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 September 30, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period _________________ to ___________________
Commission File Number 0-8480
EASTERN EDISON COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1123095
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
750 W. Center Street, West Bridgewater, Massachusetts
(Address of principal executive offices)
02379
(Zip Code)
(508)559-1000
(Registrant's telephone number including area code)
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 common stock, as of the latest practical date.
Class Outstanding at October 31, 1997
Common Shares, $25 par value 2,891,357 shares
<TABLE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
ASSETS September 30, December 31,
1997 1996
<S> <C> <C>
Utility Plant in Service $ 813,861 $ 815,187
Less: Accumulated Provision for Depreciation
and Amortization 276,188 261,464
Net Utility Plant in Service 537,673 553,723
Construction Work in Progress 10,431 2,805
Net Utility Plant 548,104 556,528
Current Assets:
Cash and Temporary Cash Investments 1,546 2,105
Accounts Receivable - Other 37,337 39,473
- Associated Companies 14,916 25,486
Fuel, Materials and Supplies 8,085 10,649
Other Current Assets 4,935 3,598
Total Current Assets 66,819 81,311
Deferred Debits and Other Non-Current Assets 167,700 137,243
Total Assets $ 782,623 $ 775,082
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Stock, $25 Par Value $ 72,284 $ 72,284
Other Paid-In Capital 47,249 47,249
Common Stock Expense (44) (44)
Retained Earnings 100,184 120,724
Total Common Equity 219,673 240,213
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (2,197) (2,630)
Long-Term Debt - Net 162,469 222,402
Total Capitalization 409,610 489,650
Current Liabilities:
Long - Term Debt Due Within One Year 60,000
Notes Payable 3,000 2,040
Accounts Payable - Associated Companies 7,105 3,950
- Other 25,137 27,391
Taxes Accrued 2,982 2,977
Interest Accrued 4,707 4,895
Other Current Liabilities 17,234 17,234
Total Current Liabilities 120,165 58,487
Deferred Credits and Other Non-Current Liabilities 112,447 84,506
Accumulated Deferred Taxes 140,401 142,439
Total Liabilities and Capitalization $ 782,623 $ 775,082
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(In Thousands)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1997 1996 1997 1996
<S> <C> <C> <C> <C>
Operating Revenues $ 109,971 $ 101,671 $ 324,275 $ 298,537
Operating Expenses:
Fuel 29,277 25,903 82,408 66,558
Purchased Power 28,134 27,463 90,798 86,034
Other Operation and Maintenance 27,698 23,798 77,379 69,298
Early Retirement Offer 0 0 737 0
Depreciation and Amortization 6,891 6,734 20,672 20,192
Taxes - Other Than Income 2,608 2,535 8,276 8,183
Income Taxes - Current 3,680 3,118 14,251 11,464
- Deferred (Credit) (30) 580 (3,770) 636
Total 98,258 90,131 290,751 262,365
Operating Income 11,713 11,540 33,524 36,172
Allowance for Other Funds
Used During Construction 111 138 170 233
Other Income - Net 366 1,790 1,972 2,766
Income Before Interest Charges 12,190 13,468 35,666 39,171
Interest Charges:
Interest on Long-Term Debt 3,752 3,809 11,255 11,482
Other Interest Expense 941 899 2,739 2,667
Allowance for Borrowed Funds Used
During Construction (Credit) (35) (150) (131) (290)
Net Interest Charges 4,658 4,558 13,863 13,859
Net Income 7,532 8,910 21,803 25,312
Preferred Dividend Requirements 497 497 1,491 1,491
Consolidated Net Earnings $ 7,035 $ 8,413 $ 20,312 $ 23,821
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Nine Months Ended
September 30,
1997 1996
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 21,803 $ 25,312
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 21,471 21,398
Amortization of Nuclear Fuel 880 1,310
Deferred Taxes (3,949) 586
Investment Tax Credit, Net (702) (704)
Allowance for Other Funds Used During Construction (170) (233)
Other - Net (1,959) (2,446)
Change in Operating Assets and Liabilities 14,651 15,880
Net Cash Provided From Operating Activities 52,025 61,103
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (11,635) (19,986)
Net Cash (Used in) Investing Activities (11,635) (19,986)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemption:
Long-Term Debt (7,000)
Common Stock Dividends Paid to EUA (40,419) (25,646)
Preferred Dividends Paid (1,490) (1,491)
Net Decrease (Increase) in Short-Term Debt 960 (4,158)
Net Cash (Used in) Financing Activities (40,949) (38,295)
Net (Decrease) Increase in Cash and Temporary
Cash Investments (559) 2,822
Cash and Temporary Cash Investments at
Beginning of Period 2,105 533
Cash and Temporary Cash Investments at
End of Period $ 1,546 $ 3,355
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 10,451 $ 11,665
Income Taxes $ 15,518 $ 7,346
See accompanying notes to consolidated condensed financial statements.
