<PAGE 1>
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 quarterly period ended September 30, 1994
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 1-7316
COMMONWEALTH ENERGY SYSTEM
(Exact name of registrant as specified in its Declaration of Trust)
Massachusetts 04-1662010
(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 November 1, 1994
Common Shares of Beneficial
Interest, $4 par value 10,521,774 shares
<PAGE 2>
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONDENSED BALANCE SHEETS
SEPTEMBER 30, 1994 AND DECEMBER 31, 1993
ASSETS
(Unaudited)
September 30, December 31,
1994 1993
(Dollars in Thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost
Electric $1 036 929 $1 018 121
Gas 332 005 322 314
Other 58 455 58 473
1 427 389 1 398 908
Less - Accumulated depreciation and
amortization 455 443 425 483
971 946 973 425
Add - Construction work in progress and
nuclear fuel in process 11 393 11 089
983 339 984 514
LEASED PROPERTY, net 15 594 16 150
INVESTMENTS
Nuclear electric power companies (2.5% to 4.5%) 10 004 9 660
Other investments 3 896 3 889
13 900 13 549
CURRENT ASSETS
Cash 3 675 6 007
Accounts receivable 70 946 93 663
Unbilled revenues 18 445 43 279
Inventories, at average cost 36 604 36 102
Prepaid taxes and other 19 879 15 231
149 549 194 282
DEFERRED CHARGES 126 105 106 668
$1 288 487 $1 315 163
<PAGE 3>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONDENSED BALANCE SHEETS
SEPTEMBER 30, 1994 AND DECEMBER 31, 1993
CAPITALIZATION AND LIABILITIES
(Unaudited)
September 30, December 31,
1994 1993
(Dollars in Thousands)
CAPITALIZATION
Common share investment -
Common shares, $4 par value -
Authorized - 18,000,000 shares
Outstanding - 10,460,623 in 1994 and
10,295,077 in 1993 $ 41 842 $ 41 180
Amounts paid in excess of par value 100 980 94 657
Retained earnings 214 865 201 233
357 687 337 070
Redeemable preferred shares, less current
sinking fund requirements 14 660 15 480
Long-term debt, including premiums, less current
sinking fund requirements and maturities 437 137 448 893
809 484 801 443
CAPITAL LEASE OBLIGATIONS 14 026 14 456
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks 13 925 71 975
Maturing long-term debt 20 000 10 000
33 925 81 975
Other Current Liabilities -
Current sinking fund requirements 6 793 6 793
Accounts payable 86 240 90 006
Accrued taxes 20 711 9 090
Other 38 774 37 322
152 518 143 211
186 443 225 186
DEFERRED CREDITS
Accumulated deferred income taxes 162 676 156 851
Unamortized investment tax credits
and other 115 858 117 227
278 534 274 078
COMMITMENTS AND CONTINGENCIES
$1 288 487 $1 315 163
See accompanying notes.
<PAGE 4>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONDENSED STATEMENTS OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER, 30, 1994 AND 1993
(Unaudited)
Three Months Ended Nine Months Ended
1994 1993 1994 1993
(Dollars in Thousands)
OPERATING REVENUES
Electric $174 421 $168 510 $493 500 $465 987
Gas 46 251 47 429 244 557 222 098
Steam and other 2 627 1 945 11 780 10 048
223 299 217 884 749 837 698 133
OPERATING EXPENSES
Fuel and purchased power 95 516 94 484 277 536 259 129
Cost of gas sold 29 263 30 526 137 185 120 113
Other operation and
maintenance 62 185 58 417 190 082 190 188
Depreciation 9 724 9 436 32 963 31 704
Taxes -
Local property and other 5 470 4 882 19 074 18 830
Federal and state income 3 502 4 098 23 022 19 374
205 660 201 843 679 862 639 338
OPERATING INCOME 17 639 16 041 69 975 58 795
OTHER INCOME (EXPENSE) (759) 530 49 5 110
INCOME BEFORE INTEREST CHARGES 16 880 16 571 70 024 63 905
INTEREST CHARGES
Long-term debt 9 942 9 632 29 644 27 877
Other interest charges 830 1 330 2 804 4 276
Allowance for borrowed funds
used during construction (108) (87) (351) (181)
10 664 10 875 32 097 31 972
NET INCOME 6 216 5 696 37 927 31 933
Dividends on preferred shares 294 309 888 933
EARNINGS APPLICABLE TO
COMMON SHARES $ 5 922 $ 5 387 $ 37 039 $ 31 000
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 10 440 347 10 231 955 10 383 895 10 194 489
EARNINGS PER COMMON SHARE $ .57 $ .52 $3.57 $3.04
DIVIDENDS DECLARED PER
COMMON SHARE $ .75 $ .73 $2.25 $2.19
See accompanying notes.
<PAGE 5>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONDENSED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1994 AND 1993
(Unaudited)
1994 1993
(Dollars in Thousands)
OPERATING ACTIVITIES
Net income $ 37 927 $ 31 933
Effects of non-cash items -
Depreciation and amortization 43 066 39 672
Deferred income taxes and investment
tax credits, net 6 506 5 107
Equity earnings from corporate joint ventures (1 313) (1 202)
Dividends from corporate joint ventures 962 1 237
Change in working capital, exclusive of cash
and interim financing 51 708 38 410
All other operating items (31 450) (23 619)
Net cash provided by operating activities 107 406 91 538
INVESTING ACTIVITIES
Additions to property, plant and equipment
(exclusive of AFUDC) -
Electric (19 818) (18 807)
Gas (11 351) (14 766)
Other (282) (974)
Allowance for borrowed funds used during
construction (351) (181)
Net cash used for investing activities (31 802) (34 728)
FINANCING ACTIVITIES
Sale of common shares 6 985 4 862
Payment of dividends (24 295) (23 288)
Payment of short-term borrowings (58 050) (77 325)
Long-term debt issues - 65 000
Long-term debt issues refunded - (21 300)
Sinking funds payments (2 576) (2 589)
Net cash used for financing activities (77 936) (54 640)
Net increase (decrease) in cash (2 332) 2 170
Cash at beginning of period 6 007 1 522
Cash at end of period $ 3 675 $ 3 692
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of capitalized amounts) $ 29 635 $ 28 513
Income taxes $ 14 088 $ 13 472
See accompanying notes.
<PAGE 6>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
NOTES TO CONDENSED FINANCIAL STATEMENTS
(1) Accounting Policies
Commonwealth Energy System, the parent company, is referred to in
this report as the "System" and together with its subsidiaries is
sometimes collectively referred to as "the system."
The system's significant accounting policies are described in Note 1
of Notes to Consolidated Financial Statements included in its 1993 Annual
Report on Form 10-K filed with the Securities and Exchange Commission.
For interim reporting purposes, the system 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.
Regulated subsidiaries of the System have 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 regulatory liabilities established by the
system are required to be refunded to customers over time. As of
September 30, 1994, principal regulatory assets included in deferred
charges were $20 million for transition costs associated with FERC Order
636, $17.9 million for postretirement benefit costs including pensions,
$13.2 million for abandonment and nonconstruction costs related to the
Seabrook project, $13.2 million for unrecovered plant and decommissioning
costs for the Yankee Atomic nuclear plant, $11.5 million for Commonwealth
Electric Company's (Commonwealth Electric) rate stabilization plan, $7.3
million related to deferred income taxes and $7.1 million in litigation
costs associated with a settlement agreement with Boston Edison Company
relative to the Pilgrim nuclear plant. The principal regulatory
liability, reflected in deferred credits, was $17.7 million related to
income taxes.
