
approximately 25,000 customers representing approximately 40 percent of annual
kilowatt-hour sales and 27 percent of service-area revenues. These reductions
in rates were offered to customers after consideration of associated NUG cost
reductions, savings from further NUG consolidations and other general cost
reductions.
The ARP also contains provisions to protect the Company and ratepayers against
unforeseen adverse results from its operation. These include review by the
MPUC if the Company's actual return on equity falls outside a designated
range, a mid-period review of the ARP by the MPUC in 1997 (including possible
modification or termination), and a "final" review by the MPUC in 1999 to
determine whether or with what changes the ARP should continue after 1999. The
Company submitted its 1997 compliance filing and mid-period review filing in
March 1997 proposing no significant change to the ARP. On June 25, the
commission approved a partial stipulation which allowed a 1.1% increase in
price caps effective July 1, 1997, made minor modifications in the parameters
for pricing flexibility, and increased the midpoint return on equity for the
earnings sharing calculation to 11.5% for the fiscal year 1998. No other
significant changes were made to the ARP.
While the ARP provides the Company with an expanded opportunity to be rewarded
for efficiency, it also presents the risk of reduced rates of return if costs
rise unexpectedly, like those that have resulted from the recent outages at
Maine Yankee, or if revenues from sales decline or are not adequate to fund
costs. The Company believes the ARP continues to be a competitive advantage
for the Company.
On May 29, 1997, the Governor of Maine signed into law a bill enacted by the
Maine Legislature that will restructure the electric utility industry in Maine
by March 1, 2000. The principal restructuring provisions of the legislation
provide for customers to have direct retail access to generation services and
for deregulation of competitive electricity providers, commencing March 1,
2000, with transmission and distribution companies continuing to be regulated
by the MPUC. By that date, subject to possible extensions of time granted by
the MPUC to improve the sale value of generation assets, investor-owned
utilities are required to divest all generation assets and generation-related
business activities, with two major exceptions: (1) non-utility generator
contracts with qualifying facilities and contracts with demand-side management
or conservation providers, brokers or hosts; and (2) ownership interests in
nuclear power plants. However, the MPUC can require the Company to divest its
interest in Maine Yankee Atomic Power Company on or after January 1, 2009. The
Company must submit a plan to the MPUC by January 1, 1999, to divest its
generation assets, but is proceeding with its previously reported plan to sell
its generation assets. The bill also requires investor-owned utilities, after
February 28, 2000, to sell their rights to the capacity and energy from all
generation assets, including the purchased-power contracts that had not
previously been divested pursuant to the legislation, with certain minor
exceptions.
Meeting the Requirements of SFAS No. 71
The Company continues to meet the requirements of SFAS No. 71. The standard
provides specialized accounting for regulated enterprises, which requires
recognition of assets and liabilities that enterprises in general could not
record. Examples of regulatory assets include deferred income taxes associated
with previously flowed through items, NUG buyout costs, losses on abandoned
plants, deferral of postemployment benefit costs, and losses on debt
refinancing. If an entity no longer meets the requirements of SFAS No. 71,
then regulatory assets and liabilities must be written off.
The ARP provides incentive-based rates intended to recover the cost of service
plus a rate of return on the Company's investment together with a sharing of
the costs or earnings between ratepayers and the shareholders should the
earnings be less than or exceed a target rate of return. The Company has
received recognition from the MPUC that the rates implemented as a result of
the ARP continue to provide specific recovery of costs deferred in prior
periods.
The recent legislation enacted in Maine associated with industry restructuring
specifically addressed the issue of cost recovery of regulatory assets
stranded as a result of industry restructuring. Specifically the legislation
requires the Maine Public Utilities Commission, when retail bids begin, to
provide a "reasonable opportunity" for the recovery of stranded costs through
the rates of the transmission and distribution company, comparable to the
utility's opportunity to recover stranded costs before the implementation of
retail access under the legislation. The Company will continue to record
regulatory assets consistent with SFAS No. 71 as long as future recovery is
probable. The Company, based on current generally accepted accounting
principles, anticipates that once a detailed plan for deregulation of
generation is known the application of SFAS No. 71 to the unregulated
generation segment will no longer apply and the Company will be required to
discontinue SFAS No. 71 for any remaining generation segment of its business.
