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 1-5366
EASTERN UTILITIES ASSOCIATES
(Exact name of registrant as specified in its charter)
Massachusetts 04-1271872
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
One Liberty Square, Boston, Massachusetts
(Address of principal executive offices)
02109
(Zip Code)
(617)357-9590
(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 April 30, 1997
Common Shares, $5 par value 20,435,997 shares
<TABLE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
March 31, December 31,
1997 1996
<S> <C> <C>
ASSETS
Utility Plant and Other Investments:
Utility Plant in Service $ 1,068,009 $ 1,067,056
Less: Accumulated Provision for Depreciation
and Amortization 359,912 350,816
Net Utility Plant in Service 708,097 716,240
Construction Work in Progress 8,533 3,839
Net Utility Plant 716,630 720,079
Investments in Jointly Owned Companies 71,747 71,626
Non-Utility Plant - Net 71,179 72,653
Total Plant and Other Investments 859,556 864,358
Current Assets:
Cash and Temporary Cash Investments 6,022 12,455
Accounts Receivable, Net 85,980 90,153
Notes Receivable 28,158 24,691
Fuel, Materials and Supplies 12,600 14,131
Other Current Assets 7,799 7,668
Total Current Assets 140,559 149,098
Deferred Debits and Other Non-Current Assets 245,749 243,573
Total Assets $ 1,245,864 $ 1,257,029
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Shares, $5 Par Value $ 102,180 $ 102,180
Other Paid-In Capital 221,246 221,160
Common Share Expense (3,931) (3,931)
Retained Earnings 54,257 52,404
Total Common Equity 373,752 371,813
Non-Redeemable Preferred Stock - Net 6,900 6,900
Redeemable Preferred Stock - Net 27,179 27,035
Long-Term Debt - Net 403,336 406,337
Total Capitalization 811,167 812,085
Current Liabilities:
Long-Term Debt Due Within One Year 27,514 27,512
Notes Payable 47,172 51,848
Accounts Payable 30,572 33,811
Taxes Accrued 4,112 3,004
Interest Accrued 8,019 9,612
Other Current Liabilities 29,231 26,772
Total Current Liabilities 146,620 152,559
Deferred Credits and Other Non-Current Liabilities 122,635 123,209
Accumulated Deferred Taxes 165,442 169,176
Total Liabilities and Capitalization $ 1,245,864 $ 1,257,029
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(In Thousands Except Number of Shares and Per Share Amounts)
<CAPTION>
Three Months Ended
March 31,
1997 1996
<S> <C> <C>
Operating Revenues $ 141,753 $ 134,800
Operating Expenses:
Fuel 29,471 23,195
Purchased Power 32,509 30,003
Other Operation and Maintenance 41,342 40,730
Depreciation and Amortization 11,630 11,123
Taxes Other Than Income 6,376 6,470
Income Taxes - Current 8,915 6,272
- Deferred (Credit) (4,696) (1,274)
Total 125,547 116,519
Operating Income 16,206 18,281
Other Income - Net 4,429 3,368
Income Before Interest Charges 20,635 21,649
Interest Charges:
Interest on Long-Term Debt 8,226 8,649
Other Interest Expense 1,594 1,620
Allowance for Borrowed Funds Used
During Construction (Credit) (240) (546)
Net Interest Charges 9,580 9,723
Net Income 11,055 11,926
Preferred Dividends of Subsidiaries 576 578
Consolidated Net Earnings $ 10,479 $ 11,348
Weighted Average Number of
Common Shares Outstanding 20,435,997 20,436,755
Consolidated Earnings Per
Average Common Share $ 0.51 $ 0.56
Dividends Paid Per Share $ 0.415 $ 0.40
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN UTILITIES ASSOCIATES
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 $ 11,055 $ 11,926
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Activities:
Depreciation and Amortization 13,153 13,181
Deferred Taxes (4,600) (877)
Non-cash (Gains)/Expenses on Sales of Investments
in Energy Savings Projects 2,652 928
Investment Tax Credit, Net (300) (302)
Allowance for Funds Used During Construction (46) (40)
Coll. and sales of project notes and leases rec. 2,605 1,587
Other - Net 337 (420)
Change in Operating Assets and Liabilities 3,024 6,777
Net Cash Provided From Operating Activities 27,880 32,760
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (20,373) (14,733
Collections on Notes and Lease Rec. of EUA Cogenex 2,922 552
Equity Investment in Joint Ventures (107) (75)
Net Cash (Used in) Investment Activities (17,558) (14,256
