UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998
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 October 31, 1998
Common Shares, $25 par value 2,891,357 shares
<TABLE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
ASSETS September 30, December 31,
1998 1997
<S> <C> <C>
Utility Plant in Service $ 821,962 $ 822,990
Less: Accumulated Provision for Depreciation
and Amortization 296,448 279,711
Net Utility Plant in Service 525,514 543,279
Construction Work in Progress 10,409 2,248
Net Utility Plant 535,923 545,527
Current Assets:
Cash and Temporary Cash Investments 305 461
Accounts Receivable - Other 41,097 40,777
- Associated Companies 16,332 14,143
Fuel, Materials and Supplies 9,302 7,982
Other Current Assets 3,641 3,688
Total Current Assets 70,677 67,051
Deferred Debits and Other Non-Current Assets 191,936 164,546
Total Assets $ 798,536 $ 777,124
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Stock, $25 Par Value $ 72,284 $ 72,284
Other Paid-In Capital 47,250 47,249
Common Stock Expense (44) (44)
Retained Earnings 99,461 98,979
Total Common Equity 218,951 218,468
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (1,761) (2,053)
Long-Term Debt - Net 162,541 162,491
Total Capitalization 409,396 408,571
Current Liabilities:
Long - Term Debt Due Within One Year 0 60,000
Notes Payable 52,195 4,675
Accounts Payable - Associated Companies 10,588 7,317
- Other 24,663 27,113
Taxes Accrued 1,382 2,325
Interest Accrued 3,876 4,923
Other Current Liabilities 12,898 15,011
Total Current Liabilities 105,602 121,364
Deferred Credits and Other Non-Current Liabilities 142,294 107,714
Accumulated Deferred Taxes 141,244 139,475
Total Liabilities and Capitalization $ 798,536 $ 777,124
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(In Thousands)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
<S> <C> <C> <C> <C>
1998 1997 1998 1997
Operating Revenues $ 101,769 $ 109,971 $ 308,039 $ 324,275
Operating Expenses:
Fuel 26,177 29,277 76,053 82,408
Purchased Power 26,337 28,134 82,123 90,798
Other Operation and Maintenance 24,068 27,698 70,543 77,379
Early Retirement Offer 0 0 737
Depreciation and Amortization 7,463 6,891 22,389 20,672
Taxes - Other Than Income 2,718 2,608 8,384 8,276
Income Taxes - Current 5,449 3,680 9,821 14,251
- Deferred (Credit) (1,361) (30) 4,075 (3,770)
Total 90,851 98,258 273,388 290,751
Operating Income 10,918 11,713 34,651 33,524
Allowance for Other Funds
Used During Construction 43 111 95 170
Other Income - Net 78 366 372 1,972
Income Before Interest Charges 11,039 12,190 35,118 35,666
Interest Charges:
Interest on Long-Term Debt 2,883 3,752 10,190 11,255
Other Interest Expense 1,560 941 3,024 2,739
Allowance for Borrowed Funds Used
During Construction (Credit) (82) (35) (167) (131)
Net Interest Charges 4,361 4,658 13,047 13,863
Net Income 6,678 7,532 22,071 21,803
Preferred Dividend Requirements 497 497 1,491 1,491
Consolidated Net Earnings $ 6,181 $ 7,035 $ 20,580 $ 20,312
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN EDISON COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 22,071 $ 21,803
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 23,587 21,471
Amortization of Nuclear Fuel 859 880
Deferred Taxes 4,082 (3,949)
Investment Tax Credit, Net (976) (702)
Allowance for Other Funds Used During Construction (95) (170)
Other - Net 2,387 (1,959)
Change in Operating Assets and Liabilities (7,064) 14,651
Net Cash Provided From Operating Activities 44,851 52,025
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (11,340) (11,635)
Decrease in Other Investments 110
Net Cash (Used in) Investing Activities (11,230) (11,635)
CASH FLOW FROM FINANCING ACTIVITIES:
Common Stock Dividends Paid to EUA (19,806) (40,419)
Preferred Dividends Paid (1,491) (1,490)
Net (Decrease) in Long-Term Debt (60,000) 0
Net Increase in Short-Term Debt 47,520 960
Net Cash (Used in) Financing Activities (33,777) (40,949)
Net (Decrease) in Cash and Temporary
Cash Investments (156) (559)
Cash and Temporary Cash Investments at
Beginning of Period 461 2,105
Cash and Temporary Cash Investments at
End of Period $ 305 $ 1,546
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 11,324 $ 10,451
Income Taxes $ 12,624 $ 15,518
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) 1997 Annual Report on Form 10-K and the
Company's Quarterly Report on Form 10-Q for the periods ended March 31, and
June 30, 1998.
