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, 1997
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, 1997
Common Shares, $5 par value 20,435,997 shares
<TABLE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
September 30, December 31,
ASSETS 1997 1996
<S> <C> <C>
Utility Plant and Other Investments:
Utility Plant in Service $ 1,067,160 $ 1,067,056
Less: Accumulated Provision for Depreciation
and Amortization 372,164 350,816
Net Utility Plant in Service 694,996 716,240
Construction Work in Progress 15,742 3,839
Net Utility Plant 710,738 720,079
Investments in Jointly Owned Companies 71,922 71,626
Non-Utility Plant - Net 60,839 72,653
Total Plant and Other Investments 843,499 864,358
Current Assets:
Cash and Temporary Cash Investments 15,200 12,455
Accounts Receivable, Net 85,866 90,153
Notes Receivable 26,072 24,691
Fuel, Materials and Supplies 11,432 14,131
Other Current Assets 8,112 7,668
Total Current Assets 146,682 149,098
Deferred Debits and Other Non-Current Assets 280,610 243,573
Total Assets $ 1,270,791 $ 1,257,029
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Shares, $5 Par Value $ 102,180 $ 102,180
Other Paid-In Capital 221,407 221,160
Common Share Expense (3,931) (3,931)
Retained Earnings 53,906 52,404
Total Common Equity 373,562 371,813
Non-Redeemable Preferred Stock - Net 6,900 6,900
Redeemable Preferred Stock - Net 27,468 27,035
Long-Term Debt - Net 334,842 406,337
Total Capitalization 742,772 812,085
Current Liabilities:
Long-Term Debt Due Within One Year 72,517 27,512
Notes Payable 57,439 51,848
Accounts Payable 31,711 33,811
Taxes Accrued 3,479 3,004
Interest Accrued 7,363 9,612
Other Current Liabilities 34,222 26,772
Total Current Liabilities 206,731 152,559
Deferred Credits and Other Non-Current Liabilities 156,684 123,209
Accumulated Deferred Taxes 164,604 169,176
Total Liabilities and Capitalization $ 1,270,791 $ 1,257,029
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(In Thousands Except Number of Shares and Per Share Amounts)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1997 1996 1997 1996
<S> <C> <C> <C> <C>
Operating Revenues $ 142,026 $ 131,076 $ 422,635 $ 388,661
Operating Expenses:
Fuel 29,278 25,904 82,412 66,563
Purchased Power 28,128 27,391 90,844 86,007
Other Operation and Maintenance 48,076 44,090 141,774 134,031
Early Retirement Offer 0 0 1,416
Depreciation and Amortization 11,484 11,240 34,608 34,038
Taxes - Other Than Income 5,920 5,807 18,259 18,216
Income Taxes - Current 3,030 2,113 14,547 8,915
- Deferred (Credit) 214 1,203 (4,654) (742)
Total 126,130 117,748 379,206 347,028
Operating Income 15,896 13,328 43,429 41,633
Other Income - Net 5,886 5,800 15,287 12,200
Income Before Interest Charges 21,782 19,128 58,716 53,833
Interest Charges:
Interest on Long-Term Debt 8,041 8,438 24,460 25,707
Other Interest Expense 2,327 1,773 5,759 4,969
Allowance for Borrowed Funds Used
During Construction (Credit (128) (472) (610) (1,457)
Net Interest Charges 10,240 9,739 29,609 29,219
Net Income 11,542 9,389 29,107 24,614
Preferred Dividends of Subsidiaries 576 578 1,729 1,735
Consolidated Net Earnings $ 10,966 $ 8,811 $ 27,378 $ 22,879
Weighted Average Number of
Common Shares Outstanding 20,435,997 20,435,997 20,435,997 20,436,290
Consolidated Earnings Per
Average Common Share $ 0.54 $ 0.43 $ 1.34 $ 1.12
Dividends Paid $ 0.415 $ 0.415 $ 1.245 $ 1.23
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION> Nine Months Ended
September 30,
1997 1996
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 29,107 $ 24,614
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Activities:
Depreciation and Amortization 38,909 38,821
Deferred Taxes (5,621) (333)
Non-cash Expenses on Sales of Investments
in Energy Savings Projects 11,538 3,184
Investment Tax Credit, Net (901) (905)
Allowance for Funds Used During Construction (170) (254)
Collections and sales of project notes and leases receiv. 12,282 5,891
Other - Net (292) 6,793
Change in Operating Assets and Liabilities 6,095 7,610
Net Cash Provided From Operating Activities 90,947 85,421
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (47,530) (49,662
Collections on Notes and Lease Receivables of EUA Cogenex 7,685 3,198
Increase in Other Investments (221) (4,036)
Net Cash (Used in) Investment Activities (40,066) (50,500
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (26,555) (18,560
Premium on Reacquisition and Financing Expenses 0 (14)
EUA Common Share Dividends Paid (25,443) (25,137
Subsidiary Preferred Dividends Paid (1,729) (1,735)
Net Increase in Short-Term Debt 5,591 13,031
Net Cash (Used in) Financing Activities (48,136) (32,415
Net Increase in Cash and Temporary Cash Investments 2,745 2,506
Cash and Temporary Cash Investments at Beginning of Period 12,455 4,060
Cash and Temporary Cash Investments at End of Period $ 15,200 $ 6,566
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 46,150 $ 31,717
Income Taxes $ 21,482 $ 11,490
Supplemental schedule of non-cash investing activities:
Conversion of Investments in Energy Savings
Projects to Notes and Leases Receivable $ 4,652 $ 4,813
See accompanying notes to consolidated condensed financial statements.