The Company further anticipates, based on current generally accepted accounting
principles, that SFAS No. 71 will continue to apply to the regulated
distribution and transmission segments of its business.
Non-Utility Generators
In April 1997, the Company terminated an agreement with the operator of a
31-megawatt wood-fired power plant. This contract was replaced with a new
agreement which should provide the same amount of energy with an additional 9
megawatts of capacity and fuel savings of approximately $7.5 million over the
next five years.
Effective July 1, 1997, changes were made to a purchased power contract with
the operator of an 18-megawatt wood-fired co-generation facility that will
result in approximate fuel savings of $5.5 million over the term of the
agreement through June 30, 2004. Under the ARP, savings from the restructured
contracts will be divided equally between the Company's ratepayers and
shareowners.
4. Debt Financing
At the annual meeting of the stockholders of the Company on May 15, 1997, the
holders of the Company's outstanding preferred stock consented to the issuance
of $350 million in principal amount of the Company's Medium-Term Notes in
addition to the $150 million in principal amount to which they had previously
consented. This expansion of the Medium-Term Note program is being implemented
to increase the Company's financing flexibility in anticipation of
restructuring and increased competition. As of June 30, 1997, $58 million of
Medium-Term Notes were outstanding which, under the terms of the program, will
permit issuance of an additional $442 million of such notes after receipt of
regulatory approvals. The Company also had $20 million outstanding as of June
30, 1997 under the 364-day Revolving Credit Agreement.
Item 2: Management's Discussion and Analysis of Financial Condition and
Results of Operations
This discussion contains forecast information items that are "forward-looking
statements" as defined in the Private Securities Litigation Reform Act of
1995. All such forward-looking information is necessarily only estimated.
There can be no assurance that actual results will not differ from
expectations. Actual results have varied materially and unpredictably from
expectations.
Factors that could cause actual results to differ materially include, among
other matters, the permanent closure and decommissioning of the Maine Yankee
nuclear generating plant and resulting regulatory proceedings, continuing
outages at the other generating units in which the Company holds interests,
electric utility restructuring, including the ongoing state and federal
activities; future economic conditions; earnings-retention and dividend-payout
policies; developments in the legislative, regulatory, and competitive
environments in which the Company operates; and other circumstances that could
affect anticipated revenues and costs, such as unscheduled maintenance or
repair requirements at nuclear plants and other facilities and compliance with
laws and regulations.
Operating Results
The second quarter of 1997 generated a net loss of $2.5 million compared to
net income of $9.1 million for the corresponding period in 1996. Year-to-date
net income was $13.5 million versus $37.0 million for the 1996 period. Loss
applicable to common stock was $4.7 million or $0.15 per share for the second
quarter of 1997 compared to earnings of $6.6 million or $0.20 per share for
the comparable period in 1996. Year-to-date earnings applicable to common
stock were $9.1 million or $0.28 per share and $31.9 million or $0.98 per
share in 1996. Net income for the first half of 1997 was significantly
impacted ($24.3 million) by increases in repair costs and replacement-power
expenses relating to the Maine Yankee plant and other New England nuclear
units in which the Company holds interests. The costs associated with
replacement power will continue and are expected to be in the range of $4.5
million to $6.0 million per month. Partially offsetting the replacement power
costs are expected reductions in Maine Yankee operations and maintenance costs
associated with the phase-in of the permanent closure of that facility.
Operating revenues in the second quarter of 1997 totaled $210 million, a
decrease of 2.9 percent from $216 million in the second quarter of 1996.
Operating revenues decreased by $12.1 or 2.5 percent to $478 million in the
first half of 1997 from $490.1 million in the first half of 1996. The decline
in revenues is a consequence of the continuing outage of Maine Yankee and
other nuclear generating units in which the Company holds interests. Energy
produced or purchased from other Company sources was used to satisfy service
territory needs and, as a result, significantly less was available for sales
outside the service territory. Compared to the first six months of 1996,
non-territorial sales are down $26 million.