Note A - In the opinion of the Company, the accompanying unaudited
consolidated condensed financial statements contain all adjustments
(consisting of only normal recurring accruals) necessary to present
fairly the financial position as of September 30, 1998 and December
31, 1997, and the results of operations for the three and nine months
ended September 30, 1998 and 1997 and cash flows for the nine months
ended September 30, 1998 and 1997. 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.
As more fully discussed in "Management's Discussion and Analysis of
Financial Condition and Results of Operations," customer choice of
electricity supplier commenced on January 1, 1998 and March 1, 1998
for EUA's Rhode Island and Massachusetts retail distribution
customers, respectively. Coincident with retail access, Montaup
Electric Company (Montaup), EUA's generation and transmission
company, began billing its affiliated EUA electric distribution
companies, Blackstone Valley Electric Company (Blackstone) and
Newport Electric Corporation (Newport), in Rhode Island, and Eastern
Edison Company (Eastern Edison), in Massachusetts, a contract
termination charge (CTC). The CTC permits Montaup to recover, among
other things, its above market investment in generation assets over a
period of twelve years, a period shorter than the expected useful
lives of these assets. As a result, Montaup is deferring revenue in
an amount equal to the difference between depreciation expense
recorded pursuant to generally accepted accounting principles and the
level of asset recovery included in the CTC. In addition, provisions
of the CTC formula require Montaup to accrue and/or defer revenues
related to recovery of certain of its generation-related expenses.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Note B - Results shown above for the respective interim periods are not
necessarily indicative of results to be expected for the fiscal years
due to seasonal factors which are inherent in electric utilities in
New England. A greater proportionate amount of revenues is earned in
the first and fourth quarters (winter season) of most years because
more electricity is sold due to weather conditions, fewer day-light
hours, etc.
Note C - Commitments and Contingencies:
Recent Nuclear Regulatory Commission (NRC) Actions
General:
Recent actions by the NRC indicate that the NRC has become more critical
and active in its oversight of nuclear power plants. Montaup is unable
to predict at this time, what, if any, ramifications these NRC actions
will have on any of the nuclear power plants in which the Company has an
ownership interest or power contract.
Millstone 3:
Montaup has a 4.01% ownership interest in Millstone 3, a 1,154-megawatt
(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) over sight 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 o f 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 on July 14, 1998, Millstone 3 returned to full
power operations. 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 two-year 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
owner's claims, or alternatively to stay pending arbitration. These
requests were denied in July 1998.
Montaup pays its share of Millstone 3's O&M expenses on a reservation of
right basis. The fact that Montaup makes payment for these expenses is
not an admission of financial responsibility for expenses incurred or to
be incurred due to the outage.
Montaup cannot predict the ultimate outcome of the legal proceedings
brought against CL&P, WMECO and Northeast or the impact they may have on
the Company and the EUA system.
Connecticut Yankee:
Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July
1996 because of issues related to certain containment air recirculation
and service water systems.
Montaup has a 4.5% equity ownership in Connecticut Yankee.