</TABLE>
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) 1996 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, 1997.
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 Sept ember 30, 1997 and
December 31, 1996, and the results of operations for the three and
nine months ended September 30, 1997 and 1996 and cash flows for
the nine months ended September 30, 1997 and 1996.
In June 1997 the Financial Accounting Standards Board (FASB) issued
Statement No. 128, "Earnings per share", which establishes
standards for computing and presenting earnings per share (EPS) and
applies to entities with publicly held common stock or potential
common stock. This Statement simplifies the standards for
computing earnings per share previously found in APB Opinion No.
15, "Earnings per share", and makes them comparable to
international EPS standards. It also requires dual presentation of
basic and diluted EPS on the statement of income for all entities
with complex capital structures and requires a reconciliation of
the basic EPS computation and the diluted EPS computation. This
Statement is effective for financial statements issued for periods
ending after December 31, 1997, including interim periods. As of
September 30, 1997, the application of this Statement currently
does not impact the Company's EPS calculations.
In June 1997 the FASB issued Statement No. 130, "Reporting
Comprehensive Income", which establishes standards for reporting
comprehensive income and its components (revenues, expenses, gains,
and losses) in a set of general-purpose financial statements. This
Statement requires that all items that are required to be
recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements.
This Statement is effective for fiscal years beginning after
December 15, 1997, and EUA will adopt Statement 130 in the first
quarter of 1998.
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 a nd
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
Millstone III:
Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw
nuclear unit that is jointly owned by a number of New England
utilities, including subsidiaries of Northeast Utilities
(Northeast). Northeast is the lead participant in Millstone III.
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.
The NRC has raised numerous issues with respect to Millstone III
and certain of the other nuclear units in which Northeast and its
subsidiaries, either individually or collectively, have the largest
ownership shares, including Connecticut Yankee (see "Connecticut
Yankee" below).
In October 1996, the NRC informed Northeast that it was
establishing a Special Projects Office to oversee inspection and
licensing activities at Millstone. The Special Projects Office is
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 plants' 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.
In March of 1997, Northeast announced that Millstone III had been
designated as the lead unit in the recovery process of the three
Millstone nuclear units that are currently out of service.
Millstone III is the largest of the three units currently out of
service, and its return to service will most benefit the energy
needs of the New England region.
In September 1997, Northeast announced that it will delay its
request to the NRC to restart Millstone III until January 1998, at
the earliest. As a result of recent NRC questions as to the status
of Millstone III's restart activities, it was noted that various
technical issues had not yet been resolved.
On October 23, 1997, Northeast presented a revised 1997 budget for
Millstone III which included significant increases in operation and
maintenance (O&M) expenses. Montaup's share of the revised O&M
budget is approximately $11.6 million, approximately $5.6 million
more than originally expected and $3.8 million more than O&M
expenditures in 1996.
While Millstone III is out of service, Montaup will incur
incremental replacement power costs estimated at $0.4 million to
$0.8 million per month. Montaup bills its replacement power costs
through its fuel adjustment clause, a wholesale tariff
jurisdictional to the Federal Energy Regulatory Commission (FERC).
However, there is no comparable clause in Montaup's FERC-approved
rates which at this time would permit Montaup to recover its share
of the incremental operation and maintenance costs incurred by
Northeast.
Montaup pays its share of Millstone III'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.
In August of 1997, nine non-operating owners, including Montaup,
who together own approximately 19.5% of Millstone III, 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 III, are Northeast
subsidiaries which agreed to be responsible for the proper
operation of the unit.
The non-operating owners of Millstone III 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 O&M costs
resulting from the shutdown of Millstone III. The non-operating
owners conservatively estimate that their losses will exceed $200
million.
EUA cannot predict the ultimate outcome of the NRC inquiries or
legal proceedings brought against CL&P, WMECO and Northeast or the
impact which 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 with a book value of $ 5.3 million
at September 30, 1997.