Generally, expenses which relate to more than one interim period are
allocated to other periods to more appropriately match revenues and
expenses. Principal items of expense which are allocated other than on
the basis of passage of time are depreciation and property taxes of the
gas subsidiary, Commonwealth Gas Company (Commonwealth Gas). These
expenses are recorded for interim reporting purposes based upon projected
gas revenue. Income tax expense is recorded using the statutory rates in
effect applied to book income subject to tax for each interim period.
The unaudited financial statements for the periods ended September
30, 1994 and 1993, reflect, in the opinion of the System, all adjustments
necessary to summarize fairly the results for such periods. In addition,
certain prior period amounts are reclassified from time to time to con-
form 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
consumption of energy and Commonwealth Gas' seasonal rate structure.
<PAGE 7>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(2) Commitments and Contingencies
(a) Construction
The system is engaged in a continuous construction program presently
estimated at $358.3 million for the five-year period 1994 through 1998.
Of that amount, $71.9 million is estimated for 1994. The program is
subject to periodic review and revision.
(b) Decommissioning of Nuclear Power Plants
The system, through Canal Electric Company (Canal), has a 3.52%
joint-ownership interest in the Seabrook nuclear power plant. Canal and
the other joint owners have established a Seabrook Nuclear
Decommissioning Financing Fund to cover post operational decommissioning
costs. The estimated cost to decommission the plant is $378 million, in
1994 dollars, through September 30, 1994. Canal's share, less its share
of the market value of the decommissioning trust ($995,000), amounts to
approximately $12.3 million.
The system also has equity ownership interests in four nuclear
generating facilities in New England and is obligated to pay its
proportionate share of the capacity and energy costs associated with
these units, which include depreciation, operations and maintenance, a
return on invested capital and the estimated cost of decommissioning the
nuclear plants at the end of their estimated service lives. Pertinent
information with respect to projected decommissioning costs, in 1994
dollars, resulting from life-of-the-unit contracts from those units still
operating is as follows:
Connecticut Maine Vermont
Yankee Yankee Yankee
(Dollars in Millions)
Equity ownership (%) 4.50 4.00 2.50
Plant entitlement (%) 4.50 3.59 2.25
Plant capability (MW) 560.0 870.0 496.0
Company entitlement (MW) 25.2 31.2 11.2
Contract expiration date 1998 2008 2012
Decommissioning cost estimate (100%) ($) 356.5 338.2 325.3
System's decommissioning cost ($) 16.0 12.1 7.3
Market value of assets (100%) ($) 145.5 74.3 111.1
System's market value of assets ($) 6.5 2.7 2.5
In February 1992, the Board of Directors of Yankee Atomic Electric
Company (Yankee Atomic) agreed to permanently discontinue power operation
and decommission the Yankee Nuclear Power Station (the plant). At
September 30, 1994, Cambridge Electric Light Company's (Cambridge
Electric) and Commonwealth Electric's respective 2% and 2.5% investment in
Yankee Atomic is approximately $1.1 million. The companies' estimated
decommissioning costs include its unrecovered share of all costs associ-
ated with the shutdown of the plant, recovery of its plant investment, and
decommissioning and closing the plant. The amount currently reflected in
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
the accompanying Balance Sheets as a liability and a corresponding
regulatory asset is $13.2 million. The market value of the companies'
share of assets in the plant's decommissioning fund at September 30, 1994
is approximately $4.7 million.
On October 26, 1994, Yankee Atomic filed with the Nuclear Regulatory
Commission a revised estimate to decommission the plant of $370 million
(in 1994 dollars). The total cost to permanently shut down the plant is
approximately $438.6 million. The companies' share of this liability is
approximately $19.7 million. The companies are reviewing Yankee Atomic's
filing and adjustments to the liability and regulatory asset accounts will
be made as appropriate during the fourth quarter of 1994.
(c) Environmental
The system is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment.
These laws and regulations affect, among other things, the siting and
operation of electric generating and transmission facilities and can
require the installation of expensive air and water pollution control
equipment. These regulations have had an impact upon the system's
operations in the past and will continue to have an impact upon future
operations, capital costs and construction schedules of major facilities.
For additional information, see "Environmental Matters" in Management's
Discussion and Analysis of Financial Condition and Results of Operations.
(d) FERC Order No. 636
As a result of implementing FERC Order No. 636 (Order 636), each
interstate pipeline company is allowed to collect certain transition costs
from their customers that resulted from the pipelines' need to buy out gas
supply contracts entered into prior to the issuance of Order 636.
Commonwealth Gas has been billed a total of approximately $24.5 million
from Tennessee Gas Pipeline Company (Tennessee), Algonquin Gas
Transmission Company and Texas Eastern Transmission Company (Texas
Eastern) through September 30, 1994.
As of October 29, 1993, Commonwealth Gas received preliminary DPU
authorization to recover these costs, with carrying charges, through the
cost of gas adjustment (CGA) over a four-year period that began in
November 1993. As a result, a regulatory asset totaling $20 million is
reflected in deferred charges as of September 30, 1994. In addition, a
related liability of $6.7 million is reflected in deferred credits.
After extensive negotiations between Texas Eastern, Tennessee and
their customers (including Commonwealth Gas), settlements were reached
regarding a number of transition obligation issues. The settlement with
Texas Eastern, which was recently approved by FERC, calls for the pipeline
to absorb approximately 20% of all transition costs incurred from June
1993 forward. This agreement also provides for an extended billing period
and annual caps on the collection of future costs. Commonwealth Gas
believes that the absorption requirement will give the pipeline incentive
to minimize future costs.
<PAGE 9>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The settlement with Tennessee, which has yet to be approved by FERC,
will lower one element of Commonwealth Gas' transition obligation by
approximately $1 million. Further negotiations are underway with
Tennessee to craft a total settlement similar to that achieved with Texas
Eastern.
Commonwealth Gas is continuing to negotiate with the pipelines on
several other issues. As a result Commonwealth Gas is unable to predict
its final transition obligation at this time, however, based on these and
subsequent settlement activities, Commonwealth Gas will adjust its
regulatory asset and liability accounts accordingly.
(e) Rate Stabilization Plan
Commonwealth Electric implemented a Fuel Charge (FC) rate settlement
on April 1, 1994 that will stabilize its quarterly FC rate during the
years 1994 through 1996 at 6.5 cents per KWH and no greater than 6.7 cents
per KWH during 1997. The settlement results in billing at a significantly
lower rate than would have otherwise been in effect and could save custom-
ers between 1.75% and 5% on their annual electric bills from 1994 through
1997. This rate stabilization results from the use of a cost deferral
mechanism that was sponsored jointly by Commonwealth Electric and the
Massachusetts Attorney General and approved by the DPU. The deferred costs
are being reflected as a regulatory asset to be recovered, with carrying
charges, over the subsequent six-year period beginning in 1998 pursuant to
a recovery schedule subject to DPU review. The deferred amount, excluding
carrying charges, is restricted to a maximum of $40 million during the
settlement period (1994 through 1997) and is further limited to an annual
cost deferral of $16 million which is the amount Commonwealth Electric
anticipates will be deferred in 1994. As of September 30, 1994,
Commonwealth Electric has deferred $11.5 million, including carrying
charges.
