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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
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, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission File Number 2-7749
COMMONWEALTH ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1659070
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
One Main Street, Cambridge, Massachusetts 02142-9150
(Address of principal executive offices) (Zip Code)
(617) 225-4000
(Registrant's telephone number, including area code)
(Former name, address and fiscal year, if changed since last report.)
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 practicable date.
Outstanding at
Class of Common Stock August 1, 1995
Common Stock, $25 par value 2,043,972 shares
The Company meets the conditions set forth in General Instruction H(1)(a) and
(b) of Form 10-Q as a wholly-owned subsidiary and is therefore filing this
Form with the reduced disclosure format.
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
COMMONWEALTH ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
JUNE 30, 1995 AND DECEMBER 31, 1994
ASSETS
(Unaudited)
June 30, December 31,
1995 1994
(Dollars in Thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $505 495 $496 166
Less - Accumulated depreciation 150 732 143 877
354 763 352 289
Add - Construction work in progress 8 270 5 216
363 033 357 505
INVESTMENTS
Equity in nuclear electric power company 616 654
Other 14 14
630 668
CURRENT ASSETS
Cash 967 1 637
Accounts receivable -
Affiliates 3 304 3 713
Customers 37 441 37 862
Unbilled revenues 5 528 8 899
Prepaid property taxes - 2 739
Inventories and other 6 071 6 032
53 311 60 882
DEFERRED CHARGES 90 006 57 831
$506 980 $476 886
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COMMONWEALTH ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
JUNE 30, 1995 AND DECEMBER 31, 1994
CAPITALIZATION AND LIABILITIES
(Unaudited)
June 30, December 31,
1995 1994
(Dollars in Thousands)
CAPITALIZATION
Common Equity -
Common stock, $25 par value -
Authorized and outstanding -
2,043,972 shares wholly-owned by
Commonwealth Energy System (Parent) $ 51 099 $ 51 099
Amounts paid in excess of par value 97 112 97 112
Retained earnings 14 773 15 350
162 984 163 561
Long-term debt, less current sinking
fund requirements 156 770 157 817
319 754 321 378
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks 7 900 6 400
Advances from affiliates 30 010 200
37 910 6 600
Other Current Liabilities -
Current sinking fund requirements 1 053 1 053
Accounts payable -
Affiliates 6 849 7 716
Other 27 804 31 911
Accrued taxes -
Local property and other 304 3 721
Income 13 233 8 049
Other 12 481 13 691
61 724 66 141
99 634 72 741
DEFERRED CREDITS
Accumulated deferred income taxes 43 101 42 074
Unamortized investment tax credits 7 778 7 994
Other 36 713 32 699
87 592 82 767
COMMITMENTS AND CONTINGENCIES
$506 980 $476 886
See accompanying notes.
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COMMONWEALTH ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME AND RETAINED EARNINGS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 1995 AND 1994
(Unaudited)
Three Months Ended Six Months Ended
1995 1994 1995 1994
(Dollars in Thousands)
ELECTRIC OPERATING REVENUES $ 97 226 $ 98 244 $210 434 $216 734
OPERATING EXPENSES
Electricity purchased for
resale, transmission and fuel 62 969 64 267 140 932 145 042
Other operation and maintenance 20 372 21 795 39 997 41 795
Depreciation 4 103 3 984 8 205 7 998
Taxes -
Income 1 701 1 011 4 365 4 021
Local property 1 382 1 240 2 764 2 524
Payroll and other 630 636 1 640 1 628
91 157 92 933 197 903 203 008
OPERATING INCOME 6 069 5 311 12 531 13 726
OTHER INCOME 1 122 208 2 782 295
INCOME BEFORE INTEREST CHARGES 7 191 5 519 15 313 14 021
INTEREST CHARGES
Long-term debt 3 520 3 544 7 041 7 090
Other interest charges 943 115 1 318 225
Allowance for borrowed funds
used during construction (123) (88) (236) (153)
4 340 3 571 8 123 7 162
NET INCOME 2 851 1 948 7 190 6 859
RETAINED EARNINGS -
Beginning of period 16 214 16 759 15 350 15 118
Dividends on common stock (4 292) (3 884) (7 767) (7 154)
End of period $ 14 773 $ 14 823 $ 14 773 $ 14 823
See accompanying notes.
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COMMONWEALTH ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1994
(Unaudited)
1995 1994
(Dollars in Thousands)
OPERATING ACTIVITIES
Net income $ 7 190 $ 6 859
Effects of noncash items -
Depreciation and amortization 9 597 9 481
Deferred income taxes and investment
tax credits, net 3 221 (350)
Change in working capital, exclusive of cash,
advances to affiliates and interim financing 2 484 18 384
Buy-out of power contract (25 500) -
Fuel charge stabilization deferral (6 865) (11 087)
All other operating items (599) (6 061)
Net cash (used for) provided by operating activities (10 472) 17 226
INVESTING ACTIVITIES
Additions to property, plant and equipment
(exclusive of AFUDC) (12 458) (9 387)
Allowance for borrowed funds used during
construction (236) (153)
Payment from affiliates - (810)
Net cash used for investing activities (12 694) (10 350)
FINANCING ACTIVITIES
Proceeds from short-term borrowings 1 500 -
Proceeds from affiliates 29 810 -
Payment of dividends (7 767) (7 154)
Sinking funds payments (1 047) (1 047)
Net cash provided by (used for) financing activities 22 496 (8 201)
Net decrease in cash (670) (1 325)
Cash at beginning of period 1 637 2 794
Cash at end of period $ 967 $ 1 469
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid (received) during the period for:
Interest (net of capitalized amounts) $ 7 792 $ 6 942
Income taxes $ (1 287) $ (821)
See accompanying notes.
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COMMONWEALTH ELECTRIC COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
(1) Accounting Policies
Commonwealth Electric Company (the Company) is a wholly-owned subsid-
iary of Commonwealth Energy System. The parent company is referred to in
this report as the "System" and, together with its subsidiaries, is
collectively referred to as "the system."
The Company's significant accounting policies are described in Note 1
of Notes to Financial Statements included in its 1994 Annual Report on
Form 10-K filed with the Securities and Exchange Commission. For interim
reporting purposes, the Company follows these same basic accounting
policies but considers each interim period as an integral part of an
annual period and makes allocations of certain expenses to interim
periods based upon estimates of such expenses for the year.
The Company has established various regulatory assets in cases where
the Massachusetts Department of Public Utilities (DPU) and/or the Federal
Energy Regulatory Commission (FERC) have permitted or are expected to
permit recovery of specific costs over time. Similarly, certain regula-
tory liabilities established by the Company are required to be refunded
to its customers over time. In March 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to be Disposed Of" (SFAS 121). SFAS 121 imposes stricter
criteria for regulatory assets by requiring that such assets be probable
of future recovery at each balance sheet date. Based on the current
regulatory framework, the Company accounts for the economic effects of
regulation in accordance with the provisions of SFAS No. 71, "Accounting
for the Effects of Certain Types of Regulation" and does not expect that
the adoption of SFAS 121, which the Company expects to adopt on January
1, 1996, will have a material impact on its financial position or results
of operations. However, this conclusion may change in the future if
changes are made in the current regulatory framework or as competitive
factors influence wholesale and retail pricing in this industry. The
principal regulatory assets included in deferred charges were as follows:
June 30, December 31,
1995 1994
(Dollars in Thousands)
Purchased power contract buy-out $25 539 $ -
Fuel charge stabilization 23 503 16 638
Postretirement benefit costs
including pensions 12 529 11 215
Yankee Atomic unrecovered plant
and decommissioning costs 8 982 10 204
Pilgrim nuclear plant litigation costs 6 822 7 001
Cannon Street generating plant
abandonment, net 4 400 4 400
Conservation and load management costs 3 307 3 659
Other 893 1 049
Total regulatory assets $85 975 $54 166
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COMMONWEALTH ELECTRIC COMPANY
The regulatory liabilities included in deferred credits - other,
principally related to taxes, amounted to $11.7 million and $3.7 million
at June 30, 1995 and December 31, 1994, respectively.
