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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 September 30, 1998
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)
Registrant's telephone number, including area code (617) 225-4000
(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, 1998
Common Shares of Beneficial
Interest, $2 par value 21,533,820 shares
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PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED BALANCE SHEETS
SEPTEMBER 30, 1998 AND DECEMBER 31, 1997
ASSETS
(Dollars in thousands)
September 30, December 31,
1998 1997
(Unaudited)
PROPERTY, PLANT AND EQUIPMENT, at original cost
Electric $1,191,436 $1,173,797
Gas 383,468 373,541
Other 118,675 72,475
1,693,579 1,619,813
Less - Accumulated depreciation and
amortization 618,987 577,962
1,074,592 1,041,851
Add - Construction work in progress
and nuclear fuel in process 15,025 8,057
1,089,617 1,049,908
EQUITY IN CORPORATE JOINT VENTURES
Nuclear electric power companies (2.5%
to 4.5%) 10,217 10,368
Other investments 2,918 3,399
13,135 13,767
CURRENT ASSETS
Cash 3,650 4,299
Accounts receivable 100,523 128,946
Unbilled revenues 11,382 32,029
Inventories, at average cost 34,624 32,644
Prepaid taxes and other 22,614 15,068
172,793 212,986
DEFERRED CHARGES
Regulatory assets 198,605 178,864
Other 64,316 29,525
262,921 208,389
$1,538,466 $1,485,050
See accompanying notes.
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COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED BALANCE SHEETS
SEPTEMBER 30, 1998 AND DECEMBER 31, 1997
CAPITALIZATION AND LIABILITIES
(Dollars in thousands)
September 30, December 31,
1998 1997
(Unaudited)
CAPITALIZATION
Common share investment -
Common shares, $2 par value -
Authorized - 50,000,000 shares
Outstanding - 21,533,820 in 1998 and
21,531,784 in 1997 $ 43,068 $ 43,063
Amounts paid in excess of par value 112,075 111,912
Retained earnings 291,585 275,795
446,728 430,770
Redeemable preferred shares, less current
sinking fund requirements 11,380 12,200
Long-term debt, including premiums, less current
sinking fund requirements and maturing debt 475,317 364,311
933,425 807,281
CAPITAL LEASE OBLIGATIONS 11,251 12,272
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks 74,050 94,075
Maturing long-term debt 49,000 19,000
123,050 113,075
Other Current Liabilities -
Current sinking fund requirements 8,473 8,473
Accounts payable 74,076 107,157
Accrued taxes 31,103 24,205
Other 77,071 58,922
190,723 198,757
313,773 311,832
DEFERRED CREDITS
Accumulated deferred income taxes 109,018 176,354
Purchased power contracts 62,132 69,659
Unamortized investment tax credits
and other 108,867 107,652
280,017 353,665
COMMITMENTS AND CONTINGENCIES
$1,538,466 $1,485,050
See accompanying notes.
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COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1998 AND 1997
(Dollars in thousands except per share amounts - unaudited)
Three Months Ended Nine Months Ended
1998 1997 1998 1997
OPERATING REVENUES
Electric $178,196 $177,723 $473,393 $511,778
Gas 43,308 41,870 216,682 235,067
Steam and other 12,102 2,522 24,426 13,404
233,606 222,115 714,501 760,249
OPERATING EXPENSES
Fuel and purchased power 94,773 97,275 250,779 289,320
Cost of gas sold 25,145 25,390 116,048 128,127
Other operation and maintenance 73,142 59,809 197,876 199,996
Depreciation 14,456 12,078 45,012 40,398
Taxes -
Federal and state income 3,431 4,513 20,449 19,907
Local property and other 6,700 6,163 21,778 21,929
217,647 205,228 651,942 699,677
OPERATING INCOME 15,959 16,887 62,559 60,572
OTHER INCOME
Gain from sale of
real estate, net 10,789 - 10,789 -
Other 2,105 340 3,604 1,970
12,894 340 14,393 1,970
INCOME BEFORE INTEREST CHARGES 28,853 17,227 76,952 62,542
INTEREST CHARGES
Long-term debt 9,488 8,123 26,708 24,912
Other interest charges 3,426 2,077 7,881 5,695
Allowance for borrowed funds
used during construction (131) (120) (331) (278)
12,783 10,080 34,258 30,329
NET INCOME 16,070 7,147 42,694 32,213
Dividends on preferred shares 234 248 708 751
EARNINGS APPLICABLE
TO COMMON SHARES $ 15,836 $ 6,899 $ 41,986 $ 31,462
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 21,533,820 21,531,784 21,533,368 21,530,378
BASIC AND DILUTED EARNINGS
PER COMMON SHARE $ .74 $ .32 $1.95 $1.46
DIVIDENDS DECLARED PER
COMMON SHARE $.405 $.395 $1.215 $1.185
See accompanying notes.