Service-area sales for the second quarter of 1997 totaled approximately 2.23
billion kilowatt-hours, up 1.9 percent from the second quarter of 1996.
Service-area sales of electricity for the first six months of 1997 totaled
approximately 4.67 billion kilowatt-hours for an increase of 1.7 percent
compared to the first six months of 1996.
Service Area Kilowatt-hour Sales (Millions of KWHs)
Period Ended June 30,
Three Months
Six Months
1997 1996 % Change 1997 1996 % Change
Residential 657.1 648.3 1.4% 1,465.0 1,482.6 (1.2)%
Commercial 585.2 572.5 2.2 1,236.9 1,234.4 0.2
Industrial 931.6 914.1 1.9 1,857.2 1,770.5 4.9
Other 52.4 50.5 3.8 111.8 107.3 4.2
2,226.3 2,185.4 1.9 4,670.9 4,594.8 1.7
The changes in service area kilowatt-hour sales reflect the following:
Kilowatt-hour sales to residential customers increased by 1.4 percent
in the second quarter and decreased by 1.2 percent for the six months
ended June 30, 1997 compared to 1996; usage per customer was down 2.2
percent for the six months ended June 30, 1997. Warmer temperatures
during the first quarter of 1997 versus the first quarter of 1996
were primarily responsible for the six-month overall decrease in
sales.
Commercial sales increased by 2.2 percent in the second quarter and
0.2 percent for the six months ended June 30, 1997 as compared to
1996. The increase in the second quarter was due primarily to
increased usage by Maine Yankee during 1997 while the plant is shut
down versus 1996 when it was operating.
Industrial kilowatt-hour sales increased by 1.9 percent in the second
quarter and by 4.9 percent for the six months ended June 30, 1997
compared to 1996. Increase in the paper industry, rebounding from
weak market conditions in 1996, and the expansion of facilities by an
electrical machinery manufacturer are the primary reasons for the
increase over 1996.
MEPCO's electric sales and transmission revenues from New England utilities
other than the Company amounted to $4.3 and $2.4 million in the second quarter
of 1997 and 1996, respectively. The totals for the six months ended June 30,
1997 and 1996 were $8.5 million and $4.1 million, respectively. Under a
Participation Agreement that terminated July 9, 1996, all of MEPCO's costs,
including a return on invested capital, were paid by the participating
utilities (Participants), which included the Company and most of the larger
New England electric companies. The level of MEPCO's revenues and expenses
changes depending upon the level of energy purchases. Effective July 9, 1996,
MEPCO and the Company filed with FERC under FERC Order 888 for new tariff
rates. Refer to "Industry Restructuring and Strandable Costs" below for
further discussion of this matter.
Purchased power-energy expense increased $5.8 million over the first half of
1996, reflecting increased replacement power cost due to the Maine Yankee and
other nuclear outages which continued through the entire first half of 1997.
Purchased power-other expense increased $10.9 million in the first half of
1997 compared to the first half of 1996, principally due to the Maine Yankee
outage throughout the first half of 1997 and increased maintenance expenses
required by the NRC to return the Maine Yankee plant to service.
Other operation expense increased by approximately $9.7 million in the second
quarter and by $10.6 million for the six months ended June 30, 1997 compared
to 1996 The increase is due primarily to a reversal in 1996 of a reserve
established in 1995 and the expense recognition of post-retirement benefits
being collected in rates under the ARP. Maintenance decreased by $0.9 million
through June primarily due to decreased storm activity in 1997 versus 1996.
Federal and state income taxes fluctuate with the level of pre-tax earnings
and the regulatory treatment of taxes by the MPUC. This expense decreased by
$18.1 million as a result of lower pre-tax earnings in the first half of 1997,
when compared to 1996.