Income tax expense is recorded using the statutory rates in effect
applied to book income subject to tax recorded in the interim period.
The unaudited financial statements for the periods ended June 30, 1995
and 1994 reflect, in the opinion of the Company, all adjustments (consist-
ing of only normal recurring accruals) necessary to summarize fairly the
results for such periods. In addition, certain prior period amounts are
reclassified from time to time to conform with the presentation used in
the current period's financial statements.
The results for interim periods are not necessarily indicative of
results for the entire year because of seasonal variations in the con-
sumption of energy.
(2) Commitments and Contingencies
(a) Construction and Financing Programs
The Company is engaged in a continuous construction program presently
estimated at $141 million for the five-year period 1995 through 1999. Of
that amount, $27.1 million is estimated for 1995. As of June 30, 1995,
the Company's construction expenditures amounted to approximately $12.7
million, including an allowance for funds used during construction. The
Company expects to finance these expenditures on an interim basis with
internally generated funds and short-term borrowings which are ultimately
expected to be repaid with the proceeds from sales of long-term debt and
equity securities.
The program is subject to periodic review and revision due to factors
such as changes in business conditions, rates of customer growth, effects
of inflation, maintenance of reliable and safe service, equipment delivery
schedules, licensing delays, availability and cost of capital and environ-
mental regulations.
(b) Decommissioning of Yankee Atomic Nuclear Power Plant
In February 1992, the Board of Directors of Yankee Atomic Electric
Company (Yankee Atomic) agreed to permanently discontinue power operation
of its plant and decommission the Yankee Nuclear Power Station (the
plant). The Company's 2.5% investment in Yankee Atomic is approximately
$616,000. The most recent cost estimate to permanently shut down the
plant is approximately $396 million. The Company's share of this liabili-
ty is $9 million and is currently reflected in the accompanying balance
sheets as a liability and corresponding regulatory asset.
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COMMONWEALTH ELECTRIC COMPANY
Item 2. Management's Discussion and Analysis of Results of Operations
The following is a discussion of certain significant factors which have
affected operating revenues, expenses and net income during the periods
included in the accompanying condensed statements of income. This discussion
should be read in conjunction with the Notes to Condensed Financial Statements
appearing elsewhere in this report.
A summary of the period to period changes in the principal items included
in the condensed statements of income for the three and six months ended
June 30, 1995 and 1994 and unit sales for these periods is shown below:
Three Months Ended Six Months Ended
June 30, June 30,
1995 and 1994 1995 and 1994
Increase (Decrease)
(Dollars in Thousands)
Electric Operating Revenues $ (1 018) (1.0)% $ (6 300) (2.9)%
Operating Expenses -
Electricity purchased for resale,
transmission and fuel (1 298) (2.0) (4 110) (2.8)
Other operation and maintenance (1 423) (6.5) (1 798) (4.3)
Depreciation 119 3.0 207 2.6
Taxes -
Federal and state income 690 68.2 344 8.6
Local property and other 136 7.2 252 6.1
(1 776) (1.9) (5 105) (2.5)
Operating Income 758 14.3 (1 195) (8.7)
Other Income 914 439.4 2 487 843.1
Income Before Interest Charges 1 672 30.3 1 292 9.2
Interest Charges 769 21.5 961 13.4
Net Income $ 903 46.4 $ 331 4.8
Unit Sales (Megawatthours or MWH)
Retail 20 307 2.7 (32 049) (2.0)
Wholesale (215 380) (59.7) (330 547) (44.1)
Total unit sales (195 073) (17.5) (362 596) (15.3)
The following is a summary of unit sales (in MWH) for the periods
indicated:
Three Months Six Months
Period Ended Total Retail Wholesale Total Retail Wholesale
June 30, 1995 920 774 775 600 145 174 2 007 624 1 589 133 418 491
June 30, 1994 1 115 847 755 293 360 554 2 370 220 1 621 182 749 038
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COMMONWEALTH ELECTRIC COMPANY
Operating Revenues, Electricity Purchased for Resale, Transmission and Fuel
Operating revenues for the three and six-month periods ended June 30,
1995 decreased by $1 million (1%) and $6.3 million (2.9%), respectively, from
the corresponding periods in 1994 due primarily to declines in wholesale unit
sales. However, fluctuations in the level of wholesale sales have little, if
any, impact on net income. In the first half of 1995, unit sales to residen-
tial customers declined 4.9% reflecting extremely mild weather in the first
quarter of this year as compared to the record cold experienced during the
same period of 1994. In the second quarter of 1995, total retail electric
revenues increased $3.8 million as unit sales increased 2.7%, and nearly
offset the $4.6 million revenue decline caused by lower wholesale sales.
The current three and six-month periods reflect the absence of power
purchases from Canal Electric Company's (Canal) Unit 1, the reduced purchases
from Canal Unit 2 and reduced power purchases from the non-affiliated Pilgrim
nuclear unit and an independent power producer (IPP) reflecting the restruc-
turing of a power contract that defers purchases for a six-year period that
began in early 1995. In January 1995, the Company terminated a long-term power
contract with another IPP through a buy-out arrangement which will reduce
future power costs. Somewhat offsetting these reduced power sources were
greater power purchases from Seabrook and several other non-utility genera-
tors.
The Company has received approval from the Massachusetts Department of
Public Utilities (DPU) to recover in revenues certain current costs associated
with conservation and load management (C&LM) programs through the operation of
a Conservation Charge decimal on a dollar-for-dollar basis. To the extent
that these expenses increase or decrease from period to period based on
customer participation, a corresponding change will occur in revenues. In
1995, the collection of these revenues declined $868,000 and $1.3 million in
the current quarter and six-month period when compared to the same periods
last year.
Historically, revenues collected through base rates have been designed to
reimburse the Company for all costs of operation other than fuel, the energy
portion of purchased power, transmission and C&LM costs, and provide a fair
return on capital invested in the business. However, as a result of a DPU-
mandated recovery mechanism implemented in July 1991 for capacity-related
costs associated with certain long-term purchased power contracts, the Company
has experienced a revenue excess or shortfall when unit sales and/or the costs
recoverable in base rates vary from test-period levels. This issue, which has
had a significant impact on net income, was addressed in a settlement agree-
ment approved by the DPU in May 1995. (Refer to the "Rate Settlement Agree-
ment" section for additional details.) For the current three and six-month
periods, in accordance with the settlement agreement, approximately $1.1
million was deferred for future recovery. The Company's undercollection of
these capacity-related costs up to the effective date of the settlement was
$1.6 million and $2 million for the current three and six-month periods,
respectively. As a result, net income was reduced by $322,000 and $589,000
for the current three and six-month periods, respectively, an improvement of
$868,000 and $818,000 from the same periods last year.
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COMMONWEALTH ELECTRIC COMPANY
Other Operation and Maintenance
Other operation and maintenance (O&M) declined in the current quarter and
six-month period of 1995 due to lower C&LM program costs ($843,000 and $1.3
million), a decline in maintenance expense of $564,000 and $315,000 (primarily
transmission and distribution facilities) and continued savings resulting from
other on-going cost containment measures. These decreases were offset, in
part, in the current quarter and six-month period, respectively, by higher
labor and benefit costs ($274,000 and $560,000), primarily reflecting the full
recognition of expenses relating to postretirement benefits other than
pensions and amortization of previously deferred postretirement benefits
costs. (Refer to the "Rate Settlement Agreement" section for additional
information.) Also, legal fees associated with power contract arbitration
proceedings ($380,000) were included in both current periods.