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COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1998 AND 1997
(Dollars in thousands - unaudited)
1998 1997
OPERATING ACTIVITIES
Net income $ 42,694 $ 32,213
Gain from sale of real estate, net (10,789) -
Effects of noncash items -
Depreciation and amortization 55,037 50,000
Deferred income taxes and investment
tax credits, net (1,833) (2,174)
Earnings from corporate joint ventures (1,300) (1,229)
Dividends from corporate joint ventures 1,698 545
Change in working capital, exclusive of cash
and interim financing 31,992 40,719
Transition costs deferral (31,288) -
All other operating items (16,951) (14,049)
Net cash provided by operating activities 69,260 106,025
INVESTING ACTIVITIES
Purchase of total energy plant
and related contracts (146,270) -
Proceeds from sale of real estate 22,175 -
Additions to property, plant and equipment
(inclusive of AFUDC) -
Electric (24,645) (23,055)
Gas (12,710) (11,632)
Other (1,713) (2,461)
Net cash used for investing activities (163,163) (37,148)
FINANCING ACTIVITIES
Payment of dividends (26,904) (26,302)
Payment of short-term borrowings (20,025) (57,425)
Long-term debt issues 152,500 35,000
Long-term debt issues refunded (10,000) (14,260)
Sinking funds payments (2,317) (2,316)
Net cash provided by (used for)
financing activities 93,254 (65,303)
Net increase (decrease) in cash (649) 3,574
Cash at beginning of period 4,299 1,495
Cash at end of period $ 3,650 $ 5,069
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of capitalized amounts) $ 32,624 $ 29,082
Income taxes $ 27,286 $ 17,154
See accompanying notes.
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COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(1) General Information
Commonwealth Energy System, the parent company, is referred to in this
report as the "System" and, together with its subsidiaries, is collec-
tively referred to as "the system." The System is an exempt public
utility holding company under the provisions of the Public Utility Holding
Company Act of 1935 with investments in four operating public utility
companies located in central, eastern and southeastern Massachusetts. In
addition, the System has interests in other utility and several non-
regulated companies.
The system has 1,792 regular employees including 1,142 (64%)
represented by various collective bargaining units covered by separate
contracts with expiration dates ranging from March 2001 through April
2003.
Accounting Policies
(a) Principles of Accounting
The system's significant accounting policies are described in Note 2
of Notes to Consolidated Financial Statements included in its 1997 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.
Generally, certain 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,
1998 and 1997, reflect, in the opinion of the System, all adjustments
(consisting of only normal recurring accruals, except for a one-time
charge recorded in June 1997 as described in Management's Discussion and
Analysis of Financial Condition and Results of Operations) 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.
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COMMONWEALTH ENERGY SYSTEM
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.
(b) Regulatory Assets and Liabilities
The system's operating utility companies are regulated as to rates,
accounting and other matters by various authorities, including the Federal
Energy Regulatory Commission (FERC) and the Massachusetts Department of
Telecommunications and Energy (DTE).
Based on the current regulatory framework, the system accounts for the
economic effects of regulation in accordance with the provisions of
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation." Regulated subsidiaries of
the System have established various regulatory assets in cases where the
DTE and/or the FERC have permitted or are expected to permit recovery of
specific costs over time. Similarly, the regulatory liabilities
established by the system are required to be refunded to customers over
time. In the event the criteria for applying SFAS No. 71 are no longer
met, the accounting impact would be an extraordinary, non-cash charge to
operations of an amount that could be material. Criteria that give rise
to the discontinuance of SFAS No. 71 include: 1) increasing competition
that restricts the system's ability to establish prices to recover
specific costs, and 2) a significant change in the current manner in which
rates are set by regulators from cost based regulation to another form of
regulation. These criteria are reviewed on a regular basis to ensure the
continuing application of SFAS No. 71 is appropriate. Based on the
current evaluation of the various factors and conditions that are expected
to impact future cost recovery, the system believes that its regulatory
assets, including those related to generation, are probable of future
recovery.
As a result of electric industry restructuring, the system's retail
electric companies discontinued application of accounting principles
applied to their investment in electric generation facilities effective
March 1, 1998. The system will not be required to write off any of its
generation-related assets, including regulatory assets. These assets will
be retained on the Consolidated Condensed Balance Sheets because the
legislation and the DTE's plan for a restructured electric industry
specifically provide for their recovery through a non-bypassable
transition charge.
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COMMONWEALTH ENERGY SYSTEM
The principal regulatory assets included in deferred charges were as
follows:
September 30, December 31,
1998 1997
(Dollars in thousands)
Transition costs $ 34,055 $ -
Maine Yankee unrecovered plant and
decommissioning costs 31,574 34,908
Fuel charge stabilization 27,283 29,655
Connecticut Yankee unrecovered plant and
decommissioning costs 26,007 28,566
Postretirement benefits costs 24,459 25,475
Power contract buy-out 16,116 17,609
Deferred income taxes 13,212 13,089
FERC Order 636 transition costs 6,310 7,336
Pilgrim litigation costs 5,553 5,929
Environmental costs 5,171 3,930
Yankee Atomic unrecovered plant and
decommissioning costs 4,552 6,184
Seabrook related costs 2,339 4,324
Other 1,974 1,859
$198,605 $178,864
The regulatory liabilities, reflected in deferred credits in the
accompanying Consolidated Condensed Balance Sheets and related primarily
to deferred income taxes, were $13.4 million and $14.1 million at
September 30, 1998 and December 31, 1997, respectively.
In November 1997, the Commonwealth of Massachusetts enacted a
comprehensive electric utility industry restructuring bill. On November
19, 1997, the System's electric subsidiaries filed a restructuring plan
with the DTE. The plan, approved by the DTE on February 27, 1998,
provides that the System's retail electric subsidiaries, beginning March
1, 1998, initiate a ten percent rate reduction for all customer classes
and allow customers to choose their energy supplier. As part of the plan,
the DTE authorized the recovery of certain strandable costs and provides
that certain future costs may be deferred to achieve or maintain the rate
reductions that the restructuring bill mandates. The legislation gives
the DTE the authority to determine the amount of strandable costs that
will be eligible for recovery. Costs that will qualify as strandable
costs and be eligible for recovery include, but are not limited to,
certain above market costs associated with generating facilities, costs
associated with long-term commitments to purchase power at above market
prices from independent power producers and regulatory assets and
associated liabilities related to the generation portion of the electric
business.