Interest on long-term debt during the first half of 1997 decreased by
approximately $1.7 million while other interest expense remained relatively
unchanged compared to 1996. The decrease reflects a lower level of Medium-Term
Notes outstanding than in the first half of 1996.
Liquidity and Capital Resources
Approximately $53.8 million of cash was provided during the first half of 1997
from net income before non-cash items, primarily depreciation and
amortization. During that period, approximately $10.2 million of cash was
generated from fluctuations in certain assets and liabilities and from other
operating activities.
During the first half of 1997, dividends paid on common stock were $14.6
million, while preferred-stock dividends utilized $4.4 million of cash.
Investing activities, primarily construction expenditures, utilized $25.4
million in cash during the first half of 1997 for generating projects,
transmission, distribution, and general construction expenditures and includes
$5.2 million the Company invested primarily in its telecommunication
subsidiary.
In order to accommodate existing and future loads on its electric system the
Company is engaged in a continuing construction program. The Company's plans
for improvements and expansions, its load forecast and its power-supply
sources are under a process of continuing review. Actual construction
expenditures will depend upon the availability of capital and other resources,
load forecasts, customer growth and general business conditions. The ultimate
nature, timing and amount of financing for the Company's total construction
programs, refinancing and energy-management capital requirements will be
determined in light of market conditions, earnings and other relevant factors.
The total of cash on deposit with the Trustee under the Company's General and
Refunding Mortgage Indenture as of June 30, 1997, was approximately $61.7
million. Under the Indenture such cash may be applied, at any time at the
direction of the Company, to the redemption of bonds outstanding under the
Indenture at a price equal to the principal amount of the bonds being
redeemed, without premium, plus accrued interest to the date fixed for
redemption on the principal amount of the bonds being redeemed. Such cash may
also be withdrawn by the Company by substitution of allocated property
additions or available bonds.
At the annual meeting of the stockholders of the Company on May 15, 1997, the
holders of the Company's outstanding preferred stock consented to the issuance
of $350 million in principal amount of the Company's Medium-Term Notes in
addition to the $150 million in principal amount to which they had previously
consented. This expansion of the Medium-Term Note program is being implemented
to increase the Company's financing flexibility in anticipation of
restructuring and increased competition. As of June 30, 1997, $58 million of
Medium-Term Notes were outstanding which, under the terms of the program, will
permit issuance of an additional $442 million of such notes after receipt of
regulatory approvals.
To support its short-term capital requirements, on October 23, 1996, the
Company entered into a $125 million Credit Agreement with several banks, with
The First National Bank of Boston and The Bank of New York acting as agents
for the lenders. The arrangement has two credit facilities: a $75 million,
364-day revolving credit facility that matures on October 22, 1997, and a
$50-million, 3-year revolving credit facility that matures on October 22,
1999. Both credit facilities require annual fees on the total credit lines.
The fees are based on the Company's credit ratings and allow for various
borrowing options including LIBOR-priced, base-rate-priced and
competitive-bid-priced loans. Access to commercial paper markets has been
substantially reduced, if not precluded, as a result of downgrading of the
Company's credit ratings. The amount of outstanding short-term borrowing will
fluctuate with day-to-day operational needs, the timing of long-term
financing, and market conditions. The Company had $20 million outstanding as
of June 30, 1997 under the 364-day Revolving Credit Agreement.
Rating Agency Actions
On May 1, 1997, Moody's Investors Service announced that it had downgraded the
Company's credit ratings. The ratings downgraded were: General and Refunding
Mortgage Bonds to "Baa3" from "Baa2"; unsecured medium-term notes, unsecured
pollution-control revenue bonds, and counterparty rating to "Ba1" from "Baa3";
shelf registration for General and Refunding Mortgage Bonds to "(P)Baa3" from
"(P)Baa2"; and preferred stock to "ba1" from "baa3". The Company's short-term
rating for commercial paper was also downgraded to "Prime-3" from "Prime-2".
Moody's said the downgrades reflected "adverse financial pressures linked to
prolonged nuclear plant outages, especially at the Maine Yankee plant."
