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 March 31, 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.)
110 Mulberry Street, Brockton, Massachusetts
(Address of principal executive offices)
02402
(Zip Code)
(508)580-1213
(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 March 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>
March 31, December 31,
1997 1996
<S> <C> <C>
ASSETS
Utility Plant in Service $ 815,969 $ 815,187
Less: Accumulated Provision for Depreciation
and Amortization 268,181 261,464
Net Utility Plant in Service 547,788 553,723
Construction Work in Progress 5,835 2,805
Net Utility Plant 553,623 556,528
Current Assets:
Cash and Temporary Cash Investments 690 2,105
Accounts Receivable - Associated Cos 11,585 25,486
- Other 36,765 39,473
Materials and Supplies 3,716 3,805
Other Current Assets 9,674 10,442
Total Current Assets 62,430 81,311
Deferred Debits and Other Non-Current Assets 134,687 137,243
Total Assets $ 750,740 $ 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 (43) (44)
Retained Earnings 104,211 120,724
Total Common Equity 223,701 240,213
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (2,485) (2,630)
Long-Term Debt - Net 222,424 222,402
Total Capitalization 473,305 489,650
Current Liabilities:
Notes Payable 1,765 2,040
Accounts Payable - Associated Companies 3,846 3,950
- Other 25,720 27,391
Taxes Accrued 6,479 2,977
Interest Accrued 4,679 4,895
Other Current Liabilities 13,635 17,234
Total Current Liabilities 56,124 58,487
Def. Credits and Other Non-Current Liabilities 81,389 84,506
Accumulated Deferred Taxes 139,922 142,439
Total Liabilities and Capitalization $ 750,740 $ 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
March 31,
1997 1996
<S> <C> <C>
Operating Revenues $ 110,588 $ 105,019
Operating Expenses:
Fuel 29,469 23,193
Purchased Power 32,484 29,972
Other Operation and Maintenance 22,460 22,759
Depreciation and Amortization 6,890 6,729
Taxes Other Than Income 2,886 2,865
Income Taxes - Current 7,512 5,350
- Deferred (Credit) (3,400) (23)
Total 98,301 90,845
Operating Income 12,287 14,174
Allowance for Other Funds
Used During Construction 38 37
Other Income (Deductions) - Net 1,153 493
Income Before Interest Charges 13,478 14,704
Interest Charges:
Interest on Long-Term Debt 3,751 3,837
Other Interest Expense 829 941
Allowance for Borrowed Funds Used
During Construction(Credit) (37) (52)
Net Interest Charges 4,543 4,726
Net Income 8,935 9,978
Preferred Dividend Requirements 497 497
Consolidated Net Earnings $ 8,438 $ 9,481
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Three Months Ended
March 31,
1997 1996
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 8,935 $ 9,978
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 7,221 7,211
Amortization of Nuclear Fuel 358 637
Deferred Taxes (3,418) (40)
Investment Tax Credit, Net (234) (235)
Allowance for Other Funds Used During Construction (38) (37)
Other - Net (175) (1,352)
Change in Operating Assets and Liabilities 15,378 7,507
Net Cash Provided From Operating Activities 28,027 23,669
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (3,864) (4,455)
Net Cash (Used in) Investing Activities (3,864) (4,455)
CASH FLOW FROM FINANCING ACTIVITIES:
Common Stock Dividends Paid to EUA (24,806) (8,298)
Preferred Dividends Paid (497) (497)
Net (Decrease) in Short-Term Debt (275) (4,158)
Net Cash (Used in) Financing Activities (25,578) (12,953)
Net (Decrease) Increase in Cash and Temporary
Cash Investments (1,415) 6,261
Cash and Temporary Cash Investments at
Beginning of Period 2,105 533
Cash and Temporary Cash Investments at
End of Period $ 690 $ 6,794
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 3,972 $ 4,159
Income Taxes $ 5,141 $ 1,070
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.
