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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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 2-1647
COMMONWEALTH GAS COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1989250
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
One Main Street, Cambridge, Massachusetts 02142-9150
(Address of principal executive offices) (Zip Code)
(617) 225-4000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
None None
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
None
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 March 16, 1999
Common Stock, $25 par value 2,857,000 shares
The Company meets the conditions set forth in General Instruction I(1)(a) and
(b) of Form 10-K as a wholly-owned subsidiary and is therefore filing this
Form with the reduced disclosure format.
Documents Incorporated by Reference Part in Form 10-K
None Not Applicable
List of Exhibits begins on page 37 of this report.
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COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1998
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business........................................ 3
General....................................... 3
Gas Supply
General..................................... 4
Hopkinton LNG Facility...................... 4
Rates and Regulation.......................... 5
Competition................................... 8
Construction and Financing.................... 8
Employees..................................... 8
Item 2. Properties...................................... 8
Item 3. Legal Proceedings............................... 9
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters..................... 10
Item 7. Management's Discussion and Analysis of
Results of Operations........................... 11
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk..................................... 18
Item 8. Financial Statements and Supplementary Data..... 18
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure............. 18
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................. 37
Signatures.................................................. 41
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COMMONWEALTH GAS COMPANY
PART I.
Item 1. Business
General
Commonwealth Gas Company (the Company) is engaged in the distribution
and sale of natural gas at retail to approximately 240,000 customers in a
1,067 square mile area which includes 51 communities in eastern, southeastern
and central Massachusetts. The approximate year-round population of this
service area is 1,128,000.
The Company, which was organized in 1851 under the laws of the Common-
wealth of Massachusetts, operates under the jurisdiction of the Massachusetts
Department of Telecommunication and Energy (DTE) that regulates retail rates,
accounting, issuance of securities and other matters. Since the date of its
organization the Company has, from time to time, acquired the property and
franchises of, or merged with, other gas companies. The Company is a wholly-
owned subsidiary of Commonwealth Energy System (the Parent), which, together
with its subsidiaries, is collectively referred to as "COM/Energy."
The Company is the only gas distribution utility in its service area
and, by virtue of its existing franchises, no other gas distribution utility
may extend its operations into the Company's service area without the authori-
zation of the DTE. Alternative sources of energy are available to customers
within the service territory, but competition from these sources has not been
a significant factor affecting the Company's firm gas sales to existing
customers. Even with the higher cost of storage and liquefied natural gas
(LNG), which is required to supplement pipeline supply, the overall long-term
cost of gas has been competitive with the cost of alternative fuel sources for
most of the Company's customers.
Of the Company's 1998 firm gas unit sales, 61% was sold to residential
customers, 28% to commercial customers, 5.8% to industrial customers and 5.2%
to other customers. Capital expenditures are required to bring gas into areas
of anticipated growth and both the distribution capability and gas supply must
be available when new development begins or potential customers will seek
alternative sources of fuel. Certain industrial customers with dual-fuel
capability can convert from gas to alternative fuels under terms of contracts
which permit interruption of their service upon short notice or at contractu-
ally scheduled times.
In December 1998, the Parent signed an agreement and Plan of Merger with
BEC Energy, the parent company of Boston Edison Company, that will create an
energy delivery company serving approximately 1.3 million customers located
entirely within Massachusetts including more than one million electric
customers in 81 communities and the Company's 240,000 customers. The merger
is expected to occur shortly after the satisfaction of certain conditions,
including receipt of certain regulatory approvals. The regulatory approval
process is expected to be completed during the second half of 1999.
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COMMONWEALTH GAS COMPANY
Gas Supply
(a) General
The Company purchases transportation, storage and balancing services
from Tennessee Gas Pipeline Company (Tennessee) and Algonquin Gas Transmission
Company (and other upstream pipelines that bring gas from the supply wells to
the final transporting pipelines) and purchases all of its gas supplies from
third-party vendors, utilizing firm contracts with terms of less than one
year. The vendors vary from small independent marketers to major gas and oil
companies.
In addition to firm transportation and gas supplies mentioned above, the
Company utilizes contracts for underground storage and LNG facilities to meet
its winter peaking demands. The underground storage contracts are a combina-
tion of existing and new agreements which are the result of Federal Energy
Regulatory Commission (FERC) Order 636 service unbundling. The LNG facili-
ties, described below, are used to liquefy and store pipeline gas during the
warmer months for use during the heating season.