Industry Restructuring and Strandable Costs
As discussed in the Management's Discussion and Analysis of Financial
Condition and Results of Operations included in the Company's 1996 Form 10-K,
the enactment by Congress of the Energy Policy Act of 1992 accelerated
planning by electric utilities, including the Company, for a transition to a
more competitive industry. Significant legislative and regulatory steps have
already been taken toward competition in generation and non-discriminatory
transmission access as discussed below. A departure from traditional
regulation, however, could have substantial impacts on the value of utility
assets and on electric utilities' abilities to recover their costs through
rates. In the absence of full recovery, utilities would find their
above-market costs to be "stranded," or unrecoverable, in the new competitive
setting.
The Company has substantial exposure to cost stranding relative to its size.
In its January 1996 filing, the Company estimated its net-present-value
strandable costs could be approximately $2 billion as of January 1, 1996.
These costs represented the excess costs of purchased-power obligations and
the Company's own generating costs over the market value of the power, and the
costs of deferred charges and other regulatory assets. Of the $2 billion,
approximately $1.3 billion was related to above-market costs of
purchased-power obligations, approximately $200 million was related to
estimated net above-market cost of the Company's own generation, and the
remaining $500 million was related to deferred regulatory assets.
The MPUC also provided estimates of strandable costs for the Company, which
they found to be within a wide range of a negative $445 million to a positive
$965 million. These estimates were prepared using assumptions that differ from
those used by the Company, particularly a starting date for measurement of
January 1, 2000 versus the measurement starting date of January 1, 1996
utilized by the Company. The MPUC concluded that there is a high degree of
uncertainty that surrounds stranded costs estimates, resulting from having to
rely on projections and assumptions about future conditions. Given the
inherent uncertainty and volatility of these projections, the Company believes
that an annual estimation of stranded costs could serve to prevent significant
over or under-collection beginning in the year 2000.
Estimated strandable costs are highly dependent on estimates of the future
market for power. Higher market rates lower stranded cost exposure, while
lower market rates increase it. In addition to market-related impacts, any
estimate of the ultimate level of strandable costs depends on state and
federal regulations; the extent, timing and form that competition for electric
service will take; the ongoing level of the Company's costs of operations;
regional and national economic conditions; growth of the Company's sales;
timing of any changes that may occur from state and federal initiatives on
restructuring; and the extent to which regulatory policies ultimately address
recovery of strandable costs.
The estimated market rate for power is based on anticipated regional market
conditions and future costs of producing power. The present value of future
purchased-power obligations and the Company's generating costs reflects the
underlying costs of those sources of generation in place today, with
reductions for contract expirations and continuing depreciation. Deferred
regulatory asset totals include the current uncollected balances and existing
amortization schedules for purchased-power contract restructuring and buyouts
negotiated by the Company to lessen the impact of these obligations, energy
management costs, financing costs, and other regulatory promises. The Company
expects its strandable-cost exposure to decline over time as the market price
of power increases, NUG contracts expire, and regulatory assets are recovered.
Restructuring Legislation
On May 29, 1997, the Governor of Maine signed into law a bill enacted by the
Maine Legislature that will restructure the electric utility industry in Maine
by March 1, 2000. With respect to the ability of the Company to recover
stranded costs, the legislation requires the Maine Public Utilities Commission
(MPUC), when retail access begins, to provide a "reasonable opportunity" to
recover stranded costs through the rates of the transmission and distribution
company, comparable to the utility's opportunity to recover stranded costs
before the implementation of retail access under the legislation. Stranded
costs are defined as the legitimate, verifiable and unmitigatable costs made
unrecoverable as a result of the restructuring required by the legislation and
would be determined by the MPUC as provided in the legislation. The MPUC must
conduct separate adjudicatory proceedings to determine the stranded costs for
each utility and the corresponding revenue requirements and stranded-cost
charges to be charged by each transmission and distribution utility. Those
proceedings must be completed by July 1, 1999.