In October 1996, Montaup, as one of the joint owners, participated in an
economic evaluation of Connecticut Yankee which recommended permanently
closing the unit and replacing its output with less expensive energy
sources. In December 1996, the Board of Directors of Connecticut Yankee
voted to retire the generating station. Connecticut Yankee certified to
the NRC that it had permanently closed power generation operations
and removed fuel from the reactor. Montaup's share of the total
estimated costs for the permanent shutdown, decommissioning, and
recovery of the investment in Connecticut Yankee is approximately $24.8
million and is included with Other Liabilities on the Consolidated
Balance Sheet as of September 30, 1998. The recovery of this estimated
amount, elements of which have been disputed by certain intervening
parties, is subject to approval of the Federal Energy Regulatory
Commission (FERC). Also, due to anticipated recoverability, a regulatory
asset has been recorded for the same amount and is included with Other
Assets.
On August 31, 1998, a FERC law judge rejected Connecticut Yankee's plan
to decommission the plant. The judge claimed that estimates of clean-up
costs were flawed and certain restoration costs were not supported. The
judge also said Connecticut Yankee could not pass on spent fuel storage
costs to rate-payers. The judge recommended that Connecticut Yankee
withdraw its decommissioning plan and submit a new plan which addresses
the issues cited by him. FERC will review the judge's recommendations
and issue a decision on this case in the coming months. If FERC concurs
with the judge's recommendation, this may result in a write down of
certain of Connecticut Yankee plant investments. Montaup cannot predict
the ultimate outcome of FERC's review.
Maine Yankee:
On August 6, 1997, as the result of an economic evaluation, the Maine
Yankee Board of Directors voted to permanently close that nuclear plant.
Montaup has a 4.0% equity ownership in Maine Yankee.
On November 5, 1997, Maine Yankee submitted a rate filing to the FERC to
provide for recovery of its costs during the decommissioning period.
The filing provides for the investment in plant, nuclear fuel and
associated facilities to continue to be recovered through October 2008.
On November 6, 1997, Maine Yankee submitted an estimate of its costs to
the 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 May 20, 1998, FERC issued a schedule
which set the discovery and testimony phase of the case through the
remainder of 1998, with a settlement conference scheduled for February
15, 1999, and a hearing scheduled for April 1, 1999.
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.
Also, as a result of the August 1997 shutdown, Montaup and the other
equity owners have been notified by the Secondary Purchasers that they
will 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% share 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. The equity owners are seeking an order from FERC declaring
that the Secondary Purchasers remain responsible for payments due under
the Purchase Contracts and directing the Secondary Purchasers to make
such payments. The equity owners also seek a modification of the
Secondary Purchase Contracts to extend the termination date or otherwise
to ensure that the equity owners may fully recover from the Secondary
Purchasers a share of the costs of shutting down and decommissioning the
Maine Yankee plant that is proportionate to the Secondary Purchasers'
entitlements to energy from the plant. Management does not believe that
this contract issue will have a material effect on Montaup's future
operating results or financial position and cannot predict its ultimate
outcome at this time.
Department of Energy Actions:
In addition to its 4.5% and 4.0% equity ownership in Connecticut Yankee
and Maine Yankee, respectively, Montaup also has a 4.5% equity ownership
interest in the Yankee Atomic nuclear generating station. This facility
has also permanently ceased power generation operations and is in the
process of decommissioning the site.
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 would 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.
Massachusetts Referendum
See Massachusetts Referendum in Item 2. Management's Discussion and
Analysis of Financial Condition and Results of Operations for a
discussion of a referendum in Massachusetts to repeal deregulation
legislation that was rejected by voters on the November 1998 ballot.
Year 2000 Issue
See Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations for a discussion of potential impacts as a
result of the Year 2000 issue.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following is Management's discussion and analysis of certain
significant factors affecting the Company's earnings and financial condition
for the interim periods presented in this Form 10-Q.
Overview
Consolidated Net Earnings for the third quarter of 1998 were approximately
$6.2 million as compared to $7.0 million in the third quarter of 1997, and
approximately $20.6 million for the nine months ended September 30, 1998 as
compared to $20.3 million for the same period of a year ago. The year-to-date
period of 1997 includes a one-time, after-tax charge of approximately $500,000,
related to the June 1997 early retirement offer.
