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, 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 July 31, 1999
Common Shares, $25 par value 2,339,401 shares
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
ASSETS June 30, December 31,
1999 1998
Utility Plant in Service $ 674,188 $ 741,902
Less: Accumulated Provision for Depreciation
and Amortization 223,334 252,301
Net Utility Plant in Service 450,854 489,601
Construction Work in Progress 7,564 2,691
Net Utility Plant 458,418 492,292
Current Assets:
Cash and Temporary Cash Investments 57,069 25,952
Accounts Receivable - Other 47,704 44,556
- Associated Companies 15,839 18,628
Fuel, Materials and Supplies 2,198 9,965
Other Current Assets 4,453 4,754
Total Current Assets 127,263 103,855
Deferred Debits and Other Non-Current Assets 335,024 235,475
Total Assets $ 920,705 $ 831,622
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Stock, $25 Par Value $ 58,485 $ 72,284
Other Paid-In Capital 38,048 47,249
Common Stock Expense (44) (44)
Retained Earnings 109,530 106,509
Total Common Equity 206,019 225,998
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (1,488) (1,670)
Long-Term Debt - Net 162,567 162,550
Total Capitalization 396,763 416,543
Current Liabilities:
Notes Payable 1,680
Accounts Payable - Associated Companies 10,379 8,987
- Other 22,884 25,502
Taxes Accrued 19,004 17,361
Interest Accrued 3,534 3,561
Other Current Liabilities 20,984 18,725
Total Current Liabilities 78,465 74,136
Deferred Credits and Other Non-Current Liabilities 334,755 221,300
Accumulated Deferred Taxes 110,722 119,643
Total Liabilities and Capitalization $ 920,705 $ 831,622
See accompanying notes to consolidated condensed financial statements.
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(In Thousands)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
Operating Revenues $ 100,031 $ 97,342 $ 209,899 $ 206,270
Operating Expenses:
Fuel and Purchased Power 57,566 51,366 121,252 105,662
Other Operation and Maintenance 20,881 22,907 42,896 46,475
Depreciation and Amortization 5,480 7,462 13,019 14,926
Taxes - Other Than Income 1,869 2,749 4,906 5,666
Income Taxes - Current 11,306 634 16,304 4,372
- Deferred (Credit) (6,673) 2,853 (7,174) 5,436
Total 90,429 87,971 191,203 182,537
Operating Income 9,602 9,371 18,696 23,733
Allowance for Other Funds
Used During Construction 49 12 96 52
Other Income - Net 613 40 1,125 294
Income Before Interest Charges 10,264 9,423 19,917 24,079
Interest Charges:
Interest on Long-Term Debt 2,882 3,556 5,765 7,307
Other Interest Expense 1,181 616 2,516 1,464
Allowance for Borrowed Funds Used
During Construction (Credit) (41) (52) (94) (85)
Net Interest Charges 4,022 4,120 8,187 8,686
Net Income 6,242 5,303 11,730 15,393
Preferred Dividend Requirements 497 497 994 994
Consolidated Net Earnings $ 5,745 $ 4,806 $ 10,736 $ 14,399
See accompanying notes to consolidated condensed financial statements.
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Six Months Ended
June 30,
1999 1998
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 11,730 $ 15,393
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 14,324 15,855
Amortization of Nuclear Fuel 924 409
Deferred Taxes (7,836) 5,441
Investment Tax Credit, Net (1,667) (651)
Allowance for Other Funds Used During Construction (96) (52)
Other - Net (14,367) (6,475)
Change in Operating Assets and Liabilities 10,358 (403)
Net Cash Provided From Operating Activities 13,370 29,517
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (9,041) (6,396)
Proceeds from Divestiture of Generation Assets 56,635
Net Cash Provided From (Used in) Investing Activities 47,594 (6,396)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Common Stock (23,000)
Long-Term Debt (20,000)
Common Stock Dividends Paid to EUA (7,533) (15,613)
Preferred Dividends Paid (994) (994)
Net Increase in Short-Term Debt 1,680 13,470
Net Cash (Used in) Financing Activities (29,847) (23,137)
Net Increase (Decrease) in Cash and Temporary
Cash Investments 31,117 (16)
Cash and Temporary Cash Investments at
Beginning of Period 25,952 461
Cash and Temporary Cash Investments at
End of Period $ 57,069 $ 445
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 5,782 $ 7,711
Income Taxes $ 15,120 $ 7,708
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 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 period ended March 31, 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 its financial position as of June 30, 1999 and December 31,
1998, and the results of operations for the three and six months
ended June 30, 1999 and 1998 and cash flows for the six months ended
June 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 issued SFAS
133, "Accounting for Derivative Instruments and Hedging Activities,"
which is effective in fiscal year 2001. This statement 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
requesting authorization for Eastern Edison to transfer all of
Eastern Edison's investment in Montaup's capitalization, including
Montaup's preferred stock, common stock and debenture bonds, to EUA.