Depreciation and Taxes
Depreciation expense increased slightly in the current three and six-
month periods due to a higher level of depreciable property, plant and equip-
ment. The increases in federal and state income taxes was due to a higher
level of pretax income. Local property and other tax increases for the three
and six-month periods of 1995 primarily reflect higher rates and assessments
($142,000 and $240,000, respectively).
Other Income and Interest Charges
Other income for the current six-month period increased by $2.5 million
due primarily to the reversal of a contingency reserve related to certain
costs associated with the Company's energy conservation program ($1.4 mil-
lion), the recovery of which has since been approved by the DPU. Also
contributing to the increase in the current three and six-month periods was a
higher level of interest income related to the fuel charge stabilization
deferral ($369,000 and $759,000, respectively) and, for both current periods,
carrying costs associated with the April 1995 buy-out of a power contract
($684,000) with an IPP. The cost of the buy-out is being recovered from
customers over a seven-year period.
Total interest charges increased by $769,000 (21.5%) and $961,000 (13.4%)
during the current three and six-month periods reflecting an increases of
$732,000 and $966,000, respectively, in interest on short-term borrowings
which were not required during the first half of 1994.
Power Contract Arbitration
On June 7, 1995, a three-member panel of arbitrators upheld the termina-
tion by the Company of a power contract with Eastern Energy Corporation
(Eastern), the developer of a proposed 300 MW coal-fired plant. In June 1989,
the Company agreed to buy 16% (50 MW) of the power to be produced by the
proposed plant, originally scheduled to begin operation in January 1992.
However, in May 1994, the Company gave notice of termination of its power
contract with Eastern based upon its failure to meet the permitting, con-
struction or operation milestones established by the contract, obtain the
required permits, commence construction or sell any additional power from the
proposed plant. Efforts to reshape the power contract to provide a satisfac-
tory arrangement were unsuccessful. In a letter dated June 30, 1994, Eastern
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<PAGE 11>
COMMONWEALTH ELECTRIC COMPANY
objected to the notice of termination and invoked arbitration seeking $31.2
million from the Company. The panel's decision is binding and prevents
Eastern from further litigating or contesting the termination of the contracts
in any other forum. This action is expected to save the Company's customers
approximately $60 million over the next ten years and as much as $135 million
over twenty years.
Rate Settlement Agreement
In May 1995, the DPU approved a settlement proposal sponsored jointly by
the Company and the Attorney General of Massachusetts which resolved issues
related to cost of service, rates, accounting matters and generating unit
performance reviews. The Company's settlement:
(1) implements a $2.7 million annual retail base rate decrease effective
May 1, 1995 including its share of excess deferred tax reserves
related to Seabrook Unit No. 1 which Canal refunded to the Company in
May. Further, the settlement imposes a moratorium on retail rate
filings until October 1998;
(2) limits the Company's return on equity, as defined in the settlement,
for the period through December 31, 1997;
(3) terminates several 1987-1994 generating unit performance review
proceedings pending before the DPU;
(4) amends the Company's fuel charge stabilization mechanism established
on April 1, 1994 to include the deferral (without carrying charges)
of certain long-term purchased power and transmission capacity costs
within the original limits established for the fuel charge stabiliza-
tion deferral ($16 million in any given calendar year and $40 million
over the life of the mechanism);
(5) requires the Company to fully expense costs relating to postretire-
ment benefits other than pensions in accordance with Statement of
Financial Accounting Standards No. 106 and amortize the current
deferred balance of $8.6 million over a ten-year period;
(6) provides eligible Economic Development Rate customers with a discount
of up to 30% but also requires these customers to provide the Company
with a five-year notice if they intend to self-generate or acquire
electricity from another provider; and
(7) prohibits the Company from seeking recovery of the costs incurred in
realizing costs savings through a 1993 work force reduction and
restructuring, totaling approximately $3 million.
The Company's management is encouraged by the support provided through
the Office of the Attorney General and believes that this settlement will
eliminate the need for potentially costly litigation and regulatory proceed-
ings and, by moderating rate impacts and enabling the Company to remain
competitive in a changing environment, is in the best interest of the Company
and its customers.
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COMMONWEALTH ELECTRIC COMPANY
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The Company is subject to legal claims and matters arising from
its course of business, including its participation in a power
contract arbitration proceeding involving the recovery of excess fuel
charges billed to the Company for power purchases with Dartmouth
Power Associates Limited Partnership. Also, the Company's decision
to cancel a power contract with Eastern Energy Corporation was upheld
by a binding arbitration panel decision in June 1995 (refer to "Power
Contract Arbitration" in Part I, Item 2 - "Management's Discussion
and Analysis of Results of Operations" section of this report.)
Item 5. Other Information
None.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 10 - Material Contracts
10.1.35.1 System Power Sales Agreement by and between The Connecticut Light
and Power Co., Western Massachusetts Electric Co., and Public
Service Company of New Hampshire, as sellers, and the Company, as
buyer, of power for peaking capacity and related energy, dated
January 13, 1995, as effective June 1, 1995 and extending to
October 31, 2000 (Filed herewith as Exhibit 2).
10.1.46.2 First Amendment, dated November 7, 1994, to Power Sale Agreement
by and between the Company and Altresco Pittsfield, L.P. dated
February 20, 1992 (Filed herewith as Exhibit 3).
10.1.44.1 Second Amendment, dated June 23, 1994, to Power Purchase Agreement
by and between the Company and Dartmouth Power Associates, L.P.
dated September 5, 1989 (Filed herewith as Exhibit 4).
Exhibit 27 - Financial Data Schedule
Filed herewith as Exhibit 1 is the Financial Data Schedule for the
six months ended June 30, 1995.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the three months ended
June 30, 1995.
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<PAGE 13>
COMMONWEALTH ELECTRIC COMPANY
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.
COMMONWEALTH ELECTRIC COMPANY
(Registrant)
Principal Financial Officer:
JAMES D. RAPPOLI
James D. Rappoli,
Financial Vice President
and Treasurer
Principal Accounting Officer:
JOHN A. WHALEN
John A. Whalen,
Comptroller
Date: August 14, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
balance sheet, statement of income and statement of cash flows contained in
Form 10-Q of Commonwealth Electric Company for the six months ended June 30,
1995 and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<CIK> 0000071222
<NAME> COMMONWEALTH ELECTRIC COMPANY
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> JUN-30-1995
<PERIOD-TYPE> 6-MOS
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 363,033
<OTHER-PROPERTY-AND-INVEST> 630
<TOTAL-CURRENT-ASSETS> 53,311
<TOTAL-DEFERRED-CHARGES> 90,006
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 506,980
<COMMON> 51,099
<CAPITAL-SURPLUS-PAID-IN> 97,112
<RETAINED-EARNINGS> 14,773
<TOTAL-COMMON-STOCKHOLDERS-EQ> 162,984
0
0
<LONG-TERM-DEBT-NET> 156,770
<SHORT-TERM-NOTES> 37,910
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1,053
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<CAPITAL-LEASE-OBLIGATIONS> 0
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<OTHER-ITEMS-CAPITAL-AND-LIAB> 148,263
<TOT-CAPITALIZATION-AND-LIAB> 506,980
<GROSS-OPERATING-REVENUE> 210,434
<INCOME-TAX-EXPENSE> 4,365
<OTHER-OPERATING-EXPENSES> 193,538
<TOTAL-OPERATING-EXPENSES> 197,903
<OPERATING-INCOME-LOSS> 12,531
<OTHER-INCOME-NET> 2,782
<INCOME-BEFORE-INTEREST-EXPEN> 15,313
<TOTAL-INTEREST-EXPENSE> 8,123
<NET-INCOME> 7,190
0
<EARNINGS-AVAILABLE-FOR-COMM> 7,190
<COMMON-STOCK-DIVIDENDS> 7,767
<TOTAL-INTEREST-ON-BONDS> 7,041
<CASH-FLOW-OPERATIONS> (10,472)
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
<PAGE 1>
SYSTEM POWER SALES AGREEMENT
DATED: January 13, 1995
BETWEEN: NORTHEAST UTILITIES SERVICE COMPANY
AS AGENT FOR:
THE CONNECTICUT LIGHT AND POWER COMPANY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
AND
COMMONWEALTH ELECTRIC COMPANY
<PAGE>
<PAGE 2>
SYSTEM POWER SALES AGREEMENT
This SYSTEM POWER SALES AGREEMENT ("Agreement") dated as of January 13,
1995, by and between Northeast Utilities Service Company ("NUSCO") as agent
for The Connecticut Light and Power Company ("CL&P"), Western Massachusetts
Electric Company ("WMECO"), and Public Service Company of New Hampshire
("PSNH"), and Commonwealth Electric Company (hereinafter "Buyer" or "Common-
wealth"). NUSCO and the Buyer are referred to herein individually as "Party"
or collectively as "Parties."