Kilowatthour (kWh) Sales
A combination of warmer weather and the continued strength of the regional
economy led to kWh sales increases of 6.5% and 3.2% in the three and nine-month
periods ending September 30, 1998, respectively. The third quarter increase
was led by increases of 8.2% and 5.2% in the residential and commercial
customer classes, which are typically more weather sensitive, and a 5.7%
increase in sales to industrial customers. For the year-to-date period, sales
of electricity to residential, commercial and industrial customers increased
approximately 1.8%, 3.6% and 6.3%, respectively, as compared to the same period
of 1997.
Operating Revenues
Operating Revenues decreased $8.2 million or 7.5% and $16.2 million or
5.0% in the three and nine month periods ended September 30, 1998,
respectively, as compared to the same periods of 1997. These decreases were
due primarily to rate reductions coincident with retail access which became
effective January 1, 1998 and March 1, 1998 in Rhode Island and Massachusetts,
respectively. Offsetting these decreases somewhat were increased recoveries of
conservation and load management (C&LM) expenses of approximately $400,000 and
$1.4 million in the respective periods, a 6.5% and a 3.2% increase in kWh sales
for the respective periods, and revenues accrued by Montaup pursuant to
approved settlement agreements.
Operations Expense
Fuel expense decreased by approximately $3.1 million or 10.6% and $6.4
million or 7.7% for the third quarter and year-to-date periods of 1998,
respectively, as compared to the same periods of 1997. For the third quarter,
nuclear units provided a greater share of kWh requirements along with a 16.9%
decrease in the cost of fossil fuels, resulting in a 18.2% decrease in average
fuel costs. For the year-to-date period, increased nuclear generation and a
13.8% decrease in the cost of fossil fuels resulted in a 17.4% decrease in the
average cost of fuel as compared to the nine months ended September 30, 1997.
Offsetting these decreases in fuel expense for the third quarter and year-to-
date periods were increases in total energy generated and purchased of 6.4% and
8.3%, respectively.
Purchased Power demand expense for the third quarter of 1998 decreased
approximately $1.8 million or 6.4% and $8.7 million or 9.6% for the nine months
ended September 30, 1998. The third quarter decrease is due to decreased
billings from Maine Yankee and Pilgrim. The year-to-date decrease is the
result of decreased billings from Maine Yankee, Connecticut Yankee, Pilgrim and
Ocean State Power.
Other Operation and Maintenance expenses decreased by approximately $3.6
million or 13.1% and $6.8 million or 8.8% for the third quarter and the nine
months ended September 30, 1998, respectively, compared to the same periods in
1997. Jointly owned units expense decreased $2.8 million and $4.9 million in
the third quarter and year-to-date periods, respectively, largely due to
decreased expenses at Millstone 3, Canal 2 and Seabrook. Legal expenses
decreased approximately $800,000 in the third quarter and approximately
$600,000 in the year-to-date period. Maintenance expenses decreased
approximately $300,000 in the third quarter and $600,000 in the year-to-date
period as the result of an extensive maintenance outage at Montaup's Somerset
Station in 1997. The year-to-date period includes decreased expenses of
approximately $400,000 as a result of higher restructuring-related assessments
by FERC in 1997 and storm-related expenses as a result of the April 1997 storm
which struck Eastern Edison's service territory. These decreases were offset
by increased C&LM expenses of $400,000 in the third quarter and $1.4 million in
the year-to-date period.
Income Taxes
Eastern Edison's effective tax rate for the nine months ended September
30, 1998 was approximately 40.1% compared to 33.9% for the same period of a
year ago. Provisions of restructuring settlement agreements which require the
acceleration of the catch-up of deferred tax deficiencies created under prior
regulatory practices are primarily responsible for this change.