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 Connecticut Yankee
Board of Directors 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. Connecticut Yankee has two years to submit its
decommissioning plan to the NRC. The preliminary estimate of the
sum of future payments for the permanent shutdown, decommissioning,
and recovery of the remaining investment in Connecticut Yankee, is
approximately $758 million. The recovery of this estimated amount,
elements of which have been disputed by certain intervening
parties, is subject to approval of FERC. Montaup's share of the
total estimated costs is $34.1 million and is included with Other
Liabilities on the Consolidated Balance Sheet for the periods
ending September 30, 1997 and December 31, 1996. Also, due to
anticipated recoverability, a regulatory asset has been recorded
for the same amount and is included with Other Assets. Montaup
cannot predict the ultimate outcome of FERC's review.
Maine Yankee:
On August 6, 1997, as the result of an economic evaluation, the
Board of Directors voted to permanently close the Maine Yankee
nuclear plant. Montaup has a 4.0% equity ownership in Maine Yankee
with a book value of approximately $3.1 million at September 30,
1997. The present estimate of the sum of future payments for the
permanent shutdown, decommissioning, and recovery of the remaining
investment in Maine Yankee, is approximately $930 million. The
recovery of this estimated amount is subject to approval of FERC.
Montaup's share of the total estimated costs is $37.2 million and
is included with Other Liabilities on the Consolidated Balance
Sheet for the period ending September 30, 1997. Also, due to
anticipated recoverability, a regulatory asset has been recorded
for the same amount and is included with Other Assets. Montaup
cannot predict the ultimate outcome of FERC's review.
In November 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy)
signed an agreement to renew the contract for Entergy to provide
management services to Maine Yankee. Entergy will provide
management services for the initial decommissioning of Maine Yankee
activities through September 30, 1998.
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 a re between the equity
owners as a group and 30 municipalities throughout New England.
Presently, the equity owners are making the payments to Maine
Yankee to cover these unrecovered costs from the municipals.
Montaup and the other equity owners will seek payment from the
municipals, but cannot predict the outcome of this contract issue
at this time.
Yankee Atomic Electric Company (Yankee Atomic):
Montaup holds a 4.5% equity ownership in Yankee Atomic. In October
1997, Yankee Atomic announced that it had accepted a Duke
Engineering and Services (DE&S) Letter of Intent to acquire Yankee
Atomic's Nuclear Services Division. Yankee Atomic indicated it was
seeking a purchaser with a long-term commitment to excellence in
nuclear operations and support services that would continue to
provide that level of service to its affiliated New England nuclear
plants. Yankee Atomic's plan is to continue as a smaller
organization responsible for the completion of the safe and
effective decommissioning of the Yankee Nuclear Power Plant in
Rowe, Massachusetts. Details of the acquisition have not yet been
released.
General:
Recent actions by the NRC, some of which are cited above, 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 w ill have on any of
the other nuclear power plants in which Montaup has an ownership
interest or power contract.
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.
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.
Overview
Consolidated Net Earnings for the third quarter of 1997 were $11.0
million compared to $8.8 million in the third quarter of 1996. The third
quarter 1997 earnings include the impact of the termination of EUA's joint
venture, discussed above. Net Earnings contributions by Business Unit for the
third quarter of 1997 and 1996 were as follows (000's):
Increase
1997 1996 (Decrease)
Core Electric Business $8,576 $9,915 $(1,339)
Energy Related Business 7 (899) 906
Corporate 2,383 (205) 2,588
Consolidated $10,966 $8,811 $2,155
Consolidated Net Earnings for the nine months ended September 30, 1997
were $27.4 million compared to $22.9 million for the same period of 1996. 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. The year-to-date 1996 earnings
include a one-time, after-tax charge to earnings of $3.7 million recorded by
EUA Cogenex in June 1996. Net Earnings contributions by Business Unit for the
first nine months of 1997 and 1996 were as follows (000's):
Increase
1997 1996 (Decrease)
Core Electric Business $25,696 $28,528 $(2,832)
Energy Related Business (767) (4,990) 4,223
Corporate 2,449 (659) 3,108
Consolidated $27,378 $22,879 $ 4,499
The earnings contribution of the Core Electric Business Unit decreased
in both the third quarter and year-to-date periods of 1997. These decreases
are primarily the result of increased jointly owned unit expenses, including
incremental costs related to the extended outage of Millstone III of $1.6
million and $3.5 million in the third quarter and year-to-date periods,
respectively. Offsetting these impacts somewhat was increased primary
kilowatthour (kWh) sales of approximately 3% in the third quarter and
approximately 1% for the year-to-date period ended September 30, 1997. The
year-to-date results also include expenses of approximately $1.4 million
related to the early retirement offer in June 1997.