WHEREAS, CL&P, WMECO, and PSNH are operating companies of the Northeast
Utilities ("NU") System Companies (hereinafter collectively referred to as
"Seller"); and
WHEREAS, Commonwealth is a regulated public utility desiring to purchase
economical and reliable sources of wholesale power supply; and
WHEREAS, Buyer solicited bids for peaking capacity and related energy in
a request for proposals dated February 7, 1994 and Seller responded to such
solicitation with a bid; and
WHEREAS, pursuant to a letter of intent between the Parties dated June
15, 1994, Seller has expressed its willingness to sell and the Buyer has
expressed its willingness to purchase peaking capacity and related energy
pursuant to terms of this Agreement; and
WHEREAS, the NU System Companies and Commonwealth are participants in
the New England Power Pool ("NEPOOL") and as such are subject to the terms and
conditions of the NEPOOL Agreement dated as of September 1, 1971, as amended
from time to time (the "NEPOOL Agreement"); and
WHEREAS, the Parties hereto desire to provide for the terms and condi-
tions pursuant to which Seller will sell to Commonwealth and Commonwealth will
purchase 75 megawatt-years of peaking capacity and related energy from the NU
System Companies during the term of this Agreement;
NOW, THEREFORE, in consideration of the premises and of the mutual
agreements herein contained, the Parties to this Agreement covenant and agree
as follows:
1. Term
Subject to Federal Energy Regulatory Commission ("FERC" or "Commission")
authorization and final approval of the Agreement by the Massachusetts
Department of Public Utilities ("MDPU") pursuant to M.G.L.C. 164, SS94A (in
form and substance acceptable to both parties) within 90 days of Common-
wealth's filing with the MDPU for approval, the term of this Agreement and
service to be rendered hereunder shall become effective at 0001 hours on June
1, 1995, and shall end at 2400 hours on October 31, 2000, unless extended by
mutual agreement of the Parties (such period hereinafter called the "Term").
The applicable provisions of this Agreement shall continue in effect after
termination hereof to the extent necessary to provide for final billing,
billing adjustments, and payments.
2. Purchase
Seller shall sell to Buyer and Buyer shall purchase from Seller a total
<PAGE>
<PAGE 3>
of 75 megawatt-years of electrical system capacity during the Term of this
Agreement. The total megawatt-years of electrical system capacity purchased
will be the sum of the annual capacity entitlements elected by the Buyer. Such
electrical system capacity shall be in the form of peaking system or unit
entitlements. The amount of peaking capacity to be purchased and sold may vary
at Commonwealth's discretion by month, subject to a monthly maximum purchase
of 125 MW-month and the scheduling provisions set forth in Schedule II, so
long as the total amount of peaking system capacity purchased over the Term is
75 megawatt-years.
3. NEPOOL Dispatch
For purposes of Buyer's NEPOOL own-load dispatch, electrical energy made
available hereunder will be dispatchable by Buyer each hour up to the applica-
ble purchase amount and such dispatched energy shall be part of Seller's
NEPOOL own-load energy requirements for the applicable hour (de-Coupled
Dispatch). The energy prices given to NEPOOL by Seller for purposes of
economic dispatch of energy made available hereunder in Buyer's own load
dispatch shall be the same as the Energy Charge Rate as determined in accor-
dance with Section 6 of this Agreement. Electrical energy will be made
available to Buyer in its NEPOOL own-load dispatch subject to the availability
criteria specified in Section 4 of this Agreement. Seller will notify NEPOOL
of Buyer's purchase prior to the commencement of the Term.
4. Availability
The peaking system energy associated with the peaking system capacity
will be made available to the Buyer in its NEPOOL own-load dispatch in accor-
dance with Section 3 of this Agreement, whenever any two of the four South
Meadow internal combustion units are available. The four South Meadow internal
combustion units each have a combined winter normal claimed capability of 46
megawatts and a summer normal claimed capability of 36 megawatts. In the event
that the peaking system energy is unavailable, the Buyer will be entitled to
the appropriate NEPOOL outage service made available as a result of the
outages at the South Meadow units.
If the NEPOOL capability credit received by the Buyer for the peaking
system is reduced to zero as the result of the applicable unit outages, the
Seller will substitute capacity of similar operating characteristics for the
purposes of this Section 4.
5. Transmission
The peaking system power purchased hereunder will be delivered to the
boundary of the NU System Companies at the Card Street/Sherman Road Intercon-
nection at the Connecticut-Rhode Island border ("Point of Delivery"). Trans-
mission service for the peaking system power will be provided pursuant to the
terms and conditions of the NU System Companies' Transmission Service Tariff
No. 1, on file with FERC. The capacity charges pursuant to Section 6 of this
Agreement include the full cost of said transmission service on the NU System
Companies. Buyer shall be responsible for all transmission electrical losses
incurred on the NU system in transmitting power to Buyer. Such losses shall be
determined in accordance with the provisions of Tariff No. 1. The Point of
Delivery may be changed by mutual agreement of the Parties.
<PAGE>
<PAGE 4>
6. Payment
A. Capacity Charges
The Capacity Charge for any calendar month shall be the product of
(i) the amount of system capacity purchased pursuant to this Agreement
(expressed in kW) for which Buyer receives NEPOOL Capability credit
during the month, and (ii) one-twelfth of the applicable fixed Capacity
Charge Rate for the applicable annual period as listed in Schedule I for
the selected Scheduling Procedure pursuant to Schedule II.
B. Energy Charge
The Energy Charge for any calendar month shall equal the product
of (i) the number of system kilowatt-hours of electrical energy deliv-
ered by Seller to Buyer for the account of the Buyer in each hour during
that month; and (ii) a heat rate of 12,000 Btu/kilowatt-hour, and (iii)
the replacement fuel price of jet kerosene as reported to NEPOOL,
pursuant to applicable NEPOOL Criteria, Rules and Standards, for South
Meadow Station (in $/Btu).
Notwithstanding the foregoing, if South Meadow Station no longer
burns jet kerosene, then the Energy Charge will be the product of the
applicable heat rate as stated above and the monthly average of the
replacement fuel price as reported to NEPOOL for the all jet turbines
for the NU System Companies.