In addition, the legislation requires utilities to use all reasonable means to
reduce their potential stranded costs and to maximize the value from
generation assets and contracts. The MPUC must consider a utility's efforts to
mitigate its stranded costs in determining the amount of the utility's
stranded costs. Stranded costs will be prospectively adjusted as necessary to
correct substantial inaccuracies in the year 2003 and at least every three
years thereafter.
The principal restructuring provisions of the legislation provide for
customers to have direct retail access to generation services and for
deregulation of competitive electricity providers, commencing March 1, 2000,
with transmission and distribution companies continuing to be regulated by the
MPUC. By that date, subject to possible extensions of time granted by the MPUC
to improve the sale value of generation assets, investor-owned utilities are
required to divest all generation assets and generation-related business
activities, with two major exceptions: (1) non-utility generator contracts
with qualifying facilities and contracts with demand-side management or
conservation providers, brokers or hosts; and (2) ownership interests in
nuclear power plants. However, the MPUC can require the Company to divest its
interest in Maine Yankee Atomic Power Company on or after January 1, 2009. The
Company must submit a plan to the MPUC by January 1, 1999, to divest its
generation assets, but is proceeding with its previously reported plan to sell
its generation assets. See Item 2, "Management's Discussion and Analysis of
Financial Condition and Results of Operations" - "Reorganization and
Divestiture," below. The bill also requires investor-owned utilities, after
February 28, 2000, to sell their rights to the capacity and energy from all
generation assets, including the purchased-power contracts that had not
previously been divested pursuant to the legislation, with certain minor
exceptions.
Upon the commencement of retail access on March 1, 2000, the Company, as a
transmission and distribution utility, will be prohibited from selling
electric energy to retail customers. Any competitive electricity provider that
is affiliated with the Company would be allowed to sell electricity outside
the Company's service territory without limitation as to amount, but within
the Company's service territory the affiliate would be limited to providing
not more than 33 percent of the total kilowatt-hours sold within the Company's
service territory, as determined by the MPUC.
Other features of the legislation include the following:
(a) After the effective date of the legislation, if an entity
purchases 10 percent or more of the stock of a distribution utility, including
the Company, the purchasing entity and any related entity would be prohibited
from selling generation service to any retail customer in Maine.
(b) The legislation encourages the generation of electricity from
renewable resources by requiring competitive providers, as a condition of
licensing, to demonstrate to the MPUC that no less than 30 percent of their
portfolios of supply sources for retail sales in Maine are accounted for by
renewable resources.
(c) The legislation requires the MPUC to ensure that standard-offer
service is available to all consumers, but any competitive provider affiliated
with the Company would be limited to providing such service for only up to 20
percent of the electric load in the Company's service territory.
(d) Beginning March 1, 2002, or, by MPUC rule, as early as March 1,
2000, the providing of billing and metering services will be subject to
competition.
(e) A customer who significantly reduces or eliminates consumption of
electricity due to self-generation, conversion to an alternative fuel, or
demand-side management may not be assessed an exit fee or re-entry fee in any
form for such reduction or elimination of consumption or for the
re-establishment of service with a transmission and distribution utility.
(f) Finally, the legislation provides for programs for low-income
assistance, energy conservation, research and development on renewable
resources, assistance for utility employees laid off as a result of the
legislation, and nuclear-plant decommissioning costs, all funded through
transmission and distribution utility rates and charges.
The Company has stated that it supports the legislation ultimately enacted,
which reflects protracted negotiations and compromises among the interested
constituencies, and will continue to urge securitization of stranded cost
recovery as the most effective method of resolving an issue that is critical
to the Company's future. The Company believes, however, that some of the
limitations imposed on transmission and distribution utilities in the
legislation are unnecessary and inappropriate in the contemplated competitive
environment.
