UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period _________________ to ___________________
Commission File Number 0-8480
EASTERN EDISON COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1123095
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
750 W. Center Street, West Bridgewater, Massachusetts
(Address of principal executive offices)
02379
(Zip Code)
(508)559-1000
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes....X......No..........
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practical date.
Class Outstanding at August 31, 1999
Common Shares, $25 par value 2,339,401 shares
<TABLE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
ASSETS September 30, December 31,
1999 1998
<S> <C> <C>
Utility Plant in Service $ 672,377 $ 741,902
Less: Accumulated Provision for Depreciation
and Amortization 225,638 252,301
Net Utility Plant in Service 446,739 489,601
Construction Work in Progress 7,016 2,691
Net Utility Plant 453,755 492,292
Current Assets:
Cash and Temporary Cash Investments 251 25,952
Accounts Receivable - Other 59,305 44,556
- Associated Companies 16,652 18,628
Fuel,Materials and Supplies 2,317 9,965
Other Current Assets 3,770 4,754
Total Current Assets 82,295 103,855
Deferred Debits and Other Non-Current Assets 491,009 235,475
Total Assets $ 1,027,059 $ 831,622
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Stock, $25 Par Value $ 58,485 $ 72,284
Other Paid-In Capital 78,049 47,249
Common Stock Expense (44) (44)
Retained Earnings 117,878 106,509
Total Common Equity 254,368 225,998
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (1,397) (1,670)
Long-Term Debt - Net 40,000 162,550
Total Capitalization 322,636 416,543
Current Liabilities:
Notes Payable 18,400
Accounts Payable - Associated Companies 10,973 8,987
- Other 20,904 25,502
Taxes Accrued 26,434 17,361
Interest Accrued 452 3,561
Other Current Liabilities 127,975 18,725
Total Current Liabilities 205,138 74,136
Deferred Credits and Other Non-Current Liabilities 390,142 221,300
Accumulated Deferred Taxes 109,143 119,643
Total Liabilities and Capitalization $ 1,027,059 $ 831,622
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(In Thousands)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
<S> <C> <C> <C> <C>
Operating Revenues $ 93,546 $ 101,769 $ 303,445 $ 308,039
Operating Expenses:
Fuel and Purchased Power 50,740 52,514 171,992 158,176
Other Operation and Maintenance 18,886 24,068 61,782 70,543
Depreciation and Amortization 5,336 7,463 18,355 22,389
Taxes- Other Than Income 1,949 2,718 6,855 8,384
Income Taxes - Current 6,794 5,449 23,098 9,821
- Deferred (Credit) (787) (1,361) (7,961) 4,075
Total 82,918 90,851 274,121 273,388
Operating Income 10,628 10,918 29,324 34,651
Allowance for Other Funds
Used During Construction 94 43 190 95
Other Income - Net 1,381 78 2,506 372
Income Before Interest Charges 12,103 11,039 32,020 35,118
Interest Charges:
Interest on Long-Term Debt 1,508 2,883 7,273 10,190
Other Interest Expense 1,700 1,560 4,216 3,024
Allowance for Borrowed Funds Used
During Construction (Credit) (42) (82) (136) (167)
Net Interest Charges 3,166 4,361 11,353 13,047
Net Income 8,937 6,678 20,667 22,071
Preferred Dividend Requirements 497 497 1,491 1,491
Consolidated Net Earnings $ 8,440 $ 6,181 $ 19,176 $ 20,580
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Nine Months Ended
September 30,
1999 1998
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 20,667 $ 22,071
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 21,605 23,587
Amortization of Nuclear Fuel 1,375 859
Deferred Taxes (8,658) 4,082
Investment Tax Credit, Net (2,010) (976)
Allowance for Other Funds Used During Construction (190) (95)
Other - Net (8,270) 2,387
Regulatory Asset - Purchase Power Contract Buyout (105,623
Change in Operating Assets and Liabilities 2,840 (7,064)
Regulatory Liability - Purchase Power Contract Buyout 105,623
Net Cash Provided From Operating Activities 27,359 44,851
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (10,029) (11,340)
Decrease in Other Investments 110
Proceeds from Divestiture of Generation Assets 56,635
Net Cash Provided From (Used in) Investing Activities 46,606 (11,230)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemption of Common Stock (23,000)
Common Stock Dividends Paid to EUA (7,533) (19,806)
Preferred Dividends Paid (1,491) (1,491)
Capital Contribution from EUA Parent 40,000
Redemptions of Long-Term Debt (123,000 (60,000)
Premiums Paid on Long-Term Debt Redemptions (3,042)
Net Increase in Short-Term Debt 18,400 47,520
Net Cash (Used in) Financing Activities (99,666) (33,777)
Net (Decrease) in Cash and Temporary
Cash Investments (25,701) (156)
Cash and Temporary Cash Investments at
Beginning of Period 25,952 461
Cash and Temporary Cash Investments at
End of Period $ 251 $ 305
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 10,757 $ 11,324
Income Taxes $ 15,142 $ 12,624
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) 1998 Annual Report on Form 10-K and the
Company's Quarterly Report on Form 10-Q for the periods ended March 31, and
June 30, 1999.
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 September 30, 1999 and December
31, 1998, and the results of operations for the three and nine months
ended September 30, 1999 and 1998 and cash flows for the nine months
ended September 30, 1999 and 1998. 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.
In June 1998, the Financial Accounting Standards Board (FASB) issued
SFAS 133, Accounting for Derivative Instruments and Hedging
Activities, which is effective for fiscal years beginning after June
15, 1999. In June 1999, the FASB issued SFAS 137, Accounting for
Derivative Instruments and Hedging Activities - Deferral of the
Effective Date, which amends SFAS 133 to be effective for all fiscal
quarters of all fiscal years beginning after June 15, 2000 (that is,
January 1, 2001 for companies with calendar-year fiscal years). SFAS
133 requires the recognition of all derivative instruments as either
assets or liabilities in the statement of financial position and the
measurement of those instruments at fair value. The Company does not
expect SFAS 133 to have a material impact on its financial position
or results of operations.