The rate stabilization mechanism is part of a long-term plan to
control Commonwealth Electric's retail rates. This plan will help to
eliminate the disincentive for economic development resulting from a
volatile and unpredictable FC rate. The stabilized FC rate will enable
current and prospective customers to better plan their business and
personal finances in a more efficient and effective manner. In addition
to the Massachusetts Attorney General, this proposal has been widely
supported by various business and customer groups and other political
interests.
<PAGE 10>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Financial Condition
Capital resources of the System and its subsidiaries are derived
principally from retained earnings and equity funds provided through the
System's Dividend Reinvestment and Common Share Purchase Plan (DRP).
Supplemental interim funds are borrowed on a short-term basis and, when
necessary, replaced with new equity and/or debt issues through permanent
financing secured on an individual company basis. The system purchases
100% of all subsidiary common stock issues and provides, to the extent
possible, a portion of the subsidiaries' short-term financing needs.
These capital resources provide the funds required for the subsidiary
companies' construction programs, current operations, debt service and
other capital requirements.
For the first nine months of 1994, cash flows from operating
activities amounted to approximately $107.4 million and reflect net
income of $37.9 million and non-cash items such as depreciation ($33.4
million), amortization ($9.7 million) and deferred income taxes (net of
investment tax credits) which amounted to $6.5 million. The change in
working capital since December 31, 1993, exclusive of the changes in cash
($2.3 million) and interim financing ($58.1 million), amounted to $51.7
million and had a significant positive effect on cash flows from
operating activities. The working capital change reflects lower levels
of unbilled revenues ($24.8 million) and accounts receivable ($22.7
million) coupled with higher levels of accrued taxes ($11.6 million) and
other miscellaneous current liabilities ($1.3 million). These were
offset, in part, by a higher level of prepaid property taxes ($5.8
million) and a lower level of accounts payable ($3.8 million). The
change in all other operating items of $31.5 million includes an $11.5
million regulatory asset established pursuant to Commonwealth Electric's
rate stabilization plan and a $6.4 million increase in the regulatory
asset pertaining to postretirement benefits for both electric and gas
operating subsidiaries.
Construction expenditures for the first nine months of 1994 were
approximately $31.8 million, including nuclear fuel and an allowance for
funds used during construction (AFUDC). Construction expenditures for
the period, together with the preferred and common dividend requirements
of the System ($24.3 million), were funded entirely with internally
generated funds. In addition, short-term borrowings were reduced by
$58.1 million to $13.9 million for the most part with internal funds
generated from higher retail unit sales for both the electric and gas
divisions during the first nine months of this year and continued cost
containment efforts.
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.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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 nine
months ended September 30, 1994 and 1993 is shown below:
Three Months Nine Months
Ended September 30, Ended September 30,
1994 and 1993 1994 and 1993
Increase (Decrease)
(Dollars in Thousands)
Operating Revenues
Electric $ 5 911 3.5% $ 27 513 5.9%
Gas (1 178) (2.5) 22 459 10.1
Steam and other 682 35.1 1 732 17.2
5 415 2.5 51 704 7.4
Operating Expenses
Fuel and purchased power 1 032 1.1 18 407 7.1
Cost of gas sold (1 263) (4.1) 17 072 14.2
Other operation and maintenance 3 768 6.5 (106) (0.1)
Depreciation 288 3.1 1 259 4.0
Taxes -
Local property and other 588 12.0 244 1.3
Federal and state income (596) (14.5) 3 648 18.8
3 817 1.9 40 524 6.3
Operating Income 1 598 10.0 11 180 19.0
Other Income (1 289) (243.2) (5 061) (99.0)
Income Before Interest Charges 309 1.9 6 119 9.6
Interest Charges (211) (1.9) 125 0.4
Net Income 520 9.1 5 994 18.8
Dividends on preferred shares (15) (4.9) (45) (4.8)
Earnings Applicable to Common Shares $ 535 9.9 $ 6 039 19.5
The following are the period to period changes in electric and gas unit
sales for the three and nine months ended September 30, 1994 and 1993.
Unit Sales
Electric - Megawatthours (MWH)
Retail 36 492 3.0 86 549 2.5
Wholesale (151 111) (14.9) 245 032 8.6
(114 619) (5.1) 331 581 5.3
Gas - Billions of British
Thermal Units (BBTU)
Firm 80 2.6 1 164 4.3
Interruptible 3 040 335.2 4 756 334.5
3 120 77.4 5 920 20.9
<PAGE 12>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Three Months Ended Nine Months Ended
September 30, September 30,
1994 1993 1994 1993
Electric Sales - MWH
Residential 468 998 450 210 1 360 515 1 321 794
Commercial 589 229 575 414 1 565 199 1 522 381
Industrial 113 108 109 126 314 505 304 439
Other 90 917 91 010 284 971 290 027
Total retail sales 1 262 252 1 225 760 3 525 190 3 438 641
Wholesale to other systems 865 562 1 016 673 3 085 321 2 840 289
Total 2 127 814 2 242 433 6 610 511 6 278 930
Gas Sales - BBTU
Residential 1 413 1 449 15 774 15 370
Commercial 953 975 7 874 7 582
Industrial 720 618 3 114 2 815
Other 119 83 1 354 1 185
Total firm sales 3 205 3 125 28 116 26 952
Interruptible sales 3 947 907 6 178 1 422
Total 7 152 4 032 34 294 28 374
Electric Revenues, Fuel and Purchased Power and Electric Unit Sales
For the first nine months of 1994 electric operating revenues
increased $27.5 million or 5.9% due primarily to higher fuel and purchased
power costs, higher base rates for Cambridge Electric which became
effective June 1, 1993 and higher retail unit sales (discussed below).
This increase was slightly offset by a $900,000 reduction in conservation
and load management costs (C&LM) for electric operations which are being
recovered through revenues. The recovery of lost base revenues related to
the C&LM programs increased by $313,000 and $720,000 for the current
quarter and nine-month period, respectively, when compared to the same
reporting periods during 1993. The recovery of lost base revenues is
allowed by the DPU to encourage effective implementation of C&LM programs.
To the extent that current costs associated with C&LM programs increase or
decrease from period to period based on customer participation, a
corresponding change will occur in revenues.
For the current nine-month period, fuel and purchased power costs
increased $18.4 million or 7.1% and averaged 4.2 cents per KWH compared to
4.1 cents per KWH for the same period in 1993 and reflects purchases from
higher-cost non-utility generators and, to a lesser extent, higher fuel
oil costs at Canal Electric's generating station. The increases were
moderated by the deferral of $11.1 million of costs related to
Commonwealth Electric's rate stabilization mechanism which was implemented
on April 1, 1994.
The increase of 2.5% in retail unit sales for the current nine-month
period reflects higher unit sales to the residential (2.9%), commercial
(2.8%) and industrial (3.3%) sectors that resulted from the extreme cold
weather conditions experienced in the system's service territory during
the first quarter. Retail unit sales for the quarter were 3% higher and
reflect a record peak demand of 962 MW achieved on July 21, 1994. The
<PAGE 13>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
fluctuation in wholesale unit sales during the current quarter and nine-
month period reflects the changing capacity needs of the New England Power
Pool and non-affiliated utilities. Changes in the level of wholesale
electric sales have little, if any, impact on net income.
