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 1-5366
EASTERN UTILITIES ASSOCIATES
(Exact name of registrant as specified in its charter)
Massachusetts 04-1271872
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
One Liberty Square, Boston, Massachusetts
(Address of principal executive offices)
02109
(Zip Code)
(617)357-9590
(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, $5 par value 20,435,997 shares
PART I - FINANCIAL INFORMATION
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
September 30, December 31,
ASSETS 1998 1997
Utility Plant and Other Investments:
Utility Plant in Service $ 1,080,118 $ 1,079,361
Less: Accumulated Provision for Depreciation
and Amortization 399,859 376,722
Net Utility Plant in Service 680,259 702,639
Construction Work in Progress 15,299 5,538
Net Utility Plant 695,558 708,177
Investments in Jointly Owned Companies 71,749 69,749
Non-Utility Plant - Net 62,595 71,516
Total Plant and Other Investments 829,902 849,442
Current Assets:
Cash and Temporary Cash Investments 6,645 7,252
Accounts Receivable, Net 98,233 92,646
Notes Receivable 19,995 27,693
Fuel, Materials and Supplies 12,855 11,201
Other Current Assets 8,811 7,177
Total Current Assets 146,539 145,969
Deferred Debits and Other Non-Current Assets 307,800 275,341
Total Assets $ 1,284,241 $ 1,270,752
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Shares, $5 Par Value $ 102,180 $ 102,180
Other Paid-In Capital 218,499 219,156
Common Share Expense (3,931) (3,931)
Retained Earnings 56,529 56,062
Total Common Equity 373,277 373,467
Non-Redeemable Preferred Stock - Net 6,900 6,900
Redeemable Preferred Stock - Net 27,904 27,612
Long-Term Debt - Net 312,400 332,802
Total Capitalization 720,481 740,781
Current Liabilities:
Long-Term Debt Due Within One Year 21,845 72,518
Notes Payable 118,652 61,484
Accounts Payable 28,400 35,036
Taxes Accrued 3,044 3,063
Interest Accrued 6,470 8,624
Other Current Liabilities 28,541 33,327
Total Current Liabilities 206,952 214,052
Deferred Credits and Other Non-Current Liabilities 189,480 152,526
Accumulated Deferred Taxes 167,328 163,393
Total Liabilities and Capitalization $ 1,284,241 $ 1,270,752
See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(In Thousands Except Number of Shares and Per Share Amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
Operating Revenues $ 136,033 $ 142,026 $ 405,385 $ 422,635
Operating Expenses:
Fuel 26,178 29,278 76,057 82,412
Purchased Power 26,376 28,128 82,209 90,844
Other Operation and Maintenance 44,513 48,076 129,660 141,774
Early Retirement Offer 0 0 1,416
Depreciation and Amortization 13,032 11,484 39,015 34,608
Taxes - Other Than Income 6,058 5,920 17,873 18,259
Income Taxes - Current 5,336 3,030 7,496 14,547
- Deferred (Credit) (922) 214 6,590 (4,654)
Total 120,571 126,130 358,900 379,206
Operating Income 15,462 15,896 46,485 43,429
Other Income - Net 3,431 5,886 9,172 15,287
Income Before Interest Charges 18,893 21,782 55,657 58,716
Interest Charges:
Interest on Long-Term Debt 6,592 8,041 21,726 24,460
Other Interest Expense 2,700 2,327 6,416 5,759
Allowance for Borrowed Funds Used
During Construction (Credit) (187) (128) (415) (610)
Net Interest Charges 9,105 10,240 27,727 29,609
Net Income 9,788 11,542 27,930 29,107
Preferred Dividends of Subsidiaries 576 576 1,729 1,729
Consolidated Net Earnings $ 9,212 $ 10,966 $ 26,201 $ 27,378
Weighted Average Number of
Common Shares Outstanding 20,435,997 20,435,997 20,435,997 20,435,997
Consolidated Basic and Diluted
Earnings Per
Average Common Share $ 0.45 $ 0.54 $ 1.28 $ 1.34
Dividends Paid $ 0.415 $ 0.415 $ 1.245 $ 1.245
See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Nine Months Ended
September 30,
1998 1997
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 27,930 $ 29,107
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Activities:
Depreciation and Amortization 42,797 38,909
Deferred Taxes 6,860 (5,621)
Non-cash Expenses on Sales of Investments
in Energy Savings Projects 7,201 11,538
Investment Tax Credit, Net (1,173) (901)
Allowance for Funds Used During Construction (94) (170)
Collections and sales of project notes and leases
receivable 10,133 12,282
Other - Net (4,158) (292)
Change in Operating Assets and Liabilities (20,813) 6,095
Net Cash Provided From Operating Activities 68,683 90,947
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (36,100) (47,530
Collections on Notes and Lease Receivables of EUA
Cogenex 12,013 7,685
Increase in Other Investments (2,149) (221)
Net Cash (Used in) Investment Activities (26,236) (40,066
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (71,061) (26,555
EUA Common Share Dividends Paid (25,443) (25,443
Subsidiary Preferred Dividends Paid (1,729) (1,729)
Net Increase in Short-Term Debt 55,179 5,591
Net Cash (Used in) Financing Activities (43,054) (48,136
Net (Decrease) Increase in Cash and Temporary Cash Invest. (607) 2,745
Cash and Temporary Cash Investments at Beginning of Period 7,252 12,455
Cash and Temporary Cash Investments at End of Period $ 6,645 $ 15,200
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 24,343 $ 31,150
Income Taxes $ 17,274 $ 21,482
Supplemental schedule of non-cash investing activities:
Conversion of Investments in Energy Savings
Projects to Notes and Leases Receivable $ 2,159 $ 4,652
See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
The accompanying Notes should be read in conjunction with the Notes to
Consolidated Financial Statements incorporated in the Eastern Utilities
Associates (EUA 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 its 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. EUA 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 Montaup
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) 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 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 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 the 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.