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (3,022) (3,019)
Premium on Reacquisition and Financing Expenses 0 (5)
EUA Common Share Dividends Paid (8,482) (8,175)
Subsidiary Preferred Dividends Paid (576) (578)
Net (Decrease) Increase in Short-Term Debt (4,675) 2,980
Net Cash (Used in) Financing Activities (16,755) (8,797)
Net (Decrease) Increase in Cash and Temp. Cash Investments (6,433) 9,707
Cash and Temporary Cash Investments at Beginning of Period 12,455 4,060
Cash and Temporary Cash Investments at End of Period $ 6,022 $ 13,767
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 10,086 $ 8,543
Income Taxes $ 7,263 $ 973
Supplemental schedule of non-cash investing activities:
Conversion of Investments in Energy Savings
Projects to Notes and Leases Receivable $ 2,189 $ 712
See accompanying notes to consolidated condensed financial statements.
</TABLE>
EASTERN UTILITIES ASSOCIATES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
The accompanying Notes should be read in conjunction with the Notes to
Consolidated Financial Statements incorporated in the Eastern Utilities
Associates (EUA 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 its 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. Certain reclassifications have been made to prior period
financial statements to conform to current period classifications.
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 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. EUA 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 $10.5 million
compared to first quarter 1996 net earnings of $11.3 million. Net Earnings
contributions by Business Unit for the first three months of 1997 and 1996 were
as follows (in thousands):
Three Months Ended March 31,
1997 1996
Core Electric Business $10,901 $11,613
Energy Related Business (510) (92)
Corporate 88 (173)
Consolidated $10,479 $11,348
The decrease in the net earnings contribution of the Core Electric
Business in the first quarter of 1997 was primarily due to decreased
kilowatthour (kWh) sales. Total primary kWh sales decreased by 2.9% in this
year's first quarter, mainly weather related. Peak demands for electricity
decreased 4.2% in this year's first quarter.
Net Earnings of our Energy Related Business Unit decreased by
approximately $400,000 in the first quarter of 1997 as compared to the same
period of a year ago. This decrease is primarily due to increased expenses of
the BIOTEN partnership, largely marketing related. As anticipated, EUA Cogenex
operated at a loss of approximately $600,000 in the first quarter of 1997,
approximately one-half of the operating loss experienced in the fourth quarter
of 1996. The improvement in new contract sales experienced in this year's
first quarter is expected to contribute to earnings in the second half of
1997. The first quarter operating loss was offset somewhat by a net gain of
approximately $500,000 resulting from a change in EUA Cogenex pension and
post-retirement welfare benefit plans. These benefit plan changes will result
in significant on-going expense savings.
The change in the earnings contribution of the Corporate Business Unit is
due primarily to lower interest expense and increased intercompany interest
income.
Operating Revenues
Operating Revenues for the first three months of 1997 increased by
approximately $7.0 million to approximately $141.8 million when compared to the
same period of 1996. Operating Revenues by Business Unit for the first quarter
of 1997 and 1996 were as follows (in thousands):
Three Months Ended March 31,
1997 1996
Core Electric Business $128,224 $122,204
Energy Related Business 13,529 12,596
Corporate 0 0
Consolidated $141,753 $134,800
Core Electric Business revenues increased $6.0 million due primarily to
recoveries of increased fuel, purchased power and conservation and load
management (C&LM) expenses aggregating approximately $8.0 million, and base
rate increases for Blackstone Valley Electric Company (Blackstone) and Newport
Electric Corporation (Newport) pursuant to the Rhode Island Utility
Restructuring Act of 1996 (URA) These increases were offset by the impacts of
decreased kWh sales and peak demand billings.