The Company entered into a multi-party agreement in 1992 to assume a
portion of Boston Gas Company's contracts to purchase Canadian gas supplies
from Alberta Northeast (ANE) and have the volumes delivered by the Iroquois
Gas Transmission System and Tennessee pipelines. The ANE gas supply contract
was filed with the DTE and hearings were completed in April 1993. The DTE
approved the ANE gas supply contract in November 1995. The Company is
presently in negotiations with the parties to allow for final execution of all
pertinent agreements and contracts.
The Company began transporting gas on its distribution system in 1990
for end-users. As of December 31, 1998, there were 593 customers using this
transportation service, accounting for 11,146 BBTU or approximately 24% of
total throughput.
(b) Hopkinton LNG Facility
A portion of the Company's gas supply during the heating season is
provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of the
Parent. The facility consists of a liquefaction and vaporization plant and
three above-ground cryogenic storage tanks having an aggregate capacity of
3 million MCF of natural gas.
In addition, Hopkinton owns a satellite vaporization plant and two
above-ground cryogenic storage tanks located in Acushnet, Massachusetts with
an aggregate capacity of 500,000 MCF of natural gas that are filled with LNG
trucked from Hopkinton.
The Company has contracts for LNG service with Hopkinton extending on a
year to year basis with notice of termination required five years in advance
of the anticipated termination date. The Company and Hopkinton are currently
evaluating the contracts to determine if amendments to the contracts should be
negotiated in light of the ongoing deregulation of the natural gas industry.
Current contract payments include a demand charge sufficient to cover Hopkin-
ton's fixed charges and an operating charge which covers liquefaction
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COMMONWEALTH GAS COMPANY
and vaporization expenses. The Company furnishes pipeline gas during the
period April 15 to November 15 each year for liquefaction and storage. As the
need arises, LNG is vaporized and placed in the distribution system of the
Company.
Based upon information presently available regarding projected growth in
demand and estimates of availability of future supplies of pipeline gas, the
Company believes that its present sources of gas supply are adequate to meet
existing load and allow for future growth in sales.
Rates and Regulation
(a) Gas Industry Restructuring
The Company 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 pipe-
lines, 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 March 18, 1998, the Collaborative filed a report to the DTE that
summarized its progress. The Collaborative reported that it had made substan-
tial 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 compre-
hensive framework for the transition to a more competitive market structure.
In response to this report, the DTE issued a Notice of Inquiry (NOI) to
address the Collaborative's unresolved issues. On May 1, 1998, the Company
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 NOI, received final comments regarding the feasibility of
implementing comprehensive unbundling for all local distribution companies
(LDCs) by November 1, 1998. On June 29, 1998, the Company and three other
Massachusetts LDCs submitted unbundled rate settlements to the DTE for
consideration.
The DTE issued a procedural order regarding the NOI on July 2, 1998
which stated that the introduction of comprehensive unbundling for all classes
of customers for all LDCs is not feasible by November 1, 1998. The DTE stated
that unbundled rates for the four LDCs that filed settlements on June 29, 1998
(including the Company) shall be in place by November 1, 1998 and that compre-
hensive 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. A partial set of Model Terms and Conditions were submit-
ted on July 10, 1998 that excluded provisions for capacity assignment as well
as those related sections of the terms and conditions that required further
development by the Collaborative once the issues being addressed in the NOI
were resolved by the DTE.
On August 15, 1998, the DTE approved the unbundled rate settlement
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COMMONWEALTH GAS COMPANY
submitted by the Company. The Company submitted compliance rates consistent
with the settlement agreement on September 11, 1998, and unbundled rates
became effective on November 1, 1998 as further discussed below.
On November 30, 1998, the DTE issued an order approving the partial set
of Model Terms and Conditions that were submitted by the Collaborative on July
10, 1998. In response to that order, however, the ten gas companies partici-
pating in the Collaborative informed the DTE that an April 1, 1999 implementa-
tion date for comprehensive gas unbundling was no longer feasible due to the
significant time required by the Collaborative to complete the Model Terms and
Conditions once the unresolved issues in the aforementioned NOI were answered
by the DTE, as well as the additional time required by the gas companies to
develop the systems necessary to implement unbundling consistent with these
provisions.