7. Contingency Regarding Taxes and Fees
If any governmental authority hereafter imposes a tax (including, but
not limited to sales tax, gross revenue tax, energy tax, but excluding taxes
assessed on income or property), fee for assessment on the capacity and/or
energy sold or delivered under this Agreement, which is not in effect on the
date this Agreement becomes effective, and such tax, fee or assessment is
payable by Seller, Buyer shall reimburse Seller for the amount of such tax,
fee or assessments actually paid by Seller with respect to the purchase, sale
or delivery of capacity and/or energy hereunder; provided, however, that to
the extent any such tax, fee or assessment is reflected in the replacement
fuel cost as defined by Section 6.B of this Agreement, Buyer shall not be
responsible for reimbursing to Seller the portion of such tax that is reflect-
ed in such replacement fuel cost. Within twenty (20) days of the rendering of
a bill or invoice for such tax, fee, or assessment, Buyer shall pay to Seller
any uncontested amount not previously billed to and paid for by Buyer. Any
contested amounts shall be subject to the provisions of Section 14 of this
Agreement.
Seller shall make a timely rate schedule change filing with the Commis-
sion under Section 205 of the Federal Power Act in order to recover the costs
associated with payment of any such new tax, fee or assessment.
The annual charge FERC assesses against the Seller pursuant to Order No.
472 ("FERC Assessment") is based on the amount of electric energy generated
and/or transmitted on the Seller's system during the year (expressed in
megawatt-hours), as reported by the Seller in accordance with Reporting
Requirement 582, as outlined in Order No. 472. Seller will charge monthly to
the Buyer a portion of the FERC Assessment which shall be an estimated dollar
amount equal to the product of (1) the amount of electric energy generated
<PAGE>
<PAGE 5>
and/or transmitted on the Seller's system for the Buyer under this Agreement
during that period of the Term which falls within such month (expressed in
megawatt-hours), and (2) the applicable FERC rate for the most recently
assessed year (expressed in dollars per megawatt-hour) as such rate appears on
the appropriate FERC "Statement of Annual Charges." Within six months of
receipt by Seller of the applicable FERC rate for a period of the term which
has been billed on an estimated basis, Seller will adjust the previously
estimated charges for that period covered by the actual applicable FERC
Assessment. Buyer shall provide to Seller any necessary information for the
calculation of such charge.
8. Billing
Buyer shall be obligated to pay to Seller all charges billed in accor-
dance with the terms of to this Agreement. Seller shall submit a bill for all
applicable charges to Buyer as soon as practicable after the end of each
calendar month during the Term. The bill shall include information in such
reasonable detail to enable the Buyer to determine the basis for the charges
for such month.
Each bill shall be subject to adjustment as set forth in Section 9
hereof and for any errors in arithmetic, computation, meter readings, estimat-
ing, or otherwise. All bills shall be due and payable not later than the Due
Date, defined as (20) days after the date of invoice (the period of 20 days
after date of invoice is intended to allow 5 days for invoice delivery and 15
days after receipt of invoice for payment). Any amount remaining unpaid after
such twenty (20) days shall bear interest at the annual rate of two (2)
percentage points over the Prime Rate (sometimes called Base Rate) for
commercial loans to large corporate customers then in effect at the main
office of the Bank of Boston, or such other lending institution as may be
Seller's primary commercial lender from time to time during the period, from
the Due Date to the date of payment by Buyer.
If the Buyer, in good faith, disputes the amount of any bill, it shall
pay to Seller the entire amount due and shall itemize the basis for its
dispute in a written notice to Seller given on or before the Due Date. Upon
final resolution of the dispute, if refunds are due to Buyer, Seller shall
make such refunds together with interest calculated at the rate set forth
above on all such disputed amounts that were paid to Seller and itemized in a
written notice to Seller.
9. Estimates and Adjustments
Pending the availability of actual data, computations by Seller of the
charges for the purposes of billings hereunder for which actual data is not so
available shall be based upon estimates made by Seller.
Seller may make adjustments to any billing for a period of up to twelve
(12) months from the date of such original billing in order to reflect
differences in charges resulting from Seller's receipt of more current data.
Buyer may dispute such adjustment in accordance with Section 8 of this
Agreement. Seller shall make additional adjustments to billings after the
twelve (12) month period to the extent such adjustments are required based
upon final resolution of any claim, action, or proceeding that is based upon
data contained in an original billing and that is formally initiated by, or
noticed to Seller prior to the end of the twelve (12) month period following
the date of such original billing. Seller shall promptly provide notice to
<PAGE>
<PAGE 6>
Buyer of any such claim, action, or proceeding it becomes aware of, and
include in such notice Seller's estimate of the potential impact of any such
claim, action, or proceeding upon billed amounts.
10. Liability for Delivery
Subject to Force Majeure, as defined in Section 11 of this Agreement,
Buyer agrees that Seller's obligations for delivery under this Agreement shall
be limited to delivery only over the NU System Companies' transmission system
to the Point of Delivery.
11. Force Majeure
As used in this Agreement, "Force Majeure" means any cause beyond the
reasonable control of, and without the fault or negligence of, the Party
claiming Force Majeure. It shall include, without limitation, sabotage,
strikes, riots or civil disturbance, acts of God, act of public enemy,
drought, earthquake, flood, explosion, fire, lightning, landslide, or similar-
ly cataclysmic occurrence, or appropriation or diversion of electricity by
sale or order of any governmental authority having jurisdiction thereof.
Economic hardship of either Party shall not constitute a Force Majeure under
this Agreement.
If either Party is rendered wholly or partly unable to perform its
obligations under this Agreement because of Force Majeure as defined above,
that Party shall be excused from whatever performance is affected by the Force
Majeure, to the extent so affected, provided that:
(a) The non-performing Party promptly, but in no case longer than five
working days after the occurrence of the Force Majeure, gives the
other Party written notice describing the particulars of the
occurrence.
(b) The suspension of performance shall be of no greater scope and of
no longer duration than is reasonably required by the Force
Majeure.
(c) The non-performing Party uses reasonable efforts to remedy its
inability to perform.
(d) The Seller's obligation to provide energy and the Buyer's obliga-
tion to make payment shall be modified in proportion to the effect
of Force Majeure conditions.
12. Assignment
This Agreement shall be binding upon and shall inure to the benefit of,
and may be performed by, the successors and assignees of the Parties, except
that no assignment, pledge or other transfer of this Agreement by either Party
shall operate to release the assignor, pledgor, or transferor from any of its
obligations under this Agreement unless: (i) the other Party (or its succes-
sors or assigns) consents in writing to the assignment, pledge or other
transfer and expressly releases the assignor, pledgor, or transferor from its
obligations hereunder, or (ii) the assignment, pledge or other transfer is to
another company in the same holding company system as the assignor, pledgor or
transferor and the assignee, pledgee or transferee is capable of fulfilling,
and expressly assumes the obligations of the assignor, pledgor or transferor,
<PAGE>
<PAGE 7>
or (iii) such transfer is incident to a merger or consolidation with, or
transfer of all (or substantially all) of the assets of the transferor to
another person or business entity which shall, as a part of such succession,
assume all the obligations of the assignor, pledgor or transferor under this
Agreement. No assignment, pledge, or transfer of this Agreement shall be made
without the prior written consent of the other Party, which shall not be
unreasonably withheld, except no prior written consent will be required as
necessary for the assignment, pledge, or transfer to any of the member
companies of such Parties' holding company system in accordance with (ii) of
this Section 12. Nothing contained in this Section 12 shall restrict the
Buyer's right to resale.
13. Interpretation
The interpretation and performance of this Agreement shall be in accor-
dance with and shall be controlled by the Federal Power Act and regulations
and orders of the FERC thereunder and, to the extent not controlled thereby,
the laws of the state of Connecticut.