</TABLE>
EASTERN EDISON COMPANY
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
The accompanying Notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in Eastern Edison Company's
(Eastern Edison or the Company) 1996 Annual Report on Form 10-K and the
Company's Quarterly Report on Form 10-Q for the periods ended March 31, and
June 30, 1997.
Note A - In the opinion of the Company, the accompanying unaudited
consolidated condensed financial statements contain all adjustments
(consisting of only normal recurring accruals) necessary to present
fairly the financial position as of Sept ember 30, 1997 and December
31, 1996, and the results of operations for the three and nine months
ended September 30, 1997 and 1996 and cash flows for the nine months
ended September 30, 1997 and 1996.
In June 1997 the FASB issued Statement No. 130, "Reporting
Comprehensive Income", which establishes standards for reporting
comprehensive income and its components (revenues, expenses, gains,
and losses) in a set of general-purpose financial statements. This
Statement requires that all items that are required to be recognized
under accounting standards as components of comprehensive income be
reported in a financial statement that is displayed with the same
prominence as other financial statements. This Statement is
effective for fiscal years beginning after December 15, 1997, and the
Company will adopt Statement 130 in the first quarter of 1998.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent 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 those estimates.
Note B - Results shown above for the respective interim periods are not
necessarily indicative of results to be expected for the fiscal years
due to seasonal factors which are inherent in electric utilities in
New England. A greater proportionate amount of revenues is earned in
the first and fourth quarters (winter season) of most years because
more electricity is sold due to weather conditions, fewer day-light
hours, etc.
Note C - Commitments and Contingencies:
Recent Nuclear Regulatory Commission (NRC) Actions
Millstone III:
Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw
nuclear unit that is jointly owned by a number of New England
utilities, including subsidiaries of Northeast Utilities (Northeast).
Northeast is the lead participant in Millstone III. On March 30,
1996, it was necessary to shut down the unit following an engineering
evaluation which determined that four safety-related valves would not
be able to perform their design function during certain postulated
events.
The NRC has raised numerous issues with respect to Millstone III and
certain of the other nuclear units in which Northeast and its
subsidiaries, either individually or collectively, have the largest
ownership shares, including Connecticut Yankee (see "Connecticut
Yankee" below).
In October 1996, the NRC informed Northeast that it was establishing
a Special Projects Office to oversee inspection and licensing
activities at Millstone. The Special Projects Office is responsible
for (1) licensing and inspection activities at Northeast's
Connecticut plants, (2) oversight of an Independent Corrective Action
Verification Program (ICAVP), (3) oversight of Northeast's corrective
actions related to safety issues involving employee concerns, and (4)
inspections necessary to implement NRC oversight of the plants'
restart activities. Also, the NRC directed Northeast to submit a
plan for disposition of safety issues raised by employees and retain
an independent third-party to oversee implementation of this plan.
In March of 1997, Northeast announced that Millstone III had been
designated as the lead unit in the recovery process of the three
Millstone nuclear units that are currently out of service. Millstone
III is the largest of the three units currently out of service, and
its return to service will most benefit the energy needs of the New
England region.
In September 1997, Northeast announced that it will delay its request
to the NRC to restart Millstone III until January 1998, at the
earliest. As a result of recent NRC questions as to the status of
Millstone III's restart activities, it was noted that various
technical issues had not yet been resolved.
On October 23, 1997, Northeast presented a revised 1997 budget for
Millstone III which included significant increases in operation and
maintenance (O&M) expenses. Montaup's share of the revised O&M
budget is approximately $11.6 million, approximately $5.6 million
more than originally expected and $3.8 million more than O&M
expenditures in 1996.
