UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 April 30, 1999
Common Shares, $25 par value 2,339,401 shares
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
ASSETS March 31, December 31,
1999 1998
<S> <C> <C>
Utility Plant in Service $ 743,948 $ 741,902
Less: Accumulated Provision for Depreciation
and Amortization 258,429 252,301
Net Utility Plant in Service 485,519 489,601
Construction Work in Progress 4,746 2,691
Net Utility Plant 490,265 492,292
Current Assets:
Cash and Temporary Cash Investments 5,047 25,952
Accounts Receivable - Other 52,733 44,556
- Associated Companies 23,947 18,628
Fuel,Materials and Supplies 8,652 9,965
Other Current Assets 4,369 4,754
Total Current Assets 94,748 103,855
Deferred Debits and Other Non-Current Assets 315,832 235,475
Total Assets $ 900,845 $ 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 107,643 106,509
Total Common Equity 204,132 225,998
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (1,579) (1,670)
Long-Term Debt - Net 162,559 162,550
Total Capitalization 394,777 416,543
Current Liabilities:
Accounts Payable - Associated Companies 9,658 8,987
- Other 30,666 25,502
Taxes Accrued 14,008 17,361
Interest Accrued 3,611 3,561
Other Current Liabilities 19,985 18,725
Total Current Liabilities 77,928 74,136
Deferred Credits and Other Non-Current Liabilities 309,819 221,300
Accumulated Deferred Taxes 118,321 119,643
Total Liabilities and Capitalization $ 900,845 $ 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
March 31,
1999 1998
<S> <C> <C>
Operating Revenues $ 109,868 $ 108,928
Operating Expenses:
Fuel and Purchased Power 63,686 54,296
Other Operation and Maintenance 22,015 23,568
Depreciation and Amortization 7,539 7,464
Taxes - Other Than Income 3,037 2,917
Income Taxes - Current 4,998 3,738
- Deferred (Credit) (501) 2,583
Total 100,774 94,566
Operating Income 9,094 14,362
Allowance for Other Funds
Used During Construction 47 40
Other Income - Net 512 254
Income Before Interest Charges 9,653 14,656
Interest Charges:
Interest on Long-Term Debt 2,883 3,751
Other Interest Expense 1,335 848
Allowance for Borrowed Funds Used
During Construction (Credit) (53) (33)
Net Interest Charges 4,165 4,566
Net Income 5,488 10,090
Preferred Dividend Requirements 497 497
Consolidated Net Earnings $ 4,991 $ 9,593
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Three Months Ended
March 31,
<S> <C> <C>
1999 1998
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 5,488 $ 10,090
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 7,005 7,981
Amortization of Nuclear Fuel 531 207
Deferred Taxes (501) 2,585
Investment Tax Credit, Net (325) (325)
Allowance for Other Funds Used During Construction (173) (40)
Other - Net 6,690 (2,568)
Change in Operating Assets and Liabilities (8,002) (1,605)
Net Cash Provided From Operating Activities 10,713 16,325
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (4,355) (2,594)
Net Cash (Used in) Investing Activities (4,355) (2,594)
CASH FLOW FROM FINANCING ACTIVITIES:
Retirement of Common Stock (23,000)
Common Stock Dividends Paid to EUA (3,766) (7,806)
Preferred Dividends Paid (497) (497)
Net (Decrease) Increase in Short-Term Debt (2,435)
Net Cash (Used in) Financing Activities (27,263) (10,738)
Net (Decrease) in Cash and Temporary
Cash Investments (20,905) 2,993
Cash and Temporary Cash Investments at
Beginning of Period 25,952 461
Cash and Temporary Cash Investments at
End of Period $ 5,047 $ 3,454
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 2,793 $ 3,986
Income Taxes $ 9,980 $ 5,612
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.