Depreciation and Amortization Expense
Depreciation and Amortization expense increased approximately $600,000 or
8.3% in the third quarter and $1.7 million or 8.3% in the year-to-date period
as compared to the same periods of 1997 due largely to amortization of certain
regulatory assets pursuant to restructuring settlement agreements.
Other Income (Deductions) - Net
Other Income and (Deductions)-Net decreased approximately $300,000 in this
year's third quarter and approximately $1.6 million in the year-to-date period
as compared to the same periods of 1997. The decreases in both periods were
due, in part, to expenses related to the Massachusetts referendum to repeal
deregulation legislation. In addition, the year-to-date decrease reflects the
absence of interest income allocated to the Company by EUA Service Corporation
related to the favorable resolution of a Massachusetts corporate income tax
dispute in the first quarter of 1997.
Net Interest Charges
Net Interest charges decreased by approximately $300,000 or 6.4% in the
third quarter and approximately $800,000 or 5.9% in the year-to-date period.
Interest on long term debt decreased as a result of the maturities of the
Company'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 interest
expense on increased short term borrowings which were used to finance the long-
term debt maturities.
Liquidity and Sources of Capital
Eastern Edison's and Montaup's need for permanent capital is primarily
related to the construction of facilities required to meet the needs of their
existing and future customers.
Traditionally, cash construction requirements not met with internally
generated funds are obtained through short-term borrowings which are ultimately
funded with permanent capital. In July 1997, several EUA System companies,
including Eastern Edison and Montaup, entered into a three-year revolving
credit agreement allowing for borrowings in aggregate of up to $145 million
from all sources of short-term credit. As of September 30, 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 September 30, 1998 these unused EUA System short-term lines of
credit amounted to approximately $46.3 million. The Company had $52.2 million
of short-term debt at September 30, 1998.
The Company's year-to-date September 30, 1998 internally generated funds
available after the payment of dividends amounted to $34.5 while its cash
construction requirements for the same period were $11.3 million.
Electric Utility Industry Restructuring
Legislation in both Rhode Island and Massachusetts along with approved
electric utility industry restructuring settlement agreements in both states
and at the federal levels, provided 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. 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. Montaup has guaranteed standard
offer supply at a fixed price schedule for the duration of the standard offer
periods. The guaranteed standard offer price will increase over time to
encourage customers to leave standard offer service and enter the competitive
power supply market. Under the approved settlement agreements, 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 offered by Montaup. The competitive process was
completed in April 1998, and resulted in none of the standard offer
requirements being awarded to competitive suppliers. Montaup will therefore
continue to provide the unawarded standard offer requirement at the indicated
fixed price schedule. This wholesale standard offer service will be assigned
to purchasers of Montaup's generating capacity.
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. 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 will reduce 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. Montaup is committed to implement the RVC within 90 days of closing
either the Canal or Somerset sale agreement. See Divestiture below.
For a more detailed discussion of electric industry restructuring, refer
to EUA's 1997 Annual Report on Form 10K.
Massachusetts Referendum
On November 3, 1998, Massachusetts voters overwhelmingly rejected a
referendum to repeal the Massachusetts Electric Utility Restructuring Act.
Divestiture
On October 15, 1998, EUA announced that Montaup has signed an agreement to
sell its 160-mw Somerset (Massachusetts) electric generating station for
approximately $55 million to NRG Energy, Inc., a wholly-owned subsidiary of
Northern States Power Co. based in Minneapolis, Minnesota. The sale also
includes an additional 69 mw of currently deactivated generating capacity, and
real estate at the Somerset site, and generating equipment at the 1.2 mw
Pawtucket Hydro Station in Pawtucket Rhode Island, which is owned by
Blackstone. With the Somerset sale agreement, EUA has now committed to sell all
of its non-nuclear power generation assets.
EUA had previously entered into agreements to sell: its 50 percent share
(280 mw) of Unit 2 of the Canal Generating Station in Sandwich, Massachusetts
to Southern Energy for approximately $75 million; 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; two diesel-powered generating units (totaling
approximately 16 mw) owned by Newport to Illinois-based Wabash County Equipment
Co. for $1.5 million.