Gas Revenues, Cost of Gas Sold and Gas Unit Sales
For the current nine-month period, gas operating revenues increased
approximately $22.5 million or 10.1% due primarily to an increase in the
cost of gas sold ($14.2 million), higher C&LM costs ($2.5 million) and
higher firm and interruptible sales. Despite the increase in the cost of
gas sold, the average cost of gas per MMBTU during the current quarter and
nine-month period decreased from $7.57 to $4.09 and from $4.23 to $4.00,
respectively. The decrease from both periods of last year was mainly due
to the inclusion of transition charges related to Order 636 in the cost of
gas sold last year. These charges totaled $6.8 million and $9.6 million
in the prior third quarter and nine-month period, respectively. In the
fourth quarter of 1993, these charges were reclassified as a regulatory
asset pursuant to the aforementioned DPU order issued on October 29, 1993.
Commonwealth Gas will recover these costs, with carrying charges, over a
four-year period which began in November 1993.
For the current nine-month period firm gas unit sales increased 4.3%
as each customer segment showed improvement due primarily to the extreme
cold weather experienced during the first quarter of 1994. Although
interruptible sales increased significantly during both the current nine
months and third quarter of 1994, fluctuations in the level of these sales
have little, if any, impact on net income.
Steam and Other Operating Revenue
Steam and other operating revenue increased 35.1% and 17.2% during
the current quarter and nine-month period, respectively, due primarily to
higher steam sales to Harvard University, Massachusetts General Hospital
and a biotechnology company which became a steam customer in August 1993.
Other Operating Expenses
For the first nine months of 1994, other operation and maintenance
costs were virtually unchanged compared to the same period in 1993
reflecting savings resulting from the second quarter 1993 work force
reduction ($2.7 million), the absence of severance pay incurred in 1993
($3.7 million), lower maintenance activity ($1.3 million) and a decline in
the provision for bad debts due to improved collection experience ($1.1
million). These factors were offset, somewhat, by higher levels of
current and amortized C&LM charges ($1.6 million) and insurance and
employee benefit costs ($1.6 million).
The 6.5% or $3.8 million increase in other operation and maintenance
for the three months ended September 30, 1994 was due to increases in
insurance and employee benefit costs ($1.8 million), increased maintenance
expense on Canal Electric's Unit 1 ($951,000), a higher level of current
<PAGE 14>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
C&LM costs incurred at Commonwealth Gas ($464,000) and slightly higher
payroll costs ($318,000).
Depreciation and Taxes
Depreciation expense increased 3.1% and 4% during the current quarter
and current nine-month period, respectively, due to higher levels of plant
in service. The change in local property and other taxes for the three
and nine-months periods reflects higher property tax rates and assessments
($604,000 and $722,000) offset by a reduction in payroll taxes ($16,000
and $478,000). The increase in property taxes was also due to an
adjustment to the 1993 property tax accrual (approximately $300,000)
associated with revisions made to the nuclear station property tax
assessed by the state of New Hampshire to the joint-owners of Seabrook
during the third quarter of 1993. The increase in federal and state
income taxes for the current nine-month period reflects the higher level
of pretax income. For the current quarter, however, federal and state
income taxes declined 14.5% due to the absence of a retroactive adjustment
made in the third quarter of 1993 to reflect the increase in the federal
tax rate to 35% and, to a lesser extent, the level of pretax income.
Other Income and Interest Charges
The substantial decrease in other income in the nine-month period was
primarily due to the absence of a 1993 second quarter reversal of a
reserve ($3.8 million pretax) related to Canal Electric's Seabrook
investment. The decision to eliminate this reserve was prompted by the
inclusion in base rates of Seabrook costs at the state level for Cambridge
Electric. Another factor contributing to the decrease in the three and
nine-month periods was a reserve related to a settlement negotiated with
an outside party for certain costs associated with Commonwealth Electric's
energy conservation program. The decline for the nine-month period was
offset, somewhat, by a $595,000 increase in other interest and dividends
due, in part, to higher equity earnings from Cambridge Electric's
investments in nuclear generating companies and a Massachusetts sales tax
abatement received by the system during the first quarter.
For the current nine-month period, long-term interest charges
increased $1.8 million due to a higher level of long-term debt reflecting
the new debt issued by Commonwealth Electric, Commonwealth Gas and
Hopkinton LNG Corp. at various times in 1993. Interest on short-term
borrowings declined by $1.8 million due to the significantly lower average
level of borrowings resulting from the 1993 financing activity.
Environmental Matters
Commonwealth Gas is participating in the assessment of a number of
former manufactured gas plant (MGP) sites and alleged MGP waste disposal
locations to determine if and to what extent such sites have been
contaminated and whether Commonwealth Gas may be responsible for remedial
actions.
<PAGE 15>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The costs associated with the assessment and clean-up of these sites
are recoverable in rates through the cost of gas adjustment clause
pursuant to a 1990 DPU order over a seven-year amortization period without
carrying costs. Commonwealth Gas has recorded an estimated $2.3 million
liability that reflects its best estimate (based on current information)
of the costs to be incurred in connection with the assessment and
remediation activities identified to this point. Commonwealth Gas has
also recorded a regulatory asset in anticipation of recovery of these
costs. Commonwealth Gas is unable to predict the total cost to ultimately
resolve these matters, due to significant uncertainty as to the actual
site conditions and the extent of any associated remediation activities
and the assignment of responsibility. However, it is expected that all
such costs will continue to be recovered in rates as described above.
Commonwealth Gas and certain other system subsidiaries are also
involved in other known or potentially contaminated sites where the
associated costs may not be recoverable in rates and have recorded an
estimated liability (and a charge to operations) of $560,000 to cover the
expected costs associated with assessment and remediation activities.
These estimates are reviewed and adjusted periodically as further
investigation and assignment of responsibility occurs. As noted above,
the system is unable to predict at this time the ultimate cost to resolve
these matters due to the uncertainties inherent in the site investigation
and remediation process.
Power Contracts
Cambridge Electric and Commonwealth Electric have long-term contracts
for the purchase of electricity from various sources. Generally, these
contracts are for fixed periods and require that Cambridge Electric and
Commonwealth Electric pay a demand charge for their capacity entitlement
in each unit and an energy charge to cover the cost of fuel. Cambridge
Electric and Commonwealth Electric collect a portion of their capacity-
related purchased power costs associated with certain long-term power
arrangements through their base rates. The recovery mechanism for these
costs uses a per KWH factor which is calculated using historical (test-
period) capacity costs and unit sales. This factor is then applied to
current monthly KWH sales. When current period capacity costs and/or unit
sales vary from test-period levels, Cambridge and Commonwealth Electric
experience a revenue excess or shortfall. All other capacity and energy-
related purchased power costs are recovered through their respective Fuel
Charge.
Power Contract Negotiations
On May 2, 1994, Commonwealth Electric and Cambridge Electric gave
notice of termination of power purchase agreements with Eastern Energy
Corp. (Eastern), the developer of a proposed 300 MW coal-fired plant in
New Bedford, Massachusetts. In June 1989, in order to meet rising energy
requirements, Commonwealth Electric and Cambridge Electric agreed to buy
27% (50 MW and 33 MW, respectively) of the power to be produced by the
proposed plant, originally scheduled to begin operation in January 1992.
