UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 July 31, 1997
Common Shares, $5 par value 20,435,997 shares
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
<TABLE>
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
June 30, December 31,
ASSETS 1997 1996
<S> <C> <C>
Utility Plant and Other Investments:
Utility Plant in Service $ 1,067,573 $ 1,067,056
Less: Accumulated Provision for Depreciation
and Amortization 368,163 350,816
Net Utility Plant in Service 699,410 716,240
Construction Work in Progress 12,523 3,839
Net Utility Plant 711,933 720,079
Investments in Jointly Owned Companies 72,611 71,626
Non-Utility Plant - Net 64,703 72,653
Total Plant and Other Investments 849,247 864,358
Current Assets:
Cash and Temporary Cash Investments 7,575 12,455
Accounts Receivable, Net 90,140 90,153
Notes Receivable 25,542 24,691
Fuel, Materials and Supplies 11,620 14,131
Other Current Assets 11,265 7,668
Total Current Assets 146,142 149,098
Deferred Debits and Other Non-Current Assets 247,708 243,573
Total Assets $ 1,243,097 $ 1,257,029
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Shares, $5 Par Value $ 102,180 $ 102,180
Other Paid-In Capital 221,329 221,160
Common Share Expense (3,931) (3,931)
Retained Earnings 51,566 52,404
Total Common Equity 371,144 371,813
Non-Redeemable Preferred Stock - Net 6,900 6,900
Redeemable Preferred Stock - Net 27,324 27,035
Long-Term Debt - Net 380,643 406,337
Total Capitalization 786,011 812,085
Current Liabilities:
Long-Term Debt Due Within One Year 47,515 27,512
Notes Payable 56,105 51,848
Accounts Payable 31,079 33,811
Taxes Accrued 2,956 3,004
Interest Accrued 8,184 9,612
Other Current Liabilities 26,740 26,772
Total Current Liabilities 172,579 152,559
Deferred Credits and Other Non-Current Liabilities 118,887 123,209
Accumulated Deferred Taxes 165,620 169,176
Total Liabilities and Capitalization $ 1,243,097 $ 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 Six Months Ended
June 30, June 30,
1997 1996 1997 1996
<S> <C> <C> <C> <C>
Operating Revenues $138,856 $122,785 $280,609 $257,585
Operating Expenses:
Fuel 23,663 17,464 53,134 40,659
Purchased Power 30,207 28,613 62,716 58,616
Other Operation and Maint. 52,356 49,211 93,698 89,941
Early Retirement Offer 1,416 0 1,416
Depreciation and Amort. 11,494 11,675 23,124 22,798
Taxes - Other Than Income 5,963 5,939 12,339 12,409
Income Taxes - Current 2,602 530 11,517 6,802
- Deferred (172) (671) (4,868) (1,945)
Total 127,529 112,761 253,076 229,280
Operating Income 11,327 10,024 27,533 28,305
Other Income - Net 4,972 3,032 9,401 6,400
Income Before Int. Charges 16,299 13,056 36,934 34,705
Interest Charges:
Interest on Long-Term Debt 8,193 8,620 16,419 17,269
Other Interest Expense 1,838 1,576 3,432 3,196
All. for Borrowed Funds Used
During Construction (Credit) (242) (439) (482) (985)
Net Interest Charges 9,789 9,757 19,369 19,480
Net Income 6,510 3,299 17,565 15,225
Preferred Dividends of Subs. 577 578 1,153 1,157
Consolidated Net Earnings $ 5,933 $ 2,721 $ 16,412 $ 14,068
Weighted Average Number of
Common Shares Outstanding 20,435,997 20,436,997 20,435,997 20,436,438
Consolidated Earnings Per
Average Common Share $ 0.29 $ 0.13 $ 0.80 $ 0.69
Dividends Paid $ 0.415 $ 0.415 $ 0.83 $ 0.815
See accompanying notes to consolidated condensed financial statements.