Note A - In the opinion of the Company, the accompanying unaudited
consolidated condensed financial statements contain all adjustments
(consisting of only normal recurring accruals) necessary to present
fairly the financial position as of March 31, 1999 and the results of
operations and cash flows for the three months ended March 31, 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.
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 March 1998, The Accounting Standards Executive Committee of the
American Institute of Certified Public Accountants (AICPA) issued
Statement of Position 98-1, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use (SOP 98-1), effective
in 1999. SOP 98-1 provides specific guidance on whether to
capitalize or expense costs within its scope.
In June 1998, the Financial Accounting Standards Board issued FAS133,
"Accounting for Derivative Instruments and Hedging Activities," which
is effective in fiscal 2000. 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 is currently evaluating the
impact FAS133 will have on its financial position or results of
operations.
Note B - Results shown above for the respective interim periods are not
necessarily indicative of results to be expected for the fiscal years
due to seasonal factors which are inherent in electric utilities in
New England. A greater proportionate amount of revenues is earned
in the first and fourth quarters (winter season) of most years
because more electricity is sold due to weather conditions, fewer
day-light hours, etc.
Note C- Commitments and Contingencies:
Recent Nuclear Regulatory Commission (NRC) Actions
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. The Special
Projects Office was responsible for (1) licensing and inspection
activities at Northeast's Connecticut plants, (2) oversight of an
Independent Corrective Action Verification Program (ICAVP), (3)
oversight of Northeast's corrective actions related to safety issues
involving employee concerns, and (4) inspections necessary to
implement NRC oversight of the plant's restart activities.
Also, the NRC directed Northeast to submit a plan for disposition of
safety issues raised by employees and retain an independent third-
party to oversee implementation of this plan.
On April 8, 1998, Northeast announced that Millstone 3 was ready for
NRC inspection, indicating that virtually all of the restart-required
physical work had been completed. On June 29, 1998, the NRC
authorized Northeast to begin restart activities of Millstone 3. The
authorization was given after the NRC staff verified that several
final technical and programmatic issues were resolved. Millstone 3
was restarted during the first week of July, 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
arbitration until after the resolution of the arbitration case.
These requests were denied in July 1998.
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.
EUA 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 shutdown 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 $30.3 million
and is included with Other Liabilities on the Consolidated Balance
Sheet as of March 31, 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. FERC also granted
intervention requests and ordered a public hearing on the prudency of
Maine Yankee's decision to shut down the plant and on the
reasonableness of the proposed rate amendments. 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. Upon
commission approval, this agreement will constitute full settlement
of 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. Prior to shutdown, the
municipals had been assigned 0.41% of Montaup's 4.0% entitlement
share of Maine Yankee and Montaup had retained a 3.59% share.
On November 28, 1997, the Secondary Purchasers sent a Notice of
Initiation of Arbitration to the equity owners of Maine Yankee. On
December 15, 1997, the equity owners as a group filed at FERC a
Complaint and Petition for Investigation, Contract Modification, and
Declaratory Order. On April 7, 1998, a Maine judge denied the
Secondary Purchasers' motion to compel arbitration and indicated the
jurisdictional question should be first decided by FERC. On April
15, 1998, the Secondary Purchasers notified FERC of the judge's
decision and asked for expedited action on the pending complaint
against them for non-payment. 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.
Management does not believe that these settlements, if approved, will
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.
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. Management cannot
predict at this time the ultimate outcome of these actions.
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, expected by early 2000.
Proxy statements which include details of the merger have been distributed
along with voting instructions. Approval of the merger requires a two-thirds
shareholder vote. EUA's Annual Meeting of Shareholders is scheduled for May
17, 1999.
On April 30, EUA and NEES jointly filed a rate plan with the Massachusetts
Department of Telecommunications and Energy reflecting consolidated rates
following the merger for each company's Massachusetts subsidiaries. A similar
filing for EUA's and NEES's Rhode Island companies before the Rhode Island
Public Utilities Commission is expected in the near future.