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COMMONWEALTH ENERGY SYSTEM
The cost of transitioning to competition will be mitigated, in part,
by the sale of the system's non-nuclear generating assets. The sale was
approved by the DTE on October 30, 1998 and by the FERC on November 12,
1998 (see the "Industry Restructuring - Electric" section under
Management's Discussion and Analysis of Financial Condition and Results of
Operations for further discussion of the sale). The net proceeds from the
sale of these assets will be used to mitigate transition costs.
The system's ability to recover its transition costs will depend on
several factors, including the aggregate amount of transition costs the
system will be allowed to recover and the market price of electricity.
Management believes that the system will recover its transition costs. A
change in any of the above listed factors could affect the recovery of
transition costs and may result in a loss to the system. For additional
information relating to industry restructuring, see the "Industry
Restructuring - Electric" section under Management's Discussion and
Analysis of Financial Condition and Results of Operations.
(3) Commitments and Contingencies
Capital Expenditures
Construction Program
The system is engaged in a continuous construction program presently
estimated at $248.6 million for the five-year period 1998 through 2002.
Of that amount, $60.7 million is estimated for 1998. The program is
subject to periodic review and revision.
Acquisition
On June 1, 1998, Advanced Energy Systems, Inc. (AES), a wholly-owned
subsidiary of the System, acquired for $146.3 million all of the issued
and outstanding shares of capital stock of Harvard University's Medical
Area Total Energy Plant, Inc. subsidiary (MATEP) and all rights under
customer contracts owned by Harvard University. MATEP's principal asset
is a cogeneration plant that provides heating, chilled water service and
electricity to several hospitals, medical research centers and teaching
institutions in the 200-acre Longwood Medical Area of Boston pursuant to
the contracts that were assigned to AES. The purchase price was
established through a sealed-bid auction process and the transaction was
initially financed with a short-term bank loan of $150 million that was
subsequently reduced with the proceeds from an equity contribution from
the System to AES of approximately $40 million. A permanent financing was
completed on August 26, 1998 that consisted of $112.5 million in 23-year
term notes at a rate of 6.92% with sinking fund payments scheduled to
begin in 2003. The notes are secured by long-term contracts between MATEP
and its customers.
MATEP had revenues of $58 million and net earnings of $7.3 million
for the fiscal year ended June 30, 1997. Results for MATEP are included
in the accompanying Consolidated Condensed Financial Statements from the
date of acquisition.
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COMMONWEALTH ENERGY SYSTEM
The acquisition was accounted for under the purchase method of
accounting. The purchase price was allocated based on the fair value of
assets acquired and resulted in the recognition of an intangible asset
amounting to approximately $31 million that is being amortized on a
straight-line basis over fifteen years.
Based on unaudited data, the following pro forma summary presents the
consolidated results of operations for the three and nine months ended
September 30, 1998 and 1997 as if the acquisition had occurred at the
beginning of the years presented:
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(Dollars in thousands except per share amounts)
Revenues $233,606 $239,386 $736,591 $806,227
Net Income
Applicable to
Common Shares $ 15,836 $ 9,305 $ 40,253 $ 33,835
Basic and Diluted
Earnings per
Common Share $ .74 $ .43 $1.87 $1.57
The pro forma results do not purport to be indicative of the results
of operations that actually would have resulted had the acquisition been
made at the beginning of the years presented, or of results that may occur
in the future.
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COMMONWEALTH ENERGY SYSTEM
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. 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.
Real estate consisting primarily of a ten acre site in Cambridge, MA
was sold for $22.2 million and resulted in a net gain of $10.8 million.
Future plans for the site announced by the developer include a hotel,
research and development facilities, laboratories, office, retail and
entertainment space and housing. This project represents further economic
growth in our service territory.
For the current nine-month period, cash flows from operating
activities amounted to approximately $69.3 million and reflect net income
of $42.7 million (which includes the net gain of $10.8 million from the
aforementioned sale of real estate) and noncash items including
depreciation of $45.5 million and amortization of $9.5 million. The
change in working capital since December 31, 1997, exclusive of cash and
interim financing, amounted to $32 million and had a positive impact on
cash flows from operating activities, reflecting a lower level of accounts
receivable ($28.4 million) and unbilled revenues ($20.6 million) coupled
with a higher level of other current liabilities ($18.1 million) and
accrued taxes ($6.9 million). These factors were offset, in part, by a
decline in accounts payable ($33.1 million) and a higher level of
inventories ($2 million), prepaid taxes ($5.8 million) and other current
assets ($1.7 million).
Construction expenditures for the current nine-month period were
approximately $39.1 million, including an allowance for funds used during
construction (AFUDC) and nuclear fuel. Construction expenditures and the
preferred and common dividend requirements of the System ($26.9 million)
were funded entirely with internally-generated funds.
The system, through its Advanced Energy Systems, Inc. subsidiary
(AES), purchased a total energy plant (MATEP), that was formerly owned and
operated by Harvard University and is located in the Longwood Medical Area
of Boston, and related contracts for $146.3 million on June 1, 1998. This
acquisition was originally financed through a $150 million term loan
agreement. The System, pursuant to a permanent financing plan, has
provided a $40 million equity contribution to AES which was financed with
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COMMONWEALTH ENERGY SYSTEM
a 2-year term note. The permanent financing, completed in August 1998,
consists of $112.5 million in 23-year term notes at a rate of 6.92% with
sinking fund payments scheduled to begin in 2003. The notes are secured
by long-term contracts between MATEP and its customers. It is projected
that this new venture will increase system revenues by approximately $45
million in 1998 and, on average, by approximately $65 million in the years
1999 through 2002.