14. Resolution of Disputes
A. Any dispute between the Seller and Buyer involving service under
this Agreement shall be referred to a senior representative of
NUSCO and a senior representative of the Buyer designated by the
Buyer for resolution on an informal basis as promptly as practica-
ble. In the event the designated senior representatives are unable
to resolve the dispute within thirty (30) days, or such other
period as the parties may jointly agree upon, if NUSCO and the
Buyer jointly agree, such dispute may be submitted to arbitration
and resolved in accordance with the arbitration procedure set
forth herein. If they do not agree, such dispute shall be present-
ed promptly to FERC, but in no event more than sixty (60) days
after rejecting arbitration.
B. The arbitration shall be conducted before a single neutral arbi-
trator appointed by the Parties. If the Parties fail to agree upon
a single arbitrator within ten (10) days of the referral of the
dispute to arbitration, NUSCO and the Buyer shall each choose one
arbitrator, who shall sit on a three-member arbitration panel. The
two arbitrators so chosen shall within twenty (20) days select a
third arbitrator to act as chairman of the arbitration panel. In
either case, the arbitrators shall be knowledgeable in electric
utility matters, including electricity transmission and bulk power
issues, and shall not have any current or past substantial busi-
ness or financial relationships with any Party to the arbitration.
The arbitrator(s) shall afford each of the Parties an opportunity
to be heard and, except as otherwise provided herein, shall
generally conduct the arbitration in accordance with the Commer-
cial Arbitration Rules of the American Arbitration Association.
There shall be no formal discovery conducted in connection with
the arbitration, however, the Parties shall exchange witness lists
and copies of any exhibits that they intend to utilize in their
direct presentations at any hearing before the arbitrator(s) at
least ten (10) days prior to such hearing, along with any other
information or documents specifically requested by the arbitra-
tor(s) prior to the hearing. Unless otherwise agreed, the arbitra-
tor(s) shall render a decision within ninety (90) days of his,
<PAGE>
<PAGE 8>
her, or their appointment and shall notify the Parties in writing
of such decision and the reasons therefore, and shall make an
award apportioning the payment of the costs and expenses of
arbitration among the Parties, provided, however, that each Party
shall bear the costs and expenses of its own arbitrator, attor-
neys, expert witnesses and consultants. The arbitrator(s) shall be
authorized only to interpret and apply the provisions of this
Agreement and shall have no power to modify or change any of the
terms of this Agreement in any manner. The decision of the arbi-
trator(s) shall be final and binding upon the Parties, and judg-
ment on the award may be entered in any court having jurisdiction.
The decision of the arbitrator(s) may be appealed solely on the
grounds that the conduct of the arbitrator(s), or the decision
itself, violated the standards set forth in the Federal Arbitra-
tion Act and/or the Administrative Dispute Resolution Act.
15. Accounts and Records
Seller shall keep complete and accurate records and meter readings of
its operations hereunder and shall maintain such data for a period of no more
than three (3) years following the end of a calendar year of service hereun-
der. Buyer shall have the right, during normal business hours, to examine and
inspect all such records and meter readings insofar as may be necessary for
the purpose of ascertaining the reasonableness and accuracy of all relevant
data, estimates or statement of charges submitted to it hereunder. The costs
of the audit shall be borne by the Buyer.
16. Authority of Northeast Utilities Service Company
The NU System Companies hereby appoint and authorize NUSCO to represent
and act for them in all matters relating to this Agreement.
17. Liability and Indemnification
Except for willful misconduct, willful breach of contract, or negli-
gence, neither Party (including such Parties' affiliated companies, trustees,
directors, officers, employees, and agents) shall be liable to the other Party
in tort, contract, or otherwise for any damages, costs, fines, penalties, or
claims whatsoever which may result from such Parties' failure to perform its
obligations hereunder. The Parties agree to indemnify, defend, and hold the
other Party, affiliated companies, trustees, directors, officers, employees,
and agents harmless from and against any and all costs, claims, liabilities,
actions, or proceedings whatsoever arising from or claimed to have arisen from
such Parties' failure to perform its obligations hereunder.
Except for claims arising from willful misconduct, willful breach of
contract, or gross negligence as provided for in the above paragraph, each
Party (the indemnifying Party) agrees to indemnify, defend, and hold the other
Party (including the other Party's affiliated companies, trustees, directors,
officers, employees, and agents) harmless from and against any and all
damages, costs (including attorney's fees), claims, liabilities, fines,
penalties, actions or proceedings in tort, contract or otherwise, resulting
from claims of third Parties arising or claimed to have arisen, from the acts
or omissions of such indemnifying Party.
The Parties hereby waive and release the other Party as well as the
other Party's affiliated companies, trustees, directors, officers, employees,
<PAGE>
<PAGE 9>
and agents from any liability, claim, or action arising from damage to
property of the Parties due to the performance of the Parties hereunder,
except where such damage is the result of gross negligence or willful miscon-
duct.
18. Notices
Any notice, demand, or request permitted or required under this Agree-
ment shall be delivered in person or mailed by certified mail, postage
prepaid, return receipt requested, or otherwise to confirm receipt, to a Party
at the applicable address set forth below:
To Buyer:
Manager, Power Supply Administrator
Commonwealth Electric Company
2421 Cranberry Highway
Wareham, MA 02571
To Seller:
Frank P. Sabatino
Vice President - Wholesale Marketing
Northeast Utilities Service Company
Post Office Box 270
Hartford, CT 06141-0270
Such addresses may be changed from time to time by written notice by either
Party to the other Party.
19. Miscellaneous
(a) Each Party shall prepare, execute and deliver to the other Party
at no additional expense any documents reasonably required to
implement any provision hereof.
(b) Any number of counterparts of this Agreement may be executed and
each shall have the same force and effect as the original.
(c) This Agreement, together with the attached Schedules I and II,
shall constitute the entire understanding between the Parties and
shall supersede any and all previous understandings pertaining to
the subject matter of this Agreement.
(d) This Agreement may be modified only by an instrument in writing
signed by the Parties whereto. The rates for service specified
herein shall remain in effect for the Term and shall not be
subject to change through application to the Federal Energy
Regulatory Commission pursuant to Section 205 of the Federal Power
Act absent the agreement of all Parties hereto.
(e) Failure of either Party to enforce any provision of this Agreement
or to require performance by the other Party of any of the provi-
sions hereof, shall not be construed as a waiver of such provi-
sions or affect the validity of this Agreement, any part hereof,
or the right of either Party to thereafter enforce each and every
provision.
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<PAGE 10>
(f) The acceptance by the FERC of this Agreement as a rate schedule
filing under Section 205 of the Federal Power Act will supersede
the letter dated June 15, 1994, confirming the mutual agreement of
Seller and Commonwealth concerning the sale of system capacity and
energy.
IN WITNESS WHEREOF, Seller and Commonwealth have caused this Agreement
to be signed by their respective duly authorized representatives as of the
date first above written.
Seller: Northeast Utilities Service Company
By FRANK P. SABATINO
Its Vice President
as agent for:
The Connecticut Light and Power Company
Western Massachusetts Electric Company
Public Service Company of New Hampshire
Buyer: Commonwealth Electric Company
By JAMES J. KEANE
Its Vice President
<PAGE>
<PAGE 11>
SCHEDULE I
CAPACITY CHARGE RATE
CAPACITY CHARGE RATE
SCHEDULING SCHEDULING
YEAR PROCEDURE #1 PROCEDURE #2
$/KW - YEAR $/KW - YEAR
1995 25 27
1996 30 32
1997 35 37
1998 40 42
1999 45 47
2000 50 52
SCHEDULE II
SCHEDULING PROCEDURES
1. Commonwealth shall provide at least 6 months advance written
notice to NUSCO of the amount of system capacity to be purchased
in each month of a 6 month period.