While Millstone III is out of service, Montaup will incur incremental
replacement power costs estimated at $0.4 million to $0.8 million per
month. Montaup bills its replacement power costs through its fuel
adjustment clause, a wholesale tariff jurisdictional to the Federal
Energy Regulatory Commission (FERC). However, there is no comparable
clause in Montaup's FERC-approved rates which at this time would
permit Montaup to recover its share of the incremental operation and
maintenance costs incurred by Northeast.
Montaup pays its share of Millstone III's O&M expenses on a
reservation of right basis. The fact that Montaup makes payment for
these expenses is not an admission of financial responsibility for
expenses incurred or to be incurred due to the outage.
In August of 1997, nine non-operating owners, including Montaup, who
together own approximately 19.5% of Millstone III, filed a demand
for arbitration against Connecticut Light and Power (CL&P) and
Western Massachusetts Electric Company (WMECO) as well as lawsuits
against Northeast and its Trustees. CL&P and WMECO, owners of
approximately 65% of Millstone III, are Northeast subsidiaries which
agreed to be responsible for the proper operation of the unit.
The non-operating owners of Millstone III claim that Northeast and
its subsidiaries failed to comply with NRC regulations, failed to
operate the facility in accordance with good utility operating
practice and attempted to conceal their activities from the non-
operating owners and the NRC. The arbitration and lawsuits seek to
recover costs associated with replacement power and O&M costs
resulting from the shutdown of Millstone III. The non-operating
owners conservatively estimate that their losses will exceed $200
million.
The Company cannot predict the ultimate outcome of the NRC inquiries
or legal proceedings brought against CL&P, WMECO and Northeast or the
impact which they may have on Montaup and the EUA System.
Connecticut Yankee:
Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July
1996 because of issues related to certain containment air
recirculation and service water systems. Montaup has a 4.5% equity
ownership in Connecticut Yankee with a book value of $ 5.3 million at
September 30, 1997.
In October 1996, Montaup, as one of the joint owners, participated in
an economic evaluation of Connecticut Yankee which recommended
permanently closing the unit and replacing its output with less
expensive energy sources. In December 1996, the Connecticut Yankee
Board of Directors voted to retire the generating station.
Connecticut Yankee certified to the NRC that it had permanently
closed power generation operations and removed fuel from the reactor.
Connecticut Yankee has two years to submit its decommissioning plan
to the NRC. The preliminary estimate of the sum of future payments
for the permanent shutdown, decommissioning, and recovery of the
remaining investment in Connecticut Yankee, is approximately $758
million. The recovery of this estimated amount, elements of which
have been disputed by certain intervening parties, is subject to
approval of FERC. Montaup's share of the total estimated costs is
$34.1 million and is included with Other Liabilities on the
Consolidated Balance Sheet for the periods ending September 30, 1997
and December 31, 1996. Also, due to anticipated recoverability, a
regulatory asset has been recorded for the same amount and is
included with Other Assets. Montaup cannot predict the ultimate
outcome of FERC's review.
Maine Yankee:
On August 6, 1997, as the result of an economic evaluation, the Board
of Directors voted to permanently close the Maine Yankee nuclear
plant. Montaup has a 4.0% equity ownership in Maine Yankee with a
book value of approximately $3.1 million at September 30, 1997. The
present estimate of the sum of future payments for the permanent
shutdown, decommissioning, and recovery of the remaining investment
in Maine Yankee, is approximately $930 million. The recovery of this
estimated amount is subject to approval of FERC. Montaup's share of
the total estimated costs is $37.2 million and is included with Other
Liabilities on the Consolidated Balance Sheet for the period ending
September 30, 1997. Also, due to anticipated recoverability, a
regulatory asset has been recorded for the same amount and is
included with Other Assets. Montaup cannot predict the ultimate
outcome of FERC's review.
In November 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy)
signed an agreement to renew the contract for Entergy to provide
management services to Maine Yankee. Entergy will provide management
services for the initial decommissioning of Maine Yankee activities
through September 30, 1998.
Also, as a result of the August 1997 shutdown, Montaup and the other
equity owners have been notified by the Secondary Purchasers that
they will no longer make payments for purchased power to Maine
Yankee. The Secondary Purchase Contracts a re between the equity
owners as a group and 30 municipalities throughout New England.