That date and later revised scheduled operating dates have not been
<PAGE 16>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
achieved, and the proposed plant has still not received the necessary
permits. Efforts to reshape the Eastern power purchase agreements to
provide a satisfactory arrangement were unsuccessful. The companies'
actions are based on Eastern's failure to meet its contractual
obligations. In a letter dated June 30, 1994, Eastern objected to the
notice of termination and provided to Commonwealth Electric and Cambridge
Electric written notice of arbitration and its designation of an
arbitrator pursuant to the 1989 agreements. The companies responded by
designating their arbitrator, and the parties are now in the process of
selecting a third, neutral arbitrator through the Boston, Massachusetts
office of the American Arbitration Association. An arbitrator decision on
the legality of the companies' termination action is expected in 1995.
Commonwealth Electric has filed for regulatory approval of
restructured power sale agreements with two other non-utility generators
that will allow Commonwealth Electric to eliminate or reduce purchased
power from the units. Also, Commonwealth Electric has reached an
agreement in principle on an innovative power contract with another New
England utility that is expected to produce long-term customer savings
beginning in 1995. This agreement will allow Commonwealth Electric to
purchase peaking unit capacity during the periods when it might otherwise
have incurred deficiency charges from the New England Power Pool, or have
been required to purchase capacity from other regional utilities at much
higher prices. This contract provides for cost-effective resources to
cover power needs in a changing environment.
<PAGE 17>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The system is not a party to any pending material legal proceeding.
Item 2. Changes in the Rights of the Company's Security Holders
None
Item 3. Defaults by the Company on its Senior Securities
None
Item 4. Results of Votes of Security Holders
None
Item 5. Other Information
Peter H. Cressy has been elected to the System's Board of Trustees
effective September 22, 1994. Dr. Cressy is currently the Chancellor
of the University of Massachusetts, Dartmouth. He was formerly
President of the Massachusetts Maritime Academy and a Rear Admiral in
the United States Navy. Dr. Cressy is a 1963 graduate of Yale
University, holds master's degrees from George Washington University
and the Naval War College, an MBA from the University of Rhode
Island, and a doctorate from the University of San Francisco. He
fills the vacant position created by the retirement of Robert E.
Siegfried, earlier this year.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Filed herewith:
Exhibit 10 Material Contracts.
10.3 Other Agreements.
10.3.3.10 Twenty-Eighth Agreement Amending New England Power Pool
Agreement dated September 1, 1971, as amended September
15, 1992 (Filed herewith as Exhibit 1).
10.3.3.11 Twenty-Ninth Agreement Amending New England Power Pool
Agreement dated September 1, 1971, as amended May 1, 1993
(Filed herewith as Exhibit 2).
Exhibit 27 Financial Data Schedule for the nine months ended
September 30, 1994 (Filed herewith as Exhibit 3).
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the three months ended
September 30, 1994.
<PAGE 18>
COMMONWEALTH ENERGY SYSTEM
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 ENERGY SYSTEM
(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: November 14, 1994
<PAGE 1>
EXHIBIT 1
TWENTY-EIGHTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS AGREEMENT, dated as of the 15th day of September, 1992 is entered
into by the signatories hereto for the amendment by them of the New England
Power Pool Agreement dated as of September 1, 1971 (the "NEPOOL Agreement"),
as previously amended or proposed to be amended by twenty-seven (27)
amendments, the most recent of which was dated as of October 1, 1990.
WHEREAS, in response to the factors specified in Section 5.10 of the
NEPOOL Agreement regarding election of members of the Management Committee to
serve as an Executive Committee, the member of the Management Committee
representing Public Service Company of New Hampshire has been elected to serve
as a member of the Executive Committee since the formation of NEPOOL; and
WHEREAS, Northeast Utilities has recently acquired Public Service
Company of New Hampshire, Public Service Company of New Hampshire has elected
to be treated as a single Participant with the other Entities controlled by
Northeast Utilities, and Public Service Company of New Hampshire is no longer
entitled to be separately represented by a member of the Management Committee;
and
WHEREAS, the signatory Participants have determined to amend the NEPOOL
Agreement in the manner specified below in order to reflect the fact that the
considerations specified in Section 5.10 for membership on the Executive
Committee can now be satisfied by election of only ten members.
NOW THEREFORE, the signatories hereby agree as follows:
SECTION I
TEXT OF AMENDMENT
Section 5.10 of the NEPOOL Agreement is amended to read as follows:
Election of Executive Committee Members
Unless there are less than eleven members of the Management
Committee, the Management Committee, at each annual meeting, shall
elect ten of its members to serve as an Executive Committee. In
electing the Executive Committee, the Management Committee shall
give such consideration as it shall deem advisable to
qualifications for the office, geographic distribution, the
relative sizes of Participants and the public and private sectors
of the electric utility industry. Each member so selected may
designate an alternate who is acceptable to the Management
Committee.
SECTION II
EFFECTIVENESS OF AGREEMENT
Following its execution by the requisite number of Participants, this
Agreement, and the amendment provided for above, shall become effective on
December 1, 1992, or on such later date as the Federal Energy Regulatory
Commission shall provide that such amendment shall become effective.
<PAGE 2>
SECTION III
USAGE OF DEFINED TERMS
The usage in this Agreement of terms which are defined in the NEPOOL
Agreement shall be deemed to be in accordance with the definitions thereof in
the NEPOOL Agreement.
SECTION IV
COUNTERPARTS
This Agreement may be executed in any number of counterparts and each
executed counterpart shall have the same force and effect as an original
instrument and as if all the parties to all the counterparts had signed the
same instrument. Any signature page of this Agreement may be detached from any
counterpart of this Agreement without impairing the legal effect of any
signatures thereof, and may be attached to another counterpart of this
Agreement identical in form hereto but having attached to it one or more
signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a counterpart
signature page to be executed by its duly authorized representative, as of the
15th day of September, 1992.
CONFORMED COPY
COUNTERPART SIGNATURE PAGE
TO TWENTY-EIGHTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
DATED AS OF SEPTEMBER 15, 1992
The NEPOOL Agreement, being dated as of September 1, 1971, and being
previously amended by twenty-seven (27) amendments, the most recent prior
amendment being an amendment dated as of October 1, 1990.
Ashburnham Municipal Light Department Bangor Hydro-Electric Company
By: /s/ Robert W. Gould By: /s/ Robert S. Briggs
Manager President & CEO
86 Central Street 33 State Street
Ashburnham, MA 01430 Bangor, Maine 04402-0932
Belmont Municipal Light Department Boston Edison Company
By: /s/ Timothy L. McCarthy By: /s/ Cameron H. Daley
Acting Manager Senior Vice President
450 Concord Avenue 800 Boylston Street
Belmont, MA 02178 Boston, MA 02199
Boylston Municipal Light Department Central Maine Power Company
By: /s/ H. Bradford White, Jr. By: /s/ Donald F. Kelly
Manager Senior Vice President
P.O. Box 560 Edison Drive
Boylston, MA 01505 Augusta, Maine 04336
<PAGE 3>
City of Chicopee Municipal Lighting Plant Commonwealth Energy System Cos.
Commonwealth Electric Company
Cambridge Electric Light Co.
Canal Electric Company
By: /s/ Barry W. Soden By: /s/ Harold N. Scherer, Jr.