In addition, Montaup has agreed to sell its 2.9 percent share (34 mw) of
the Seabrook Station nuclear power plant to the Great Bay Power Corporation, a
subsidiary of BayCorp Holdings, LTP for $3.2 million and announced the signing
of agreements for the transfer of power purchase contracts for approximately
160 mw between Montaup and Ocean State Power.
All of the sale and contract transfer agreements are subject to federal
and state regulatory approvals, including that of the Nuclear Regulatory
Commission with respect to the Seabrook sale. The Canal sale has been approved
by both the Massachusetts Department of Telecommunications and Energy (DTE) and
FERC. Closing of the non-nuclear sale agreements are anticipated to take place
in the first quarter of 1999. The Seabrook sale is expected to take place in
the later part of 1999.
EUA's remaining generating capacity includes approximately 300 mw of power
contracts, a 26 mw entitlement from Hydro Quebec and 58 mw from EUA's ownership
shares of the Millstone 3 and Vermont Yankee nuclear facilities.
The Year 2000 Issue
The Year 2000 issue exists because some computer programs and embedded
systems and components may not properly recognize a year that begins with "20"
instead of "19," and therefore may fail or create erroneous results. The
Company became aware of and started addressing Year 2000 issues in 1993 when
certain forward looking computer programs experienced date related problems.
Since that time, the Company has continued to broaden its efforts to address
Year 2000 issues.
The Company's State of Readiness:
The transition to the Year 2000 presents potential challenges to the
Company from three perspectives: the acquisition of products and services
(including purchased power); the generation and delivery of electricity to
customers; and, the ongoing general company activities related to the
corporate infrastructure and support functions. These challenges emanate from
sources both internal and external to the Company. By October 31, 1998, EUA
had completed a comprehensive inventory and assessment of its systems and
equipment that could potentially be affected by the Year 2000. All computer
software and hardware as well as all office and field machinery, equipment and
facilities were included. The results indicate that approximately 75% of the
Year 2000 issues reside in the Company's computer systems and 25% reside in its
embedded systems and components. The Company expects to complete its
assessment of the Year 2000 compliance status of its material relationships
with third parties, either as a customer or a vendor, during the first half of
1999.
EUA has adopted a four phase approach in addressing information technology
(IT) issues. As of September 30, 1998, each phase was at the following
percentage of completion: analysis - 70%; remediation - 32%; unit testing -
25%; and integrated testing - 6%. Based on the current schedule, the Company
estimates that 99% of all projects, and 100% of mission critical projects,
will be completed and Year 2000 ready by June 30, 1999. For non-I/T Year 2000
issues, the Company has completed its inventory and assessment of embedded
systems and components. The results of the assessment indicate that in excess
of 90% of the items listed are either Year 2000 compliant or not affected by
the Year 2000. The remaining items are scheduled to be analyzed, remediated
where necessary, tested, and returned to service by May 31, 1999. Management
does not believe these items represent significant costs or risks to the
Company.
Costs to Address the Company's Year 2000 Issues:
Through September 30, 1998, EUA has incurred costs of approximately $2.3
million to address Year 2000 issues, including approximately $0.9 million of
non-incremental internal labor costs, $1.1 million of capital expenditures and
$0.3 of consulting costs.
EUA estimates it will incur additional costs approximating $7.7 million
during the period October 1, 1998 through March 31, 2000, to complete its
resolution of Year 2000 issues including approximately $6.0 million of non-
incremental internal labor, $0.5 million of capital expenditures and $1.2
million of consulting and other costs.
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 the Company's Year 2000 Issues:
The Company's first priority is to minimize any potential disruptions to
electric service as a result of the Year 2000. The Company's ability to
maintain service depends in large part on the viability of the New England
Power Grid which is managed by ISO/NEPOOL. The Company is participating
extensively with ISO/NEPOOL Year 2000 operating and oversight committees.