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.
In July 1999, EUA filed an application under the Public Utility
Holding Company Act with the Securities and Exchange Commission (SEC)
requesting authorization for Eastern Edison to transfer all of
Eastern Edison's investment in Montaup's securities, including
Montaup's preferred stock, common stock and debenture bonds, to EUA.
Montaup would then become a wholly-owned subsidiary of EUA. Also
related to this transfer, Eastern Edison filed a Petition for
Approval of the transfer or Request for Alternative Findings of No
Jurisdiction with the Massachusetts Department of Telecommunications
and Energy (MDTE). A public hearing was held at the MDTE on October
18, 1999 at which no one from the public intervened. Eastern Edison
is awaiting a decision from the MDTE on its petition, and expects it
will receive SEC approval shortly thereafter.
In July 1999, in connection with Entergy Nuclear Generation Company's
(Entergy) acquisition of Pilgrim Station from Boston Edison, Montaup
agreed to buy out its power purchase agreement (approximately 73 mw)
with Boston Edison. As a condition of the buy-out, Montaup entered
into a reduced term power purchase contract for Pilgrim Station power
with Entergy. Accordingly, Montaup has recorded on Eastern Edison's
Consolidated Balance Sheet as of September 30, 1999, a regulatory
asset of approximately $113.4 million, a corresponding current
regulatory liability of $105.6 million, and a long-term regulatory
liability of $7.8 million.
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:
Nuclear Ownership Issues
General:
Recent actions by the NRC 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.
Millstone 3:
Montaup has a 4.01% ownership interest in Millstone 3, an 1,154 mw
nuclear unit that is jointly owned by a number of New England
utilities, including subsidiaries of Northeast Utilities (Northeast).
Subsidiaries of Northeast are the lead participants in Millstone 3.
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.
In October 1996, the NRC, which had raised numerous issues with
respect to Millstone 3 and certain of the other nuclear units in
which Northeast and its subsidiaries, either individually or
collectively, have the largest ownership shares, informed Northeast
that it was establishing a Special Projects Office to oversee
inspection and licensing activities at Millstone. During the first
week of July 1998, after the NRC performed an inspection and verified
that several final technical and programmatic issues were resolved,
Millstone 3 was restarted, and returned to full power operation on
July 14, 1998. The NRC will continue to closely monitor Millstone
3's performance.
In August 1997, nine non-operating owners, including Montaup, who
together own approximately 19.5% of Millstone 3, 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 3, are Northeast subsidiaries that agreed to be
responsible for the proper operation of the unit.
The non-operating owners of Millstone 3 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 operation and maintenance (O&M)
costs resulting from the shutdown of Millstone 3. The non-operating
owners conservatively estimate that their losses exceed $200 million.
In December 1997, Northeast filed a motion to dismiss the non-
operating owners' claims, or alternatively to stay the pending
lawsuit until after the resolution of the arbitration case. These
requests were denied in July 1998. In May 1999 Northeast filed a
request for summary judgement in the arbitration case. This request
was denied in July 1999. In May 1999, all parties entered into a
Alternative Dispute Resolution Agreement and began mediation sessions
in an effort to reach a settlement of all issues. Montaup
understands that Northeast and its subsidiaries, the Connecticut
Light and Power Company and Western Massachusetts Electric Company
have agreed in principle with New England Power Company (NEP) a
subsidiary of New England Electric System, to settle various
arbitration and litigation claims asserted by NEP, Montaup and the
other non-operating owners of Millstone 3. A settlement on
comparable terms has been offered to Montaup. Montaup will give
serious consideration to the advisability of the settlement as
proposed.
Montaup paid its share of Millstone 3's O&M expenses during the
prolonged outage on a reservation of right basis. The fact that
Montaup paid these expenses is not an admission of financial
responsibility for expenses incurred during the outage.
Given the recent settlement offered to Montaup, the Company does not
expect the outcome of these proceedings to have a material effect on
its operating results or financial position.
Maine Yankee:
Montaup has a 4.0% equity ownership in the permanently closed Maine
Yankee nuclear plant. Montaup's share of the total estimated costs
for the permanent shutdown, decommissioning, and recovery of the
remaining investment in Maine Yankee is approximately $26.5 million
and is included with Other Liabilities on the Consolidated Balance
Sheet as of September 30, 1999. Also, due to recoverability, a
regulatory asset has been recorded for the same amount and is
included with Other Assets.
On November 6, 1997, Maine Yankee submitted an estimate of its costs,
including recovery of unamortized plant investment (including fuel),
to FERC reflecting the fact that the plant was no longer operating
and had entered the decommissioning phase. On January 14, 1998, the
FERC accepted the new rates, subject to refund, and amounts of Maine
Yankee's collections for decommissioning. On January 19, 1999, Maine
Yankee and the active intervening parties, including the Secondary
Purchasers, filed an Offer of Settlement with FERC which was
supported by FERC trial staff on February 8, 1999. The FERC approved
the Settlement effective June 1, 1999. This agreement constitutes
full settlement of the issues raised in this proceeding.
Also, as a result of the shutdown, Montaup and the other equity
owners were notified by the Secondary Purchasers that they would no
longer make payments for purchased power to Maine Yankee. The
Secondary Purchase Contracts are between the equity owners as a group
and 30 municipalities throughout New England. Presently, the equity
owners are making payments to Maine Yankee to cover the payments that
would be made by the municipals.