On February 1, 1999, the DTE issued an order in the NOI with regard to
capacity assignment and cost responsibility. The DTE found in favor of
mandatory capacity assignment, where gas marketers would be required to accept
the full cost and contractual obligations of the capacity that the gas
companies had historically procured to serve their common customers. In
support of its decision, the DTE determined that the capacity market in
Massachusetts was not yet workably competitive to allow it to remove tradi-
tional regulatory controls that were designed to ensure the reliability of gas
service to customers. The DTE further reaffirmed that the LDCs must continue
with their obligation to plan for and procure sufficient upstream capacity.
Finally, the DTE found that alternative approaches to mandatory capacity
assignment would result in transition costs that would conflict with the
well-established policy on cost allocation.
On February 17, 1999, the Collaborative reconvened to continue its work
in completing the Model Terms and Conditions consistent with the DTE's order
on capacity assignment with a goal to begin the implementation of comprehen-
sive unbundling for all LDCs beginning in 1999.
(b) Unbundled Rates
New unbundled rates for the Company went into effect on November 1,
1998. The unbundled rates were developed in accordance with the settlement
agreement reached by participants in the Collaborative that was filed with the
DTE on June 29, 1998 and approved on August 15, 1998. The new unbundled rates
reflect the separation of the Company's gas supply function from its local
distribution function.
Commencing with the billing month of November 1998, the Company has a
Seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution
Adjustment Clause (LDAC) that provide for the recovery, from firm customers or
default service customers, of certain costs previously recovered through base
rates. The CGAC provides for rates that must be approved semi-annually by the
DTE. The LDAC provides for rates that require annual approval.
As part of its new unbundled rates, the Company modified its existing
CGAC to allow for the following changes: (a) the addition of provisions that
allow for the recovery of certain bad-debt expenses; (b) new formulas that no
longer adjust the Gas Adjustment Factors for the seasonal embedded gas costs
that were in existing sales rates; (c) updated language reflecting the
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COMMONWEALTH GAS COMPANY
ratemaking requirements for non-core revenue margins; and (d) the removal of
provisions for the recovery of environmental remediation costs and FERC Order
636 transition costs, which will instead be recovered through the LDAC.
The Company's new LDAC recovers conservation charges, environmental
remediation costs, balancing penalty revenue credits, and costs associated
with the its participation in the Collaborative.
(c) Regulatory Matters
In May 1994, the Company requested the DTE to change the back-up service
charges under its firm transportation rate. Back-up charges result when the
Company sells gas from its system supplies to a customer whose off-system gas
supply has failed or is temporarily unavailable for reasons beyond the
customer's control. The change involved an upward indexing of back-up charges
based on changes in the gas supply demand costs occasioned by FERC Order 636.
On December 22, 1994, the DTE approved the Company's requested change effec-
tive January 1, 1995. This change, which has no effect on revenue, results in
a more equitable recovery of pipeline capacity costs between Commonwealth Gas'
total requirements and transportation customers.
(d) Off-system Gas Sales and Capacity Release Services
The Company utilizes the off-system sales and capacity release markets
as a means to sell excess resources. Off-system sales totaled 3,255 BBTU in
1998, while 25,796 BBTU of capacity was sold in the capacity release market.
A margin-sharing agreement for these sales was approved by the DTE on February
14, 1996 allowing the Company to retain 25% of the gross margins realized
above a certain threshold amount as set from year to year with the remaining
margins credited to firm customers through the CGAC. As a result of this
margin-sharing agreement, the Company retained approximately $118,000 in 1998.
(e) Conservation and Load Management Program
In 1998, the Company's gas conservation programs transitioned from a
comprehensive, traditional array of programs offered in all customer sectors
and funded via a stand-alone Conservation Charge mechanism to a market
transformation-oriented program funded via the Company's new LDAC. Where once
all conservation activities were implemented company-by-company, now such
programs as residential and commercial/industrial equipment rebates are being
pursued collaboratively with other gas utilities in the state. An additional
feature of the new gas conservation strategy is to minimize commercial/indus-
trial programs and customer conservation surcharges. The conservation budget
has remained fairly stable at $5.4 million, including $2.9 million in program
expenses and $2.5 million in lost margins and incentives.