On May 27, 1998, the System announced that three of its subsidiary
companies (Commonwealth Electric Company, Cambridge Electric Light Company
and Canal Electric Company) selected affiliates of Southern Energy New
England, L.L.C., an affiliate of The Southern Company, to buy
substantially all of their non-nuclear electric generating assets for $462
million, an amount that is six times the book value of $79 million. The
sale was approved by the DTE on October 30, 1998 and by the FERC on
November 12, 1998. The net proceeds from the sale of these assets will be
used to mitigate transition costs.
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 Consolidated Condensed Statements of
Income. This discussion should be read in conjunction with the Notes to
Condensed Financial Statements appearing elsewhere in this report.
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COMMONWEALTH ENERGY SYSTEM
A summary of the period to period changes in the principal items
included in the Consolidated Condensed Statements of Income for the three
and nine months ended September 30, 1998 and 1997 and unit sales for these
periods are shown below:
Three Months Nine Months
Ended September 30, Ended September 30,
1998 and 1997 1998 and 1997
Increase (Decrease)
(Dollars in thousands)
Operating Revenues -
Electric $ 473 0.3 % $(38,385) (7.5)%
Gas 1,438 3.4 (18,385) (7.8)
Steam and other 9,580 379.9 11,022 82.2
11,491 5.2 (45,748) (6.0)
Operating Expenses -
Fuel and purchased power (2,502) (2.6) (38,541) (13.3)
Cost of gas sold (245) (1.0) (12,079) (9.4)
Other operation and maintenance 13,333 22.3 (2,120) (1.1)
Depreciation 2,378 19.7 4,614 11.4
Taxes -
Federal and state income (1,082) (24.0) 542 2.7
Local property and other 537 8.7 (151) (0.7)
12,419 6.1 (47,735) (6.8)
Operating Income (928) (5.5) 1,987 3.3
Other Income 12,554 3,692.4 12,423 630.6
Income Before Interest Charges 11,626 67.5 14,410 23.0
Interest Charges 2,703 26.8 3,929 13.0
Net Income 8,923 124.8 10,481 32.5
Dividends on preferred shares (14) (5.6) (43) (5.7)
Earnings Applicable to Common Shares $ 8,937 129.5 $ 10,524 33.4
Unit Sales
Electric - Megawatthours (MWH)
Retail 64,504 4.9 37,261 1.0
Wholesale (82,983) (8.1) (91,105) (3.1)
(18,479) (0.8) (53,844) (0.8)
Gas - Billions of British Thermal
Units (BBTU)
Firm (425) (14.0) (4,921) (18.2)
Interruptible and other (61) (6.0) 419 12.1
(486) (12.0) (4,502) (14.7)
<PAGE 14>
COMMONWEALTH ENERGY SYSTEM
The following is a summary of electric unit sales and gas throughput
for the periods indicated:
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
Electric Sales - MWH
Residential 517,615 482,030 1,369,746 1,376,795
Commercial 733,428 700,817 1,934,289 1,891,519
Industrial 113,564 117,416 329,091 327,433
Other 5,558 5,398 17,201 17,319
Total retail sales 1,370,165 1,305,661 3,650,327 3,613,066
Wholesale sales 941,029 1,024,012 2,803,404 2,894,509
Total 2,311,194 2,329,673 6,453,731 6,507,575
Gas Sales - BBTU
Residential 1,480 1,466 13,243 15,123
Commercial 818 1,012 6,333 7,776
Industrial 196 393 1,363 2,663
Other 108 156 1,228 1,526
Total firm sales 2,602 3,027 22,167 27,088
Interruptible
and other 959 1,020 3,876 3,457
Total sales 3,561 4,047 26,043 30,545
Transportation 1,075 498 6,474 4,627
Total throughput 4,636 4,545 32,517 35,172
Electric Revenues, Fuel and Purchased Power Costs
Operating revenues from regulated operations for the current quarter
and nine-month period were $8.8 million and $54.5 million lower,
respectively, than the corresponding periods in 1997 due to the 10 percent
rate reduction (further discussed below), decreases in electricity
purchased for resale, fuel and transmission charges ($3.9 million and $38
million, respectively), and a lower level of revenues associated with
demand-side management programs. The decline in these costs reflects a
cost deferral of $2 million for the quarter and $31.3 million for the nine-
month period in conjunction with the Company's restructuring plan as
approved by the DTE. As a result of industry restructuring, the Company
has unbundled its rates, provided customers with a 10 percent rate
reduction as of March 1, 1998 and has afforded customers the opportunity to
purchase generation supply in the competitive market consistent with the
electric industry restructuring legislation further discussed below.
Delivery rates are composed of a customer charge (to collect metering and
billing costs), a distribution charge, a transition charge (to collect
stranded costs), a transmission charge, an energy conservation charge (to
collect costs for demand-side management programs) and a renewable energy
charge. Electricity supply services provided by the Company include
optional standard offer service and default service. Amounts collected
through these various charges will be reconciled to actual expenditures on
an on-going basis. Operating revenues from two non-regulated subsidiaries
increased by $9.3 million and $16.1 million for the current quarter and
nine-month period.
