UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period _________________ 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 July 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 June 30, December 31,
1997 1996
<S> <C> <C>
Utility Plant in Service $ 815,001 $ 815,187
Less: Accumulated Provision for Depreciation
and Amortization 274,344 261,464
Net Utility Plant in Service 540,657 553,723
Construction Work in Progress 8,264 2,805
Net Utility Plant 548,921 556,528
Current Assets:
Cash and Temporary Cash Investments 1,106 2,105
Accounts Receivable - Other 36,680 39,473
- Associated Cos. 12,633 25,486
Fuel, Materials and Supplies 8,294 10,649
Other Current Assets 7,102 3,598
Total Current Assets 65,815 81,311
Deferred Debits and Other Non-Current Assets 132,739 137,243
Total Assets $ 747,475 $ 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 101,099 120,724
Total Common Equity 220,588 240,213
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (2,341) (2,630)
Long-Term Debt - Net 202,447 222,402
Total Capitalization 450,359 489,650
Current Liabilities:
Long - Term Debt Due Within One Year 20,000
Notes Payable 9,511 2,040
Accounts Payable - Associated Companies 5,122 3,950
- Other 23,948 27,391
Taxes Accrued 3,863 2,977
Interest Accrued 4,899 4,895
Other Current Liabilities 11,495 17,234
Total Current Liabilities 78,838 58,487
Deferred Credits and Other Non-Current Liab. 78,189 84,506
Accumulated Deferred Taxes 140,089 142,439
Total Liabilities and Capitalization $ 747,475 $ 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 Six Months Ended
June 30, June 30,
1997 1996 1997 1996
<S> <C> <C> <C> <C>
Operating Revenues $ 103,716 $ 91,847 $ 214,304 $ 196,866
Operating Expenses:
Fuel 23,662 17,462 53,131 40,655
Purchased Power 30,180 28,599 62,664 58,571
Other Operation and Maintenance 27,221 22,741 49,681 45,500
Early Retirement Offer 737 737
Depreciation and Amortization 6,891 6,729 13,781 13,458
Taxes - Other Than Income 2,782 2,783 5,668 5,648
Income Taxes - Current 3,059 2,996 10,571 8,346
- Deferred (Credit) (340) 79 (3,740) 56
Total 94,192 81,389 192,493 172,234
Operating Income 9,524 10,458 21,811 24,632
Allowance for Other Funds
Used During Construction 21 58 59 95
Other Income - Net 453 483 1,606 976
Income Before Interest Charges 9,998 10,999 23,476 25,703
Interest Charges:
Interest on Long-Term Debt 3,752 3,836 7,503 7,673
Other Interest Expense 969 827 1,798 1,768
All. for Borrowed Funds Used
During Construction (Credit) (59) (88) (96) (140)
Net Interest Charges 4,662 4,575 9,205 9,301
Net Income 5,336 6,424 14,271 16,402
Preferred Dividend Requirements 497 497 994 994
Consolidated Net Earnings $ 4,839 $ 5,927 $ 13,277 $ 15,408
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Six Months Ended
<CAPTION> June 30,
1997 1996
CASH FLOW FROM OPERATING ACTIVITIES:
<S> <C> <C>
Net Income $ 14,271 $ 16,402
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 14,447 14,329
Amortization of Nuclear Fuel 586 1,000
Deferred Taxes (3,711) 22
Investment Tax Credit, Net (468) (470)
Allowance for Other Funds Used During Construction (59) (96)
Other - Net (1,487) (1,832)
Change in Operating Assets and Liabilities 7,377 5,853
Net Cash Provided From Operating Activities 30,956 35,208
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (5,819) (11,663)
Net Cash Used in Investing Activities (5,819) (11,663)
CASH FLOW FROM FINANCING ACTIVITIES:
Common Stock Dividends Paid to EUA (32,613) (16,972)
Preferred Dividends Paid (994) (994)
Net Decrease (Increase) in Short-Term Debt 7,471 (4,158)
Net Cash Used in Financing Activities (26,136) (22,124)
Net (Decrease) Increase in Cash and Temporary
Cash Investments (999) 1,421
Cash and Temporary Cash Investments at
Beginning of Period 2,105 533
Cash and Temporary Cash Investments at
End of Period $ 1,106 $ 1,954
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 7,572 $ 7,657
Income Taxes $ 10,026 $ 6,970
</TABLE>
See accompanying notes to consolidated condensed financial statements.