On November 28, 1997, the Secondary Purchasers sent a Notice of
Initiation of Arbitration to the equity owners of Maine Yankee, which
was denied by a Maine judge on April 7, 1998. The judge indicated
that the jurisdictional question should be first decided by FERC. On
December 15, 1997, the equity owners as a group filed at FERC a
Complaint and Petition for Investigation, Contract Modification, and
Declaratory Order. A separately negotiated Settlement Agreement filed
with FERC on February 5, 1999, was approved by FERC and made
effective on June 1, 1999. This settlement resolved issues raised by
the Secondary Purchasers by limiting the amount they will pay for
decommissioning and settling other points of contention.
The outcome of these recent settlements will not have a material
effect on EUA's future operating results or financial position.
On August 4, 1998, the Maine Yankee Board of Directors selected Stone
& Webster Engineering Corporation to execute a $250 million contract
for the decommissioning and decontamination of Maine Yankee. The
decommissioning plan includes an option for Stone & Webster to
repower the Maine Yankee site with a gas-fired plant.
Vermont Yankee:
Montaup has a 2.5% equity ownership interest in the 540-mw Vermont
Yankee nuclear unit. On October 15, 1999, Vermont Yankee accepted a
bid from AmerGen Energy Company for AmerGen to purchase the unit for
approximately $23.5 million. As part of the agreement, Vermont
Yankee will make a one-time payment to the unit's decommissioning
fund, and AmerGen will assume responsibility for all future operating
costs and costs to decommission the plant at the end of its operating
licence in 2012. Vermont Yankee expects to complete this sale by
mid-2000. This transaction is subject to approvals from the NRC, the
SEC, and the Vermont Public Service Board.
Department of Energy Actions:
In early 1998, Yankee Atomic, Maine Yankee and Connecticut Yankee,
individually, as well as a number of other utilities, filed suit in
federal appeals court seeking a court order to require the Department
of Energy (DOE) to immediately establish a program for the disposal
of spent nuclear fuel. Under the Nuclear Waste Policy Act of 1992,
the DOE was to provide for the disposal of radioactive wastes and
spent nuclear fuel starting in 1998 and has collected funds from
owners of nuclear facilities to do so. On February 19, 1998, Maine
Yankee also filed a petition in the U.S. Court of Appeals seeking to
compel the Department of Energy to remove and dispose of the spent
fuel at the Maine Yankee site. Under their Standard Contract, the
DOE had a deadline for beginning the removal process at all nuclear
plants on January 31, 1998, which was not met. On May 5, 1998, the
Court of Appeals denied several motions brought in the proceeding,
including several motions for injunctive relief brought by the
utility petitioners. In particular, the Court denied the requests to
require the DOE to immediately establish a program for the disposal
of spent nuclear fuel.
Also, Yankee Atomic, Connecticut Yankee, and Maine Yankee filed
lawsuits against the DOE in the U.S. Court of Federal Claims seeking
damages of $70 million, $90 million and $128 million, respectively,
as a result of the DOE's refusal to accept the spent nuclear fuel.
In late October and early November 1998, the U.S. Court of Federal
Claims issued rulings with respect to Yankee Atomic, Maine Yankee,
and Connecticut Yankee finding that the DOE was financially
responsible for failing to accept spent nuclear fuel. These rulings
clear the way for Yankee Atomic, Connecticut Yankee and Maine Yankee
to pursue at trial their individual damage claims. These trials are
expected to begin in early 2000. Management cannot predict at this
time the ultimate outcome of these actions.
Environmental Matters
During the second quarter of 1999, Eastern Edison identified a new
site related to the production of manufactured gas at which certain
environmental conditions may exist. Eastern Edison has conducted a
preliminary assessment of the potential cost of remediation at this
site. An engineering model was recently obtained by the Company to
provide the estimated potential costs. Since site specific studies
have not yet been performed, Eastern Edison has recorded a minimum
liability for this site based on this engineering model to recognize
risk assessment, monitoring, and legal and administrative costs.
Eastern Edison has not yet recorded any estimated environmental
remediation liability for this site. An estimate had not been
recorded on this site because a site-specific study had not yet been
completed and a reliable engineering model deemed essential to
develop a reasonable estimate was not previously available.
Eastern Edison is currently recovering certain environmental cleanup
costs in rates. In addition, Eastern Edison will seek recovery of
certain costs from its insurance carriers and other possible
responsible parties. The Company expects, based on prior regulatory
approvals, to recover such costs in future rates. As a result,
Eastern Edison does not believe that the ultimate impact of the
cleanup costs associated with the previously identified site will be
material to the results of its operations or its financial position.
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.
Merger Update
On February 1, 1999, EUA and New England Electric System (NEES) announced
a merger agreement under which NEES will acquire all outstanding shares of EUA
for $31 per share in cash. The merger agreement, which is subject to the
approval of various regulatory agencies, values EUA's equity at approximately
$634 million, which represents a 23% premium above the price of EUA shares on
December 4, 1998, the last trading day before other regional merger
announcements affected EUA's share price. EUA shareholders will continue to
receive dividends at the current level, as declared by the Board of Trustees,
until the closing of the merger.
The closing of the merger is expected to occur by early 2000. The merger
agreement contains an upward price adjustment in the event the merger does not
close within six months from May 17,1999, the date EUA shareholders approved
the merger plan. Therefore, after November 17, 1999, NEES will pay an
additional $0.003 per day per share for EUA's outstanding common stock until
the merger closes, up to a maximum price of $31.495 per share.
On May 5, 1999, EUA and NEES filed a joint application with the Federal
Energy Regulatory Commission (FERC) seeking FERC approval and related waivers
or authorizations to merge EUA and NEES and to subsequently merge and
consolidate the complimentary operating companies of EUA and NEES. With its
approval on September 29, 1999, FERC concluded that the proposed merger will
not adversely affect competition, rates or regulation, and that the merger is
in the public's best interest.