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.
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
this 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 EUA'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 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.
Other
EUA is continually evaluating the strategic alternatives available to
the Company to maximize shareholder value, including potential
combinations and alliances involving other investor-owned utility
companies, as well as other companies engaged in the sale at retail or
wholesale of electricity, natural gas and related products and
services. Such combinations and alliances have become more prevalent
in the utility industry over the last few years. A possible outcome
of such activity is that EUA may acquire other companies or may itself
be acquired. EUA's policy prohibits management from commenting on
any possible merger, acquisition, or other strategic alliances prior
to the time that the law requires public disclosure. Consequently,
EUA may engage in preliminary discussions or negotiations at any time,
without disclosing their existence, that could subsequently lead to
public announcement. EUA has engaged Salomon Smith Barney to assist
it in the evaluation of its strategic alternatives and has determined
to offer its subsidiary, EUA Cogenex Corporation, for sale with
Salomon Smith Barney providing advice with respect to the possible
sale. There can be no assurance that EUA will consummate a sale of
Cogenex or any other strategic alternatives which may be evaluated.
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 $9.2 million compared to approximately $11.0 million in the
third quarter of 1997. The third quarter 1997 earnings include the impact of
the termination of EUA's joint venture, discussed below. Net Earnings
contributions by Business Unit for the third quarter of 1998 and 1997 were as
follows (000's):
Increase
1998 1997 (Decrease)
Core Electric Business $ 8,603 $9,413 $(810)
Energy Related Business 155 7 148
Corporate 455 66 389
Subtotal $ 9,213 $ 9,486 $ (273)
Joint Venture Termination 1,480 (1,480)
Consolidated $ 9,213 $10,966 $(1,753)
Consolidated Net Earnings for the nine months ended September 30, 1998
were $26.2 million compared to $27.4 million for the same period of 1997. The
year-to-date 1997 earnings include the impact of the joint venture termination
as well as an after-tax charge of approximately $900,000 related to an early
retirement offer recorded in June of 1997. Net Earnings contributions by
Business Unit for the first nine months of 1998 and 1997 were as follows
(000's):
Increase
1998 1997 (Decrease)
Core Electric Business $26,710 $27,336 $(626)
Energy Related Business (731) (686) (45)
Corporate 222 140 82
Subtotal $26,201 $26,790 $ (589)
Joint Venture Termination 1,480 (1,480)
June 1997 Early Retirement (892) 892
Consolidated $26,201 $27,378 $(1,177)
The earnings contribution of the Core Electric Business Unit decreased in
both the third quarter and year-to-date periods of 1998. Decreased jointly
owned unit expenses of approximately $2.8 million and $4.9 million, and
increased primary kilowatthour sales of 5.2% and 2.6%, mitigated the impacts of
rate reductions pursuant to approved utility restructuring settlement
agreements in both the third quarter and year-to-date periods, respectively.
Net earnings of the Energy Related Business Unit increased by
approximately $150,000 in the third quarter and decreased slightly in the year-
to-date period as compared to the same periods of 1997. Improved results at
EUA Cogenex in both periods were offset by increased losses at EUA
Trancapacity. EUA continues to negotiate a strategic alliance for the
continued development of the Bioten partnership's patented biomass-fired
electric generation technology.
The change in the third quarter earnings contribution of the Corporate
business unit is primarily due to the reallocation of certain corporate
charges by the Parent company in the third quarter of 1998. This reallocation
had no impact on earnings.