Net Losses of the Energy Related Business Unit decreased by
approximately $900,000 and $4.2 million in the third quarter and year-to-date
periods of 1997, respectively, as compared to the same periods of a year ago.
EUA Cogenex was profitable for this year's third quarter, an improvement of
approximately $1.0 million from its $860,000 loss in the third quarter of 1996.
The year-to-date 1996 results include a $3.7 million after-tax charge by EUA
Cogenex. In addition to the 1996 charge, EUA Cogenex earnings increased $1.4
million. EUA Energy Investment losses increased by approximately $400,000,
largely due to increased marketing expenses of the BIOTEN partnership,
partially offset by decreased losses at EUA TransCapacity.
The increases in earnings of the Corporate business unit in both the
third quarter and year-to-date periods of 1997 are primarily a result of the
net impacts of the previously discussed termination of the power marketing
joint venture and increased intercompany interest income.
Operating Revenues
Operating Revenues for the third quarter of 1997 increased by
approximately $11.0 million when compared to the same period of 1996. Revenues
by Business Unit operations were as follows (000's):
Three Months Ended September 30,
Increase
1997 1996 (Decrease)
Core Electric Business $127,653 $118,211 $ 9,442
Energy Related Business 14,373 12,865 1,508
Corporate 0 0 0
Consolidated $142,026 $131,076 $10,950
Core Electric Business revenues include the impact of recoveries of
increased fuel, purchased power and conservation and load management (C&LM)
expenses aggregating $5.0 million (see Operating Expense Below) and a 3.1%
increase in primarily kWh sales. Base rate increases, effective January 1,
1997 for Blackstone Valley Electric Company (Blackstone) and Newport Electric
Company (Newport) pursuant to the Rhode Island Utility Restructuring Act of
1996 (URA) also contributed to the revenue increase.
EUA Cogenex revenues, which account for the majority of the Energy
Related Business Unit revenues, increased by approximately $1.3 million due
primarily to an increase in EUA Citizens revenues. Also impacting Energy
Related Business revenues was increased revenues at EUA TransCapacity of
approximately $200,000.
Operating Revenues for the first nine months of 1997 increased by $34.0
million or 8.7% when compared to the same period of 1996. Operating Revenues
by Business Unit for the first nine months of 1997 and 1996 were as follows
(000's):
Nine Months Ended September 30,
Increase
1997 1996 (Decrease)
Core Electric Business $376,230 $347,746 $28,484
Energy Related Business 46,405 40,915 5,490
Corporate 0 0 0
Consolidated $422,635 $388,661 $33,974
Core Electric Business revenues increased by $28.5 million due
primarily to recoveries of increase fuel, purchased power and C&LM expenses of
$21.3 million and increased base rate recoveries related to kWh sales
improvement and base rate increases, as discussed above.
Energy Related Business revenues increased approximately $5.5 million
for the year-to-date period of 1997 as compared to the same period of 1996.
EUA Cogenex revenues increased by approximately $5.1 million due primarily to
increased Cogenex Division project sales and increased revenues of Cogenex-
Canada and EUA Citizens. In addition, EUA TransCapacity revenues increased
approximately $400,000 for the year-to-date period.
Kilowatthour Sales
Primary kWh sales of electricity by EUA's Core Electric Business Unit
increased by 3.1% in the third quarter of 1997 compared to the same period last
year. This increase was led by increases of 4.7% and 4.6% in the residential
and commercial customer classes, which are typically more weather sensitive.
Year-to-date September 30, 1997 sales of electricity increased approximately 1%
compared to the same period of 1996. Increased kWh sales in the second and
third quarter offset t he decreased kilowatthour sales in the first quarter of
1997.
Operations Expense
Fuel expense of the Core Electric Business increased by approximately
$3.4 million or 13.0% and $15.9 million or 23.8% for the third quarter and
year-to-date periods of 1997, respectively, as compared to the same periods of
1996. Outages of nuclear units in this year's third quarter and year-to-date
period contributed to a greater dependance on higher cost fossil fuels for
energy requirements, resulting in increases in average fuel costs of 9.0% and
20.9% for the respective periods. Al so impacting fuel expense were increases
in total energy generated and purchased of 3.1% for the third quarter of 1997
and 5.4% for the year-to-date period as compared to the same periods of 1996.
Purchased Power demand expense for the third quarter of 1997 increased
approximately $700,000 or 2.7% and $4.8 million or 5.6% for the nine months
ended September 30, 1997. The third quarter and year-to-date changes are
primarily due to the impact of a prior period refund to retail customers from
the Pilgrim Nuclear Unit of approximately $2.0 million recorded in the third
quarter of 1996, and increased billings from the Maine Yankee unit offset by
decreased billings from Connecticut Yankee and the Ocean State Power Project.