Presently, the equity owners are making the payments to Maine Yankee
to cover these unrecovered costs from the municipals. Montaup and
the other equity owners will seek payment from the municipals, but
cannot predict the outcome of this contract issue at this time.
Yankee Atomic Electric Company (Yankee Atomic):
Montaup holds a 4.5% equity ownership in Yankee Atomic. In October
1997, Yankee Atomic announced that it had accepted a Duke
Engineering and Services (DE&S) Letter of Intent to acquire Yankee
Atomic's Nuclear Services Division. Yankee Atomic indicated it was
seeking a purchaser with a long-term commitment to excellence in
nuclear operations and support services that would continue to
provide that level of service to its affiliated New England nuclear
plants. Yankee Atomic's plan is to continue as a smaller
organization responsible for the completion of the safe and effective
decommissioning of the Yankee Nuclear Power Plant in Rowe,
Massachusetts. Details of the acquisition have not yet been
released.
General:
Recent actions by the NRC, some of which are cited above, indicate
that the NRC has become more critical and active in its oversight of
nuclear power plants. The Company is unable to predict at this
time, what, if any, ramifications these NRC actions will have on any
of the other nuclear power plants in which Montaup has an ownership
interest or power contract.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following is Management's discussion and analysis of certain
significant factors affecting the Company's earnings and financial condition
for the interim periods presented in this Form 10-Q.
Overview
Consolidated Net Earnings for the three and nine months ended September
30, 1997 were approximately $7.0 million and $20.3 million, respectively, as
compared to $8.4 million and $23.8 million for the respective periods of a year
ago. The yea r-to-date period of 1997 includes a one-time, after-tax charge of
approximately $500,000, related to the June 1997 early retirement offer
accepted by a group of employees who were eligible but not offered a Voluntary
Retirement Incentive offer completed in 1995.
Kilowatthour Sales
Retail kWh sales increased 1.6% in the third quarter of 1997 compared
to the third quarter of 1996. For the year-to-date period, retail sales were
relatively flat compared to those of the same period of 1996.
Operating Revenues
Operating Revenues increased $8.3 million or 8.2% and $25.7 million or
8.6% in the three and nine month periods ended September 30, 1997,
respectively, as compared to the same periods of 1997. These increases were
due to recoveries of increased purchased power, fuel and conservation and load
management (C&LM) expenses aggregating approximately $5.1 million and $21.1
million for these respective periods. Also impacting revenues in both periods
were increased base rate recoveries and increased short-term contract demand
sales.
Operations Expense
Fuel expense increased by approximately $3.4 million or 13.0% and $15.9
million or 23.8% for the third quarter and year-to-date periods of 1997,
respectively, as compared to the same periods of 1996. Outages of nuclear
units in this year's third quarter and year-to-date period contributed to a
greater dependance on higher cost fossil fuels for energy requirements,
resulting in increases in average fuel costs of 9.0% and 20.9% for the
respective periods. Also impacting fuel expense were increases in total energy
generated and purchased of 3.1% for the third quarter of 1997 and 5.4% for the
year-to-date period as compared to the same periods of 1997.
Purchased Power demand expense for the third quarter of 1997 increased
approximately $700,000 or 2.4% and $4.8 million or 5.5% for the nine months
ended September 30, 1997. The third quarter and year-to-date changes are
primarily due to the impact of a prior period refund to retail customers from
the Pilgrim Nuclear Unit of approximately $2.0 million recorded in the third
quarter of 1997, and increased billings from the Maine Yankee unit offset by
decreased billings from Connecticut Yankee and the Ocean State Power Projects.
Other Operation and Maintenance expenses increased by approximately
$3.9 million or 16.3% and $8.1 million or 11.7% for the third quarter and the
nine months ended September 30, 1997, respectively, from the same periods in
1996. The third quarter change was primarily due to incremental expenses
related to the Millstone III outage of approximately $1.6 million, increased
legal expenses of approximately $1.2 million and increased conservation and
load management (C&LM) expenses of approximately $1.0 million. For the year-
to-date period, jointly owned unit expenses increased approximately $5.9
million, $3.5 of which relates to the Millstone
III outage. In addition, legal expenses increased $1.4 million and C&LM
expenses increased b y $1.0 million for the period.
