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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 August 1, 1998
Common Shares of Beneficial
Interest, $2 par value 21,533,820 shares
<PAGE 2>
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED BALANCE SHEETS
JUNE 30, 1998 AND DECEMBER 31, 1997
ASSETS
(Dollars in thousands)
June 30, December 31,
1998 1997
(Unaudited)
PROPERTY, PLANT AND EQUIPMENT, at original cost
Electric $1,185,822 $1,173,797
Gas 379,204 373,541
Other 119,573 72,475
1,684,599 1,619,813
Less - Accumulated depreciation and
amortization 608,659 577,962
1,075,940 1,041,851
Add - Construction work in progress
and nuclear fuel in process 11,558 8,057
1,087,498 1,049,908
EQUITY IN CORPORATE JOINT VENTURES
Nuclear electric power companies (2.5%
to 4.5%) 10,959 10,368
Other investments 3,232 3,399
14,191 13,767
CURRENT ASSETS
Cash 2,144 4,299
Accounts receivable 103,664 128,946
Unbilled revenues 8,185 32,029
Inventories, at average cost 30,238 32,644
Prepaid taxes and other 8,534 15,068
152,765 212,986
DEFERRED CHARGES
Regulatory assets 200,996 178,864
Other 60,731 29,525
261,727 208,389
$1,516,181 $1,485,050
See accompanying notes.
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COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED BALANCE SHEETS
JUNE 30, 1998 AND DECEMBER 31, 1997
CAPITALIZATION AND LIABILITIES
(Dollars in thousands)
June 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 112,043 111,912
Retained earnings 284,480 275,795
439,591 430,770
Redeemable preferred shares, less current
sinking fund requirements 11,950 12,200
Long-term debt, including premiums, less current
sinking fund requirements and maturing debt 343,164 364,311
794,705 807,281
CAPITAL LEASE OBLIGATIONS 11,322 12,272
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks 226,625 94,075
Maturing long-term debt 29,000 19,000
255,625 113,075
Other Current Liabilities -
Current sinking fund requirements 8,473 8,473
Accounts payable 75,228 107,157
Accrued taxes 4,109 24,205
Other 80,039 58,922
167,849 198,757
423,474 311,832
DEFERRED CREDITS
Accumulated deferred income taxes 114,066 176,354
Nuclear units' purchased power contracts 64,520 69,659
Unamortized investment tax credits
and other 108,094 107,652
286,680 353,665
COMMITMENTS AND CONTINGENCIES
$1,516,181 $1,485,050
See accompanying notes.
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COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 1998 AND 1997
(Dollars in thousands except per share amounts - unaudited)
Three Months Ended Six Months Ended
1998 1997 1998 1997
OPERATING REVENUES
Electric $139,393 $157,251 $295,197 $334,055
Gas 58,235 60,930 173,374 193,197
Steam and other 6,663 3,763 12,324 10,882
204,291 221,944 480,895 538,134
OPERATING EXPENSES
Fuel and purchased power 69,398 85,786 156,006 192,045
Cost of gas sold 35,526 30,627 90,903 102,737
Other operation and maintenance 66,244 79,593 124,734 140,187
Depreciation 14,377 12,808 30,556 28,320
Taxes -
Federal and state income 912 (1,280) 17,018 15,394
Local property and other 6,288 6,617 15,078 15,776
192,745 214,151 434,295 494,449
OPERATING INCOME 11,546 7,793 46,600 43,685
OTHER INCOME 804 981 1,499 1,630
INCOME BEFORE INTEREST CHARGES 12,350 8,774 48,099 45,315
INTEREST CHARGES
Long-term debt 8,703 8,385 17,220 16,789
Other interest charges 2,678 1,813 4,445 3,618
Allowance for borrowed funds
used during construction (96) (90) (200) (158)
11,285 10,108 21,475 20,249
NET INCOME (LOSS) 1,065 (1,334) 26,624 25,066
Dividends on preferred shares 237 251 474 503
EARNINGS (LOSS) APPLICABLE
TO COMMON SHARES $ 828 $ (1,585) $ 26,150 $ 24,563
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 21,533,820 21,531,784 21,533,141 21,530,144
BASIC AND DILUTED EARNINGS
(LOSS) PER COMMON SHARE $ .03 $(.07) $1.21 $1.14
DIVIDENDS DECLARED PER
COMMON SHARE $.405 $.395 $.405 $.395
See accompanying notes.