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 March 31, 1997 and the results of
operations and cash flows for the three months ended March 31, 1997
and 1996. The year-end consolidated condensed balance sheet data was
derived from audited financial statements but does not include all
disclosures required under generally accepted accounting principles.
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, and on March 30,
1996, Northeast determined 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 July 1996, Northeast reported that it was responding to a series of
requests from the NRC seeking assurance that the Millstone III unit
would be operated in accordance with the terms of its operating license
and other NRC requirements and regulations and dealing with a series of
issues that Northeast has identified in the course of these reviews.
Providing these assurances and addressing these issues were components
of an Operational Readiness Plan which was submitted to the NRC on July
2, 1996 and is presently being implemented.
On October 18 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.
The ICAVP for Millstone III is scheduled to begin in May of 1997. The
ICAVP is an external review process that is necessary prior to the
restart of the unit.
On October 24, 1996 the NRC issued another order directing that prior
to restart of Millstone III, Northeast submit a plan for disposition of
safety issues raised by employees and retain an independent third-party
to oversee implementation of this plan. This third-party oversight
will continue until the situation is corrected.
Northeast expects that one of the three Millstone units will be ready
for restart in the third quarter of 1997, one in the fourth quarter of
1997, and one in the first quarter of 1998. Subject to final NRC
reviews and inspections, Northeast expects that at least one of the
units will be back on line by the end of 1997.
In March of 1997, Northeast announced that Millstone III has 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.
On May 8, 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 $10.4 million, approximately $4.4 million more than
originally expected and $3.2 million more than O&M expenditures in
1996.
While Millstone III is out of service, Montaup will incur incremental
replacement power costs estimated at $0.5 million to $0.7 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.
EUA cannot predict the ultimate outcome of the NRC inquiries or the
impact which they may have on Montaup and the EUA system. Montaup is
also evaluating its rights and obligations under the various agreements
relating to the ownership and operation of Millstone III.
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 $5.0 million at March 31, 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. As a result of the analysis, work at the
plant had slowed pending a final board decision. In December 1996, the
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.
Montaup's share of the total estimated costs is $34.1 million.
Maine Yankee:
On June 7, 1996, the NRC commissioned an independent Safety Assessment
Team to assess the conformance of the Maine Yankee Atomic Power
Station to its design and licensing basis. Montaup holds a 4.0%
ownership interest in the Maine Yankee Unit. On October 7, 1996, the
NRC released an Independent Safety Assessment (ISA) report. In
evaluating the Plant's conformance to its licensing basis, the report
concluded that Maine Yankee was in general conformance with its
licensing basis although significant items of nonconformance were
identified stemming from two closely related root causes: (1) economic
pressure to be a low-cost energy provider had limited available
resources to address corrective actions and some improvements and (2)
a questioning culture was lacking, which had resulted in a failure to
identify or promptly correct significant problems in areas perceived
by Maine Yankee to be of low safety significance.
A letter to Maine Yankee from the Chair of the NRC accompanying the
ISA report directed Maine Yankee to provide to the NRC its plans for
addressing the root causes of the deficiencies identified by the ISA.
In December, 1996 the unit was shut down for inspections and repairs
to resolve cable-separation and associated issues. While the Plant
has been out of service, Maine Yankee, having previously detected
indications of minor leakage in a small number of the Plant's 38,000
fuel rods, used the opportunity to inspect the Plant's 217 fuel
assemblies. As a result of the inspection, Maine Yankee determined
that several fuel assemblies that contained leaking rods should be
replaced and has commenced that process. On January 29, 1997 the NRC
announced that it had placed the unit on its "watch list." The
operator expects the Plant to remain out of service until the fuel-
assembly replacement and a thorough inspection of the Plant's
electrical cabling are completed and associated issues resolved, and
restarting the Plant is approved by the NRC.
In February 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy)
signed a contract for Entergy to provide management services including
plant operations at the Maine Yankee plant through September 1997.
Maine Yankee and Entergy have been discussing the possibilities of a
longer term contract.