Reorganization and Divestiture
The Company announced a major internal reorganization which became effective
May 1, 1997, in anticipation of industry-wide open competition. The new
structure is organized into four lines of business. The "Energy Services" and
"Distribution Services" groups will operate as strategic business units within
the Company. A "Related Business Group" includes the Company's subsidiaries -
MaineCom Services, Union Water-Power Company, TeleSmart, and CMP International
Consultants. The "Operations Support Division" will include most of the
departments that provide support services to the other three lines of
business. The reorganization is expected to better position the Company to
succeed in a competitive marketplace, and is consistent with the restructuring
legislation currently pending.
On April 28, 1997, the Company announced a plan to seek proposals to purchase
its generation assets, including interests in nuclear plants and rights to
power under NUG contracts. The Company believes that current market conditions
may offer advantages to seeking proposals before divestiture is required by
legislation. Several other utilities, including New England Electric System
(NEES) in Massachusetts, are in the process of divestiture of their generation
assets with a large number of prospective purchasers expressing interest in
acquiring the facilities. On August 6, 1997, NEES announced that it had agreed
to sell its non-nuclear generating business to an affiliate of PG&E Corp.
(U.S. Generating Company) for $1.59 billion, which is approximately 44% above
NEES' reported book value of the assets.
In early June, the Company, working with its investment advisors, developed
and contacted a group of approximately 150 potential bidders that are believed
to be interested in the Company's generation assets and financially qualified
to bid. Non-binding bids are scheduled to be submitted in early September. At
that time, the Company will begin a process of working with a smaller group of
qualified buyers. The potential consummation of a sale will extend into late
1998 and is subject to regulatory approvals. The Company does not intend to
sell its generation assets if terms satisfactory to the Company cannot be
arranged. The Company cannot predict whether such a sale will occur, whether
it will receive satisfactory proposals, or whether the necessary approvals
will be obtained.
On July 21, 1997 the Company and New York State Electric and Gas Corp. signed
a memorandum of understanding that could lead to formation of a new
natural-gas distribution company to serve Maine customers. The Company has
asked the MPUC for permission to offer natural-gas distribution service to
Maine customers in areas not currently served by a natural-gas provider.
Various regulatory approvals would be required before the Company or a jointly
owned company could operate a new gas distribution service.
Open-Access Transmission Service Rule
On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued
Order No. 888, which requires all public utilities that own, control or
operate facilities used for transmitting electric energy in interstate
commerce to file open access non-discriminatory transmission tariffs that
offer both load-based, network and contract-based, point-to-point service,
including ancillary service to eligible customers containing minimum terms and
conditions of non-discriminatory service. This service must be comparable to
the service they provide themselves at the wholesale level; in fact, these
utilities must take wholesale transmission service they provide themselves
under the filed tariffs. The order also permits public utilities and
transmitting utilities the opportunity to recover legitimate, prudent and
verifiable wholesale stranded costs associated with providing open access and
certain other transmission services. It further requires public utilities to
functionally separate transmission from generation marketing functions and
communications. The intent of this order is to promote the transition of the
electric utility industry to open competition. Order No. 888 also clarifies
federal and state jurisdiction over transmission in interstate commerce and
local distribution and provides for deference of certain issues to state
recommendations.
On July 9, 1996, the Company and MEPCO submitted compliance filings to meet
the new pro forma tariff non-price minimum terms and conditions of
non-discriminatory transmission. Since July 9, 1996, the Company and MEPCO have
been transmitting energy pursuant to their filed tariffs, subject to refund.
FERC subsequently issued Order No. 888-A which generally reaffirmed Order No.
888 and clarified certain terms.
Also on April 24, 1996, FERC issued Order No. 889 which requires public
utilities to functionally separate their wholesale power marketing and
transmission operation functions and to obtain information about their
transmission system for their own wholesale power transactions in the same way
their competitors do through the Open Access Same-time Information System
(OASIS). The rule also prescribed standards of conduct and protocols for
obtaining the information. The standards of conduct are designed to prevent
employees of a public utility engaged in marketing functions from obtaining
preferential information. The Company participated in efforts to develop a
regional OASIS, which was operational January 3, 1997. FERC subsequently
approved a New England Power Pool-wide Open Access Tariff, subject to refund
and issuance of further orders. The Company also participated in revising the
New England Power Pool Agreement.