2. Commonwealth shall provide at least 6 months advance written
notice to NUSCO of the amount of system capacity to be purchased
in a given month.
<PAGE 1>
AMENDMENT TO POWER SALE AGREEMENT
BY AND BETWEEN COMMONWEALTH ELECTRIC COMPANY
AND ALTRESCO PITTSFIELD, L.P.
AMENDMENT dated as of this 7th day of November 1994, by and between Common-
wealth Electric Company, a Massachusetts corporation with a usual place of
business at 2421 Cranberry Highway, Wareham, Massachusetts ("Company") and
Altresco Pittsfield, L.P., a Delaware limited partnership with a principal
place of business at One Bowdoin Square, Boston, Massachusetts ("Seller"), to
the Power Sale Agreement dated February 20, 1992 ("Agreement").
WHEREAS the Company, pursuant to the Agreement and subject specifically to the
provisions contained in Article 2.1 of the Agreement, purchases 17.2 percent
of the electricity produced by the Seller's electric cogeneration facility,
which is capable of generating approximately one-hundred sixty (160) megawatts
("MW") of electricity and which is located at a site owned by General Electric
in Pittsfield, Massachusetts (the "Facility" or "Unit"); and
WHEREAS, the Total Purchase Price for electricity purchased by the Company
pursuant to Section 1 of Appendix B of the Agreement includes a component
known as the Monthly Energy Charge, which component is defined in Section 3 of
Appendix B of the Agreement; and
WHEREAS, the Monthly Energy Charge is calculated, in part, by reference to the
Tennessee Gas Pipeline Company's ("Tennessee") Current Average Cost of
Purchased Gas, also known as the Weighted Average Cost of Gas ("WACOG"), or
its successor index, as specified in Tennessee's approved Federal Energy
Regulatory Commission ("FERC") Gas Tariff; and
WHEREAS, Tennessee's WACOG ceased to be available as of July, 1992 as a
consequence of the restructuring of Tennessee's services pursuant to FERC
Order No. 636, and no successor index to Tennessee's WACOG exists; and
WHEREAS, the Company and the Seller have agreed upon the terms of an index to
replace Tennessee's WACOG for purposes of calculating the Monthly Energy
Charge, and desire to execute this Amendment for purposes of memorializing
their agreement.
NOW, THEREFORE, in consideration of the mutual covenants set forth herein, the
Company and the Seller agree as follows:
1. Unless otherwise defined herein, capitalized terms shall have the same
meaning given to them in the Agreement.
2. For the purposes of determining the Monthly Energy Charge as defined in
Section 3 of Appendix B of the Agreement, the first sentence of said
section shall be deleted in its entirety and the following shall be
substituted in place thereof:
The Monthly Energy Charge shall be equal to the product of (i) the Delivered
Energy and (ii) the Kilowatthour Charge,
where the Kilowatthour Charge is equal to the product of (i) one and
thirty-six hundredths cents per kilowatthour ($0.0136/kWh) and (ii) an
index factor represented by the quantity M/N,
<PAGE>
<PAGE 2>
where M shall be equal to the monthly weighted average sum of the
following three fuel components, each expressed in U.S. dollars per
MMBtu:
(a) 50% weighting for the monthly average of the daily quotes
during the Billing Period for No. 6 residual 2.2% sulfur fuel
oil as listed in Platt's Oilgram under the heading "Estimated
New York Harbor Spot Price," using the low cargo quotation, and
assuming 6.3 MMBtu per barrel; and
(b) 40% weighting for the average of the T2 spot price for each of
the twelve (12) months immediately preceding the Billing Peri-
od, where the T2 spot price for any month shall be equal to the
arithmetic average of the following six indices for such month:
the Louisiana & Offshore (zone 1 ) and Texas (zone 0) indices
for Tennessee and the East Louisiana, West Louisiana, East
Texas and South Texas indices for the Texas Eastern Transmis-
sion Corporation, or their successor indices, each as published
in the first of the month edition of Inside F.E.R.C.'s Gas
Market Report, by reference to the table entitled "Prices of
Spot Gas Delivered to Pipelines...," provided that at least
four of the six indices, or their successor indices, are so
published for any month, and if at least four of the six indi-
ces are not so published for any month, the parties shall
determine mutually acceptable substitute indices to use for the
calculation of the T2 spot price; and
(c) 10% weighting for New England Power Company's weighted average
delivered cost of coal as reported in the most recently submit-
ted FERC Form 423 for New England Power Company from time to
time, and
where N is $1.81/MMBtu.
3. The Company shall submit this Amendment to the Massachusetts Department
of Public Utilities for approval. This Amendment shall become effective
upon the receipt of such approvals in form and substance acceptable to
the Company and the Seller.
4. All other terms and conditions of said Agreement shall remain in full
force and effect.
IN WITNESS WHEREOF, the Company and the Seller have caused this Amendment to
be duly executed as of the day and year first above written.
COMMONWEALTH ELECTRIC COMPANY ALTRESCO PITTSFIELD, L.P.
BY JMC ALTRESCO, INC.
ITS GENERAL PARTNER
By: JAMES J. KEANE By: JAMES A. KELLER
James J. Keane
Title: Vice President Title: Vice President
Power Supply & Transmission
<PAGE 1>
SECOND AMENDMENT TO POWER PURCHASE AGREEMENT
AMENDMENT dated as of this 23rd day of June, 1994, by and between Commonwealth
Electric Company, a Massachusetts corporation with a principal place of
business at One Main Street, Cambridge, Massachusetts ("the Company") and
Dartmouth Power Associates Limited Partnership, a Massachusetts Limited
Partnership with a place of business at One Energy Road, Dartmouth, Massachu-
setts ("Seller"), to the Power Purchase Agreement by and between the Company
and Seller, dated as of September 5, 1989 and amended by an Amendment to Power
Purchase Agreement by and between the Company and Seller, dated as of August
3, 1990 (as amended, "the Agreement").
WHEREAS the Company, pursuant to the Agreement, purchases all electricity
produced by the Seller's 67,600 KW generating facility located at One Energy
Road, in Dartmouth, Massachusetts ("the Unit"); and
WHEREAS the Total Purchase Price for electricity purchased by the Company
pursuant to the Agreement includes a component known as the Monthly Energy
Charge, which is defined (in section 4 of Appendix B of the Agreement) as
including a component known as the Variable Fuel Supply Rate; and
WHEREAS, the Variable Fuel Supply Rate is calculated, in part, by reference to
the following indices for natural gas pipeline service: The "Tennessee CD-6"
index (for service pursuant to the CD-6 rate under a FERC approved tariff by
Tennessee Gas Pipeline Company, "Tennessee") and (2) the "Algonquin F-l" Index
(for service pursuant to the F-1 rate under a FERC approved tariff by Algon-
quin Gas Transmission Company, "Algonquin"); and
WHEREAS, both the Algonquin F-1 rate and the Tennessee CD-6 rate have ceased
to be available as a consequence of the restructuring of services of each of
those respective pipelines pursuant to Federal Energy Regulatory Commission
("FERC") Order No. 636; and
WHEREAS, the Variable Fuel Supply Rate is calculated, in, part, by reference
to an index calculated by the Alberta Petroleum Marketing Commission for the
Minister of Energy for the Province of Alberta, Canada known as the Alberta
Market Price (AMP); and
WHEREAS, the AMP, effective December 31, 1993 is no longer published; and
WHEREAS, the Company and Seller have agreed upon the terms of an index to
replace the F-1, CD-6 and AMP indices for purposes of calculating the Variable
Fuel Supply Rate, and desire to execute this Amendment for purposes of
memorializing their agreement.