Total unit sales decreased in both the current quarter and nine-
<PAGE 15>
COMMONWEALTH ENERGY SYSTEM
month period despite increases in retail sales as wholesale sales decreased
by 8.1% and 3.1%, respectively.
Gas Revenues and Cost of Gas Sold
Operating revenues from regulated operations decreased by $1.5
million and $29.7 million during the current quarter and nine-month period,
respectively, due primarily to the considerable declines in firm unit
sales. Operating revenues from an unregulated subsidiary increased by $2.9
million and $11.3 million for the current quarter and nine-month period.
Also affecting revenues in both periods was a lower average cost of gas.
The decrease in unit sales to firm customers reflects the impact of
the milder weather conditions experienced during 1998 on all customer
segments. The fluctuation in interruptible and other sales reflects the
competitive market that exists today in the natural gas industry.
Other Operating Expenses
For the current quarter, other operation and maintenance increased
by $13.3 million (22.3%) and reflects costs associated with new business
development ($5.8 million), higher costs relating to the outsourcing of the
information technology, telecommunications and network services function
($3 million) that includes costs associated with Year 2000 compliance,
higher conservation and load management (C&LM) costs ($2.6 million), an
increase in costs associated with non-regulated real estate operations
($1.5 million) and an increase in transmission charges ($1 million). These
increases were partially offset by a decline in insurance and employee
benefits costs ($2.3 million) and labor savings resulting from a personnel
reduction program (PRP) initiated during the second quarter of 1997 ($1
million). For the current nine-month period, other operation and mainten-
ance decreased by $2.1 million (1.1%) reflecting the absence of a one-time
charge ($17.7 million) related to the aforementioned PRP program, labor
savings realized from the PRP ($5.4 million), a reduction in insurance and
employee benefits costs ($3.8 million, the absence of storm damage costs
related to an April 1997 blizzard ($2 million) and a decline in the pro-
vision for bad debts ($1.6 million). These decreases were offset, in part,
by costs associated with new business development ($11.5 million), higher
costs ($9.1 million) associated with information technology and related
services as detailed above, increased C&LM costs ($2.6 million) and higher
costs associated with non-regulated real estate operations ($1.2 million).
Depreciation increased $2.4 million (19.7%) during the current
quarter and $4.6 million (11.4%) in the nine-month period and reflects the
treatment allowed for certain production plant pursuant to the electric
industry restructuring legislation as well as a higher level of depreciable
plant including the newly acquired MATEP facility. Federal and state
income taxes decreased $1.1 million (24%) during the current quarter and
increased $542,000 (2.7%) for the nine-month period reflecting the level of
pretax income related to continuing operations. The tax impact from the
sale of real estate ($6.3 million) was reflected as an offset to the gain
from the sale in Other Income on the Consolidated Condensed Statements of
Income. The increase of $537,000 (8.7%) in local property and other taxes
for the current quarter was due primarily to real estate taxes associated
<PAGE 16>
COMMONWEALTH ENERGY SYSTEM
with MATEP and higher real estate tax rates and assessments offset, in
part, by a decline in payroll taxes attributable to savings realized from
the aforementioned PRP.
Other Income and Interest Charges
During the current quarter and nine-month period, other income
increased by $12.6 million and $12.4 million due to the gain from the
aforementioned sale of real estate ($10.8 million net of taxes).
The increase in total interest charges for the current three and
nine-month periods mainly reflects higher levels of short-term borrowings,
the issuance of two new series of long-term debt in September 1997 and the
issuance of 23-year term notes in August 1998 partially offset by maturing
long-term debt and scheduled sinking fund payments.
Industry Restructuring - Electric
On November 25, 1997, the Governor of Massachusetts signed into law
the Electric Industry Restructuring Act (the Act). This legislation
provided, among other things, that customers of retail electric utility
companies who take standard offer service receive a 10 percent rate
reduction and be allowed to choose their energy supplier, effective March
1, 1998. The Act also provides that utilities be allowed full recovery of
transition costs subject to review and an audit process. The rate
reduction mandated by the legislation increases to 15 percent effective
September 1, 1999 for customers who continue to take standard offer
service. A statewide ballot referendum that sought to repeal the
legislation was defeated by a wide margin on November 3 of this year.
The system filed a comprehensive electric restructuring plan with
the DTE in November 1997, that was substantially approved by the DTE in
February 1998. The divestiture of the system's non-nuclear generation
assets and the entitlements associated with its purchased power contracts
is an integral part of the system's restructuring plan and is consistent
with the Act. While the system is encouraged with the treatment afforded
net non-mitigable transition costs (which, for the system, are primarily
the result of above-market purchased power contracts with non-utility
generators) by the legislation and the DTE, the mandated rate reduction has
had a significant impact on cash flows of the system. However, the
successful results of the generation auction, as discussed below, could
significantly reduce the impact that the rate reductions will have on
future cash flows.
In March 1997, the system had submitted a report to the DTE that
detailed the proposed auction process for selling its electric generation
assets and the entitlements associated with purchased power contracts. The
auction process provided a market-based approach to maximizing stranded
cost mitigation and minimizing the transition costs that retail customers
will have to pay for stranded cost recovery. A request for bids from
interested parties was issued in August 1997 and an Offering Memorandum
followed in October 1997. Potential bidders examined all pertinent
information related to the generating facilities and purchased power
<PAGE 17>
COMMONWEALTH ENERGY SYSTEM
contracts in order to prepare and submit their first round of bids in mid-
December. Final binding bids were submitted in May 1998.