On May 20, 1999, EUA and NEES jointly filed a rate consolidation plan
with the Rhode Island Public Utilities Commission reflecting consolidated
rates for each company's Rhode Island subsidiaries, indicating savings to
Rhode Island customers of approximately $79 million. Hearings are scheduled
to start in December 1999. A similar filing was made for EUA's and NEES's
Massachusetts subsidiaries on April 30, 1999 with the Massachusetts Department
of Telecommunications and Energy (MDTE) indicating savings of over $100
million. A settlement agreement on the Massachusetts filing is expected
shortly.
On July 19, 1999, a Voluntary Early Retirement Program (VERP) was
offered to certain of EUA's and NEES's employees who will be least
fifty-five years of age by December 31, 2000. The VERP offer was accepted by
82% of eligible employees. On October 12, 1999, details of a Severance Plan
were distributed. The Severance Plan will provide benefits and provisions for
eligible non-union employees who are involuntarily terminated due to the
merger. At the same time, the Company also offered a Limited Hardship Early
Decision Severance Plan (LHEDO) to designated non-union employees who choose
to terminate their employment with EUA rather than be considered for a
position in the merged company. Employees who were offered the LHEDO must
decide if they will accept the offer by November 29, 1999. Under the LHEDO,
employees will receive an additional eight weeks of severance pay for
accepting the offer. At this time, the Company cannot reasonably estimate the
participation in the LHEDO. Therefore, expenses related to this plan have not
yet been recorded.
Overview
Consolidated Net Earnings for the third quarter of 1999 were
approximately $8.4 million as compared to $6.2 million in the third quarter of
1998, and approximately $19.2 million for the nine months ended September 30,
1999 as compared to $20.6 million for the same period of a year ago.
Kilowatthour (kWh) Sales
Kilowatthour (kWh) sales increased 9.8% in the third quarter of 1999 and
5.3% in the year-to-date period of 1999 as compared to the same periods of
1998, largely the result of strong economic conditions in the Company's
service territory and warmer weather in 1999 particularly in the months of
August and September of 1999. These changes were led by 10.9% and 7.0%
increases in sales to residential customers and 8.3% and 4.3% increases in
sales to commercial customers in the third quarter and year-to-date periods,
respectively.
Operating Revenues
Operating Revenues for the three and nine months ended September 30, 1999
decreased by approximately $8.2 million or 8.1% and approximately $4.6 million
or 1.5%, respectively, as compared to the same periods in 1998. Generation-
related revenues decreased approximately $10.0 million for the quarter and $2.6
million for the year-to-date period. Since the sale of Montaup's Somerset
Station in April 1999, and the transfer of its purchased power contracts to
various non-affiliated parties, Blackstone, Eastern Edison and Newport no
longer purchase their standard offer requirements from Montaup, but instead are
buying power from other non-affiliated suppliers (see Electric Industry
Restructuring below). This decrease was compounded by a decrease in the
wholesale contract termination charge rate, effective January 1, 1999 and April
1, 1999, for Rhode Island and Massachusetts and offset by an increase in the
wholesale standard offer rate. Distribution-related revenues increased
approximately $1.8 million for the quarter and decreased approximately $1.9
million for the year-to-date period. These changes were due to increased kWh
sales for the quarter and year-to-date periods. In the year-to-date period,
the kWh sales increase was offset by a full-period impact of rate reductions
coincident with retail access which became effective March 1, 1998 in
Massachusetts.
Operations Expense
Fuel and Purchased Power expense, in aggregate, for the quarter and nine
months ended September 30, 1999 decreased by approximately $1.8 million or
3.3% and increased approximately $13.8 million or 8.7%, respectively, as
compared to the same periods in 1998. These changes were primarily due to
decreased generation-related expenses as a result of the aforementioned
purchases of standard offer requirements from non-affiliated suppliers, offset
by an increase in the wholesale standard offer rate and an increases in kWh
sales in both periods.
Other Operation and Maintenance expenses decreased by approximately $5.2
million or 21.5% and $8.8 million or 12.4% for the third quarter and the nine
months ended September 30, 1999, respectively, compared to the same periods in
1998. The decrease in the third quarter was due to decreased jointly owned
units expenses of $1.6 million which reflects the impact of decreased expenses
of Canal 2 after the sale of the unit in December 1998, decreased conservation
and load management (C&LM) expenses of approximately $500,000, and decreased
FAS106 expenses of approximately $300,000. In the year-to-date period, jointly
owned units expenses decreased approximately $4.1 million, C&LM expenses
decreased approximately $1.5 million and FAS106 expenses decreased by
approximately $300,000. In addition, pension and benefits expenses decreased
in both the third quarter and year-to-date periods of 1999 after the sale of
Montaup's Somerset plant in April 1999. These decreases were offset in the
year-to-date period by the impacts of adjustments to 1998 employee incentive
plan accruals in the first quarter of 1999 and non-recurring expense credits
related to billings to Maine utilities for EUA's storm restoration support in
February of 1998.
Depreciation and Amortization expense decreased approximately $2.1
million or 28.5% in the third quarter and $4.0 million or 18.0% in the
nine-month period ended September 30, 1999 when compared to the same periods
of last year. These decreases were due largely to decreased depreciable
property, particularly since the sale of Montaup's 50% ownership of the Canal
Unit 2 generating station in December of 1998 and the sale of the Somerset
Generating Station in April of 1999.
Taxes - Other Than Income decreased approximately $800,000 or 28.3% in
the third quarter of 1999 and approximately $1.5 or 18.2% in the year-to-date
period of 1999 as compared to the same periods of 1998 as a result of
decreased property taxes after the sale of Montaup's Somerset Generating
Station in April of 1999 and Montaup's 50% ownership of the Canal Unit 2
Generating Station in December of 1998.