EASTERN EDISON COMPANY
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 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 period ended March 31, 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 its financial position as of June 30, 1997 and December 31,
1996, and the results of operations for the three and six months
ended June 30, 1997 and 1996 and cash flows for the six months ended
June 30, 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. 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 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 were 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.
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.
The ICAVP for Millstone III began in May of 1997 and is ongoing. The
ICAVP is an external review process that is necessary prior to the
restart of the unit.
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.
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.
EUA 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 $5.1 million at June 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 June 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:
In December 1996, Maine Yankee Atomic Power Plant was shut down for
inspections and repairs to resolve cable-separation and associated
issues. Further inspections while the unit was shut down indicated that
several fuel assemblies that contained leaking rods should be replaced.
After ongoing safety assessments by the NRC, it was determined that the
Plant would remain out of service until the fuel-assembly replacement
and a thorough inspection of the Plant's electrical cabling were
completed and associated issues were resolved. A restart of the Plant
would have required NRC approval.
In August of 1997, as the result of an economic evaluation, the Board of
Directors of Maine Yankee voted to permanently close the Plant. Montaup
has a 4.0% equity ownership in Maine Yankee with a book value of
approximately $3.0 million at June 30, 1997. The amount of unrecovered
assets and estimated costs to decommission the Plant is currently
being revised from a 1996 estimate. When the amount is known, most
likely in the third quarter of 1997, Montaup will record it's share of
that future liability, and at the same time, due to anticipated
recoverability, will record a regulatory asset for the same amount.
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.
Early Retirement Offer
In June of 1997, an early retirement offer was accepted by a group of
employees who were eligible but not offered a Voluntary Retirement Incentive
offer completed in 1995, resulting in a charge of approximately $700,000
(approximately $500,000 after-tax) to second quarter 1997 earnings.
Overview
Consolidated Net Earnings for the second quarter of 1997 were $4.8
million, compared to the second quarter 1996 net earnings of $5.9 million. For
the six months ended June 30, 1997, net earnings were $13.3 million, compared
to 1996's six months net earnings of $15.4 million. Both second quarter and
year-to-date 1997 results include the impacts of the June 1997 early retirement
offer (discussed above).
Kilowatthour Sales
Retail sales increased by 3.2% for this year's second quarter as compared
to 1996. The second quarter's increase was led by increased sales to
industrial customers of 7.2%. The first quarter's sales decrease essentially
offset the second quarter's sales increase and therefore the year-to-date
retail sales were relatively unchanged.
Operating Revenues
Operating Revenues for the second quarter of 1997 increased $11.9 million
or 12.9% as compared to the second quarter of 1996. This increase was due to
recoveries of increased purchased power, fuel and conservation and load
management (C&LM) expenses aggregating approximately $8.2 million. Also
impacting second quarter revenues were increased base rate recoveries and
increased short-term contract demand sales. Year-to-date 1997 revenues
increased $17.4 million or 8.9% as compared to year-to-date 1996 due to
recoveries of increased purchased power, fuel and C&LM expenses aggregating
$16.0 million. Also impacting year-to-date revenues were increased base rate
recoveries and increased short-term contract demand sales.
Operations Expense
Fuel expense for the second quarter and year-to-date periods increased by
approximately $6.2 million or 35.5% and $12.5 million or 30.7%, respectively,
as compared to the same periods in 1996. Outages of nuclear units in the
second quarter and year-to-date periods of 1997 contributed to a greater
dependance on higher cost fossil fuels for energy requirements, resulting in
increases in average fuel costs of 28.3% and 27.8% for the respective periods.
Also contributing to the increases in fuel expense for the second quarter and
year-to-date periods were increases in total energy generated and purchased of
5.4% and 1.8%, respectively.
Purchased Power demand expense for the second quarter and the six months
ended June 30, 1997 increased approximately $1.6 million or 5.5% and $4.1
million or 7.0%, respectively, as compared to the same periods in 1996. These
increases are due primarily to increased billings from Maine Yankee and the
Ocean State Power project.