On April 23, 1997, a representative of Kennebunk Light & Power District and
Fox Islands Electric Cooperative, two wholesale customers of the Company,
notified the Company that the two customers were terminating their power
supply contracts with the Company, effective May 1, 1999, and would begin
purchasing power from another supplier on that date. The two customers
currently account for less than 0.5 percent of the Company's annual revenues.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Regulatory Matters. For a discussion of certain significant regulatory matters
affecting the Company, including those leading to a decision by the Maine
Yankee Board of Directors to permanently shut down the Maine Yankee Plant,
electric-utility restructuring, and stranded costs, see Note 2, "Commitments
and Contingencies" - "Maine Yankee Atomic Power Company," and Item 2 of Part
I, "Management's Discussion and Analysis of Financial Condition and Results of
Operation" - "Industry Restructuring and Strandable Costs," which are
incorporated herein by reference.
Environmental Matters. For a discussion of administrative and judicial
proceedings concerning cleanup of a site containing soil contaminated by PCB's
from equipment originally owned by the Company, see Note 2, "Commitments and
Contingencies," "Legal and Environmental Matters," which is incorporated
herein by reference.
Item 2. through Item 3. Not applicable
Item 4. Submission of Matters to a Vote of Security Holders
The annual meeting of the stockholders of the Company was held on May 15,
1997. Proxies for the meeting were solicited pursuant to Regulation 14 under
the Securities Exchange Act of 1934. There was no solicitation in opposition
to the management's nominees as listed in the proxy statement, and all of such
nominees were elected.
Four matters were voted on at the meeting. One was the election of four
directors to Class I of the Company's Board of Directors for a three-year
term. All four nominees were elected, with the following vote tabulations:
Charles H. Abbott
Votes for - 2,447,257
Votes withheld - 66,665
William J. Ryan
Votes for - 2,445,432
Votes withheld - 68,490
Kathryn M. Weare
Votes for - 2,445,417
Votes withheld - 68,505
Lyndel J. Wishcamper
Votes for - 2,448,065
Votes withheld - 65,857
Three other matters voted on at the meeting were:
1. Approval of the appointment of Coopers & Lybrand L.L.P., Boston,
Massachusetts, as the Company's auditors for the year 1997. The appointment
was approved, with the following vote tabulations:
Votes for - 2,473,785
Against - 19,071
Abstentions - 21,066
2. A Company proposal to amend its Long-Term Incentive Plan. The proposal
was approved, with the following vote tabulations:
Votes for - 1,922,511
Against - 530,669
Abstentions - 60,742
3. A Company proposal to consent to an increase in the existing unsecured
Medium-Term Note Program. The proposal was approved, with the following vote
tabulations:
Votes for - 687,608
Against - 129,875
Abstentions - 14,211
Broker nonvotes - 704
Item 5. Not Applicable.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits. None.
(b) Reports on Form 8-K. The Company filed the following reports
on Form 8-K during the first quarter of 1997 and thereafter
to date:
Date of Report Items Reported
May 15, 1997 Item 5
a) The Board of Directors of Maine Yankee voted to reduce maintenance and
repair spending at the plant and announced that Maine Yankee was
considering permanent closure based on economic concerns and uncertainty
about operation of the plant.
b) On May 29, 1997, the governor of Maine signed into law a bill enacted by
the Maine Legislature that will restructure the electric utility industry
in Maine by March 1, 2000.
c) At the annual meeting of the stockholders of the Company on May 15,
1997, the holders of the Company's outstanding preferred stock consented
to the issuance of $350 million in principal amount of the Company's
Medium-Term Notes in addition to the $150 million in principal amount to
which they had previously consented.
Signatures
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.
CENTRAL MAINE POWER COMPANY
(Registrant)
Date: August 14, 1997
By
Michael W. Caron,
Comptroller (Chief Accounting Officer)
By
David E. Marsh, Chief Financial Officer
(Principal Financial Officer and duly
authorized officer)