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COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 1998 AND 1997
(Dollars in thousands - unaudited)
1998 1997
OPERATING ACTIVITIES
Net income $ 26,624 $ 25,066
Effects of noncash items -
Depreciation and amortization 36,447 35,267
Deferred income taxes and investment
tax credits, net 198 (1,283)
Earnings from corporate joint ventures (852) (870)
Dividends from corporate joint ventures 277 382
Change in working capital, exclusive of cash
and interim financing 27,637 35,763
Transition costs deferral (30,246) -
All other operating items 6,952 (10,978)
Net cash provided by operating activities 67,037 83,347
INVESTING ACTIVITIES
Purchase of total energy plant
and related contracts (146,270) -
Additions to property, plant and equipment
(inclusive of AFUDC) -
Electric (15,462) (12,938)
Gas (7,428) (6,790)
Other (3,246) (921)
Net cash used for investing activities (172,406) (20,649)
FINANCING ACTIVITIES
Payment of dividends (17,939) (17,537)
Proceeds from (payment of) short-term borrowings 132,550 (26,650)
Long-term debt issue refunded (10,000) (14,260)
Sinking funds payments (1,397) (1,398)
Net cash provided by (used for)
financing activities 103,214 (59,845)
Net increase (decrease) in cash (2,155) 2,853
Cash at beginning of period 4,299 1,495
Cash at end of period $ 2,144 $ 4,348
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of capitalized amounts) $ 19,544 $ 19,550
Income taxes $ 22,130 $ 16,933
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. One of these collec-
tive bargaining units, representing approximately 5% of regular employees,
recently reached an agreement on a new five-year contract that remains in
effect until April 30, 2003. Upon expiration of another contract
(representing approximately 5% of regular employees) scheduled to expire
on September 1, 1998, a new agreement, which has already been ratified,
will become effective through March 1, 2001. A third agreement
(representing 2% of regular employees) is scheduled to expire in September
1998.
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 June 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
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COMMONWEALTH ENERGY SYSTEM
prior period amounts are reclassified from time to time to conform with
the presentation used in the current period's financial statements.
The results for interim periods are not necessarily indicative of
results for the entire year because of seasonal variations in the
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:
June 30, December 31,
1998 1997
(Dollars in thousands)
Maine Yankee unrecovered plant and
decommissioning costs $ 32,595 $ 34,908
Transition costs 30,554 -
Fuel charge stabilization 27,885 29,655
Connecticut Yankee unrecovered plant and
decommissioning costs 26,839 28,566
Postretirement benefits costs 24,867 25,475
Power contract buy-out 16,515 17,609
Deferred income taxes 13,171 13,089
FERC Order 636 transition costs 6,652 7,336
Environmental costs 5,548 3,930
Yankee Atomic unrecovered plant and
decommissioning costs 5,086 6,184
Seabrook related costs 3,670 4,324
Other 7,614 7,788
$200,996 $178,864
The regulatory liabilities, reflected in deferred credits in the
accompanying Consolidated Condensed Balance Sheets and related primarily
to deferred income taxes, were $13.5 million and $14.1 million at June 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.
The cost of transitioning to competition will be mitigated, in part,
by the sale of the system's non-nuclear generating assets. The sale is
expected to be completed by year-end 1998 pending receipt of the necessary
regulatory approvals. The net proceeds from the sale of these assets will
be used to mitigate transition costs.
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COMMONWEALTH ENERGY SYSTEM
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 or in the current legislation
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 long-term financing
agreement for approximately $110 million is expected to be finalized in
the third quarter of 1998.
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.
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.
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COMMONWEALTH ENERGY SYSTEM
Based on unaudited data, the following pro forma summary presents the
consolidated results of operations for the three and six months ended June
30, 1998 and 1997 as if the acquisition had occurred at the beginning of
the years presented:
Three Months Ended Six Months Ended
June 30, June 30,
1998 1997 1998 1997
(Dollars in thousands except per share amounts)
Revenues $212,581 $235,506 $502,985 $566,841
Net Income (Loss)
Applicable to
Common Shares $ (521) $ (1,941) $ 24,335 $ 24,483
Basic and Diluted Earnings
(Loss) per Common Share $(.02) $(.09) $1.13 $1.14
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.
For the first six months of 1998, cash flows from operating
activities amounted to approximately $67 million and reflect net income of
$26.6 million and noncash items including depreciation of $30.6 million
and amortization of $5.8 million. The change in working capital since
December 31, 1998, exclusive of cash and interim financing, amounted to
$27.6 million and had a positive impact on cash flows from operating
activities, reflecting a lower level of accounts receivable ($25.3
million), unbilled revenues ($23.8 million), prepaid taxes ($9.3 million)
and inventory ($2.9 million) coupled with a higher level of other current
liabilities ($21.1 million). These factors were offset, in part, by a
lower level of accrued taxes ($20.1 million), a decline in accounts
payable ($31.9 million) and a higher level of other current assets ($2.8
million).