1997 Termination of Power Marketing Joint Venture
In the third quarter of 1997, EUA announced the termination of a power
marketing joint venture with an affiliate of Duke Energy Corporation and also
established provisions for increased legal costs, costs associated with
restructuring due to electric industry deregulation and costs (or
contingencies) related to certain of its energy related business activities.
Collectively, these actions resulted in a net positive after-tax impact of
$1.5 million to third quarter 1997 earnings.
Operating Revenues
Operating Revenues for the third quarter of 1998 decreased by
approximately $6.0 million when compared to the same period of 1997. Revenues
by Business Unit operations were as follows (000's):
Three Months Ended September 30,
Increase
1998 1997 (Decrease)
Core Electric Business $120,460 $127,653 $(7,193)
Energy Related Business 15,573 14,373 1,200
Corporate 0 0 0
Consolidated $136,033 $142,026 $(5,993)
Core Electric Business revenues reflect the impact of customer rate
reductions concurrent with retail choice effective January 1, 1998 and March
1, 1998 for EUA's Rhode Island and Massachusetts retail customers,
respectively. Offsetting these decreases were increased recoveries of
conservation and load management (C&LM) expenses of approximately $600,000, a
5.2% increase in retail kWh sales and revenues accrued pursuant to approved
settlement agreements.
Energy Related Business revenues increased by $1.2 million due
primarily to increased revenue at the EUA Cogenex division of $3.4 million
offset by decreased revenues of EUA Citizens and EUA Cogenex West aggregating
approximately $2.0 million.
Operating Revenues for the first nine months of 1998 decreased by
approximately $17.3 million when compared to the same period of 1997.
Operating Revenues by Business Unit for the first nine months of 1998 and 1997
were as follows (000's):
Nine Months Ended September 30,
Increase
1998 1997 (Decrease)
Core Electric Business $361,008 $376,230 $(15,222)
Energy Related Business 44,377 46,405 (2,028)
Corporate 0 0 0
Consolidated $405,385 $422,635 $(17,250)
Core Electric Business revenues decreased by $15.2 million due
primarily to the aforementioned rate reductions offset by increased C&LM
expenses of approximately $1.4 million.
Energy Related Business revenues decreased approximately $2.0
million for the year-to-date period of 1998 as compared to the same period of
1997. Revenues of EUA Cogenex West and EUA Cogenex-Canada decreased by
approximately $2.7 million and $1.9 million, respectively, offset by increased
EUA Cogenex Division and EUA Citizens revenues of approximately $1.6 million
and $900,000, respectively.
Kilowatthour (kWh) Sales
A combination of warmer weather and the continued strength of the
regional economy led to kWh sales increases of 5.2% and 2.6% in the three and
nine-month periods ending September 30, 1998, respectively. The third quarter
increase was led by increases of 7.7% and 4.1% in the residential and
commercial customer classes, which are typically more weather sensitive, and a
2.5% increase in sales to industrial customers. For the year-to-date period,
sales of electricity to residential, commercial and industrial customers
increased approximately 1.3%, 2.6% and 4.5%, respectively, as compared to the
same period of 1997.
Operations Expense
Fuel expense of the Core Electric Business 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 an 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 6.2% and $8.6 million or 9.5% 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 (O&M) expenses decreased by approximately
$3.6 million or 7.4% and $12.1 million or 8.5% for the third quarter and the
nine months ended September 30, 1998, respectively, as compared to the same
periods in 1997. Total O&M expenses are comprised of three components:
Direct, Indirect and Energy Related.
Direct expenses of the Core and Corporate Business units decreased by
$1.3 million in the third quarter of 1998 and approximately $2.6 million for
the year-to-date period of 1998 as compared to the same periods of 1997. These
changes are due to decreased legal expenses of $1.2 million in the third
quarter and $900,000 in the year-to-date period, and decreased expenses of
$300,000 and $600,000 in the respective periods as a result of an extensive
scheduled 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.
Indirect expenses, items over which there is limited short-term control,
or items which are fully recovered in rates, decreased by approximately $2.6
million and $4.4 million in the third quarter and year-to-date periods of 1998
as compared to the same periods of 1997. Jointly owned units expense
reflected decreases at Millstone 3, Canal and Seabrook aggregating $2.8
million in the third quarter and $4.9 million in the year-to-date period of
1998 as compared to the same periods of 1997. Charges from other utilities
decreased approximately $300,000 in the third quarter and $400,000 in the year-
to-date period of 1998 as compared to the same periods of 1997. In addition,
FAS106 expenses decreased approximately $400,000 in the year-to-date period.
Offsetting these decreases were increased C&LM expenses of approximately
$600,000 and $1.4 million for the respective periods.