</TABLE>
<TABLE>
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Six Months Ended
June 30,
1997 1996
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 17,565 $ 15,225
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Act.:
Depreciation and Amortization 26,206 26,542
Deferred Taxes (4,753) (1,472)
Non-cash Expenses on Sales of Inv.
in Energy Savings Projects 9,809 2,350
Investment Tax Credit, Net (601) (604)
Allowance for Funds Used During Construction (59) (102)
Coll. and sales of project notes and leases rec. 4,690 3,954
Other - Net (2,186) 5,849
Change in Operating Assets and Liabilities (8,230) 1,243
Net Cash Provided From Operating Activities 42,441 52,985
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (34,068) (33,046)
Coll. on Notes and Lease Rec. of EUA Cogenex 6,560 2,149
Increase in Other Investments (221) (4,036)
Net Cash Used in Investment Activities (27,729) (34,933)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (5,734) (5,737)
Premium on Reacquisition and Fin. Expenses (6)
EUA Common Share Dividends Paid (16,962) (16,656)
Subsidiary Preferred Dividends Paid (1,153) (1,157)
Net Increase in Short-Term Debt 4,257 8,641
Net Cash Used in Financing Activities (19,592) (14,915)
Net (Decrease) Inc. in Cash and Temp. Cash Inv. (4,880) 3,137
Cash and Temporary Cash Inv. at Beg. 12,455 4,060
Cash and Temporary Cash Inv. at End of Period $ 7,575 $ 7,197
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Capitalized Interest) $ 18,692 $ 17,742
Income Taxes $ 14,499 $ 10,987
Supplemental schedule of non-cash inv. act.:
Conversion of Investments in Energy Savings
Projects to Notes and Leases Receivable $ 3,114 $ 3,195
</TABLE>
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) 1996 Annual Report on Form 10-K and the
Company's Quarterly Report on Form 10-Q for the period ended March 31, 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 June 30, 1997 and December 31,
1996, and the results of operations for the three and six months
ended June 30, 1997 and 1996 and cash flows for the six months ended
June 30, 1997 and 1996. The year-end consolidated condensed balance
sheet data was derived from audited financial statements but does not
include all disclosures required under generally accepted accounting
principles.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
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 July 1996, Northeast reported that it was responding to a series
of requests from the NRC seeking assurance that the Millstone III
unit would be operated in accordance with the terms of its operating
license and other NRC requirements and regulations and dealing with a
series of issues that were identified in the course of these reviews.
Providing these assurances and addressing these issues were
components of an Operational Readiness Plan which was submitted to
the NRC on July 2, 1996 and is presently being implemented.
On October 18, 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.
On October 24, 1996 the NRC issued another order directing that prior
to restart of Millstone III, Northeast submit a plan for disposition
of safety issues raised by employees and retain an independent third-
party to oversee implementation of this plan. This third-party
oversight will continue until the situation is corrected.
Northeast expects that one of the three Millstone units will be ready
for restart in the third quarter of 1997, one in the fourth quarter
of 1997 and one in the first quarter of 1998.
Subject to final NRC reviews and inspections, Northeast expects that
at least one of the units will be back on line by the end of 1997.
In March of 1997, Northeast announced that Millstone III has 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.
On May 8, 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 $10.4 million, approximately $4.4 million
more than originally expected and $3.2 million more than O&M
expenditures in 1996.
The ICAVP for Millstone III began in May of 1997 and is ongoing. The
ICAVP is an external review process that is necessary prior to the
restart of the unit.
While Millstone III is out of service, Montaup will incur incremental
replacement power costs estimated at $0.5 million to $0.7 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 $5.1 million at
June 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 June 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:
In December 1996, Maine Yankee Atomic Power Plant was shut down for
inspections and repairs to resolve cable-separation and associated
issues. Further inspections while the unit was shut down indicated
that several fuel assemblies that contained leaking rods should be
replaced. After ongoing safety assessments by the NRC, it was
determined that the Plant would remain out of service until the fuel-
assembly replacement and a thorough inspection of the Plant's
electrical cabling were completed and associated issues were
resolved. A restart of the Plant would have required NRC approval.
In August of 1997, as the result of an economic evaluation, the Board
of Directors of Maine Yankee voted to permanently close the Plant.