On April 30, the EUA and NEES merger plan received clearance under the
federal Hart-Scott-Rodino Act. Under the Act, EUA and NEES had to file certain
information with the Federal Trade Commission and the Department of Justice.
Those agencies have reviewed the filings and have determined that the merger
will not violate anti-trust laws.
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.
Overview
Consolidated Net Earnings for the first quarter of 1999 were $5.0 million,
compared to first quarter 1998 net earnings of $9.6 million. First quarter
1999 earnings reflect a full quarter's impact of Massachusetts restructuring
settlement agreements, which became effective March 1, 1998 and provided, among
other things, rate reductions to all of Eastern Edison's customers. Also,
1998 first quarter results included billings to Maine utilities for storm
restoration support and $1.7 million of increased unbilled revenue
(subsequently offset in the second quarter) due to timing of restructured
rates. These negative impacts on earnings were offset somewhat by a 1.4%
increase in kilowatthour sales for the quarter.
Operating Revenues
Operating Revenues increased approximately $900,000 to $109.9 million in
the first quarter of 1999 compared to the same period in 1998. Generation-
related revenues increased approximately $4.9 million as a result of the
assignment of entitlements from certain power contracts to third parties and
associated repurchases and sale of energy to satisfy standard offer
requirements (see Electric Industry Restructuring below). Offsetting this
increase were the impacts of rate reductions to all of EUA's retail customers,
pursuant to electric industry restructuring legislation and settlements
effective January 1, 1998 and March 1, 1998, in Rhode Island and Massachusetts,
respectively. Distribution-related revenues decreased approximately $3.9
million due to the net impacts of restructured rates and increased kWh sales
for the period.
Operating Expenses
Fuel and Purchased Power expenses, in aggregate, increased approximately
$9.4 million, or 17.3% in the first quarter of 1999 as compared to the same
period of 1998. This increase is due to the assignment of entitlements from
certain power contracts to third parties and associated repurchases of energy
to satisfy standard offer requirements. Also impacting this increase was a
1.4% increase in kilowatthour sales in the first quarter of 1999.
Other Operation and Maintenance (O&M) expenses for the first quarter of
1999 decreased approximately $1.6 million from the same period in 1998. This
decrease is primarily due to decreased jointly-owned units expense of $2.1
million, $1.5 of which is due to the sale of Canal Unit 2 in December of 1998,
decreased charges from other utilities of approximately $400,000 and decreased
conservation and load management expenses of approximately $300,000. Offsetting
these decreases were increased expenses related to employee incentive plan
true-ups in the first quarter of 1999 and non-recurring expense credits related
to billings to Maine utilities for the Company's storm restoration support in
February of 1998.
Net Interest Charges
Net Interest Charges decreased by approximately $400,000 or 8.8% in the
first quarter of 1999 as compared to the same period 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. Offsetting this decrease
was increased other interest expense related to revenue reconciliation accounts
pursuant to restructuring settlement agreements.
Income Taxes
Eastern Edison's effective tax rate for the quarter ended March 31, 1998
was approximately 45.1% compared to 39.6% for the same period of a year ago.
This increase reflects the impact of accelerated reversal of timing differences
pursuant to restructuring settlement agreements along with lower taxable income
in the first quarter of 1999.
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.
In the utility industry, 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 December 31, 1998,
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 March 31, 1999, under the revolving credit
agreement the EUA System had unused short-term lines of credit of approximately
$120.0 million.
At March 31, 1999, Eastern Edison and Montaup had zero outstanding short-
term debt. On December 30, 1998, Montaup completed the sale of its 50%
ownership interest in the Canal 2 generating station, in Sandwich
Massachusetts, to Southern Energy for approximately $75 million. Montaup used
the proceeds from the sale to 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 the first quarter of
1999, internally generated funds amounted to $15.1 million while cash
construction requirements for the same period were approximately $4.4 million.
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 to purchasers of its generating assets. 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 increased to 3.5 cents per kilowatthour coincident with the Eastern
Edison retail transition charge decrease effective April 1, 1999.