Other Income (Deductions) - Net
Other Income and (Deductions)-Net decreased $1.4 million in this year's
third quarter and approximately $800,000 in the year-to-date period as compared
to the same periods of 1996. The third quarter and year to date decreases are
due primarily to gains from the 1996 sale of Seabrook II equipment jointly
owned by Montaup. The year-to-date decrease was offset somewhat by interest
income allocated to the Company by EUA Service Corporation related to the
favorable resolution of a Massachusetts corporate income tax dispute in the
first quarter of 1997.
Liquidity and Sources of Capital
Eastern Edison's and Montaup's need for permanent capital is primarily
related to the construction of facilities required to meet the needs of their
existing and future customers.
Traditionally, cash construction requirements not met with internally
generated funds are obtained through short-term borrowings which are ultimately
funded with permanent capital. In July 1997, several EUA System companies
entered into a three-year revolving credit agreement with various financial
institutions allowing for borrowings in aggregate of up to $75 million. At
September 30, 1997 under the revolving credit agreement the EUA System had
short-term borrowings available of approximately $17.6 million. The Company
had $3.0 million of outstanding short-term debt at September 30, 1997.
The Company's year-to-date September 30, 1997 internally generated
funds amounted to $13.4 million while its cash construction requirements for
the same period were $11.6 million.
Electric Utility Industry Restructuring
On August 7, 1996, the Governor of Rhode Island signed into law the
Utility Restructuring Act of 1996 (URA). The URA provides for customer choice
of electricity supplier to be phased-in commencing July 1, 1997 for large
manufacturing customers, certain new commercial and industrial customers, and
State of Rhode Island accounts. In addition to State of Rhode Island accounts,
11 customers of Blackstone and one customer of Newport were eligible for choice
commencing July 1, 1997. As of November 1, 1997, in addition to certain State
of Rhode Island accounts, eleven customers exercised their right to choose an
alternate supplier of electricity. By July 1, 1998, or sooner, all customers
will have retail access. Under the URA the local distribution company will
retain the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory. For customers
who do not choose an alternative supplier, the local distribution company will
arrange for supply at a non-discriminatory, "standard offer" price.
Distribution companies will also be providers of last resort, required to
arrange for supply at prevailing market prices for customers who are unable to
obtain their own supply.
The URA provides for full recovery of prudently incurred embedded
generation costs that might not be recovered in a competitive electric
generation market, commonly referred to as "stranded costs," through a non-
bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000. The transition charge recovers, among other things, costs
of depreciated generation, net of its market value, regulatory assets, nuclear
decommissioning costs and above- market payments t o power suppliers. The
costs of net, above-market generation assets and regulatory assets will be
recovered, with a return, through a fixed component of the transition charge
from July 1, 1997, through December 31, 2009. A variable component of the
transition charge will recover, on a reconciling basis, among other things,
nuclear decommissioning and above market purchased power commitments from July
1, 1997, through the life of the respective unit or contract. The URA also
provides for commitments to demand side management initiatives and renewables,
low-income customer protections, divestiture of at least 15% of owned non-
nuclear generating units as a valuation basis for mitigation of stranded cost
recovery, and performance based rate -making standards for electric
distribution companies. These performance based standards provide for a 6%
minimum and an approximate 12% maximum allowed return on equity for Blackstone
and Newport, EUA's Rhode Island Distribution Companies (R.I. Distribution
Companies). In addition, the URA provides for adjustments to electric
distribution companies' base rates using the prior year's Consumer Price Index
and other performance factors. Under this provision of the law, base rates
were increased 1.88% for customers of Blackstone, and 2.18% for our Newport
customers effective January 1, 1997.
In June 1997, Legislation was enacted in Rhode Island, which would
allow securitization of utilities' stranded assets, a method of providing
savings to customers.
The implementation of the URA requires approvals from applicable
regulatory agencies, including the Federal Energy Regulatory Commission (FERC),
the Rhode Island Public Utilities Commission (RIPUC), and the Securities and
Exchange Commission (SEC).