General Manager President and CEO
725 Front Street 2421 Cranberry Highway
Chicopee, MA 01021-0405 Wareham, MA 02571
Concord Municipal Light Plant CT Municipal Elec. Energy Co-op
By: /s/ Daniel J. Sack By: /s/ Maurice R. Scully
Superintendent Executive Director
135 Keyes Road 30 Stott Avenue
Concord, MA 01742 Norwich, CT 06360-1526
Eastern Utilities Groton Electric Light Department
By: /s/ Donald G. Pardus By: /s/ Roger H. Beeltje
Chairman/CEO Manager
One Liberty Square P.O. Box 679
Boston, MA 02109 Groton, MA 01450
Hingham Municipal Lighting Plant Holden Municipal Light Department
By: /s/ Joseph R. Spadea, Jr. By: /s/ Edla Ann Bloom
General Manager Director of Electric Services
19 Elm Street 94 Reservoir Street
Hingham, MA 02043 Holden, MA 01520
Holyoke Gas & Electric Department Ipswich Municipal Light Dept.
By: /s/ George E. Leary By: /s/ Donald R. Stone
Manager Director of Utilities
70 Suffolk Street P.O. Box 151
Holyoke, MA 01040 Ipswich, MA 01938
Mansfield Municipal Electric Department Marblehead Municipal Light Dept.
By: /s/ John Larch By: /s/ Richard L. Bailey
Manager General Manager
50 West Street 80 Commercial Street
Mansfield, MA 02048 Marblehead, MA 01945
Merrimac Municipal Light Department Middleton Municipal Elec. Dept.
By: /s/ David Vance By: /s/ William E. Kelley
Commissioner Manager
2 School Street 197 North Main Street
Merrimac, MA 01860 Middleton, MA 01949
The Narragansett Electric Company New England Power Company
By: /s/ Robert L. McCabe By: /s/ Jeffrey D. Tranen
President Vice President
280 Melrose Street 25 Research Drive
Providence, Rhode Island Westborough, MA 01582
<PAGE 4>
Massachusetts Electric Company Granite State Electric Company
By: /s/ John H. Dickson By: /s/ Lydia M. Pastuszek
President President
25 Research Drive 33 West Lebanon Road
Westborough, MA 01582 Lebanon, New Hampshire
The Connecticut Light and Power Company Western Massachusetts Elec. Co.
By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox
President President
P.O. Box 270 P.O. Box 270
Hartford, CT 06141-0270 Hartford, CT 06141-0270
Holyoke Water Power Company Holyoke Power and Electric Co.
By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox
President President
P.O. Box 270 P.O. Box 270
Hartford, CT 06141-0270 Hartford, CT 06141-0270
Public Service Company of New Hampshire Pascoag Fire Dist.-Electric Dept.
By: /s/ Bernard M. Fox By: /s/ James E. Daniels
President Chairman, Operating Committee
P.O. Box 270 55 South Main Street
Hartford, CT 06141-0270 Pascoag, RI 02859
Princeton Municipal Light Department Rowley Municipal Lighting Plant
By: /s/ Sharon A. Staz By: /s/ G. Robert Merry
Manager Manager
P.O. Box 247 47 Summer Street
Princeton, MA 01541-0247 Rowley, MA 01969
Taunton Municipal Lighting Plant The United Illuminating Company
By: /s/ Joseph M. Blain By: /s/ Richard J. Grossi
General Manager Chairman and CEO
55 Weir Street 157 Church Street
Taunton, MA 02780 New Haven, CT 06506-0901
Vermont Electric Power Company, Inc. Central Vermont Public Svc. Corp.
By: /s/ Richard W. Mallary By: /s/ Robert de R. Stein
President Vice President
P.O. Box 548 77 Grove Street
Rutland, Vermont 05702-0548 Rutland, VT 05701
Citizens Utilities Company City of Burlington Electric Dept.
By: /s/ James P. Avery By: /s/ Dale L. Pohlman
Vice President General Manager
High Ridge Park 585 Pine Street
Stamford, CT 06905 Burlington, VT 05401
<PAGE 5>
Franklin Electric Light Co. Green Mountain Power Corporation
By: /s/ Hugh H. Gates By: /s/ John V. Cleary
President President & CEO
P.O. Box 96 P.O. Box 850
Franklin, VT 05457-0096 S. Burlington, Vermont 05402
Rochester Electric Light & Power Company Vermont Marble Company
By: /s/ Thomas Pierce By: /s/ John M. Mitchell
President President
P.O. Box 6 61 Main Street
Rochester, Vermont 05767 Proctor, Vermont 05765
Vermont Public Power Supply Authority Village of Hardwick Elec. Dept.
By: /s/ William J. Gallagher By: /s/ Jack E. Young
General Manager General Manager
512 St. George Road Box 516
Williston, VT 05495 Hardwick, Vermont 05843
Village of Ludlow Village of Morrisville
Electric Light Department Water and Light Department
By: /s/ Donald Ellison By: /s/ James C. Fox
Commissioner, Chairman Superintendent
P.O. Box 289 18 Portland Street
Ludlow, Vermont 05149 Morrisville, VT 05661
Village of Northfield Village of Orleans
Electric Department Electric Department
By: /s/ Kevin O'Donnell By: /s/ Slayton R. Marsh
Municipal Manager Superintendent
26 South Main Street Memorial Square
Northfield, Vermont 05663 Orleans, VT 05860
Village of Readsboro Wakefield Municipal Light Dept.
Electric Light Department
By: /s/ Annette Caruso By: /s/ William J. Wallace
Utility Clerk Manager
P.O. Box 247 11 Albion Street
Readsboro, Vermont 05350 Wakefield, MA 01880
<PAGE 1>
EXHIBIT 2
TWENTY-NINTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS AGREEMENT, dated as of the 1st day of May, 1993 is entered into by
the signatories hereto for the amendment by them of the New England Power Pool
Agreement dated as of September 1, 1971 (the "NEPOOL Agreement"), as
previously amended by twenty-eight (28) amendments, the most recent of which
was dated as of September 15, 1992.
WHEREAS, Participant generation resources, other than hydroelectric
units, whose annual hours of operation are restricted by regulatory
requirements, contract terms or engineering or operating constraints, may
require treatment different from that otherwise provided in the NEPOOL
Agreement for Capability Responsibility and energy billing purposes; and
WHEREAS, the signatory Participants have determined to amend the NEPOOL
Agreement in the manner specified below in order to provide for a modified
Capability Responsibility and energy billing treatment for restricted
generation resources.
NOW THEREFORE, the signatories hereby agree as follows:
SECTION I
TEXT OF AMENDMENTS
A. Amendment of Section 9.2(b)(2)
Section 9.2(b)(2) of the NEPOOL Agreement is amended by inserting the
following additional provisions immediately following the present final
paragraph of Section 9.2(b)(2):
The New Unit Adjustment Factor for any Restricted Unit for which
proposed plans were submitted subsequent to November 1, 1990 for
review pursuant to Section 10.4 (or, in the case of a unit with a
rated capacity of less than 5MW, for which notification was first
given to NEPOOL subsequent to November 1, 1990) and for the
Peabody Municipal Light Plant's Waters River #2 unit shall be
determined in accordance with the formula previously specified in
this Section 9.2(b)(2), modified as follows:
n = K1(c-C)+K2(f-F)+K3(m-M)+K4(d-D)+K5(f-F)c2+K6(2500-a)
The symbols used in the above formula, as modified, shall have the
meanings previously specified, except that the symbols "K6" and
"a" shall have the following meanings:
K6 is a scaling factor of 0.0001.
a is as follows:
for units with more than 2500 annual hours available for
operation, "a" = 2500,
for units with annual hours available for operation between
500 and 2500, inclusive, "a" = annual hours available for
operation, and
for units with annual hours available for operation less
than 500 hours, "a" = -7500;
<PAGE 2>
provided, however, that a Participant may elect to avoid, in whole
or part, the effect on its Capability Responsibility of a
Restricted Unit's availability being limited to 2500 hours or less
a year by agreeing to leave unfilled a portion of its dispatchable
load allocation in accordance with rules to be adopted by the
Operations Committee.