Generation Divestiture
On April 26, 1999, Montaup completed the sale of its 170 mw Somerset
Generating Station, located in Somerset, Massachusetts, to NRG Energy Inc.
(NRG), a subsidiary of Northern States Power Company, for approximately $55
million. Closing of the transaction, originally announced in October 1998,
culminates 75 years of power plant operation by Montaup.
The sale of Montaup's 50% share (280 mw) of Unit 2 of the Canal generating
station in Sandwich, Massachusetts to Southern Energy for $75 million, which
was announced in May 1998, was completed on December 30, 1998, and the sale of
two diesel-powered generating units (totaling approximately 16 mw) owned by
Newport to Illinois-based Wabash Power Equipment Co. for $1.5 million closed on
October 1, 1998.
Montaup's agreements to transfer purchase power contracts totalling
approximately 177 mw to Constellation, to sell its 2.6% (16 mw) share of the
W. F. Wyman Unit 4 in Yarmouth Maine to the Florida-based FPL group for
approximately $2.4 million and for the transfer of its power purchase contracts
with Ocean State Power (170 mw) to TransCanada are anticipated to occur in
the second quarter of 1999. The sale of Montaup's 2.9% share (34 mw) of the
Seabrook Station nuclear power plant to the Great Bay Power Corporation and the
renegotiation of its 11% (73 mw) power entitlement from the Pilgrim Nuclear
Power Station in Plymouth, Massachusetts are expected to take place later in
1999. All of the sale and contract transfer agreements are subject to
federal and/or state regulatory approvals, including that of the Nuclear
Regulatory Commission with respect to the Seabrook sale.
Montaup's remaining generating capacity includes approximately 46 mw from
its 4.0% joint ownership share of Millstone 3 nuclear unit and 12 mw from its
2.25% equity ownership of the Vermont Yankee nuclear facility.
The Year 2000 Issue
EUA is addressing the Year 2000 issue on an EUA System basis, which
includes Eastern Edison. EUA's Year 2000 Program (Program) continues to
proceed on schedule toward its goal of achieving Year 2000 readiness on or
before June 30, 1999. The Program is addressing the potential impact on
computer systems and embedded systems and components resulting from a common
software program code convention that utilizes two digits instead of four to
represent a year. If not addressed, the year 2000 may be systemically
recognized as the year 1900, which could cause system or equipment failures or
malfunctions, and ultimately result 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 has 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 relating to the corporate infrastructure and support
functions, which include among other things, billings and collections.
Based on work completed as of December 31, 1998, the following date
sensitive IT systems and remediation needs were identified:
> Central Applications: 54 date sensitive items consisting of
centralized computing software that addresses 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%
are Year 2000 ready or inert. 3.7% must be tested - any that fail
will be replaced.
EUA utilizes a four phase approach in addressing information technology
(IT) issues. The four phases are: 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 are
repaired or replaced during the Remediation phase. The Unit Testing phase
involves testing at the module, program and application level to assure that
each such item still functions properly after repair or replacement. Finally,
in the Integration Testing phase, dates are moved ahead, data are aged, and all
date conditions pertinent to each application or product are tested "end-to-
end" to assure that each item is tested in its final complete environment.
For mission critical systems, as of March 31, 1999, the phases described above
were at the following percentages of completion: Analysis - 100%; Remediation -
100%; Unit Testing - 100%. The most recent information regarding Integration
Testing is as of April 26, 1999. At that date, Integration Testing was 85%
complete. EUA is on schedule to achieve Year 2000 readiness for 100% of
mission critical projects by June 30, 1999. For non-I/T projects, as of the
end of April 1999, approximately 99% are either Year 2000 ready or not affected
by the Year 2000. The remaining items are in the process of being remediated
and tested and are scheduled to be Year 2000 ready by June 30, 1999.