Construction expenditures for the first half of 1998 were
approximately $25.1 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 ($17.9 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 financed, on a short-term basis, through a $150 million
term loan agreement that will be repaid with the proceeds from a permanent
financing plan that is expected to be completed during the third quarter.
The System, pursuant to the permanent financing plan, has provided a $40
million equity contribution to AES with a portion of the proceeds from the
aforementioned term loan agreement. The permanent financing plan will
also include a $110 million long-term bank loan to AES. 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.
<PAGE 12>
COMMONWEALTH ENERGY SYSTEM
On May 28, 1998, the System announced that three of its subsidiary
companies (Commonwealth Electric Company, Cambridge Electric Light Company
and Canal Electric Company) have 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 is expected to be completed by year-end 1998 pending receipt of the
necessary regulatory approvals. 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 six months ended June 30, 1998 and 1997 and unit sales for these
periods are shown below:
Three Months Six Months
Ended June 30, Ended June 30,
1998 and 1997 1998 and 1997
Increase (Decrease)
(Dollars in thousands)
Operating Revenues -
Electric $(17,858) (11.4)% $(38,858) (11.6)%
Gas (2,695) (4.4) (19,823) (10.3)
Steam and other 2,900 77.1 1,442 13.3
(17,653) (8.0) (57,239) (10.6)
Operating Expenses -
Fuel and purchased power (16,388) (19.1) (36,039) (18.8)
Cost of gas sold 4,899 16.0 (11,834) (11.5)
Other operation and maintenance (13,349) (16.8) (15,453) (11.0)
Depreciation 1,569 12.3 2,236 7.9
Taxes -
Federal and state income 2,192 171.3 1,624 10.5
Local property and other (329) (5.0) (688) (4.4)
(21,406) (10.0) (60,154) (12.2)
Operating Income 3,753 48.2 2,915 6.7
Other Income (177) (18.0) (131) (8.0)
Income Before Interest Charges 3,576 40.8 2,784 6.1
Interest Charges 1,177 11.6 1,226 6.1
Net Income 2,399 179.8 1,558 6.2
Dividends on preferred shares (14) (5.6) (29) (5.8)
Earnings Applicable to Common Shares $ 2,413 152.2 $ 1,587 6.5
Unit Sales
Electric - Megawatthours (MWH)
Retail (34,214) (3.0) (27,243) (1.2)
Wholesale 24,885 3.6 (8,122) (0.4)
(9,329) (0.5) (35,365) (0.8)
Gas - Billions of British Thermal
Units (BBTU)
Firm (1,697) (24.9) (4,496) (18.7)
Interruptible and other 168 14.2 480 19.7
(1,529) (19.1) (4,016) (15.2)
<PAGE 14>
COMMONWEALTH ENERGY SYSTEM
The following is a summary of electric unit sales and gas throughput
for the periods indicated:
Three Months Ended Six Months Ended
June 30, June 30,
1998 1997 1998 1997
Electric Sales - MWH
Residential 379,912 420,714 852,131 894,765
Commercial 604,001 601,114 1,200,861 1,190,702
Industrial 114,247 110,245 215,527 210,017
Other 4,955 5,256 11,643 11,921
Total retail sales 1,103,115 1,137,329 2,280,162 2,307,405
Wholesale sales 722,048 697,163 1,862,375 1,870,497
Total 1,825,163 1,834,492 4,142,537 4,177,902
Gas Sales - BBTU
Residential 2,995 3,775 11,763 13,657
Commercial 1,463 1,914 5,515 6,764
Industrial 352 697 1,167 2,270
Other 297 418 1,120 1,370
Total firm sales 5,107 6,804 19,565 24,061
Interruptible
and other 1,354 1,186 2,917 2,437
Total sales 6,461 7,990 22,482 26,498
Transportation 3,032 2,935 5,399 4,129
Total throughput 9,943 10,925 27,881 30,627
Electric Revenues, Fuel and Purchased Power Costs
Electric operating revenues decreased $17.9 million (11.4%) and
$38.9 million (11.6%) during the current quarter and first half of 1998,
respectively, due mainly to lower fuel and purchased power costs ($16.4
million and $36 million, respectively).
Fuel and purchased power costs decreased approximately $16.4 million
(19.1%) and $36 million (18.8%) and reflects a deferral of costs ($15.3
million and $30.2 million )in conjunction with the system's electric
restructuring plan as approved by the DTE. Also contributing to the
declines in revenue in both current periods were lower fuel costs and a
decrease in retail unit sales. As a result of industry restructuring, the
system's retail electric companies have unbundled rates, provided customers
with a ten percent rate reduction as of March 1, 1998 and have 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 system's retail subsidiaries 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.