B. Amendment of Section 12.6
The first two sentences of Section 12.6 of the NEPOOL Agreement are
amended to read as follows:
If pursuant to Section 12.5A, a Participant is deemed to have
received energy service in any hour when the Participant (i) had
Entitlements in one or more generating units which were available
for service but were not scheduled for operation by NEPEX at their
full available Reserve Capability (or, to the extent applicable,
at their full available Temporary Reserve Capability) and which,
in the case of any Restricted Unit, had an unused portion of an
available Restricted Unit Operational Allowance and/or (ii) had
Scheduled Outage Service Entitlements, the Participant shall be
deemed to have received Economy Flow Service and/or Scheduled
Outage Service in an amount equal to the lesser of:
(a) the amount of energy service the Participant is deemed to
have received pursuant to Section 12.5A, or
(b) the amount of energy service which could have been provided
from its share of (1) the unused portion of the available
Reserve or Temporary Reserve Capabilities of the units
described in (i) above, as limited in the case of any
Restricted Unit by the unused portion of its available
Restricted Unit Operational Allowance, plus (2) its
Scheduled Outage Service Entitlements.
Economy Flow Service is service which a Participant is deemed to
receive at any time to replace service which it could have
provided at the time from units described in (i) above, and the
amount of Economy Flow Service which it is deemed to receive at
the time shall not exceed the amount of energy service which could
have been provided from its share of the unused portions of the
available Reserve Capabilities (or, to the extent applicable, the
unused portion of the available Temporary Reserve Capabilities or
the unused portion of the available Restricted Unit Operational
Allowances, whichever is controlling) of such units.
C. Addition of Definitions of "Restricted Unit" and "Restricted Unit
Operational Allowance".
The NEPOOL Agreement is amended by adding the following definitions
following the definition of "Reserve Savings Shares" in Section 15.37A:
15.37B. Restricted Unit is a generating unit, other than
a hydroelectric unit, that is restricted in
annual hours available for operation by
regulatory requirements, contract terms or
actual engineering or operating constraints.
<PAGE 3>
Planned or forced outages due to maintenance
requirements are not considered restrictions in
annual hours available for operation.
15.37C. Restricted Unit Operational Allowance
("Allowance") for a Participant's Entitlement in
a Restricted Unit for any calendar year (or for
the term of the Entitlement in any year, if such
term is for a shorter period than the year) is
the number of hours for which the Restricted
Unit is available for operation during the year
or such shorter period, whichever is applicable.
The Allowance for a Participant's Entitlement in
a Restricted Unit for any year or shorter period
shall be deemed to be exhausted when (i) the
number of hours that the Operations Committee
determines the Participant would have used its
Restricted Unit Entitlement to minimize the
Participant's overall energy costs in the
absence of NEPEX dispatch, plus (ii) the number
of hours that the Participant is deemed to
receive Scheduled Outage Service with respect to
its Entitlement in the Restricted Unit during
the year or such shorter period pursuant to
Section 12.6, equals the Allowance.
D. Modification of Definition of "Scheduled Outage Service Entitlement".
The definition of "Scheduled Outage Service Entitlement" in Section
15.38B of the NEPOOL Agreement is amended to read as follows:
15.38B Scheduled Outage Service Entitlement of a
Participant is the amount of Scheduled Outage
Service which the Participant is entitled to
receive in any hour with respect to a generating
unit which is scheduled by the Operations
Committee to be out of service, in whole or in
part, for maintenance during a period approved
for it by the Operations Committee for Scheduled
Outage Service and is in fact out of service, in
whole or in part, for any reason during the
approved period. Such amount is equal to the
lesser of (i) the portion of the Participant's
share of the Reserve Capability of such unit
which is unavailable for service times an
estimated average availability of such unit
between its periodic scheduled outages or (ii)
in the case of any generating unit with a
currently applicable Temporary Reserve
Capability, the portion of the Participant's
share of the Temporary Reserve Capability which
is unavailable for service; provided, however,
that (a) in the case of any Limited Fuel Unit,
the amount of a Participant's Scheduled Outage
Service Entitlement shall be reduced, if
appropriate, to take account of any limit on the
availability of stream flow or fuel to operate
the unit during the outage period, and (b) in
the case of any Restricted Unit, the
<PAGE 4>
Participant's Scheduled Outage Service
Entitlement shall be limited to the unused
portion, if any, of its currently available
Restricted Unit Operational Allowance for the
unit. The Operations Committee shall develop
rules for establishing the estimated average
availability of each unit between scheduled
outages. Such rules shall become effective upon
approval by the Management Committee.
SECTION II
EFFECTIVENESS OF AGREEMENT
Following its execution by the requisite number of Participants, this
Agreement, and the amendments provided for above, shall become effective on
August 1, 1993, or on such later date as the Federal Energy Regulatory
Commission shall provide that such amendment shall become effective.
SECTION III
USAGE OF DEFINED TERMS
The usage in this Agreement of terms which are defined in the NEPOOL Agreement
shall be deemed to be in accordance with the definitions thereof in the NEPOOL
Agreement.
SECTION IV
COUNTERPARTS
This Agreement may be executed in any number of counterparts and each executed
counterpart shall have the same force and effect as an original instrument and
as if all the parties to all the counterparts had signed the same instrument.
Any signature page of this Agreement may be detached from any counterpart of
this Agreement without impairing the legal effect of any signatures thereof,
and may be attached to another counterpart of this Agreement identical in form
hereto but having attached to it one or more signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a counterpart signature
page to be executed by its duly authorized representative, as of the 1st day
of May, 1993.
<PAGE 5>
CONFORMED COPY
COUNTERPART SIGNATURE PAGE
TO TWENTY-NINTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
DATED AS OF MAY 1, 1993
The NEPOOL Agreement, being dated as of September 1, 1971, and being
previously amended by twenty-eight (28) amendments, the most recent prior
amendment being an amendment dated as of September 15, 1992.
Ashburnham Municipal Light Department Bangor Hydro-Electric Company
By: /s/ Robert W. Gould By: /s/ Carroll R. Lee
Manager Vice President, Operations
86 Central Street 33 State Street
Ashburnham, MA 01430 Bangor, ME 04402-0932
Braintree Electric Light Department Boston Edison Company
By: /s/ Walter R. McGrath By: /s/ B.W. Reznicek
General Manager Chairman, President & CEO
44 Allen Street 800 Boylston Street
Braintree, MA 02184 Boston, MA 02199
Boylston Municipal Light Department Central Maine Power Company
By: /s/ H. Bradford White, Jr. By: /s/ Donald F. Kelly
Manager Senior Vice President
Tivnan Rd, P.O. Box 560 Edison Drive
Boylston, MA 01505 Augusta, ME 04336
Fitchburg Gas and Electric Light Co. Commonwealth Electric Company
By: /s/ David K. Foot By: /s/ James J. Keane
Senior Vice President Vice President-Power Supply
216 Epping Road and Transmission
Exeter, NH 03833 2421 Cranberry Highway
Wareham, MA 02571
Concord Municipal Light Plant CT Municipal Elec. Energy Co-op
By: /s/ Daniel J. Sack By: /s/ Maurice R. Scully
Superintendent Executive Director
135 Keyes Road 30 Stott Avenue
Concord, MA 01742 Norwich, CT 06360-1526
Eastern Utilities Groton Electric Light Department
By: /s/ Donald G. Pardus By: /s/ Roger H. Beeltje
Chairman/CEO Manager
P.O. Box 2333 P.O. Box 679
Boston, MA 02107 Groton, MA 01450
<PAGE 6>
Hingham Municipal Lighting Plant Holden Municipal Light Department
By: /s/ Joseph R. Spadea, Jr. By: /s/ Edla Ann Bloom
General Manager Director of Electric Services
19 Elm Street 94 Reservoir Street
Hingham, MA 02043 Holden, MA 01520
Holyoke Gas & Electric Department Georgetown Municipal Light Dept.