Montaup would then become a wholly-owned subsidiary of EUA.
Note B - Results shown for the respective interim periods being reporting
herein 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. 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.
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. This effort is
ongoing.
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.
The Company cannot predict the ultimate outcome of legal proceedings
brought against CL&P, WMECO and Northeast or the impact they may have
on Montaup and the EUA system.
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 $27.4 million
and is included with Other Liabilities on the Consolidated Balance
Sheet as of June 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, upon approval, would resolve issues
raised by the Secondary Purchasers by limiting the amount they will
pay for decommissioning and settling other points of contention. The
FERC approved the Settlement effective June 1, 1999.
The outcome of these recent settlements will not have a material
effect on the Company'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. Vermont Yankee has been in negotiations since
March 1999 with AmerGen Energy Co. for AmerGen to purchase the unit.
On August 2, 1999, Vermont Yankee announced that it had also received
an unsolicited expression of interest form Entergy Nuclear, Inc. to
buy the unit. Vermont Yankee has commenced negotiations with Entergy
and at the same time, is continuing its negotiations with AmerGen.
Vermont Yankee intends to reach a final agreement to sell the unit by
October 1, 1999. This transaction is subject to approvals from the
NRC, the Securities and Exchange Commission, and the Vermont Public
Service Board. Montaup cannot predict the ultimate outcome of these
negotiations.
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
EUA recently identified new sites related to the production of
manufactured gas at which pre-existing environmental conditions may
exist. One site pertains to Eastern Edison, a manufactured gas plant
that was located at Rose Street, in Stoughton, Massachusetts. This
site was built in the 1800's and ceased operations early this
century. EUA may have joint and several liability for investigation
and remediation at these sites, if such actions are necessary. EUA
is currently conducting a preliminary assessment of the potential
costs of remediation and therefore, has not yet provided for this
potential liability.
Eastern Edison is currently recovering certain environmental cleanup
costs in rates. In addition, The Company will seek recovery of
certain costs from its insurance carriers and other possible
responsible parties. As a result, the Company does not believe that
the ultimate impact of the cleanup costs associated with this
additional environmental site will be material to its results of
operations or 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 EUA shareholders and various regulatory agencies, values the equity
of EUA 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. EUA and NEES expect that
the merger will be finalized by early 2000, but are trying to accomplish
it earlier.
At EUA's Annual Meeting of Shareholders on May 17, 1999, EUA shareholders
voted to approve EUA's merger with NEES. At the meeting, 97% of the votes
received were in favor of the merger.
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.
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. 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 indicating savings of over $100
million.
As part of the merger process, on July 19, 1999, a Voluntary Early
Retirement Program was offered to certain of EUA's and NEES's union and non-
union employees who are least fifty-five years of age. In addition,
information on the Limited Hardship Early Decision Option (LHEDO) to be offered
in September 1999, the employees' voluntary severance package and relocation
assistance for those employees who qualify have also been announced.
Overview
Consolidated Net Earnings for the second quarter of 1999 were
approximately $5.7 million, compared to the net earnings of the second quarter
1998 of $4.8 million. For the six months ended June 30, 1999, net earnings were
approximately $10.7 million, compared to net earnings of $14.4 million for the
respective period of 1998.
Kilowatthour Sales
Kilowatthour (kWh) sales increased 4.3% in the second quarter of 1999 and
2.8% in the year-to-date period of 1999 as compared to the same periods of
1998, largely the result of warmer weather in 1999, particularly during the
month of June. These changes were led by 5.5% and 4.8% increases in sales to
residential customers in the second quarter and year-to-date periods,
respectively.
Operating Revenues
Operating Revenues for the three and six months ended June 30, 1999
increased by approximately $2.7 million or 2.8% and approximately $3.6 million
or 1.8%, respectively, as compared to the same periods in 1998. Generation-
related revenues increased approximately $2.5 million for the quarter and $7.3
million for the year-to-date period, as a result of the assignment of
entitlements from certain power purchase contracts to third parties and
associated repurchases and sale of energy to satisfy standard offer
requirements (see Electric Industry Restructuring below). This increase was
compounded by an increase in the wholesale standard offer rate and offset by a
decrease in the wholesale contract termination charge rate, effective January
1, 1999 and April 1, 1999, for Rhode Island and Massachusetts, respectively.
Distribution-related revenues increased approximately $200,000 for the quarter
and decreased approximately $3.7 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.
Operating Expenses
Fuel and Purchased Power expense, in aggregate, for the quarter and six
months ended June 30, 1999 increased by approximately $6.2 million or 12.1% and
approximately $15.6 million or 14.8%, respectively, as compared to the same
periods in 1998. These increases were primarily due to increased generation-
related expenses as a result of the aforementioned repurchase of energy to
satisfy standard offer requirements, compounded by an increase in the wholesale
standard offer rate and an increase in kWh sales.