ISO/NEPOOL currently does not expect that large-scale power interruptions on
the regional power grid external to the Company's service territory are likely.
The Company's assessment of its own transmission and distribution (T&D)
equipment and facilities indicated that the risk of failure of this equipment
does not appear to be significant. However, while management believes that a
significant disruption to the Company's T&D system caused by a Year 2000
problem is not reasonably likely, due to the interconnectivity to the New
England power grid and the reliance on many other entities also connected to
the grid, it is impossible to conclude with certainty that there will be no
significant interruptions in service.
In addition, dependable voice and data telecommunications are critical to
the Company's ongoing operations. The Company's internal telecommunication
systems are either Year 2000 compliant now, or on schedule to become compliant
by mid-1999. The Company 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 made direct contact with
representatives of the telephone companies on which the Company depends, each
of which anticipates being Year 2000 ready and devoid of major system failures.
No other significant reasonably likely failure scenarios stemming solely
from Year 2000 related problems have been identified thus far through the risk
inventory and assessment process. Accordingly, the Company does not currently
believe that any Year 2000 related risks in and of themselves constitute
reasonably likely worst case scenarios. Rather, the Company'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, the Company believes that such year 2000
failures would not likely affect whether the storm event would have a material
impact on the Company's business or financial condition.
Year 2000 Contingency Plans:
The Company is in the process of developing contingency plans for any
potential Year 2000 exposure that could have a material impact on its
operations or financial well being. It is expected that a preliminary
contingency plan will be developed during the first quarter of 1999. A final
contingency plan should be completed by June 1999.
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 on Form 10-Q 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 key elements of the restructuring proposal are the implementation of
a regional NEPOOL Open Access Transmission Tariff (NEPOOL Tariff), the creation
of an Independent System Operator (ISO), and the restatement of the NEPOOL
Agreement to establish a broader governance structure for NEPOOL and to develop
a more open competitive market structure.
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.
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. The remaining markets - operable capability, energy, automatic
generation control and the reserve markets are expected to start on January 1,
1999. If the January date is to be achieved, a favorable FERC order needs to
be received on or before December 15, 1998.
In general, the EUA System companies support the changes to NEPOOL because
much of the cross-subsidies for sharing costs will be eliminated. These changes
will have an impact on the Company's operating revenues and costs as NEPOOL
transitions from a cost based to a bid based system.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits - None.
(b) Reports on Form 8-K
- None filed in the quarter ended September 30, 1998.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Eastern Edison Company
(Registrant)
Date: November 13, 1998 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr. Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)
<TABLE> <S> <C>
<ARTICLE> OPUR1
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 535923
<OTHER-PROPERTY-AND-INVEST> 15727
<TOTAL-CURRENT-ASSETS> 70677
<TOTAL-DEFERRED-CHARGES> 176209
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 798536
<COMMON> 72284
<CAPITAL-SURPLUS-PAID-IN> 47206
<RETAINED-EARNINGS> 99461
<TOTAL-COMMON-STOCKHOLDERS-EQ> 218951
27904
0
<LONG-TERM-DEBT-NET> 162541
<SHORT-TERM-NOTES> 52195
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 336945
<TOT-CAPITALIZATION-AND-LIAB> 798536
<GROSS-OPERATING-REVENUE> 308039
<INCOME-TAX-EXPENSE> 13896
<OTHER-OPERATING-EXPENSES> 259492
<TOTAL-OPERATING-EXPENSES> 273388
<OPERATING-INCOME-LOSS> 34651
<OTHER-INCOME-NET> 467
<INCOME-BEFORE-INTEREST-EXPEN> 35118
<TOTAL-INTEREST-EXPENSE> 13047
<NET-INCOME> 22071
1491
<EARNINGS-AVAILABLE-FOR-COMM> 20580
<COMMON-STOCK-DIVIDENDS> 19806
<TOTAL-INTEREST-ON-BONDS> 10190
<CASH-FLOW-OPERATIONS> 44851
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