Montaup has a 4.0% equity ownership in Maine Yankee with a book value
of approximately $3.0 million at June 30, 1997. The amount of
unrecovered assets and estimated costs to decommission the Plant is
currently being revised from a 1996 estimate. When the amount is
known, most likely in the third quarter of 1997, Montaup will record
it's share of that future liability, and at the same time, due to
anticipated recoverability, will record a regulatory asset for the
same amount.
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 will 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.
Early Retirement Offer
In June of 1997, an early retirement offer was accepted by a group of nine
employees who were eligible but not offered a Voluntary Retirement Incentive
offer completed in 1995, resulting in a $1.4 million (approximately $900,000
after-tax) charge to second quarter 1997 earnings.
Overview
Consolidated Net Earnings for the quarter ended June 30, 1997 were $5.9
million compared to $2.7 million in the second quarter of 1996. The second
quarter 1997 results include an after-tax charge of approximately $900,000
related to an early retirement offer (see above). The second quarter 1996
results include a one-time, after-tax charge to earnings of $3.7 million
recorded by EUA Cogenex in June 1996 related to the expensing of certain
project proposal costs and joint start-up costs. Net Earnings contributions by
Business Unit for the second quarter of 1997 and 1996 were as follows (000's):
Increase
1997 1996 (Decrease)
Core Electric Business $7,022 $7,001 $21
Energy Related Business (182) (327) 145
Corporate (14) (281) 267
Subtotal 6,826 6,393 433
June 1996 EUA Cogenex Charge (3,672) 3,672
June 1997 Early Retirement Offer (893) (893)
Consolidated $5,933 $2,721 $3,212
Net Earnings of the Core Electric Business Unit were essentially flat in
the second quarter of 1997. A 2.3% increase in primary kilowatthour sales in
this year's second quarter contributed to increased base rate recoveries and
essentially offset increased jointly owned unit expenses including incremental
expenses of approximately $900,000 related to the extended outage of the
Millstone III Nuclear Generating Station and costs associated with a scheduled
maintenance outage at Montaup Electric Company's Somerset Station.
Net Earnings of the Energy Related Business Unit increased by approximately
$100,000 in the second quarter of 1997 as compared to the same period of a year
ago primarily due to improved operating results of EUA Cogenex.
The Corporate Business Unit Net Earnings for the second quarter of 1997
compared to the same period in 1996 increased by approximately $300,000 due
primarily to lower interest expense and increased intercompany interest income.
Consolidated Net Earnings for the six months ended June 30, 1997 were
$16.4 million compared to $14.1 million for the same period of 1996. Net
Earnings contributions by Business Unit for the first six months of 1997 and
1996 were as follows (000's):
Increase
1997 1996 (Decrease)
Core Electric Business $17,923 $18,613 $(690)
Energy Related Business (692) (419) (273)
Corporate 74 (454) 528
Subtotal 17,305 17,740 (435)
June 1996 EUA Cogenex Charge (3,672) 3,672
June 1997 Early Retirement Offer (893) (893)
Consolidated $16,412 $14,068 $2,344
Net Earnings of the Core Electric Business Unit for the first half of 1997
decreased by approximately $700,000 as compared to the year-to-date period of
1996. Increased jointly owned unit expenses including incremental expenses of
the Millstone III unit of $1.9 million and the aforementioned Somerset Station
expenses were somewhat offset by increased base rate recoveries.
Net Earnings of the Energy Related Business Unit decreased by approximately
$300,000 in the first six months of 1997 as compared to the same period of a
year ago. EUA Cogenex's improved operating results for the year-to-date period
were essentially offset by increased Energy Investment losses of approximately
$400,000 largely due to increased marketing expenses of the BIOTEN partnership
and increased intercompany interest expense.
The Corporate Business Unit Net Earnings for the first six months of 1997
compared to the same period in 1996 increased by approximately $500,000 due
primarily to decreased short-term debt interest expense and increased
intercompany interest income.
Operating Revenues
Operating Revenues for the second quarter of 1997 increased by
approximately $16.1 million or 13.1% when compared to the same period of 1996.