Income Taxes
Eastern Edison's effective tax rate for the year-to-date period ended
September 30, 1999 was approximately 39.1% compared to 40.1% for the same
period of a year ago. This decrease is primarily due to investment tax
credits associated with the sale of Montaup's Somerset plant. Current income
tax expense increased by $13.1 million in the second quarter resulting from a
significant tax gain associated with sale of Montaup's Somerset Station. This
increase was almost entirely offset by a decrease in deferred tax expense
resulting from the Somerset property sale.
Other Income - Net
Other Income - Net increased approximately $1.3 million in the third
quarter of 1999 and $2.1 million in the year-to-date period of 1999 as
compared to the same periods of 1998. These changes were due to decreased
expenses related to the Massachusetts referendum to repeal deregulation
legislation in 1998, increased investment income from the sale of Montaup's
Somerset Generating Station in April 1999, and increased interest income on
outstanding power billings.
Net Interest Charges
Net Interest Charges decreased by approximately $1.2 million or 27.4% in
the third quarter of 1999 and decreased by $1.7 million or 13.0% in the
year-to-date period of 1999 as compared to the same periods of 1998. Interest
on long term debt principally decreased as a result of Eastern Edison's
redemption of all of its First Mortgage Bonds in July 1999, its $35 million
7.78% Secured Medium Term Notes in August 1999 and the maturities of its $20
million First Mortgage Bonds in May of 1998 and $40 million First Mortgage
Bonds in July of 1998. These decreases were offset by increased other
interest expense related to revenue reconciliation accounts pursuant to
restructuring settlement agreements.
Liquidity and Sources of Capital
Eastern Edison's and Montaup's need for permanent capital is primarily
related to the construction of facilities required to meet the needs of their
existing and future customers.
Traditionally, cash construction requirements not met with internally
generated funds are obtained through short-term borrowings which are
ultimately funded with permanent capital. In July 1997, several EUA System
companies, including Eastern Edison and Montaup, entered into a three-year
revolving credit agreement allowing for borrowings in aggregate of up to $145
million from all sources of short-term credit. As of September 30, 1999,
various financial institutions have committed up to $75 million under the
revolving credit facility. In addition to the $75 million available under the
revolving credit facility, EUA System companies maintain short-term lines of
credit with various banks totaling $90 million for an aggregate amount
available of $165 million. Eastern Edison and Montaup are negotiating a new
$60 million unsecured revolving credit facility. At September 30, 1999 these
unused EUA System short-term lines of credit amounted to approximately $47.5
million under the revolving credit agreement. The Company had approximately
$18.4 million of short-term debt at September 30, 1999.
In December 1998, Montaup used the proceeds from the sale of its 50%
ownership interest in the Canal 2 Generating Station to Southern Energy for
approximately $75 million to redeem $55 million of Montaup debenture bonds,
wholly-owned by Eastern Edison, and paid a special dividend to Eastern
Edison. Eastern Edison used these proceeds to repay its outstanding
short-term debt and make short-term investments of $25.6 million. In January
1999, Eastern Edison used those investments to retire 551,956 shares of its
outstanding, $25 par value, common stock at a price of $41.67 per share.
In April 1999, Montaup completed the sale of its Somerset Station to NRG
Energy Inc. for approximately $55 million. In July 1999, Montaup used the
proceeds from this sale to redeem $54.8 million of its outstanding securities
wholly-owned by Eastern Edison. Eastern Edison used these proceeds along with
a capital contribution from EUA to redeem $40 million of 8%, $40 million of 6
7/8%, and $8 million of 6.35% First Mortgage and Collateral Trust Bonds.
The Company's year-to-date September 30, 1999 internally generated funds
available after the payment of dividends amounted to $82.1 million while its
cash construction requirements for the same period were $10.0 million.
In July 1999, EUA filed an application under the Public Utility Holding
Company Act with the Securities and Exchange Commission (SEC) requesting
authorization for Eastern Edison to transfer all of Eastern Edison's
investment in Montaup's securities, including Montaup's preferred stock,
common stock and debenture bonds, to EUA. Montaup would then become a
wholly-owned subsidiary of EUA. Also related to this transfer, Eastern Edison
filed a Petition for Approval of the transfer or Request for Alternative
Findings of No Jurisdiction with the MDTE. A public hearing was held at the
MDTE on October 18, 1999 at which no one from the public intervened. Eastern
Edison is awaiting a decision from the MDTE on its petition, and expects SEC
approval shortly thereafter.
Electric Utility Industry Restructuring
Legislation enacted in Rhode Island in 1996 and Massachusetts in 1997
along with approved electric utility industry restructuring settlement
agreements in both states and at the federal level, granted EUA's Rhode Island
and Massachusetts electric customers with choice of electricity supplier and
rate reductions commencing January 1, 1998 and March 1, 1998, respectively.
Until a customer chooses an alternative supplier, that customer will receive
standard offer service from the retail distribution company. Blackstone and
Newport are required to arrange for standard offer service through December
31, 2009 and Eastern Edison must arrange for this service through February 28,
2005. Under the approved settlement agreements, Montaup had guaranteed
standard offer supply at a fixed price schedule for the duration of the
standard offer periods and Blackstone, Newport and Eastern Edison agreed to
subject their standard offer requirements to a competitive bidding process in
which competitive suppliers would bid against the guaranteed price. Through
its successful divestiture process, combined with a competitive bidding
process conducted in late 1998, Montaup has assigned 100% of its standard
offer obligation. A majority of this standard offer assignment became
effective January 1, 1999; the remainder became effective on September 1, 1999
with the closing of the transfer of power purchase agreements to Constellation
Power Source Inc. (Constellation), see Generation Divestiture below. The
guaranteed standard offer price will increase over time to encourage customers
to leave standard offer service and enter the competitive power supply
market.
Provisions of the approved settlement agreements also allowed Montaup to
replace its all-requirements wholesale contracts with its affiliated retail
distribution companies with a contract termination charge (CTC) which permits
Montaup to recover, among other things, its above market investments and
commitments in generation assets along with an 80% ratepayer/20% shareholder
sharing mechanism for ongoing nuclear generation operations. Montaup began
billing the CTC coincident with retail access and the distribution companies
are recovering the CTC through a non-bypassable transition charge to all of
their distribution customers.