Other Operation and Maintenance expenses increased by approximately
$4.0 million or 9.0% and $7.7 million or 5.8% for the third quarter and the
nine months ended September 30, 1997, respectively, as compared to the same
periods in 1996.
Direct expenses of the Core and Corporate Business units were
relatively unchanged in the third quarter and year-to-date periods of 1997.
Indirect expenses, items over which there is limited short-term control
or items which are fully recovered in rates, increased by $4.1 million and $8.1
million in the third quarter and year-to-date periods of 1997 as compared to
the same periods of 1996. The third quarter change was primarily due to
incremental expenses related to the Millstone III outage of approximately of
$1.5 million, increased C&LM expenses of approximately $1.4 million, and
increased FAS106 expenses of $1.5 million, partially offset by lower
transmission charges of approximately $400,000. The year-to-date change was
primarily due to increased jointly owned units expense of approximately $5.9
million, approximately $3.5 million of which is related to the Mill stone III
outage. Also impacting the year-to-date change was increased C&LM expenses of
approximately $1.2 million and increased FAS106 expenses of approximately $1.0
million.
Expenses of the Energy Related Business unit was relatively unchanged
in the third quarter of 1997 and decreased by approximately $400,000 in the and
year-to-date period of 1997, respectively. These changes are primarily due to
ongoing cost control efforts of EUA Cogenex.
Other Income (Deductions) - Net
Other Income and (Deductions) - Net was relatively unchanged in this
year's third quarter and increased by $3.0 million in the year-to-date period
as compared to the same periods of 1996. The year to date increase is due
primarily to interest income related to the favorable resolution of a
Massachusetts corporate income tax dispute in the first quarter of 1997, the
impact of changes to EUA Cogenex pension and post-retirement welfare benefit
plans offset by gains recorded in 1996 from the sale of Seabrook II equipment
jointly owned by Montaup.
Other Interest Expense
Other Interest expense increased approximately $600,000 in the third
quarter of 1997 and increased approximately $800,000 in the year-to-date
period of 1997 as compared to the same periods of 1996. These increases are
primarily the result of a reserve of $500,000 recorded in the third quarter of
1997 for interest on Internal Revenue Service audit assessments in addition to
interest on increased short term borrowings.
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 financed 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 with various financial
institutions allowing for borrowings in aggregate of up to $75 million.
Outstanding short-term debt at September 30, 1997 and December 31, 1996
by Business Unit was as follows (000's):
September 30, 1997 December 31, 1996
Core Electric Business $ 8,250 $ 3,670
Energy Related Business 40,189 24,341
Corporate 9,000 23,837
Consolidated $57,439 $51,848
For the nine months ended September 30, 1997 internally generated funds
available after the payment of dividends amounted to approximately $58.8
million while the EUA System's cash construction requirements amounted to
approximately $47.5 mil lion 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
On August 7, 1996 the Governor of Rhode Island signed into law the
Utility Restructuring Act of 1996 (URA). The URA provides for customer choice
of electricity supplier to be phased-in commencing July 1, 1997 for large
manufacturing customer s, certain new commercial and industrial customers, and
State of Rhode Island accounts. In addition to State of Rhode Island accounts,
11 customers of Blackstone and one customer of Newport were eligible for choice
commencing July 1, 1997. As of November 1, 1997, in addition to certain State
of Rhode Island accounts, eleven customers exercised their right to choose an
alternate supplier of electricity. By July 1, 1998, or sooner, all customers
will have retail access. Under the URA the local distribution company will
retain the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory. For customers
who do not choose an alternative supplier, the local distribution company will
arrange for supply at a non-discriminatory, "standard offer" price.
Distribution companies will also be providers of last resort, required to
arrange for supply at prevailing market prices for customers who are unable to
obtain their own supply.
The URA provides for full recovery of prudently incurred embedded
generation costs that might not be recovered in a competitive electric
generation market, commonly referred to as "stranded costs," through a non-
bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000. The transition charge recovers, among other things, costs
of depreciated generation, net of its market value, regulatory assets, nuclear
decommissioning costs and above- market payments t o power suppliers. The
costs of net, above-market generation assets and regulatory assets will be
recovered, with a return, through a fixed component of the transition charge
from July 1, 1997, through December 31, 2009. A variable component of the
transition charge will recover, on a reconciling basis, among other things,
nuclear decommissioning and above market purchased power commitments from July
1, 1997, through the life of the respective unit or contract. The URA also
provides for commitments to demand side management initiatives and renewables,
low-income customer protections, divestiture of at least 15% of owned non-
nuclear generating units as a valuation basis for mitigation of stranded cost
recovery, and performance based rate -making standards for electric
distribution companies. These performance based standards provide for a 6%
minimum and an approximate 12% maximum allowed return on equity for Blackstone
and Newport, EUA's Rhode Island Distribution Companies (R.I. Distribution
Companies). In addition, the URA provides for adjustments to electric
distribution companies' base rates using the prior year's Consumer Price Index
and other performance factors. Under this provision of the law, base rates
were increased 1.88% for customers of Blackstone, and 2.18% for our Newport
customers effective January 1, 1997.