Revenues by Business Unit operations were as follows (000's):
Three Months Ended June 30,
Increase
1997 1996 (Decrease)
Core Electric Business $120,353 $107,331 $13,022
Energy Related Business 18,503 15,454 3,049
Corporate 0 0 0
Consolidated $138,856 $122,785 $16,071
Core Electric Business revenues include the impact of recoveries of
increased fuel, purchased power and conservation and load management (C&LM)
expenses aggregating $8.2 million (see Operations Expense below). A 2.3%
increase in primarily kWh sales and 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 virtually all of the Energy Related
Business Unit revenues, increased by $3.0 million due primarily to increases in
Cogenex Division project sales and increases in Cogenex-Canada and EUA Cogenex-
West (formerly EUA Highland) revenues.
Operating Revenues for the first six months of 1997 increased by $23.0
million or 8.9% when compared to the same period of 1996. Operating Revenues
by Business Unit for the first six months of 1997 and 1996 were as follows
(000's):
Six Months Ended June 30,
Increase
1997 1996 (Decrease)
Core Electric Business $248,577 $229,535 $19,042
Energy Related Business 32,032 28,050 3,982
Corporate 0 0 0
Consolidated $280,609 $257,585 $23,024
Core Electric Business revenues increased by $19.0 million due primarily to
recoveries of increased fuel, purchased power and C&LM expenses of $16.2
million and increased base rate recoveries.
EUA Cogenex revenues increased by approximately $3.8 million due primarily
to increased Cogenex Division project sales and increased revenues of Cogenex-
Canada and EUA Cogenex-West.
Operations Expense
Fuel expense of the Core Electric Business Unit for the second quarter and
first half of 1997 increased from that of the same periods in 1996 by
approximately $6.2 million or 35.5% and $12.5 million or 30.7%, respectively.
Outages of nuclear units in this year's second 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 28.3% and
27.8% for the respective periods. Also impacting fuel expense were increases
in total energy generated and purchased of 5.4% for the second quarter of 1997
and 1.8% for the year-to-date period as compared to the same periods of 1996.
Purchased Power demand expense for the second quarter of 1997 increased
$1.6 million or 5.6% and increased $4.1 million or 7.0% for the six months
ended June 30, 1997. These changes are due primarily to the impact of
increased billings from Maine Yankee and the Ocean State Power project.
Other Operation and Maintenance expenses for the three and six months ended
June 30, 1997 increased approximately $3.1 million or 6.4% and $3.8 million or
4.2%, respectively, from the same periods in 1996.
Direct expenses of the Core and Corporate Business units increased by $1.1
million in the second quarter of 1997 and approximately $300,000 for the year
to date period of 1997 as compared to the same periods of 1996. These
increases are due primarily to expenses of approximately $700,000 related to a
scheduled maintenance and refueling outage at Montaup Electric's Somerset
plant in the second quarter of 1997. The year-to-date increase was offset
somewhat by decreased storm related expenses of approximately $400,000 due to
an unusual amount of storms occurring in our service territory in 1996.
Indirect expenses, items over which there is limited short-term control or
items which are fully recovered in rates, increased by approximately $3.3
million in the second quarter of 1997 as compared to the second quarter of
1996. This change was primarily due to increased jointly owned unit expenses of
approximately $2.8 million, approximately $900,000 of which is related to the
Millstone III outage, and the remainder is comprised of expenses related to the
scheduled maintenance outages at the Canal and Seabrook units. Also impacting
this increase were increased C&LM expense of approximately $300,000 and
increased transmission charges from other utilities of approximately
$400,000, partially offset by decreased FAS106 expenses of approximately
$200,000. For the year-to-date period, indirect expenses increased
approximately $4.1 million. Jointly owned unit expenses increased
approximately $4.4 million, $1.9 million of which relates to the Millstone III
outage, and the remainder is due to the expenses of the Canal and Seabrook
units. An increase in transmission charges of approximately $400,000 was
offset by decreased FAS106 expenses of approximately $500,000.
Expenses of the Energy Related Business Unit decreased approximately $1.1
million in the second quarter of 1997 and $500,000 for the year-to-date period
of 1997, respectively, as compared to the same periods of 1996. These
decreases are primarily due to decreased expenses of Cogenex's Nova and Day
divisions as a result of decreased operating activity, partially offset by
increased marketing expenses of Energy Investment's BIOTEN partnership.