As part of the approved settlement agreements, Montaup agreed to divest
its entire generation portfolio. The net proceeds of the sale, as defined in
the settlement agreements, will be used to mitigate Montaup's CTC to its
retail affiliates via a Residual Value Credit (RVC). The RVC reduces the
fixed component of the CTC by an amount equal to the net proceeds, with a
return, over the period commencing on the date the RVC is implemented through
December 31, 2009. Effective April 1, 1999, subject to dispute resolution
procedures pursuant to restructuring settlement agreements, Montaup reduced
its CTC to its retail subsidiaries to reflect the RVC and other adjustments.
Montaup lowered its CTC from 3.04 cents per kWh to 2.10 cents per kWh for
Eastern Edison and from 3.0 cents per kWh to 2.04 cents per kWh and 2.06 cents
per kWh in the case of Blackstone and Newport, respectively. Retail transition
charge decreases to reflect these changes were authorized by respective state
regulatory bodies effective April 1, 1999 for Eastern Edison and May 1, 1999
for Blackstone and Newport.
Effective January 1, 1999 the standard offer service rate for Blackstone
and Newport customers was increased from an average 3.2 cents per kilowatthour
to an average 3.5 cents per kilowatthour. Coincident with the May 1, 1999
reduction in Blackstone's and Newport's retail transition charge, the standard
offer rate was changed to a flat rate of 3.5 cents per kilowatthour for all
customer classes.
The standard offer service rate for Eastern Edison customers was
increased to a flat rate of 3.1 cents per kilowatthour effective January 1,
1999. This rate was further increased to 3.5 cents per kilowatthour coincident
with the Eastern Edison retail transition charge decrease effective April 1,
1999.
Generation Divestiture
By the end of 1998, pursuant to settlement agreements approved by federal
and state regulators, Montaup signed agreements to sell all of its non-nuclear
power generation assets and power purchase agreements to various
non-affiliated parties in connection with electric utility restructuring
undertaken in Massachusetts and Rhode Island. At the end of 1998, Montaup
sold several diesel-powered generating units (totaling approximately 16 mw)
owned by Newport to Illinois-based Wabash Power Equipment Company for
approximately $1.4 million and its 50% share (approximately 280 mw) of Unit 2
of the Canal generating station in Sandwich, Massachusetts to Southern Energy
Canal, LLC an indirect subsidiary of The Southern Company, for approximately
$75 million. On April 7, 1998, Montaup entered into an agreement to transfer
power purchase contracts for approximately 170 mw of output from Ocean State
Power I and Ocean State Power II to TransCanada Power Marketing Ltd., an
indirect subsidiary of TransCanada Pipelines Limited; the transfer was
effective June 1, 1999. On December 21, 1998, Montaup entered into an
agreement to transfer purchase power contracts totaling approximately 177 mw
to Constellation Power Source, Inc., a wholly-owned affiliate of the Baltimore
Gas and Electric Company; the transfer became effective on September 1, 1999.
On April 26, 1999, Montaup completed the sale of its 170 mw Somerset
Generating Station, located in Somerset, Massachusetts, to Somerset Power,
LLC, a direct subsidiary of NRG, Inc., for approximately $55 million. In
June of 1999, Montaup completed the sale of its and Newport's combined 2.6%
(approximately 16 mw) share of the W.F. Wyman Unit 4 in Yarmouth, Maine to FPL
Energy Wyman IV LLC, an indirect subsidiary of the Florida-based FPL Group,
Inc for $2.4 million. Also in June of 1999, Blackstone sold its hydroelectric
facility in Pawtucket, Rhode Island (approximately 1 mw) to Putnam Hydropower
LLC, an affiliate of Pawtucket Hydropower Inc.
In July 1999, in connection with Entergy Nuclear Generation Company's
acquisition of Pilgrim Station from Boston Edison, Montaup agreed to buy out
its power purchase agreement (approximately 73 mw) with Boston Edison. As a
condition of the buy-out, Montaup entered into a reduced term power purchase
contract for Pilgrim Station power with Entergy Nuclear Generation Company.
Accordingly, Montaup recorded on EUA's Consolidated Balance Sheet as of
September 30, 1999, a regulatory asset of approximately $113.4 million, a
corresponding current regulatory liability of $105.6 million, and a long-term
regulatory liability of $7.8 million.
In October 1999, Vermont Yankee agreed to the sell the 540-mw nuclear
unit to AmerGen Energy Company for approximately $23.5 million. Montaup has a
2.5% (12 mw) equity ownership interest in the unit. As part of the agreement,
Vermont Yankee will make a one-time payment to the unit's decommissioning
fund, and AmerGen will assume responsibility for all future operating costs
and costs to decommission the plant at the end of its operating license in
2012. Vermont Yankee expects to complete this sale by mid-2000.
Montaup also has agreed to sell its ownership interest in the Seabrook
Station nuclear power plant to Little Bay Power Corporation, a subsidiary of
BayCorp Holdings, Ltd.. Montaup has received all federal and state approvals
regarding the sale of its interest in Seabrook and expects to close on this
sale later in 1999. EUA's only remaining generating capacity is approximately
58 mw from its ownership share of the Millstone 3 nuclear facility. EUA
ultimately intends to sell and/or transfer its interest in Millstone 3. All
of the sale and contract transfer agreements are subject to federal and/or
state regulatory approvals, including that of the NRC with respect to the sale
of nuclear units.