On March 7, 1997, Maine Yankee submitted its Restart Readiness Plan
(RRP) to the NRC. The RRP is subject to public participation and
comment prior to NRC approval. Maine Yankee expects the unit to be
out of service until at least August 1997, but cannot predict when or
whether all regulatory and/or operational issues will be
satisfactorily resolved.
The owners of Maine Yankee continue to evaluate the impact of
substantially increased maintenance costs on the economic viability of
the unit.
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 first quarter of 1997 were $8.4 million,
compared to first quarter 1996 net earnings of $9.5 million. This change was
due primarily to a 3.7% decrease in retail kilowatthour (kWh) sales, largely
weather related. Peak demands for electricity decreased by 4.2% in the period.
Operating Revenues
Operating Revenues increased $5.6 million to $110.6 million in the first
quarter of 1997 compared to the same period in 1996. This increase is
primarily due to recoveries of increased fuel, purchased power and conservation
and load management expenses aggregating $7.8 million. Offsetting this
increase somewhat were decreased base rate revenues resulting from decreased
kWh sales and peak demand billings in the first quarter.
Operating Expenses
Fuel expense for the first quarter of 1997 increased from that of the same
period in 1996 by approximately $6.3 million or 27.1%. Outages of nuclear
units in this year's first quarter contributed to a greater dependance on
higher cost fossil fuels for energy requirements, resulting in a 27.7% increase
in average fuel costs. This increase was offset somewhat by decreased energy
requirements for the period.
Purchased Power expense for the first quarter of 1997 increased $2.5
million or 8.4% as compared to last year's first quarter. Higher costs billed
to Montaup by Maine Yankee, Connecticut Yankee and Ocean State Power in 1997's
first quarter were primarily responsible for this change.
Other Operation and Maintenance (O&M) expenses for the first quarter of
1997 decreased approximately $300,000 from the same period in 1996. This
decrease is due primarily to decreases in conservation and load management
expenses and employee benefits expenses of approximately $600,000 and $500,000,
respectively, and decreases in customer accounts expense, power contracts
and distribution expenses aggregating approximately $800,000. Offsetting
these decreases somewhat was increased jointly owned unit expenses of $1.6
million, $1.0 million of which is related to the Millstone III outage.
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. EUA System companies, including Eastern Edison
and Montaup, maintain short-term lines of credit with various banks aggregating
approximately $140 million. These credit lines are available to other
affiliated companies under joint credit line arrangements. At March 31, 1997,
these unused EUA System short-term lines of credit amounted to approximately
$93 million. The Company had $1.8 million of short-term debt outstanding at
March 31, 1997. In the first quarter of 1997, internally generated funds
amounted to $4.3 million while cash construction requirements for the same
period were $3.9 million.
Electric Utility Industry Restructuring
On August 7, 1996 the Governor of Rhode Island signed into law the Rhode
Island 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. 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 choose not to choose, the local distribution company would 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 to 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.
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 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 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."
The agreement envisions that all of Eastern Edison's customers will have
the ability to choose an alternative supplier of electricity beginning 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, to be submitted to the MDPU by July 1,
1997, 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, to be conducted by
an independent third party.
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. Subsequent 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 agreement, implementation is also
subject to the approval of FERC. 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. EUA intends to amend
this filing once settlement negotiations have concluded in Rhode Island and
Massachusetts. 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 for 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.
Negotiations in both Massachusetts and Rhode Island on final settlement
terms regarding electric utility industry restructuring, including the CTC, are
continuing, subsequent to which formal filings will be made to the MDPU and
RIPUC for approval. It is EUA's intent to file both Massachusetts and Rhode
Island settlements with FERC for approval of amendments to the all-requirements
wholesale contracts contained in the respective settlements.
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 operations will continue to meet
the criteria established in these accounting standards.