EUA Cogenex revenues, which account for nearly all of the Energy Related
Business Unit revenues, increased by approximately $900,000 due primarily to an
increase of $1.6 million in partnership project sales offset somewhat by a
decrease in EUA Day Division revenues in the first quarter.
Operating Expenses
Fuel expense of the Core Electric Business 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 quarter ended March
31, 1997 increased approximately $600,000 or 1.5% from the same period in 1996
due to the following: Direct expenses of the Core and Corporate Business units
decreased by approximately $800,000 in this year's first quarter due primarily
to decreased customer accounts expense of approximately $400,000 and decreased
distribution expenses aggregating approximately $300,000.
Indirect expenses, items in which we have limited short-term control or
items which are fully recovered in rates, increased by approximately $800,000
in the first quarter of 1997 as compared to the same period of 1996. This
change was due primarily to increased jointly owned unit expenses of
approximately $1.6 million, $1.0 million of which is related to the Millstone
III outage, partially offset by decreases in C&LM expenses of approximately
$400,000 and decreased employee benefits expenses of approximately $300,000.
Expenses of the Energy Related Business unit increased by $600,000 for the
period. This increase is primarily due to increased marketing-related expenses
of the BIOTEN partnership.
Depreciation and Amortization Expense
Depreciation and Amortization expense increased $500,000 or 4.6% in the
first quarter of 1997 when compared to last year's first quarter due largely to
increased Core Electric plant in service.
Other Income and (Deductions) - Net
Other Income and (Deductions) - Net increased by approximately $1.1
million in this year's first quarter. This increase is due primarily to
interest income related to the favorable resolution of a Massachusetts
corporate income tax dispute and the impact of changes to EUA Cogenex pension
and post-retirement welfare benefit plans.
Interest Charges
Net interest charges decreased by approximately $100,000 in the first
quarter of 1997 due primarily to a decrease of $400,000 in long-term debt
interest resulting from the operation of normal sinking fund provisions offset
by a decrease in capitalized interest of EUA Cogenex of approximately $300,000.
Liquidity and Sources of Capital
The EUA System's need for permanent capital is primarily related to
investments in facilities required to meet the needs of its existing and future
customers.
Traditionally, cash construction requirements not met with internally
generated funds are financed through short-term borrowings which are ultimately
funded with permanent capital. At March 31, 1997, EUA System companies
maintained short-term lines of credit with various banks aggregating
approximately $140 million. Outstanding short-term debt at March 31, 1997 and
December 31, 1996 by Business Unit was as follows (in Thousands):
March 31, 1997 December 31, 1996
Core Electric Business $ 9,103 $ 3,670
Energy Related Business 28,412 24,341
Corporate 9,657 23,837
Consolidated $47,172 $51,848
For the three months ended March 31, 1997, internally generated funds
amounted to approximately $15.3 million while the EUA System's cash
construction requirements amounted to approximately $20.4 million for the same
period. Various laws, regulations and contract provisions limit the use of
EUA's internally generated funds such that the funds generated by one
subsidiary are not generally available to fund the operations of another
subsidiary.
Electric Utility Industry Restructuring
On August 7, 1996 the Governor of Rhode Island signed into law the 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. 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.
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
ulimately 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. EUA believes that its Core Electric 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 EUA 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, EUA 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
EUA 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 EUA System 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 - On 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 Utilities Associates
(Registrant)
Date: May 14, 1997 /s/ Richard M. Burns
Richard M. Burns
(on behalf of the Registrant and
as Chief Accounting Officer)
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