Other Operation and Maintenance (O&M) expenses decreased approximately
$2.0 million or 8.8%, and approximately $3.6 million or 7.7%, for the second
quarter and year-to-date periods of 1999, respectively, as compared to the same
periods of 1998. The decrease in the second quarter was due to decreased
conservation and load management (C&LM) expenses of approximately $600,000,
decreased jointly owned units expenses of $400,000 which reflects the net
impacts of decreased expenses of $2.1 million of Canal 2 after the sale of the
unit in December 1998 offset by increased expenses at the Millstone and
Seabrook units of $1.7 million due to the timing of their scheduled maintenance
outages. In addition pension and benefits expenses decreased in both the
second quarter and year-to-date periods of 1999 after the sale of Montaup's
Somerset plant in April 1999. Also, in the year-to-date period, jointly owned
units expense decreased approximately $2.5 million which consists of decreased
expenses of Canal 2 of $3.6 million offset by increased expenses of Millstone
and Seabrook of $1.2 million. These decreases were further 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, which aggregated approximately $2.3 million.
Depreciation and Amortization expense decreased approximately $2.0 million
or 26.6% in the second quarter and $1.9 million or 12.8% in the six month
period ended June 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 $900,000 or 32.0% in the
second quarter of 1999 and approximately $800,000 or 13.4% 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.
Other Income - Net
Other Income - Net increased approximately $600,000 in the second quarter
of 1999 and $80,000 in the year-to-date period of 1999 as compared to the same
periods of 1998. These increases were due to the release of investment tax
credits associated with the sale of Montaup's Somerset Generating Station in
April of 1999.
Income Taxes
Eastern Edison's effective tax rate for the year-to-date period ended June
30, 1999 was approximately 38.8% compared to 40.4% 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 $10.7 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.
Net Interest Charges
Net Interest Charges decreased by approximately $100,000 or 2.4% in the
second quarter of 1999 and decreased by $500,000 or 5.7% in the year-to-date
period of 1999 as compared to the same periods of 1998. Interest on long term
debt decreased as a result of normal cash sinking fund payments and the
maturities of Eastern Edison's $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 June 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.
At June 30, 1999 these unused EUA System short-term lines of credit amounted to
approximately $113.5 million under the revolving credit agreement. The Company
had approximately $1.7 million of short-term debt at June 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 $30 million of its debenture bonds and $24.8
million, or 164,600 shares, of its outstanding $100 par value common stock.
Eastern Edison used these proceeds along with a capital contribution from EUA
of $40 million 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 June 30, 1999 internally generated funds
available after the payment of dividends amounted to $53.8 million while its
cash construction requirements for the same period were $9.0 million.
In July 1999, EUA filed an application under the Public Utility Holding
Company Act with the Securities and Exchange Commission requesting
authorization for Eastern Edison to transfer all of Eastern Edison's investment
in Montaup's capitalization, including Montaup's preferred stock,
common stock and debenture bonds, to EUA. Montaup would then become a wholly-
owned subsidiary of EUA.
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 with the remainder to be effective 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 has 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 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 will
become 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. As a result of the sale, a regulatory asset has
been recorded and is included in Other Assets, and a regulatory liability has
been recorded and is included in Other Liabilities on the Consolidated Balance
Sheet. 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 bought 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.
Montaup also has agreed to sell its ownership interest in the Seabrook
Station nuclear power plant to Great Bay Power Corporation, a subsidiary of
BayCorp Holdings, Ltd., with an expected closing later in 1999. EUA's
remaining generating capacity comprises 58 mw from its ownership shares of the
Millstone 3 and Vermont Yankee nuclear facilities. EUA is in negotiations to
sell and/or transfer its interests in the Vermont Yankee facility, (see "Note C
- -Commitments and Contingencies: Nuclear Ownership Issues") and ultimately
intends to sell and/or transfer its interests in Millstone 3 as well. 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. EUA has reached a notable milestone with its Year 2000
Program (Program). 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 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 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 year 2000 ready or inert. 3.7% were tested -- none failed.
EUA utilized a four phase approach to address information technology (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 level 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 June 30, 1999, EUA has incurred costs of approximately $6.4
million to address Year 2000 issues, including approximately $3.9 million of
non-incremental labor, $1.2 million of capital expenditures and $1.3 million of
consulting and other costs. The company estimates it will incur additional
costs approximating $3.6 million during the period July 1, 1999 through March
31, 2000, to complete its Year 2000 Program including approximately $2.5
million of non-incremental labor, $500,000 of capital expenditures and $600,000
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 to 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.
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. The
Implementation Plan was completed and 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 the North American
Electric Reliability Council (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" for
a discussion of pending legal actions involving several of the nuclear plants
in which Montaup has an ownership interest.
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 21, 1999 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 in its entirety.
(c) The only matters voted on in the Consent to Action was the election
of directors.
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 and an order accepting the settlement was received on July 30, 1999 with a
compliance filing due in sixty days.
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.
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.
See "Note C - Commitments and Contingencies: Environmental Matters" for a
discussion of newly identified sites where the Company 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.
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 13, 1999 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)