However, the potential exists that the final outcome of state and federal
agency determinations could result in the Company no longer meeting the
criteria of these accounting standards which could trigger the discontinuance
of Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (FAS71). Should it be required to
discontinue the application of FAS71, the Company would be required to take an
immediate write-down of the affected assets in accordance with FAS101,
"Accounting for the Discontinuation of Application of FAS71."
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.
Item 5. Other Information
On April 24, 1996, FERC issued orders on its March 24, 1995 Notice of
Proposed Rulemaking (NOPR). FERC's purpose in proposing the new rules was to
encourage competition in the bulk power market. FERC's April 24th actions
include:
- order No. 888, a final rule requiring open access transmission and
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.
Utilities must take transmission service for their own wholesale
transactions under the terms and conditions of the tariff;
- establishing the right and a mechanism for recovery of prudently
incurred stranded costs by public utilities and transmitting utilities;
which arise as a result of wholesale open access;
- order No. 889, a final rule requiring public utilities to implement
standards of conduct and an Open Access Same-time Information System
(OASIS). Utilities must obtain information about their transmission the
same way as their competitors through the OASIS;
- a 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 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
tariffs were the subject of a settlement agreement which was filed on June 14,
1996. Montaup amended its filing on July 9, 1996 to modify its terms and
conditions in conformance with FERC's order. These tariffs are in compliance
with FERC's April 24th rulings.
On November 13, 1996, FERC issued a final order on the non-rate terms and
conditions of Montaup's open access transmission tariff. Montaup was required
to provide a more detailed description of the method used to compute available
transmission capability. FERC has not taken any action on the rates portion of
the tariff.
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. On January 21,1997, Montaup filed revisions to its Open Access
Transmission tariff to coincide with the New England Power Pool (NEPOOL) Open
Access Transmission tariff filed on December 31, 1996 (see below) which became
effective March 1, 1997, subject to refund and the issuance of further orders.
On April 2, 1997, Montaup filed additional revised tariff sheets to update
the filing's formula rate for local network service.
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 regionwide
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,
compliance tariffs must be filed by July 14, 1997.
In addition to the above transmission tariffs filings, the EUA System
companies have been actively involved in the restructuring of NEPOOL. 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 the 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.
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 NEPOOL 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 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- January 6, 1997, the Registrant filed a current
report of form 8-K with respect to Item 5 (Other Events).
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: May 14, 1997 /s/Richard M. Burns
Richard M. Burns,Vice President
(on behalf of the Registrant
and as Chief Accounting
Officer)
<TABLE> <S> <C>
<ARTICLE> OPUR1
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> MAR-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 553623
<OTHER-PROPERTY-AND-INVEST> 2706
<TOTAL-CURRENT-ASSETS> 62430
<TOTAL-DEFERRED-CHARGES> 131981
<OTHER-ASSETS> 13491
<TOTAL-ASSETS> 750740
<COMMON> 72284
<CAPITAL-SURPLUS-PAID-IN> 47206
<RETAINED-EARNINGS> 104211
<TOTAL-COMMON-STOCKHOLDERS-EQ> 223701
27180
0
<LONG-TERM-DEBT-NET> 222424
<SHORT-TERM-NOTES> 1765
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 275670
<TOT-CAPITALIZATION-AND-LIAB> 750740
<GROSS-OPERATING-REVENUE> 110588
<INCOME-TAX-EXPENSE> 4112
<OTHER-OPERATING-EXPENSES> 94189
<TOTAL-OPERATING-EXPENSES> 98301
<OPERATING-INCOME-LOSS> 12287
<OTHER-INCOME-NET> 1191
<INCOME-BEFORE-INTEREST-EXPEN> 13478
<TOTAL-INTEREST-EXPENSE> 4543
<NET-INCOME> 8935
497
<EARNINGS-AVAILABLE-FOR-COMM> 8438
<COMMON-STOCK-DIVIDENDS> 24806
<TOTAL-INTEREST-ON-BONDS> 3751
<CASH-FLOW-OPERATIONS> 28027
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