EUA has an ongoing process to identify and assess the Year 2000 readiness
of third parties with which it has 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 a significant majority of
the 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. Where necessary, contingency plans
will be developed. This process is on schedule to be completed by June 30,
1999. All critical vendors except one are Year 2000 ready or on schedule to be
ready by December 31, 1999. The single exception is the municipality which
provides infrastructure services to EUA Service Corporation. Contingency plans
are in the process of being developed for services provided by this
municipality, as well as for all other critical vendors. Such plans will
identify workarounds for any critical vendor for which there is not an
alternative source.
Costs to Address EUA's Year 2000 Issues:
Through March 31, 1999, EUA has incurred costs of approximately $4.7
million to address Year 2000 issues, including approximately $2.6 million of
non-incremental labor, $1.2 million of capital expenditures and $900,000 of
consulting and other costs. Due to their nature, the capital expenditures and
the consulting and other costs are not allocable to the various phases of EUA's
Year 2000 Program identified above; however, the $2.6 million in non-
incremental labor costs can be assigned to particular phases of the Company's
Year 2000 project, in the following amounts: Analysis - $600,000; Remediation -
$550,000; Unit Testing - $550,000; and Integration Testing - $900,000. EUA
estimates it will incur additional costs approximating $5.3 million during the
period January 1, 1999 through March 31, 2000, to complete its resolution of
Year 2000 issues including approximately $3.8 million of non-incremental labor,
$500,000 of capital expenditures and $1.0 million of consulting and other
costs. Again, due to the nature of the capital, consulting and other costs,
they are generally not allocable to particular phases of EUA's Year 2000
Program; however, certain non-incremental labor costs may be assigned as
follows: Integration Testing - $2.6 million. In addition, EUA estimates it will
incur approximately $1.2 million in non-incremental labor costs during the
period July 1, 1999 through March 31, 2000 for Year 2000 related activities
such as: retesting, documentation review, communications outreach and customer
and vendor awareness programs, training, maintaining a "clean room"
environment, transition weekend preparations, transition weekend activities,
and post-transition weekend problem resolution. Because 70% of the total
estimated costs associated with the Year 2000 issue relate to non-incremental
internal labor, management continues to believe that the Year 2000 will not
present a material incremental impact to future operating results or financial
condition.
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 are either
Year 2000 ready now, or on schedule to become Year 2000 ready, by 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 have been
established and are responsible for developing contingency plans. The overall
strategy will be 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. Preliminary plans were developed by March 31, 1999. Final plans are
scheduled to be in place and ready to implement, if necessary, by June 30,
1999.
Summary:
The amount of effort and resources necessary to address Year 2000 issues
and make EUA Year 2000 ready is significant. There are dedicated teams in place
to ensure EUA's transition into the next century occurs with minimal
disruption. By the end of December 1998, EUA had the equivalent of twenty full
time employees working on its Year 2000 project. Beginning in 1999, during
peak times, up to 7 contract programmers have been added to help EUA's
permanent IT staff deal with internal Year 2000 activities. Also, more than 12
vendor-provided IT professionals have been used to help with various short
duration Year 2000 projects specifically targeting that vendor's products.
EUA's Year 2000 program is on schedule and in accordance with timetables and
progress points published by the North American Electric Reliability Council.
In addition, EUA is utilizing outside technical consultants and other experts
to help ensure that its Year 2000 program remains on schedule and effective and
that risk and resource issues are appropriately assessed and addressed.
Management believes EUA's Year 2000 project is well managed and has the
appropriate resources and plans in place to ensure the Company is 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: Recent Nuclear Regulatory
Commission (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.
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.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits - None.
(b) Reports on Form 8-K- On January 5, 1999, Eastern Edison Company
filed a Current Report on Form 8-K with respect to Item 5 (Other
Events).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Eastern Edison Company
(Registrant)
Date: May 14, 1999 /s/Clifford J. Hebert, Jr., Treasurer
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant
and as Principal Financial Officer)
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