Other Operation and Maintenance (O&M) expenses for the second quarter of
1997 increased $4.5 million or 19.7%. This change was due primarily to
increased jointly owned unit expenses of $2.8 million, approximately $900,000
of which is related to the Millstone III outage, and the remainder is comprised
of expenses related to the scheduled maintenance outages at the Canal and
Seabrook Units. Also impacting the increases in O&M were incremental costs of
approximately $700,000 associated with a scheduled outage at Montaup Electric's
Somerset Station and increased conservation and load management expenses of
approximately $600,000. For the year-to-date period, O&M expenses increased by
$4.2 million, or 9.2%, as compared to the same period of 1996. Jointly owned
unit expenses increased $4.4 million in the year-to-date period, $1.9 million
of which relates to the Millstone III outage and remainder is due to expenses
from the Canal and Seabrook units. The aforementioned increased expenses at
the Somerset Station were offset by decreased storm related expenses of
approximately $400,000 due to an unusual amount of storms occurring in our
service territory in 1996, and decreased customer accounts expense of
approximately $300,000.
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 June 30, 1997
these unused EUA System short-term lines of credit amounted to approximately
$83.9 million. The Company had $9.5 million of short-term debt at June 30,
1997.
The Company's year-to-date June 30, 1997 internally generated funds
available after the payment of dividends amounted to $8.0 while its cash
construction requirements for the same period were $5.8 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 August 1, 1997 two customers had 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 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.
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 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." 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 in the third quarter of 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,
submitted to the MDPU on 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.
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 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. EUA intends to
amend this filing once settlement negotiations in Rhode Island, currently in
progress, have concluded. 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 Rhode Island on final settlement terms regarding electric
utility industry restructuring, including the CTC, are continuing, subsequent
to which a formal filing will be made to the RIPUC for approval.
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.
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.
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings
See "Note C - Commitments and Contingencies: Recent 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 4. Submission of Matters to a Vote of Security Holders.
(a) A Consent to Action in Lieu of Annual Meeting of Stockholders (Consent
to Action) was executed April 16, 1997 by Eastern Utilities
Associates, the holder of the entire issued and outstanding Common
Stock of the Company and the only class of stock entitled to vote at
the Annual Meeting of Stockholders.
(b) The Board of Directors as previously reported to the Securities and
Exchange Commission was re-elected, with the exception of David H.
Gulvin, who upon retirement, was replaced by Clifford J. Hebert, Jr.
(c) The only matters voted on in the Consent to Action was the election of
directors and the election of Clifford J. Hebert, Jr. to continue as
Treasurer and Clerk.
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,
on July 14, 1997, 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.
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 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 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 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.
- May 19, 1997, the Registrant filed a current report on
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: August 14, 1997 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)
<TABLE> <S> <C>
<ARTICLE> OPUR1
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 548921
<OTHER-PROPERTY-AND-INVEST> 2706
<TOTAL-CURRENT-ASSETS> 65815
<TOTAL-DEFERRED-CHARGES> 116356
<OTHER-ASSETS> 13677
<TOTAL-ASSETS> 747475
<COMMON> 72284
<CAPITAL-SURPLUS-PAID-IN> 47205
<RETAINED-EARNINGS> 101099
<TOTAL-COMMON-STOCKHOLDERS-EQ> 220588
27324
0
<LONG-TERM-DEBT-NET> 202447
<SHORT-TERM-NOTES> 9511
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 20000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 267605
<TOT-CAPITALIZATION-AND-LIAB> 747475
<GROSS-OPERATING-REVENUE> 214304
<INCOME-TAX-EXPENSE> 6831
<OTHER-OPERATING-EXPENSES> 185662
<TOTAL-OPERATING-EXPENSES> 192493
<OPERATING-INCOME-LOSS> 21811
<OTHER-INCOME-NET> 1665
<INCOME-BEFORE-INTEREST-EXPEN> 23476
<TOTAL-INTEREST-EXPENSE> 9205
<NET-INCOME> 14271
994
<EARNINGS-AVAILABLE-FOR-COMM> 13277
<COMMON-STOCK-DIVIDENDS> 32613
<TOTAL-INTEREST-ON-BONDS> 7503
<CASH-FLOW-OPERATIONS> 30956
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