On May 27, 1998, the System announced that three of its subsidiary
companies (Cambridge Electric Light Company, Canal Electric Company and
Commonwealth Electric Company) selected affiliates of Southern Energy New
England, L.L.C. (Southern Energy), an affiliate of The Southern Company of
Atlanta, Georgia, to buy substantially all of their non-nuclear electric
generating assets for approximately $462 million (subject to certain
adjustments at closing). These facilities represent 984 megawatts (mw) of
electric capacity and have an approximate book value of $79 million.
The plants being sold include: Canal Unit 1 (566 mw) and a one-half
interest in Canal Unit 2 (282.5 mw) located in Sandwich, MA and owned by
Canal Electric; the Kendall Station facility (67 mw) and the adjacent
Kendall Jets (46 mw), located in Cambridge, MA and owned by Cambridge
Electric; five diesel generators (13.8 mw) in Oak Bluffs and West Tisbury
on the island of Martha's Vineyard that are owned by Commonwealth Electric,
and a 1.4 percent joint-ownership interest (8.9 mw) in Wyman Unit No. 4
located in Yarmouth, ME, also owned by Commonwealth Electric.
The system continues to evaluate bids related to the purchased power
contracts. The system is also evaluating the disposition of the Blackstone
Station generating unit (15.3 mw) owned by Cambridge Electric and located
in Cambridge, MA which is subject to a right of first offer held by Harvard
University on any divestiture of the facility.
On July 31, 1998, a formal divestiture filing was submitted to the
FERC and the DTE that requested approval of the sale of the system's
generating assets to Southern Energy and further proposes (subject to
completion of the sale) that the current 10 percent rate reduction
increase, effective January 1, 1999, to 12.1 percent for Commonwealth
Electric and to 15.2 percent for Cambridge Electric. In addition, the
companies propose to increase the retail price of standard offer service,
starting January 1, 1999, from the present rate of 2.8 cents per
kilowatthour (kwh) to 3.5 cents. At the same time that the price for
standard offer service is increased, the transition charge for Commonwealth
Electric's customers will decline from 4.08 cents per kwh to 3.13 cents and
for Cambridge Electric's customers from 2.73 cents per kwh to 1.56 cents.
These proposed changes, which are intended to further reduce the cost of
electricity to customers, to make the market increasingly more attractive
for independent power suppliers to sell electricity directly to consumers,
and to reduce the system's cost deferrals associated with the pricing of
standard offer service, are based on a specific allocation methodology for
the net proceeds from the sale of the Canal units.
On October 30, 1998, the DTE approved the system's sale of its
generating assets to Southern Energy. The DTE, however, deferred ruling on
the allocation of proceeds from the sale of Canal Units 1 and 2 between
Cambridge Electric and Commonwealth Electric and on the rate of return to
be paid to customers on the net proceeds from the sale over an eleven-year
period. These issues are not expected to impact the asset sale that is
scheduled to close in the fourth quarter. The FERC approved the sale on
November 12, 1998.
<PAGE 18>
COMMONWEALTH ENERGY SYSTEM
Industry Restructuring - Gas
On July 18, 1997, the DTE directed the ten Massachusetts gas
utilities, including Commonwealth Gas, to initiate a collaborative process
that will establish guiding principles and specific procedures for
unbundling rates and services for all customers.
The DTE listed six principles that it considers important to the
success of a competitive natural gas market that will provide safe and
reliable service at the lowest possible cost to customers. The natural gas
market would: (1) provide the broadest possible choice; (2) provide all
customers with an opportunity to share in the benefits of increased
competition; (3) ensure full and fair competition in the gas supply market;
(4) functionally separate supply from local distribution services; (5)
support and further the goals of environmental regulation; and lastly (6)
rely on incentive regulation where a fully competitive market cannot or
presently does not exist.
In addition, the DTE outlined several specific issues that it
expects the collaborative to address: (1) services that can be offered on a
competitive basis; (2) terms and conditions of service; (3) consumer
protections and social programs; (4) mitigation of gas related and non-gas
related transition costs; (5) third-party supplier qualifications; and (6)
curtailment principles. The DTE also suggested that the collaborative
reconsider the pricing and provision of interruptible transportation
services.
On August 18, 1997, the DTE noted that the development of unbundling
principles and procedures constitutes only a part of the effort necessary
to develop full customer choice for gas service. The DTE recognized that
each local distribution company will be filing a comprehensive unbundling
proposal at some later date. In the interim, the DTE directed those
companies that do not currently have unbundled rates, including Common-
wealth Gas, to have such rates in effect no later than November 1, 1998.
Commonwealth Gas and eight other gas utilities initiated the
Massachusetts Gas Unbundling Collaborative (the Collaborative) on September
15, 1997, to explore and develop generic principles to achieve the goals
set forth by the DTE. Collaborative participants represented a broad array
of stakeholder interests including the utilities, natural gas marketers,
interstate pipelines, producers, energy consultants, labor unions, consumer
advocates and representatives for the DTE, the Massachusetts Attorney
General's Office, and the Massachusetts Division of Energy Resources.
On November 15, 1997, the Collaborative filed a status report with
the DTE that outlined its progress in moving the gas industry to a more
competitive structure that provides all customers with meaningful access to
competitive markets consistent with public-policy objectives. The status
report summarized the substantive issues that had been the subject of
Collaborative discussion, including: (1) the disposition of interstate
pipeline capacity; (2) the unbundling of rates; (3) customer enrollment,
billing, termination, and information exchange procedures; and, (4)
consumer protections, low-income discounts, and competitive supplier
<PAGE 19>
COMMONWEALTH ENERGY SYSTEM
registration. The status report also established a schedule to implement a
final unbundling plan by November 1, 1998.