Other Income and (Deductions) - Net
Other Income and (Deductions) - Net increased by approximately $2.0 million
in this year's second quarter and increased by $3.0 million in the year-to-date
period as compared to same periods of 1996. These increases are due primarily
to interest income related to the favorable resolution of a Massachusetts
corporate income tax dispute, the impact of changes to EUA Cogenex pension and
post-retirement welfare benefit plans and increased interest income of EUA
Cogenex.
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. At June 30, 1997, EUA System companies
maintained short-term lines of credit with various banks aggregating
approximately $140 million. Outstanding short-term debt at June 30, 1997 and
December 31, 1996 by Business Unit was as follows (000's):
June 30, 1997 December 31, 1996
Core Electric Business $18,269 $ 3,670
Energy Related Business 26,036 24,341
Corporate 11,800 23,837
Consolidated $56,105 $51,848
For the six months ended June 30, 1997 internally generated funds available
after the payment of dividends amounted to approximately $33.9 million while
the EUA System's cash construction requirements amounted to approximately $34.1
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
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 customers, 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 August 1, 1997 two customers had 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 to 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 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 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 in the third quarter of 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,
submitted to the MDPU on July 1, 1997, 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. Subsequent 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. EUA intends to
amend this filing once settlement negotiations in Rhode Island, currently in
progress, have concluded. 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 for 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.
Negotiations in Rhode Island on final settlement terms regarding electric
utility industry restructuring, including the CTC, are continuing, subsequent
to which a formal filing will be made to the RIPUC for approval.
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.
EUA believes that its Core Electric operations will continue to meet the
criteria established in these accounting standards.
However, the potential exists that the final outcome of state and federal
agency determinations could result in EUA no longer meeting the criteria of
these accounting standards which could trigger the discontinuance of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (FAS71). Should it be required to discontinue the
application of FAS71, EUA would be required to take an immediate write-down of
the affected assets in accordance with FAS101, "Accounting for the
Discontinuation of Application of FAS71."
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 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, FERC issued orders on its March 24, 1995 Notice of
Proposed Rulemaking (NOPR). FERC's purpose in proposing the new rules was to
encourage competition in the bulk power market. FERC's April 24th actions
include:
- order No. 888, a final rule requiring open access transmission and
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.
Utilities must take transmission service for their own wholesale
transactions under the terms and conditions of the tariff;
- establishing the right and a mechanism for recovery of prudently
incurred stranded costs by public utilities and transmitting utilities;
which arise as a result of wholesale open access;
- order No. 889, a final rule requiring public utilities to implement
standards of conduct and an Open Access Same-time Information System
(OASIS). Utilities must obtain information about their transmission the
same way as their competitors through the OASIS;
- a 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 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
tariffs were the subject of a settlement agreement which was filed on June 14,
1996. Montaup amended its filing on July 9, 1996 to modify its terms and
conditions in conformance with FERC's order. These tariffs are in compliance
with FERC's April 24th rulings.
On November 13, 1996, FERC issued a final order on the non-rate terms and
conditions of Montaup's open access transmission tariff. Montaup was required
to provide a more detailed description of the method used to compute available
transmission capability. FERC has not taken any action on the rates portion of
the tariff.
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. On
January 21, 1997, Montaup filed revisions to its Open Access Transmission
tariff to coincide with the New England Power Pool (NEPOOL) Open Access
Transmission tariff filed on December 31, 1996 (see below) which became
effective March 1, 1997, subject to refund and the issuance of further orders.
On April 2, 1997, Montaup filed additional revised tariff sheets to update
the filing's formula rate for local network service.
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 regionwide
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, 1997, 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.
In addition to the above transmission tariffs filings, the EUA System
companies have been actively involved in the restructuring of NEPOOL. 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 NEPOOL 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 EUA System 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 May 19, 1997, the Registrant filed a
current report on Form 8-K with respect to Item 5 (Other
Events).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Eastern Utilities Associates
(Registrant)
Date: August 14, 1997 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)
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