NOW, THEREFORE, in consideration of the mutual covenants set forth herein, the
Company and Seller agree as follows:
1. That for the purposes of determining the Variable Fuel Supply Rate as
referenced in section 4.1 of Appendix B of the Agreement, the last para-
graph (including the table) of said section shall be deleted in its
entirety and the following shall be substituted in place thereof:
The Initial Variable Fuel Supply Rate shall be adjusted monthly to
reflect the proportional change in the T2 index (as hereinafter defined)
and the Alberta Reference Price, using the year 1988 as a base, and shall
be calculated pursuant to the provisions of subsection 4.14.
<PAGE>
<PAGE 2>
4.14 For each Billing Period during the term of this Agreement, the
Variable Fuel Supply Rate shall equal the product of (i) the Initial
Variable Fuel Supply Rate and (ii) an Index Factor, the numerator of
which shall be "N1" (as hereinafter defined) and the denominator of which
shall be "D1" (as hereinafter defined);
Where:
"N1" shall equal the sum of (i) "T2" (as hereinafter defined) and (ii)
the available Alberta Reference Price for the billing month.
"D1" shall equal two (2) multiplied by "AFC-l".
"T2" shall be calculated as the arithmetic average of the following four
indices for the Billing Period:
(a) the Offshore and Louisiana (Zone 1) index for Tennessee Gas
Pipeline Company;
(b) the Louisiana and Texas (Zone 0) index for Tennessee Gas
Pipeline Company;
(c) the arithmetic average of the East Texas and South Texas
indices for Texas Eastern Transmission Corporation;
(d) the arithmetic average of the East Louisiana and West
Louisiana indices for the Texas Eastern Transmission Corpo-
ration.
all as reported in the table entitled "Prices of Spot Gas Delivered to
Pipelines" in the first of the month edition of Inside F.E.R.C.'s Gas
Market Report, provided that if any of the above described indices, or
their successors, are not reported in any month, T2 shall be equal to the
arithmetic average of the indices that are reported, provided that at
least three of the above indices are so reported. If at least three of
the above indices are not reported in any month, then the Henry Hub Cash
Price, as reported in the first of the month edition of Inside F.E.R.C.'s
Gas Market Report will serve as a Proxy for T2. However, the Henry Hub
Cash Price shall not be used as a Proxy for T2 for two consecutive months
unless agreed to by both parties.
"AFC-1" shall equal $1.486 per MMBTU. This value is the sum of (i) the
average "T2" value for calendar year 1988 and (ii) the average Alberta
Market Price for calendar year 1988, divided by two (2).
The "Alberta Reference Price" is the gas reference price prescribed by
the Minister of Energy for the Province of Alberta, Canada for the
calendar month of the Billing Period (for example, the gas reference
price published by the Minister for June, 1994 would be the Alberta
Reference Price used to calculate the Variable Fuel Supply Rate for June,
1994 but actually reflect data for the month of April, 1994). The data is
published by the Alberta Petroleum Marketing Commission.
2. The following shall be inserted as section 4.3 of Appendix B of the
Agreement:
4.3 Redetermination of the Variable Fuel Supply Rate:
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Either the Seller or the Company shall have the right to require a
redetermination of the provisions of subsection 4.14 of this
Appendix relating to the composition of the Index Factor, effec-
tive upon November 1 of each of the following years: 1997, 2002,
2007 and 2012 (the "Redetermination Dates"). A party electing to
require such a redetermination shall provide written notice (the
"Redetermination Notice") to the other party no less than six (6)
months and no more than one (1) year before the Redetermination
Date on which such redetermination is to take effect.
If a Redetermination Notice is not served by either party upon the
other party during the specified time period, the Variable Fuel
Supply Rate in effect immediately prior to the relevant Redeterm-
ination Date shall continue to be calculated in the manner in
effect prior to such Redetermination Date. If a Redetermination
Notice is served within the time required, then the provisions of
subsections 4.3.1 through 4.3.4 below shall apply.
4.3.1 Following receipt of a Redetermination Notice, the
parties will negotiate in good faith to determine mutually satis-
factory modifications to the Variable Fuel Supply Rate.
4.3.2 If the parties are unable to agree upon renegotiated
Variable Fuel Supply Rate provisions on or before the date which
is three (3) months prior to the Redetermination Date, either
party may elect by written notice (the "Arbitration Notice") to
the other party, to refer the redetermination of the Variable Fuel
Supply Rate provisions to binding arbitration pursuant to Article
12 of the Agreement. If an Arbitration Notice is not issued by
either party before the date which is three (3) months prior to
the Redetermination Date, and the parties have not agreed upon
renegotiated Variable Fuel Supply Rate provisions on or before the
Redetermination Date, the Variable Fuel Supply Rate provisions
shall continue to be calculated in the manner in effect immediate-
ly prior to such Redetermination Date.
4.3.3 During the renegotiation of the Variable Fuel Supply
Rate provisions and during any arbitration relating thereto, the
parties and the arbitrators shall work to modify the Index Factor,
N1/D1, as defined in subsection 4.14 such that the renegotiated
Variable Fuel Supply Rate provisions will yield:
(a) a price of natural gas that reflects the value of other
long-term baseload gas supplies delivered at the city gate
to local electric utility companies in Massachusetts and
Rhode Island, where such prices have been adjusted by sub-
tracting all applicable costs (at 100% load factor) of firm
pipeline transportation from the wellhead to the respective
city gates, including commodity charges, demand charges and
fuel gas costs.
(b) a Variable Fuel Supply Rate that the parties anticipate will
enable the Unit to operate at an average capacity factor of
at least sixty percent (60%) over the following five year
period.
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(c) in the event that the objectives in (a) and (b) above are in
conflict, objective (b) relating to operation at a capacity
factor of at least sixty percent (60%) shall be considered
the controlling factor.
4.3.4 Whenever there is a redetermination of the Variable
Fuel Supply Rate in progress, transactions under this Agreement
shall continue in the same fashion as they were conducted before
such redetermination was initiated without prejudice to the rights
of either party under this section 4.3, pending a redetermination
resulting from renegotiation or arbitration. The Variable Fuel
Supply Rate in effect prior to such redetermination shall be
applied to all electricity delivered pursuant to this Agreement
during the time period after the Redetermination Date until the
day upon which a renegotiated or arbitrated decision is reached
and issued (in this section, the "Subject Period"), whereupon the
Variable Fuel Supply Rate Provisions as determined by the re-
negotiation or arbitration shall, unless otherwise agreed by the
parties, be applied to the Subject Period with interest (at the
annual rate of two percentage points over the current interest
rate on prime commercial loans then in effect at the First Nation-
al Bank of Boston) and with appropriate adjustments (i.e., payment
by the Company to the extent the Redetermined Variable Fuel Supply
Rate is greater; payment by the Seller to the extent the Redeter-
mined Rate is less) being made between the parties to reflect the
change in the Variable Fuel Supply Rate Provisions.
3. The Company shall submit this Amendment to the MDPU, and the Seller shall
submit this Amendment to the FERC, for the approval of each of the MDPU
and the FERC. This Amendment shall become effective upon the receipt of
such approvals in form and substance acceptable to the Company and the
Seller.
4. All other terms and conditions of said Agreement shall remain in full
force and effect.
IN WITNESS WHEREOF, the Company and the Seller have caused this Amendment to
be duly executed as of the day and year first above written.
DARTMOUTH POWER ASSOCIATES
LIMITED PARTNERSHIP BY
EMI/DARTMOUTH, INC.,
ITS GENERAL PARTNER
By: JAMES S. GORDON
Title: President
COMMONWEALTH ELECTRIC COMPANY
By: JAMES J. KEANE
Title: Vice President -
Power Supply & Transmission