By: /s/ George E. Leary By: /s/ Edward Stanley
Manager Manager
70 Suffolk Street Moulton and West Main Streets
Holyoke, MA 01040 Georgetown, MA 01938
Littleton Electric Light and Water Dept. Marblehead Municipal Light Dept.
By: /s/ Curtis J. Lanciani By: /s/ Richard L. Bailey
General Manager General Manager
39 Ayer Road 80 Commercial Street, Box 369
Littleton, MA 01460 Marblehead, MA 01945
Middleborough Gas & Electric Department Middleton Municipal Elec. Dept.
By: /s/ John W. Dunfey By: /s/ William E. Kelley
General Manager Interim Manager
32 South Main Street 197 North Main Street
Middleborough, MA 02346 Middleton, MA 01949
Paxton Light Department New England Electric System
By: /s/ Harold L. Smith By: /s/ Jeffrey D. Tranen
Manager Vice President
578 Pleasant Street 25 Research Drive
Paxton, MA 01612 Westborough, MA 01582
Shrewsbury's Electric Light Plant Town of S. Hadley Electric
Light Department
By: /s/ Thomas R. Josie By: /s/ Wayne D. Doerpholz
General Manager Manager
100 Maple Ave. 85 Main Street
Shrewsbury, MA 01545 South Hadley, MA 01075
The Connecticut Light and Power Company Western Massachusetts Elec. Co.
By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox
President and CEO President and CEO
P.O. Box 270 P.O. Box 270
Hartford, CT 06141-0270 Hartford, CT 06141-0270
Holyoke Water Power Company Holyoke Power and Electric Co.
By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox
President and CEO President and CEO
P.O. Box 270 P.O. Box 270
Hartford, CT 06141-0270 Hartford, CT 06141-0270
<PAGE 7>
Public Service Company of New Hampshire Pascoag Fire Dist.-Electric Dept.
By: /s/ W.T. Frain, Jr. By: /s/ Thomas J. Beauregard
Senior Vice President Chairman
1000 Elm Street P.O. Box 107
Manchester NH 03105 Pascoag, RI 02859
Princeton Municipal Light Department Rowley Municipal Lighting Plant
By: /s/ Sharon A. Staz By: /s/ G. Robert Merry
General Manager Manager
P.O. Box 247 47 Summer Street
Princeton, MA 01541-0247 Rowley, MA 01969
Taunton Municipal Lighting Plant The United Illuminating Company
By: /s/ Joseph M. Blain By: /s/ Richard J. Grossi
General Manager Chairman and CEO
P.O. Box 870 157 Church Street
Taunton, MA 02780 New Haven, CT 06506-0901
Vermont Electric Power Company, Inc. Central Vermont Public Svc. Corp.
By: /s/ Richard W. Mallary By: /s/ Robert de R. Stein
President Vice President
P.O. Box 548 77 Grove Street
Rutland, Vermont 05702-0548 Rutland, VT 05701
Templeton Municipal Light Plant UNITIL Power Corporation
By: /s/ Gerald Skelton By: /s/ David K. Foote
Manager/Engineer Senior Vice President
2 School Street 216 Epping Road
Baldwinville, MA 01436 Exeter, NH 03833
Franklin Electric Light Co. Green Mountain Power Corporation
By: /s/ Hugh H. Gates By: /s/ John V. Cleary
President President & CEO
P.O. Box 96 P.O. Box 850
Franklin, VT 05457-0096 S. Burlington, Vermont 05402
Village of Jacksonville Vermont Marble Power Div. of
OMYA, Inc.
By: /s/ Earle S. Holland By: /s/ John M. Mitchell
President Board of Trustees Executive Vice President
P.O. Box 73 61 Main Street
Jacksonville, Vermont 05342 Proctor, Vermont 05765
Village of Ludlow Village of Morrisville
Electric Light Department Water and Light Department
By: /s/ Donald Ellison By: /s/ James C. Fox
Commissioner, Chairman Superintendent
P.O. Box 289 P. O. Box 325
Ludlow, Vermont 05149 Morrisville, VT 05661
<PAGE 8>
Village of Northfield Readsboro Electric
Electric Department
By: /s/ Kevin O'Donnell By: /s/ Annette Caruso
Municipal Manager Clerk
26 South Main Street P.O. Box 247
Northfield, Vermont 05663 Readsboro, VT 05350
Westfield Gas and Electric Wakefield Municipal Light Dept.
Light Department
By: /s/ Daniel Golubek By: /s/ William J. Wallace
General Manager General Manager
100 Elm Street 9 Albion Street
Westfield, MA 01085 Wakefield, MA 01880
<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 Energy System for the nine months ended September
30, 1994 and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<CIK> 0000071304
<NAME> COMMONWEALTH ENERGY SYSTEM
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> SEP-30-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 983,339
<OTHER-PROPERTY-AND-INVEST> 13,900
<TOTAL-CURRENT-ASSETS> 149,549
<TOTAL-DEFERRED-CHARGES> 126,105
<OTHER-ASSETS> 15,594
<TOTAL-ASSETS> 1,288,487
<COMMON> 41,842
<CAPITAL-SURPLUS-PAID-IN> 100,980
<RETAINED-EARNINGS> 214,865
<TOTAL-COMMON-STOCKHOLDERS-EQ> 357,687
14,660
0
<LONG-TERM-DEBT-NET> 437,137
<SHORT-TERM-NOTES> 13,925
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 25,973
820
<CAPITAL-LEASE-OBLIGATIONS> 14,026
<LEASES-CURRENT> 1,568
<OTHER-ITEMS-CAPITAL-AND-LIAB> 422,691
<TOT-CAPITALIZATION-AND-LIAB> 1,288,487
<GROSS-OPERATING-REVENUE> 749,837
<INCOME-TAX-EXPENSE> 23,022
<OTHER-OPERATING-EXPENSES> 656,840
<TOTAL-OPERATING-EXPENSES> 679,862
<OPERATING-INCOME-LOSS> 69,975
<OTHER-INCOME-NET> 49
<INCOME-BEFORE-INTEREST-EXPEN> 70,024
<TOTAL-INTEREST-EXPENSE> 32,097
<NET-INCOME> 37,927
888
<EARNINGS-AVAILABLE-FOR-COMM> 37,039
<COMMON-STOCK-DIVIDENDS> 23,407
<TOTAL-INTEREST-ON-BONDS> 29,644
<CASH-FLOW-OPERATIONS> 107,406
<EPS-PRIMARY> 3.57
<EPS-DILUTED> 3.57
</TABLE>