In accordance with that schedule, the Collaborative submitted to the
DTE a Rate Unbundling Status Report on January 16, 1998. The report
detailed an overall process for developing unbundled rates consistent with
the DTE's rate structure goals of efficiency, fairness, simplicity,
continuity and earnings stability. In response to the Collaborative's
proposal, the DTE ordered Commonwealth Gas to submit, by April 15, 1998, a
consensus-based settlement, or partial settlement, of unbundled rate
tariffs designed according to the general concepts set forth in the report.
Subsequently, the DTE granted Commonwealth Gas an extension to reach a
settlement with the Collaborative's participants.
On March 18, 1998, the Collaborative filed a second status report
that summarized the progress made by the Collaborative since it had last
updated the DTE on its activities. The Collaborative reported that it had
made substantial progress in the areas of rate unbundling and terms and
conditions for unbundled services. The report also described at least two
policy issues, capacity disposition and cost responsibility, on which the
Collaborative's participants require specific regulatory guidance before
completing a comprehensive framework for the transition to a more
competitive market structure.
In response to the March report, the DTE issued a Notice of Inquiry
to address the Collaborative's unresolved issues. On May 1, 1998, Common-
wealth Gas filed initial written comments in the proceeding arguing in
favor of a mandatory capacity assignment proposal. On June 8, 1998, the
DTE, as part of the aforementioned Notice of Inquiry, received final
comments regarding the feasibility of implementing comprehensive unbundling
for all local distribution companies by November 1, 1998. On June 29,
1998, Commonwealth Gas and three other Massachusetts local distribution
companies submitted unbundled rate settlements to the DTE for
consideration.
The DTE issued a procedural order regarding the Notice of Inquiry
on July 2, 1998 which stated that the introduction of comprehensive un-
bundling for all classes of customers for all local distribution companies
is not feasible by November 1, 1998. The DTE stated that unbundled rates
for the four local distribution companies that filed settlements on June
29, 1998 (including Commonwealth Gas) shall be in place by November 1, 1998
and that comprehensive unbundling shall be implemented no later than April
1, 1999. Also, as part of the July 2, 1998 procedural order, the DTE
ordered that a set of proposed Model Terms and Conditions be submitted by
the Collaborative no later than July 15, 1998. These Model Terms and
Conditions were submitted on July 10, 1998 but a decision has not yet been
issued by the DTE.
<PAGE 20>
COMMONWEALTH ENERGY SYSTEM
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. The DTE has approved recovery of costs associated with MGP sites.
Commonwealth Gas is also involved in certain other known or potentially
contaminated sites where the associated costs may not be recoverable in
rates. For further information on other related environmental matters,
refer to the System's 1997 Annual Report on Form 10-K.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133 (SFAS No. 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts possibly including fixed-price fuel supply and power
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying
hedges allows a derivative's gains and losses to offset related results on
the hedged item in the income statement, and requires that a company must
formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15,
1999 and may be implemented as of the beginning of any fiscal quarter after
issuance but cannot be applied retroactively. SFAS No. 133 must be applied
to derivative instruments and certain derivative instruments embedded in
hybrid contracts that were issued, acquired or substantively modified after
December 31, 1997 and, at the company's election, before January 1, 1998.
The system has not yet quantified the impacts of adopting SFAS No.
133 on its financial statements and has not determined the timing of its
method of adopting SFAS No. 133.
In April 1998, the American Institute of Certified Public
Accountants issued Statement of Position 98-5 "Reporting on the Costs of
Start-Up Activities" (SOP 98-5). SOP 98-5 provides guidance on the
financial reporting of start-up and organization costs and requires that
these costs be expensed as incurred. The impact of SOP 98-5 is not
expected to have a material impact on the system's results of operations or
financial condition.
<PAGE 21>
COMMONWEALTH ENERGY SYSTEM
Year 2000
The Year 2000 issue is the result of computer programs being written
using two digits rather than four to define the applicable year. Any
computer program that has date sensitive software may recognize a date
using "00" as the year 1900 rather than the year 2000. This could result
in a temporary inability to process transactions or engage in normal
business activities. The system has been involved in Year 2000 compliancy
since 1996.
The system, on a coordinated basis and with the assistance of RCG
Information Technologies and other consultants, is addressing the Year 2000
issue. The system has inventoried and assessed all date sensitive informa-
tion and transaction processing computer systems and determined that a
substantial portion of its software needed to be modified or replaced.
Plans have been developed and are being implemented to correct and test all
affected systems, with priorities assigned based on the importance of the
activity. The system has identified the software and hardware
installations that will be necessary. All installations are expected to be
completed and tested by mid-1999. The system has also inventoried its non-
information technology systems that may be date sensitive, (facilities,
electric and gas operations, energy supply/production and distribution),
that use embedded technology such as micro-controllers and micro-
processors. The system anticipates that these systems will be updated or
replaced as necessary and tested by mid-1999.
Modifying and testing the system's information and transaction
processing systems from 1996 through 2000 is currently expected to cost $6
to $7 million, including approximately $900,000 incurred through 1997 and
$1.6 million spent during the first nine months of 1998. Approximately
$1.2 million is expected to be spent in the fourth quarter of this year and
the balance of $2.5 to $3 million in 1999 and 2000. Year 2000 costs have
been expensed as incurred and will continue to be funded from operations.