The Year 2000 Issue
EUA is addressing the Year 2000 issue on an EUA System basis, which
includes Eastern Edison. On June 30, 1999, EUA reported to the North American
Electric Reliability Council (NERC) that all of its mission critical systems
were Year 2000 ready, consistent with the recommended industry schedule
published by NERC. The EUA Year 2000 Program addressed the potential impact
on computer systems and embedded systems and components resulting from a
common software program code convention that utilized two digits instead of
four to represent a year. If not addressed, the year 2000 could have been
systemically recognized as the year 1900, causing system or equipment failures
or malfunctions, and ultimately resulting in disruptions to Company
operations. This disclosure constitutes a Year 2000 Statement and Readiness
Disclosure. It is subject to the protections afforded it as such by the Year
2000 Information and Readiness Disclosure Act of 1998.
EUA's State of Readiness:
To address potential Year 2000 issues, EUA divided the focus of its Year
2000 Program into three major categories of business activity: the generation
and delivery of electricity to customers, the acquisition of goods and
services (including purchased power), and ongoing general and administrative
activities related to the corporate infrastructure and support functions,
which included among other things, billings and collections.
Based on work completed as of December 31, 1998, the following types and
quantities of date sensitive information technology (IT) systems were
identified and remediated:
>Central Applications: 54 date sensitive items consisting of centralized
computing software that addressed major business and operational needs
were identified; 67% required repair or replacement.
>Server Based Networks: 22 date sensitive items consisting of networked
applications, as well as supporting computing and communications
equipment were identified; 55% required repair or replacement.
>Desktops: 48 categories of items typically consisting of personal
computer hardware and software were identified; 52% of such categories
required repair or replacement.
>Infrastructure: 44 items consisting of components of central IT
operations (e.g., the mainframe computer, its operating system and
centralized database) were identified; 57% required repair or
replacement.
>Embedded Systems and Components: 3,977 items were identified; 96.3% were
Y2K ready or inert. 3.7% were tested -- none failed.
EUA utilized a four phase approach to address IT issues. The four phases
were: Analysis, Remediation, Unit Testing and Integration Testing. The
Analysis phase consisted of two stages. The first stage consisted of
conducting an inventory of all products, applications and systems, department
by department. The second stage consisted of an assessment of the risk
(potential impact and likelihood of failure) of each item identified in the
inventory. Items identified as not being Year 2000 ready were repaired or
replaced during the Remediation phase. The Unit Testing phase involved testing
at the module, program and application levels to assure that each such item
functioned properly after repair or replacement. Finally, in the Integration
Testing phase, dates were moved ahead, data were aged, and all date conditions
pertinent to each application or product were tested "end-to-end" to assure
that each item was tested in its final complete environment. As of June 30,
1999, each phase described above was 100% completed and all mission critical
systems were Year 2000 ready. All mission critical non-information services
systems (i.e., embedded systems and components) were also 100% Year 2000 ready
as of that date as well.
EUA developed a process to identify and assess the Year 2000 readiness of
third parties with which it had a material relationship. First, a list of all
vendors utilized over the prior two years was developed from the accounts
payable system. Sub-lists were then developed and distributed to departments
based on the departmental allocation of charges for goods and services.
Departmental managements worked with the purchasing department to rank vendors
identified as being critical or important.
All vendors, regardless of rank, were contacted in writing requesting
information regarding their Year 2000 status. Vendors ranked as critical or
important were selected for additional inquiry, in the form of additional
written inquiry and telephone inquiries. If available, vendor literature,
regulatory filings and web sites were also reviewed. Critical vendors included
providers of a variety of goods and services, such as telecommunications,
banking and other financial services, computer products and services,
equipment, fuel and mail delivery. As a result of this process, the purchasing
department and/or the department(s) utilizing the goods or services in
question have been able to confirm to their satisfaction that all mission
critical vendors and a significant majority of the important vendors have
provided adequate evidence of their Year 2000 readiness. All remaining vendors
are being monitored as the process of gathering their Year 2000 readiness
information continues. This process was essentially complete on June 30, 1999.
Contingency plans have been developed for services provided by all mission
critical vendors. These plans identify workarounds for any mission critical
vendor for which there is not an alternative source.
Costs to Address EUA's Year 2000 Issues:
Through September 30, 1999, EUA has incurred costs of approximately $6.9
million to address Year 2000 issues, including approximately $4.3 million of
non-incremental labor, $1.2 million of capital expenditures and $1.4 million
of consulting and other costs. The company estimates it will incur
additional costs approximating $1.1 million during the period October 1, 1999
through March 31, 2000, to complete its Year 2000 Program including
approximately $700,000 of non-incremental labor and $400,000 of consulting and
other costs.
Risks of EUA's Year 2000 Issues:
EUA's first priority continues to be the minimization of any potential
disruptions to electric service as a result of the Year 2000. The provision
of electric service depends in large part on the viability of the New England
power grid which is managed by ISO/NEPOOL. EUA is actively participating on
ISO/NEPOOL's Year 2000 operating and oversight committees. EUA's assessment of
its own transmission and distribution equipment and facilities indicated that
the risk of failure of this equipment does not appear to be significant.
However, due to the interconnectivity of the New England power grid, and the
reliance on many other entities also connected to the grid, it is not possible
to conclude with certainty that there will be no significant interruptions in
service.
In addition, dependable voice and data telecommunications are critical to
EUA's ongoing operations. EUA's internal telecommunication systems were Year
2000 ready as of June 30, 1999. EUA also relies heavily on external
telecommunication systems, i.e., the local and regional telephone systems, and
has identified these providers as critical vendors. EUA has gathered extensive
documentation regarding the Year 2000 efforts and status of the regional
telephone companies upon which it relies. In addition, EUA has also had
face-to-face meetings with representatives of these companies and attended
public conferences sponsored by these companies, at which they have described
their Year 2000 process and progress. Each of these companies anticipates
being Year 2000 ready and devoid of major system failures. Nevertheless, EUA
has provided for several methods for maintaining adequate communications. For
example, if the regional, land-line telephone systems were not in service, EUA
could rely on mobile or cellular telephones. If those failed, EUA maintains
mobile radios. Further, all of EUA's operating locations, including EUA
Service Corporation's, are linked through a captive microwave
telecommunications system.