In June 1997, Legislation was enacted in Rhode Island, which would
allow securitization of utilities' stranded assets, a method of providing
savings to customers.
The implementation of the URA requires approvals from applicable
regulatory agencies, including the Federal Energy Regulatory Commission (FERC),
the Rhode Island Public Utilities Commission (RIPUC), and the Securities and
Exchange Commission (SEC).
In February 1997, Blackstone, Newport and Montaup reached a settlement
in principle with the Rhode Island Division of Public Utilities and Carriers
(RIDIV) and the state's Attorney General and filed a Memorandum of
Understanding (MOU) with the RIPUC in March 1997 outlining the terms of the
settlement. In addition to complying with the URA, the settlement provides for
an immediate 10% rate reduction and the filing of a plan to divest all of
Montaup's generating assets, and is similar in many respects to the settlement
negotiated in Massachusetts, described below.
On December 23, 1996, Eastern Edison and Montaup reached an agreement
in principle with the Attorney General of Massachusetts and the Massachusetts
Department of Energy Resources (MADOER) and filed a MOU with the Massachusetts
Department of Public Utilities (MDPU) outlining the terms of a plan, similar in
many aspects to the URA, which would allow retail customers to choose their
supplier of electricity in 1998 and provide Eastern Edison and Montaup full
recovery of "stranded costs." On May 16, 1997 an Offer of Settlement was filed
with the MDPU. Hearings on the Offer of Settlement concluded in July 1997 and
a MDPU decision is expected by year-end 1997.
The Offer of Settlement envisions that all of Eastern Edison's
customers will have the ability to choose an alternative supplier of
electricity beginning as soon as January 1, 1998. Until a customer chooses an
alternative supplier, that customer would receive "standard offer" service
which would be priced to guarantee at least a 10% savings from today's
electricity rates. Eastern Edison would be required to arrange for "standard
offer" service and would purchase power for "standard offer" service from
suppliers through a competitive bidding process. The agreement is also
designed to achieve full divestiture of Montaup's generating assets via
implementation of a plan, that would require (1) separation by Montaup of its
generating and transmission businesses, and (2) full market valuation and sale
of all generating assets through an auction or equivalent process.
Upon the commencement of retail choice in Massachusetts, Montaup's FERC
approved, all-requirements wholesale contract with Eastern Edison would be
terminated. In its place, Montaup will bill Eastern Edison a Contract
Termination Charge (CTC) designed to recover the cost of Montaup's above
market, embedded generation commitments to serve Eastern Edison's customers,
with a return. Eastern Edison will recover the CTC through a non-bypassable
transition access charge to all of its distribution customers. The transition
access charge would be reduced by the fair market value of Montaup's
generating assets as determined by selling, spinning off, or otherwise
disposing of such generating facilities.
Embedded costs associated with generating plants and regulatory assets
would be recovered, with a return, over a period of 12 years. Purchased power
contracts and nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond 12 years.
The initial transition access charge would be set at 3.04 cents per kWh through
December 31, 2000, and is expected to decline thereafter.
The agreement also establishes performance-based regulation for Eastern
Edison, incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates would be frozen until December
31, 2000. Sub sequent to the commencement of retail choice, Eastern Edison's
annual return on equity would be subject to a floor of 6% and a ceiling of
11.75%.
In addition to MDPU approval of the Offer of Settlement, implementation
is also subject to the approval of FERC. Elements of the Offer of Settlement
which fall under the jurisdiction of FERC were filed with FERC on May 30, 1997
and await review. Any disposition of generation assets resulting from the
agreements or the URA would also require the approval of the SEC under the
Public Utility Holding Company Act of 1935.
On May 1, 1997, Montaup and the R.I. Distribution Companies jointly
filed amendments to the FERC-approved all-requirements power contracts between
Montaup and the R.I. Distribution Companies, respectively, with FERC. The
filing included a calculation for a CTC to recover stranded costs and a
provision for standard offer service for resale to retail customers who do not
choose an alternate generation supplier. These provisions are intended to
ultimately replace the current services offered by the all-requirements
contracts upon full retail access pursuant to the URA. The filing also
includes "hold harmless" provisions for Montaup's other wholesale customers and
for retail customers of the R.I. Distribution Companies, which allow f or
recovery of any of Montaup's lost revenues during the initial phases of retail
access in Rhode Island. This filing allows the R.I. Distribution Companies to
implement on July 1, 1997 the phase-in provisions of the URA and to avoid any
cross-subsidies by their retail customers who are excluded from the groups of
customers given retail choice prior to the final phase and by Montaup's other
customers.