In February 1997, Blackstone, Newport and Montaup reached a settlement
in principle with the Rhode Island Division of Public Utilities and Carriers
(RIDIV) and the state's Attorney General and filed a Memorandum of
Understanding (MOU) with the RIPUC in March 1997 outlining the terms of the
settlement. In addition to complying with the URA, the settlement provides for
an immediate 10% rate reduction and the filing of a plan to divest all of
Montaup's generating assets, and is similar in many respects to the settlement
negotiated in Massachusetts, described below.
On December 23, 1996, Eastern Edison and Montaup reached an agreement
in principle with the Attorney General of Massachusetts and the Massachusetts
Department of Energy Resources (MADOER) and filed a MOU with the Massachusetts
Department of Public Utilities (MDPU) outlining the terms of a plan, similar in
many aspects to the URA, which would allow retail customers to choose their
supplier of electricity in 1998 and provide Eastern Edison and Montaup full
recovery of "stranded costs." On May 16, 1997 an Offer of Settlement was filed
with the MDPU. Hearings on the Offer of Settlement concluded in July 1997 and
a MDPU decision is expected by year-end 1997.
The Offer of Settlement envisions that all of Eastern Edison's
customers will have the ability to choose an alternative supplier of
electricity beginning as soon as January 1, 1998. Until a customer chooses an
alternative supplier, that customer would receive "standard offer" service
which would be priced to guarantee at least a 10% savings from today's
electricity rates. Eastern Edison would be required to arrange for "standard
offer" service and would purchase power for "standard offer" service from
suppliers through a competitive bidding process. The agreement is also
designed to achieve full divestiture of Montaup's generating assets via
implementation of a plan, that would require (1) separation by Montaup of its
generating and transmission businesses, and (2) full market valuation and sale
of all generating assets through an auction or equivalent process.
Upon the commencement of retail choice in Massachusetts, Montaup's FERC
approved, all-requirements wholesale contract with Eastern Edison would be
terminated. In its place, Montaup will bill Eastern Edison a Contract
Termination Charge (CTC) designed to recover the cost of Montaup's above
market, embedded generation commitments to serve Eastern Edison's customers,
with a return. Eastern Edison will recover the CTC through a non-bypassable
transition access charge to all of its distribution customers. The transition
access charge would be reduced by the fair market value of Montaup's
generating assets as determined by selling, spinning off, or otherwise
disposing of such generating facilities.
Embedded costs associated with generating plants and regulatory assets
would be recovered, with a return, over a period of 12 years. Purchased power
contracts and nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond 12 years.
The initial transition access charge would be set at 3.04 cents per kWh through
December 31, 2000, and is expected to decline thereafter.
The agreement also establishes performance-based regulation for Eastern
Edison, incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates would be frozen until December
31, 2000. Sub sequent to the commencement of retail choice, Eastern Edison's
annual return on equity would be subject to a floor of 6% and a ceiling of
11.75%.
In addition to MDPU approval of the Offer of Settlement, implementation
is also subject to the approval of FERC. Elements of the Offer of Settlement
which fall under the jurisdiction of FERC were filed with FERC on May 30, 1997
and await review. Any disposition of generation assets resulting from the
agreements or the URA would also require the approval of the SEC under the
Public Utility Holding Company Act of 1935.
On May 1, 1997, Montaup and the R.I. Distribution Companies jointly
filed amendments to the FERC-approved all-requirements power contracts between
Montaup and the R.I. Distribution Companies, respectively, with FERC. The
filing included a calculation for a CTC to recover stranded costs and a
provision for standard offer service for resale to retail customers who do not
choose an alternate generation supplier. These provisions are intended to
ultimately replace the current services offered by the all-requirements
contracts upon full retail access pursuant to the URA. The filing also
includes "hold harmless" provisions for Montaup's other wholesale customers and
for retail customers of the R.I. Distribution Companies, which allow f or
recovery of any of Montaup's lost revenues during the initial phases of retail
access in Rhode Island. This filing allows the R.I. Distribution Companies to
implement on July 1, 1997 the phase-in provisions of the URA and to avoid any
cross-subsidies by their retail customers who are excluded from the groups of
customers given retail choice prior to the final phase and by Montaup's other
customers.