No other significant reasonably likely failure scenarios stemming solely
from problems relating to Year 2000 have been identified thus far.
Accordingly, EUA does not currently believe that any Year 2000 related risks
in and of themselves constitute reasonably likely worst case scenarios.
Rather, EUA's most reasonably likely Year 2000 related worst case scenario
would be the occurrence of isolated year 2000 failures such as described above
in conjunction with a severe winter storm. However, EUA believes that such
year 2000 failures would not likely affect whether the storm event would have
a material impact on EUA's business or financial condition. In this context,
and based on its communications with key vendors and customers and its long
experience with storm events, EUA does not currently anticipate significant
adverse effects on its relationships with its customers or vendors, or any
resulting material adverse effects on its business or operations.
<PAGE>Year 2000 Contingency Plans:
Contingency planning teams consisting of managers and employees
experienced in system reliability, disaster recovery and risk were established
and made responsible for developing contingency plans. The overall strategy
was to identify Year 2000 risks, both internal and external to EUA, that could
have a material impact on EUA's operations or financial well-being. For such
risks, formal, written contingency plans were created. Preliminary plans were
developed in March, 1999 and final contingency plans were in place and ready
to implement as of June 30, 1999.
In addition to the contingency plans described above which are designed
to ensure a rapid recovery from any Year 2000 related failures, EUA has also
developed a formal, written Implementation Plan. The purpose of this plan is
to ensure that the activities necessary to maintain a clean systems
environment from July 1, 1999 through the transition weekend and into the year
2000 are properly planned for, appropriately communicated throughout the
company, and understood by those responsible for performing the various tasks.
This plan includes provisions for additional staffing during the transition
weekend to monitor mission critical systems and to resolve any Year 2000
issues which might arise. The Implementation Plan was in place as of June 30,
1999.
Summary:
The amount of effort and resources necessary to address Year 2000 issues
and make EUA Year 2000 ready has been significant. There are currently
dedicated teams in place, guided by a formal implementation plan, to ensure
EUA remains Year 2000 ready through the remainder of 1999 and into the next
century. EUA's Year 2000 program has consistently been on schedule and in
accordance with timetables and progress points published by NERC. This effort
culminated with the June 30, 1999 reporting to NERC that EUA had achieved 100%
Year 2000 readiness for all mission critical systems and embedded components.
EUA has utilized independent, outside technical consultants and other experts
to review and assess its Year 2000 efforts and status throughout the project.
Their findings have validated the progress and status of the company's Year
2000 project and the achievement of Year 2000 readiness. Management is
confident that EUA's Year 2000 project has been, and continues to be, well
managed with the appropriate resources and plans in place to ensure the
Company remains Year 2000 ready and positioned for a successful transition to
the Year 2000.
Other
The Company occasionally makes forward-looking projections of expected
future performance or statements of our plans and objectives. These
forward-looking statements may be contained in filings with the SEC, press
releases and oral statements. This report contains information about the
Company's future business prospects including, without limitation, statements
about the potential impact of Year 2000 issues on the Company's financial
condition or results. These statements are considered "forward-looking"
within the meaning of the Private Securities Litigation Reform Act. These
statements are based on the Company's current plans and expectations and
involve risks and uncertainties that could cause actual future activities and
results of operations to be materially different from those set forth in the
forward-looking statements. The Company expressly undertakes no duty to
update any forward-looking statement.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See "Note C - Commitments and Contingencies: Nuclear Ownership Issues
(NRC) Actions" for a discussion of pending legal actions involving several of
the nuclear plants in which Montaup has an ownership interest.
Item 5. Other Information
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 was 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 were 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 NEPOOL's bulk power
transmission facilities. The NEPOOL Tariff promotes competition in the New
England power market through its single transmission 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.
On April 20, 1998, FERC accepted the NEPOOL Tariff conditional on
NEPOOL's compliance with a number of issues raised by FERC. On July 22, 1998,
NEPOOL made its compliance filing at FERC. The NEPOOL Tariff changes and
amendments to the Restated NEPOOL Agreement included in the filing effected
compliance with the Commission's April 20, 1998 Order. While there were a
large number of changes in the filing, the principal areas of change relate to
the addition in the NEPOOL Tariff of a separately available Internal Point to
Point Service, the addition of a mechanism to allocate costs to update the
regional transmission system, and the replacement of a Non-Use Charge with an
In-Service Charge across interconnections. A settlement agreement was filed
on April 7, 1999. An order accepting the settlement was received on July 30,
1999 and a compliance filing was made on September 28, 1999.
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,
automatic generation control, 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 meet 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. On October 29, 1997, FERC issued an order permitting
implementation of the installed capability market, which occurred in April of
1998. On April 6, 1999, FERC issued an order approving market rules and on
May 1, 1999, the remaining markets (operable capability, energy, automatic
generation control and the reserve markets) were implemented.
A Notice of Proposed Rulemaking by the FERC dated May 13, 1999 is
proposing to amend its regulations under the Federal Power Act (FPA) to
facilitate the formation of Regional Transmission Organizations (RTO's). FERC
proposes to require that each public utility that owns, operates, or controls
facilities for the transmission of electric energy interstate commerce make
certain filings with respect to forming and participating in an RTO.
See "Note C - Commitments and Contingencies: Environmental Matters" for a
discussion of a newly identified site where Eastern Edison could be joint and
severally responsible for environmental cleanup costs.
Item 6. Exhibits and Reports on Form 8-K
(a)Exhibits - None.
(b)Reports on Form 8-K
- None filed in the quarter ended September 30, 1999.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Eastern Edison Company
(Registrant)
Date: November 15, 1999 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr. Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)
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