The May 1st and May 30th filings were consolidated by FERC and on
October 29, 1997, settlement agreements among Montaup, its affiliated and non-
affiliated customers, the Massachusetts Attorney General, the MADOER, the RIDIV
and RIPUC were submitted for FERC approval. These settlements represent a
comprehensive resolution of federal/wholesale issues of electric utility
industry restructuring based on the settlement agreements in Massachusetts and
Rhode Island.
Negotiations in Rhode Island on final settlement terms regarding retail
issues of electric utility industry restructuring, are nearing completion,
subsequent to which a formal filing will be made to the RIPUC for approval.
EUA is currently reviewing legislation that has been introduced in
Massachusetts concerning electric industry restructuring. Certain provisions
of the legislation as drafted are problematic to the consensus achieved through
our negotiated settlement with Massachusetts stakeholders.
Historically, electric rates have been designed to recover a utility's
full costs of providing electric service including recovery of investment in
plant assets. Also, in a regulated environment, electric utilities are subject
to certain accounting rules that are not applicable to other industries. These
accounting rules allow regulated companies, in appropriate circumstances, to
establish regulatory assets and liabilities, which defer the current financial
impact of certain costs that are expected to be recovered in future rates. The
SEC has raised issues concerning the continued applicability of these standards
with certain other electric utilities in other states facing restructuring.
The Company believes that its Core Electric operations will continue to meet
the criteria established in these accounting standards.
In July 1997, the Emerging Issues Task Force (EITF) reached a consensus
regarding certain issues raised related to the application of Statement of
Financial Accounting Standards No. 71, (FAS71) "Accounting for the Effects of
Certain Types of Regulation". The EITF determined that when sufficient detail
is available for the enterprise to reasonably determine how the transition plan
will affect the separable portion of its business being deregulated, the
enterprise should discontinue the application of FAS71 to that deregulated
portion of its business. In Massachusetts and Rhode Island, sufficient detail
is deemed to be available, upon approval by FERC, of those restructuring plans
submitted by EUA in its respective jurisdictions. The EITF further determined
that regulatory assets and liabilities originating in the separable portion of
the business and no longer subject to rate regulation should be evaluated on
the basis of where regulated cash flows to recover those regulatory assets and
liabilities will be derived. Based on the current settlement agreements
submitted by EUA in Massachusetts and Rhode Island, management does not believe
the EITF decisions will have a material effect on EUA.
In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover the company's costs, a
write-down of plant assets could be required pursuant to Financial Accounting
Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of".
Other
EUA occasionally makes projections of expected future performance or
statements of its plans, objectives and new business opportunities which are
forward-looking statements under federal securities law. Actual results could
differ materially from those discussed and there can be no assurance that such
estimates of future results will be achieved.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See "Note C - Commitments and Contingencies: Recent Nuclear Regulatory
Commission (NRC) Actions - Millstone III" for a discussion of pending legal
action involving Montaup, Northeast Utilities, Connecticut Light & Power and
Western Massachusetts Electric Company.
Item 5. Other Information
On April 24, 1996, the FERC issued orders No. 888 and No. 889 to
encourage competition in the bulk power market by requiring all public
utilities that own, operate or control interstate transmission to file tariffs
that offer others the same transmission services they provide themselves, under
comparable terms and conditions, establishing the right and a mechanism for
recovery of prudently incurred stranded costs and requiring public utilities to
implement standards of conduct and an Open Access Same-time Information System
(OASIS). FERC also issued a Notice of Proposed Rulemaking (NOPR) requesting
comment on replacing the single tariff contained in the final open access rule
with a capacity reservation tariff that would reveal how much transmission is
available at any given time.
Open-access transmission tariffs for point-to-point and local network
service were filed with FERC by Montaup in February 1996 and became effective
April 21, 1996, subject to refund, for a period of at least one year. The
rates in the tariff s were the subject of a settlement agreement which was
filed on July 9, 1996 to modify its terms and conditions in conformance with
FERC's order.
On December 31, 1996, Montaup filed revisions to its Open Access
Transmission tariff necessary to comply with FERC's order on September 11,
1996, which dealt with use rights of High Voltage Direct Current (HVDC)
interconnection transmission facilities with the Hydro Quebec system and on
January 21, 1997, filed additional revisions to coincide with the New England
Power Pool (NEPOOL) Open Access Transmission filing (see below).
On January 3, 1997, as required by FERC in Order No. 889, Montaup filed
its Standards of Conduct Implementation Procedures detailing Montaup's
compliance with the requirements of FERC's standards. Coincident with this
filing, Montaup complied with OASIS's requirements as part of a region wide
OASIS in NEPOOL.