<PAGE 15>
COMMONWEALTH ENERGY SYSTEM
Gas Revenues and Cost of Gas Sold
Gas operating revenues decreased by $2.7 million and $19.8 million
during the current quarter and six-month period, respectively, due
primarily to the considerable declines in firm unit sales. 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 the first half of 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 and first half of 1998, other operation and
maintenance decreased $13.3 million (16.8%) and $15.5 million (11%),
respectively, reflecting the absence of a one-time charge ($17.7 million)
related to the personnel reduction program (PRP) initiated in the second
quarter of 1997. Also contributing to the decrease in the current quarter
and six-month period were labor savings realized from the aforementioned
PRP ($1.3 million and $4.4 million, respectively), the absence of storm
damage costs related to an April 1997 blizzard ($2 million), a reduction in
the provision for bad debts ($1.5 million in both current periods), and a
reduction in insurance and employee benefits costs ($1.3 million and $1.6
million, respectively). The impact of these factors was offset somewhat by
higher costs relating to the outsourcing of the information technology,
telecommunications and network services function ($2.7 million and $6.1
million, respectively) that includes costs associated with Year 2000
compliance, and costs associated with new business development ($3.4
million and $5.6 million, respectively).
Depreciation increased $1.6 million (12.3%) and $2.2 million (7.9%)
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. Federal and state income taxes increased $2.2
million (171.3%) and $1.6 million (10.5%) and reflect the higher level of
pretax income. The decreases of $329,000 (5%) for the quarter and $688,000
(4.4%) for the six-month period in local property and other taxes was due
primarily to a decline in payroll taxes attributable to savings realized
from the aforementioned PRP.
Other Income and Interest Charges
During the current quarter and first half of 1998, other income
declined $177,000 and $131,000 as compared to the same periods in 1997
primarily due to a lower rate of return from steam production and lower
equity earnings related to a non-utility investment.
The increases in total interest charges for the current three and
six-month periods mainly reflect higher levels of short-term borrowings at
slightly higher interest rates and the issuance of two new series of long-
term debt in September 1997 partially offset by maturing long-term debt and
scheduled sinking fund payments.
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COMMONWEALTH ENERGY SYSTEM
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.
It is likely that a statewide referendum will appear on the ballot
in November of this year that is seeking to repeal the legislation.
Management is unable to predict what the ultimate outcome of this challenge
will be.
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 last August and an Offering Memorandum
followed in October. Potential bidders examined all pertinent information
related to the generating facilities and purchased power contracts in order
to prepare and submit their first round of bids in mid-December. Final
binding bids were submitted on May 8, 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) had selected affiliates of Southern Energy
New England, L.L.C., 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
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COMMONWEALTH ENERGY SYSTEM
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. Also, the system is 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 requests approval of the sale of the system's
generating assets 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 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. The
required approvals of the sale and rate structures are expected to be
received by year-end 1998.
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
<PAGE 18>
COMMONWEALTH ENERGY SYSTEM
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
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
<PAGE 19>
COMMONWEALTH ENERGY SYSTEM
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 and a decision will be issued by
the DTE no later than September 30, 1998. The DTE intends to issue an
order on capacity assignment and cost responsibility by October 30, 1998.
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
<PAGE 20>
COMMONWEALTH ENERGY SYSTEM
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.
Year 2000
The system has been involved in Year 2000 compliancy since 1996. A
complete inventory and review of software, information processing, delivery
systems and operational components for certain facilities has been
completed, and work continues on computer systems wherever necessary.
While some computer systems have already been updated, tested and placed in
production, the system expects to complete the balance of the modifications
by mid-1999.
Costs associated with Year 2000 compliancy are being expensed as
incurred. The total cost of this project is expected to be funded with
internally generated funds.
Management believes that, with appropriate modifications, the system
will be fully compliant regarding all Year 2000 issues and will continue to
provide its products and services uninterrupted through the millennium
change. Failure to become fully compliant could have a significant impact
on the system's operations.
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 21>
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 22>
COMMONWEALTH ENERGY SYSTEM
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit 27 - Financial Data Schedule
Filed herewith as Exhibit 1 is the Financial Data Schedule for
the three months ended June 30, 1998.
(b) Reports on Form 8-K
Two reports on Form 8-K were filed during the three months ended
June 30, 1998. One report was filed June 5, 1998 for an event
first reported May 27, 1998 regarding the sale of the system's
non-nuclear generation assets. A second report was filed on
June 12, 1998 relating to the acquisition of a total energy
plant on June 1, 1998.
<PAGE 23>
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: August 14, 1998