Expenses of the Energy Related Business unit increased approximately
$300,000 and decreased approximately $5.2 million in the third quarter and
year-to-date periods of 1998, respectively. These changes are primarily due
to expense variances at EUA Cogenex, directly related to revenue variances and
operating activity in the respective periods.
Income Taxes
EUA's effective tax rate for the nine months ended September 30, 1998 was
approximately 40.3% compared to 35.9% 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 $1.5
million or 13.5% in the third quarter and $4.4 million or 12.7% in the nine
month period ended September 30, 1998 when compared to the same periods of
last year. These increases are due largely to increased depreciation at EUA
Cogenex, and amortization of certain regulatory assets pursuant to
restructuring settlement agreements.
Other Income and (Deductions) - Net
Other Income and (Deductions) - Net decreased by approximately $2.5
million in this year's third quarter and decreased by $6.1 million in the year-
to-date period as compared to the same periods of 1997. These decreases are due
primarily to the net impacts of the power marketing joint venture termination
in the third quarter of 1997 and decreased interest income of EUA Cogenex. The
year-to-date decrease also reflects the absence of interest
income recorded in the first quarter of 1997 related to the favorable
resolution of a Massachusetts corporate income tax dispute, and gains recorded
in the first quarter of 1997 resulting from changes to EUA Cogenex's pension
and post retirement welfare benefit plans.
Net Interest Charges
Net Interest charges decreased by approximately $1.1 million or 11.1% in
the third quarter and approximately $1.8 million or 6.4% in the year-to-date
period. Interest on long term debt decreased as a result of normal cash
sinking fund payments and the maturities of Eastern Edison's $20 million First
Mortgage Bonds in May of 1998 and $40 million First Mortgage Bonds in July of
1998. These decreases were offset by interest expense on increased short term
borrowings, which were used to finance Eastern Edison's long-term debt
maturities.
Liquidity and Sources of Capital
The EUA system's need for permanent capital is primarily related to
investments in facilities required to meet the needs of its 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 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. Outstanding short-
term debt at September 30, 1998 and December 31, 1997 by Business Unit
was as follows (000's):
September 30, 1998 December 31, 1997
Core Electric Business $59,665 $7,075
Energy Related Business 27,267 44,609
Corporate 31,720 9,800
Consolidated $118,652 $61,484
For the nine months ended September 30, 1998 internally generated funds
available after the payment of dividends amounted to approximately $64.0
million while the EUA System's cash construction requirements amounted to
approximately $36.1 million for the same period. Various laws, regulations
and contract provisions limit the use of EUA's internally generated funds such
that the funds generated by one subsidiary are not generally available to fund
the operations of another subsidiary.
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
EUA 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
Tax Issue
On January 10, 1997, the Internal Revenue Service (IRS) issued a report
in connection with its examination of the consolidated income tax returns of
EUA for 1992 and 1993. The report includes an adjustment to disallow EUA's
inclusion of its investment in EUA Power's Preferred Stock as a deduction in
determining Excess Loss Account (ELA) taxable income relating to the
redemption of EUA Power's Common and Preferred Stock in 1993. The IRS has
taken the position that the redemption of the Preferred Stock resulted in a
capital loss transaction and not a deduction in determining ELA. The Company
disagrees with the IRS's position and filed a protest in March 1997. During
1998, EUA has been engaged in discussions with the IRS Appeals Office
concerning this matter; a resolution has not yet been achieved. EUA believes
that it will ultimately prevail in this matter. However, if the ultimate
resolution of this matter is a favorable decision for the IRS and EUA has not
generated sufficient capital gain transactions to offset the capital loss,
then EUA would be required to record a charge that could have a material
impact on financial results in the year of the charge but would not materially
impact the financial position of the company.
EUA Cogenex Arbitration
On October 23, 1998, an arbitrators' panel rendered their decision in a
matter involving the 1995 sale of a portfolio of cogeneration units by EUA
Cogenex to Ridgewood/Mass Power Partners, et als (Ridgewood). Ridgewood
claimed that financial and other warranties in the purchase and sale agreement
had been breached. Cogenex entered counterclaims seeking recovery of costs of
certain services performed for Ridgewood. The arbitration panel found for the
buyer on some of the warranty claims, and awarded damages of approximately
$2.6 million plus interest of approximately $900,000 (an amount substantially
less than claimed). Cogenex was awarded approximately $400,000 plus interest
of approximately $130,000 on its counterclaim.
EUA Cogenex is reviewing the arbitration panel's decision with counsel to
determine the advisability of an appeal. Should EUA decide not to appeal,
this charge to earnings would be partially offset by previously established
energy related reserves, and thus would not have a material impact on results
of operations.
Other
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 Utilities Associates
(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)