On March 4, 1997, FERC issued Orders 888A and 889A which reaffirms the
legal and policy bases in which Orders 888 and 889 are grounded and addresses
interventions that were filed in response to Orders 888 and 889. As a result,
on July 14, 19 97, Montaup filed revisions to its open access transmission
service for compliance with FERC Order 888A. The filing incorporates all of
the tariff amendments to date.
On June 4, 1997, as supplemented on July 14, 1997, Montaup filed with
FERC in Docket No. ER97-3200-000 amendments to its open access transmission
tariff to provide for unbundled retail transmission service. Montaup proposed
to allow retail customers to obtain retail transmission service directly from
Montaup or through Montaup's retail affiliates acting as the retail customers'
agent. Montaup requested FERC to allow the tariff amendments to become
effective for service to retail customers in Blackstone's and Newport's service
areas on July 1, 1997. FERC accepted the amendment to become effective subject
to refund on that date in an order issued September 12, 1997. FERC accepted
the amendment subject to any modification that may be required as a result of
other pending proceedings concerning Montaup's transmission tariff and ordered
Montaup to make a compliance filing changing the amendments in certain limited
respects. The compliance filing was made by Montaup on October 1 0, 1997.
NEPOOL is a voluntary organization open to any person engaged in the
electric business such as investor-owned utilities, municipals, cooperative
utilities, power marketers, brokers and load aggregators. On December 31,
1996, NEPOOL, on behalf of its participants, filed a restructuring proposal
with FERC. The NEPOOL restructuring proposal is the product of over two years
of intense discussions, deliberations and negotiations among the over 130
NEPOOL member participants and many non-participants, including New England
state regulators. The key elements of the restructuring proposal 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.
The NEPOOL Tariff, which became effective on March 1, 1997, ensures
non-discriminatory open access to the regional transmission network by
providing a single rate for all transactions that utilize the NEPOOL's bulk
power transmission facilities. The NEPOOL Tariff promotes competition in the
New England power market through its non-pancaked rate structure. All regional
service within NEPOOL, except for wheeling through or out, is to be provided as
a network service.
On June 25, 1997, FERC issued an order conditionally authorizing the
establishment of an ISO by NEPOOL effective July 1, 1997, affirming that the
transfer of control of transmission facilities owned by the public utility
members of NEPOOL to the ISO is consistent with the public interest under
section 203 of the Federal Power Act.
NEPOOL is in the process of transferring operational control of the New
England bulk power system to the ISO, a newly created non-profit Delaware
corporation. The ISO's primary responsibility is to ensure system reliability,
administer the NE POOL Tariff, and oversee the efficient and competitive
functioning of the regional power market. The selection of the ISO's Board of
Directors was announced in April 1997.
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, 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 transfer 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. Implementation of the
installed capability market is planned for November 1997, the operable
capability and energy markets are planned for April 1998, and the reserve
markets will follow later in 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 - On October 2, 1997, the Registrant filed a
Current Report on Form 8-K will respect to Item 5 (Other Events).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Eastern Utilities Associates
(Registrant)
Date: November 14, 1997 /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-31-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 710738
<OTHER-PROPERTY-AND-INVEST> 132761
<TOTAL-CURRENT-ASSETS> 146862
<TOTAL-DEFERRED-CHARGES> 204626
<OTHER-ASSETS> 75984
<TOTAL-ASSETS> 1270791
<COMMON> 102180
<CAPITAL-SURPLUS-PAID-IN> 217476
<RETAINED-EARNINGS> 53906
<TOTAL-COMMON-STOCKHOLDERS-EQ> 373562
27468
6900
<LONG-TERM-DEBT-NET> 334842
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 57439
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 72517
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 398063
<TOT-CAPITALIZATION-AND-LIAB> 1270791
<GROSS-OPERATING-REVENUE> 422635
<INCOME-TAX-EXPENSE> 9893
<OTHER-OPERATING-EXPENSES> 369313
<TOTAL-OPERATING-EXPENSES> 379206
<OPERATING-INCOME-LOSS> 43429
<OTHER-INCOME-NET> 15287
<INCOME-BEFORE-INTEREST-EXPEN> 58716
<TOTAL-INTEREST-EXPENSE> 29609
<NET-INCOME> 29107
1729
<EARNINGS-AVAILABLE-FOR-COMM> 27378
<COMMON-STOCK-DIVIDENDS> 25443
<TOTAL-INTEREST-ON-BONDS> 24460
<CASH-FLOW-OPERATIONS> 90947
<EPS-PRIMARY> 1.245
<EPS-DILUTED> 1.245
</TABLE>