The May 1st and May 30th filings were consolidated by FERC and on
October 29, 1997, settlement agreements among Montaup, its affiliated and non-
affiliated customers, the Massachusetts Attorney General, the MADOER, the RIDIV
and RIPUC were submitted for FERC approval. These settlements represent a
comprehensive resolution of federal/wholesale issues of electric utility
industry restructuring based on the settlement agreements in Massachusetts and
Rhode Island.
Negotiations in Rhode Island on final settlement terms regarding retail
issues of electric utility industry restructuring, are nearing completion,
subsequent to which a formal filing will be made to the RIPUC for approval.
The Company is currently reviewing legislation that has been introduced
in Massachusetts concerning electric industry restructuring. Certain
provisions of the legislation as drafted are problematic to the consensus
achieved through our negotiated settlement with Massachusetts stakeholders.
Historically, electric rates have been designed to recover a utility's
full costs of providing electric service including recovery of investment in
plant assets. Also, in a regulated environment, electric utilities are subject
to certain accounting rules that are not applicable to other industries. These
accounting rules allow regulated companies, in appropriate circumstances, to
establish regulatory assets and liabilities, which defer the current financial
impact of certain costs that are expected to be recovered in future rates. The
SEC has raised issues concerning the continued applicability of these standards
with certain other electric utilities in other states facing restructuring.
The Company believes that its Core Electric operations will continue to meet
the criteria established in these accounting standards.
In July 1997, the Emerging Issues Task Force (EITF) reached a consensus
regarding certain issues raised related to the application of Statement of
Financial Accounting Standards No. 71, (FAS71) "Accounting for the Effects of
Certain Types of Regulation". The EITF determined that when sufficient detail
is available for the enterprise to reasonably determine how the transition plan
will affect the separable portion of its business being deregulated, the
enterprise should discontinue the application of FAS71 to that deregulated
portion of its business. In Massachusetts and Rhode Island, sufficient detail
is deemed to be available, upon approval by FERC, of those restructuring plans
submitted by the Company in its respective jurisdictions. The EITF further
determined that regulatory assets and liabilities originating in the separable
portion of the business and no longer subject to rate regulation should be
evaluated on the basis of where regulated cash flows to recover those
regulatory assets and liabilities will be derived. Based on the current
settlement agreement submitted by the Company in Massachusetts, management does
not believe the EITF decisions will have a material effect on the Company.
In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover the company's costs, a
write-down of plant assets could be required pursuant to Financial Accounting
Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of".
Other
The Company occasionally makes projections of expected future
performance or statements of its plans, objectives and new business
opportunities which are forward-looking statements under federal securities
law. Actual results could differ materially from those discussed and there can
be no assurance that such estimates of future results will be achieved.
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings
See "Note C - Commitments and Contingencies: Recent Nuclear Regulatory
Commission (NRC) Actions - Millstone III" for a discussion of pending legal
action involving Montaup, Northeast Utilities, Connecticut Light & Power and
Western Massachusetts Electric Company.
Item 5. Other Information
On April 24, 1996, the FERC issued orders No. 888 and No. 889 to
encourage competition in the bulk power market by requiring all public
utilities that own, operate or control interstate transmission to file tariffs
that offer others the same transmission services they provide themselves, under
comparable terms and conditions, establishing the right and a mechanism for
recovery of prudently incurred stranded costs and requiring public utilities to
implement standards of conduct and an Open Access Same-time Information System
(OASIS). FERC also issued a Notice of Proposed Rulemaking (NOPR) requesting
comment on replacing the single tariff contained in the final open access rule
with a capacity reservation tariff that would reveal how much transmission is
available at any given time.
Open-access transmission tariffs for point-to-point and local network
service were filed with FERC by Montaup in February 1996 and became effective
April 21, 1996, subject to refund, for a period of at least one year. The
rates in the tariff s were the subject of a settlement agreement which was
filed on July 9, 1996 to modify its terms and conditions in conformance with
FERC's order.
On December 31, 1996, Montaup filed revisions to its Open Access
Transmission tariff necessary to comply with FERC's order on September 11,
1996, which dealt with use rights of High Voltage Direct Current (HVDC)
interconnection transmission facilities with the Hydro Quebec system and on
January 21, 1997, filed additional revisions to coincide with the New England
Power Pool (NEPOOL) Open Access Transmission filing (see below).