The system has initiated formal communications with its significant
suppliers to determine the extent to which the system may be vulnerable to
their failure to correct their own Year 2000 issues. The system has not
received enough responses to its survey to make an accurate assessment of
the Year 2000 readiness of its suppliers. Failure of the system's
significant suppliers to address Year 2000 issues could have a material
adverse effect on the system's operations, although it is not possible at
this time to quantify the amount of business that might be lost or the
costs that could be incurred by the system.
In addition, parts of the global infrastructure, including national
banking systems, electrical power grids, gas pipelines, transportation
facilities, communications and governmental activities, may not be fully
functional after 1999. Infrastructure failures could significantly reduce
the system's ability to acquire energy and its ability to serve its
customers as effectively as they are now being served. The system is
identifying elements of the infrastructure that are critical to its
operations and is obtaining information as to the expected Year 2000
readiness of these elements.
<PAGE 22>
COMMONWEALTH ENERGY SYSTEM
The system has started its contingency planning for critical
operational areas that might be effected by the Year 2000 issue if
compliance by the system is delayed. System gas and electric operations
currently have emergency operating plans as well as information technology
disaster recovery plans as components of its standard operating procedures.
These plans will be enhanced to identify potential Year 2000 risks to
normal operations and the appropriate reaction to these potential failures
including contingency plans that may be required for any third parties that
fail to achieve Year 2000 compliance. All necessary contingency plans are
expected to be completed by early 1999, although in certain cases,
especially infrastructure failures, there may be no practical alternative
course of action available to the system.
The system is working with other energy industry entities, both
regionally and nationally with respect to Year 2000 readiness and is
cooperating in the development of local and wide-scale contingency
planning.
While the system believes its efforts to address the Year 2000 issue
will be successful in avoiding any material adverse effect on the system's
operations or financial condition, it recognizes that failing to resolve
Year 2000 issues on a timely basis would, in a "most reasonably likely
worst case scenario," significantly limit its ability to acquire and
distribute energy and process its daily business transactions for a period
of time, especially if such failure is coupled with third party or
infrastructure failures. Similarly, the system could be significantly
effected by the failure of one or more significant suppliers, customers or
components of the infrastructure to conduct their respective operations
after 1999. Adverse affects on the system could include, among other
things, business disruption, increased costs, loss of business and other
similar risks.
The foregoing discussion regarding Year 2000 project timing,
effectiveness, implementation and costs includes forward-looking statements
that are based on management's current evaluation using available
information. Factors that might cause material changes include, but are
not limited to, the availability of key Year 2000 personnel, the readiness
of third parties, and the system's ability to respond to unforeseen Year
2000 complications.
Forward-Looking Statements
This discussion contains statements which, to the extent it is not a
recitation of historical fact, constitute "forward-looking statements" and
is intended to be subject to the safe harbor protection provided by the
Private Securities Litigation Reform Act of 1995. A number of important
factors affecting the System's business and financial results could cause
actual results to differ materially from those reflected in the forward-
looking statements or projected amounts. Those factors include
developments in the legislative, regulatory and competitive environment,
certain environmental matters, demands for capital and new business
development expenditures and the availability of cash from various sources.
<PAGE 23>
COMMONWEALTH ENERGY SYSTEM
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The System is subject to legal claims and matters arising from its
course of business including when Cambridge Electric was an intervenor
in an appeal at the Massachusetts Supreme Judicial Court (SJC) filed
by the Massachusetts Institute of Technology (MIT) involving a DTE
decision approving a customer transition charge (CTC) for the recovery
of stranded investment costs. By its terms, the CTC was terminated on
March 1, 1998, coincident with the retail access date established by
the Massachusetts Legislature in the Electric Industry Restructuring
Act. On September 18, 1997, the SJC remanded the CTC matter to the
DTE for further consideration. The SJC stated that, although recovery
of prudent and verifiable stranded costs by utility companies is in
the public interest and consistent with the Public Utility Regulatory
Policies Act, the insufficiencies of the DTE's subsidiary findings
precluded the SJC from undertaking a meaningful review of the DTE's
calculations that formed the basis of the CTC. The DTE is in the
process of determining whether to hear additional evidence in the
remand or to rely on the record and pleadings already filed. On
January 16, 1998 Cambridge Electric submitted to the DTE a customer
exit charge rate tariff and sought a finding that the tariff would
apply to MIT. On July 23, 1998 the DTE issued a ruling which rejected
the form of customer exit charge rate tariff, but opened a new
investigation into whether MIT should be required to pay an exit
charge, and, if so, what the amount of the exit charge should be.
Also, the DTE's investigation includes whether this case should be
joined with the remand proceeding currently before the DTE. This
issue is discussed more fully in the System's 1997 Annual Report on
Form 10-K. At this time, management is unable to predict the ultimate
outcome of this 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
None.
<PAGE 24>
COMMONWEALTH ENERGY SYSTEM
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 3 - Declaration of Trust
Commonwealth Energy System (Registrant)
3.1.1 Filed herewith as Exhibit 1 is the Declaration of Trust of CES
dated December 31, 1926, as amended by vote of the shareholders
and trustees May 7, 1998.
Exhibit 27 - Financial Data Schedule
Filed herewith as Exhibit 2 is the Financial Data Schedule for
the nine months ended September 30, 1998.
(b) Reports on Form 8-K
None.
<PAGE 25>
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 and
Accounting Officer
JAMES D. RAPPOLI
James D. Rappoli,
Financial Vice President
and Treasurer
Date: November 13, 1998