On January 3, 1997, as required by FERC in Order No. 889, Montaup filed
its Standards of Conduct Implementation Procedures detailing Montaup's
compliance with the requirements of FERC's standards. Coincident with this
filing, Montaup complied with OASIS's requirements as part of a region wide
OASIS in NEPOOL.
On March 4, 1997, FERC issued Orders 888A and 889A which reaffirms the
legal and policy bases in which Orders 888 and 889 are grounded and addresses
interventions that were filed in response to Orders 888 and 889. As a result,
on July 14, 19 97, Montaup filed revisions to its open access transmission
service for compliance with FERC Order 888A. The filing incorporates all of
the tariff amendments to date.
On June 4, 1997, as supplemented on July 14, 1997, Montaup filed with
FERC in Docket No. ER97-3200-000 amendments to its open access transmission
tariff to provide for unbundled retail transmission service. Montaup proposed
to allow retail customers to obtain retail transmission service directly from
Montaup or through Montaup's retail affiliates acting as the retail customers'
agent. Montaup requested FERC to allow the tariff amendments to become
effective for service to retail customers in Blackstone's and Newport's service
areas on July 1, 1997. FERC accepted the amendment to become effective subject
to refund on that date in an order issued September 12, 1997. FERC accepted
the amendment subject to any modification that may be required as a result of
other pending proceedings concerning Montaup's transmission tariff and ordered
Montaup to make a compliance filing changing the amendments in certain limited
respects. The compliance filing was made by Montaup on October 1 0, 1997.
NEPOOL is a voluntary organization open to any person engaged in the
electric business such as investor-owned utilities, municipals, cooperative
utilities, power marketers, brokers and load aggregators. On December 31,
1996, NEPOOL, on behalf of its participants, filed a restructuring proposal
with FERC. The NEPOOL restructuring proposal is the product of over two years
of intense discussions, deliberations and negotiations among the over 130
NEPOOL member participants and many non-participants, including New England
state regulators. The key elements of the restructuring proposal are the
implementation of a regional NEPOOL Open Access Transmission Tariff (NEPOOL
Tariff), the creation of an Independent System Operator (ISO), and the
restatement of the NEPOOL Agreement to establish a broader governance
structure for NEPOOL and to develop a more open competitive market structure.
The NEPOOL Tariff, which became effective on March 1, 1997, ensures
non-discriminatory open access to the regional transmission network by
providing a single rate for all transactions that utilize the NEPOOL's bulk
power transmission facilities. The NEPOOL Tariff promotes competition in the
New England power market through its non-pancaked rate structure. All regional
service within NEPOOL, except for wheeling through or out, is to be provided as
a network service.
On June 25, 1997, FERC issued an order conditionally authorizing the
establishment of an ISO by NEPOOL effective July 1, 1997, affirming that the
transfer of control of transmission facilities owned by the public utility
members of NEPOOL to the ISO is consistent with the public interest under
section 203 of the Federal Power Act.
NEPOOL is in the process of transferring operational control of the New
England bulk power system to the ISO, a newly created non-profit Delaware
corporation. The ISO's primary responsibility is to ensure system reliability,
administer the NE POOL Tariff, and oversee the efficient and competitive
functioning of the regional power market. The selection of the ISO's Board of
Directors was announced in April 1997.
To give market participants more choice and to foster competition, the
restructured NEPOOL proposes the unbundling of electric service in the NEPOOL
control area. The restructured NEPOOL calls for the development of competitive
wholesale markets for installed capability, operable capability, energy, and
reserves. These wholesale products will be market priced based on bid clearing
pricing rather than the current cost-based pricing. Market participants will be
able to transfer their responsibility for these products by buying or selling
these various services through bilateral transactions or through the regional
power exchange that will be administered through the ISO. Implementation of the
installed capability market is planned for November 1997, the operable
capability and energy markets are planned for April 1998, and the reserve
markets will follow later in 1998.
In general, the EUA System companies support the changes to NEPOOL
because much of the cross-subsidies for sharing costs will be eliminated.
These changes will have an impact on the Company's operating revenues and
costs as NEPOOL transitions from a cost based to a bid based system.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits - None
(b) Reports on Form 8-K
- None filed in the quarter ended September 30, 1997.
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.
Eastern Edison Company
(Registrant)
Date: November 14, 1997 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr. Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)
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