Competition
The Company faces competition from suppliers of fuel oil, propane and
electricity and also, for large commercial and industrial customers, from
other suppliers of natural gas. The Company is continuously developing and
implementing strategies to deal with the increasingly competitive environment.
FERC Order 636 marked the beginning of the deregulation and restructur-
ing of the natural gas industry. In addition to opening up customer
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COMMONWEALTH GAS COMPANY
markets to competition, the regulations shifted many supply-related responsi-
bilities to LDCs including direct gas purchases from suppliers, pipelines and
producers, transportation services and storage services. The Company has
developed a gas control and information system that has purchasing and
tracking systems. This ability, coupled with aggressive planning and procure-
ment strategies, will secure the Company's existing market share and permit
the expansion of core and non-core supply capabilities.
The Company's substantial LNG and storage capabilities provide it with
the reliability needed during the coldest winter days and the flexibility to
sell capacity when supply and pricing conditions are favorable. Through
expanding non-firm and transportation sales, the Company has been able to
maximize the use of its gas supply and transportation system resulting in a
lower cost of gas for firm customers helping the Company to remain competitive
in its traditional markets.
On February 6, 1997, due to the dramatically changing nature of the
electric and gas industries, COM/Energy announced the consolidation of
management personnel of affiliated companies Cambridge Electric Light Company
(Cambridge Electric), Commonwealth Electric Company (Commonwealth Electric),
COM/Energy Services Company and the Company effective on that date. The
Company and these affiliates continue to operate under their existing company
names. The consolidation process for these companies involved the merging of
similar functions and activities to eliminate duplication in order to create
the most efficient and cost-effective operation possible. As part of this
consolidation effort, the Company initiated a voluntary Personnel Reduction
Program that ultimately resulted in a decrease of 100 regular employees
(approximately 15%) in 1997.
Construction and Financing
Information concerning the Company's financing and construction programs
is contained in Note 6(a) of the Notes to Financial Statements filed under
Item 8 of this report.
Employees
The Company has 604 regular employees including 408 (68%) who are repre-
sented by three collective bargaining units covered by separate contracts with
expiration dates ranging from March 2002 through April 2003. Although a labor
dispute with one collective bargaining unit occurred during 1996, employee
relations have generally been satisfactory since the dispute was resolved in
September 1996.
Item 2. Properties
The Company's principal gas properties consist of distribution mains,
services and meters necessary to maintain reliable service to customers. At
December 31, 1998, the gas system included 2,826 miles of gas distribution
lines, 168,188 services and 247,560 customer meters together with the neces-
sary measuring and regulating equipment.
In addition, the Company owns a central headquarters and service
building in Southborough, Massachusetts, five district office buildings and
various natural gas receiving and take stations.
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COMMONWEALTH GAS COMPANY
The Company's property is subject to encumbrances under its Indenture of
Trust and First Mortgage Bonds.
Item 3. Legal Proceedings
The Company is not a party to any pending material legal proceeding.
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COMMONWEALTH GAS COMPANY
PART II.
Item 5. Market for the Registrant's Common Stock and Related Stockholder
Matters
(a) Principal Market
Not applicable. The Company is a wholly-owned subsidiary of
Commonwealth Energy System.
(b) Number of Shareholders at December 31, 1998
One
(c) Frequency and Amount of Dividends Declared in 1998 and 1997
1998 1997
Per Share Per Share
Declaration Date Amount Declaration Date Amount
May 11, 1998 $3.75 April 25, 1997 $2.00
July 30, 1998 .50 December 22, 1997 1.30
$4.25 $3.30
(d) Future dividends may vary depending upon the Company's earnings
and capital requirements as well as financial and other conditions
existing at that time.
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COMMONWEALTH GAS COMPANY
Item 7. Management's Discussion and Analysis of Results of Operations
The following is a discussion of certain significant factors which have
affected operating revenues, expenses and net income during the periods
included in the accompanying Statements of Income and is presented to facili-
tate an understanding of the results of operations. This discussion should be
read in conjunction with the Notes to Financial Statements filed under Item 8
of this report.
A summary of the period to period changes in the principal items
included in the accompanying Statements of Income for the years ended December
31, 1998 and 1997 and unit sales for these periods is shown below:
Years Ended Years Ended
December 31, December 31,
1998 and 1997 1997 and 1996
Increase (Decrease)
(Dollars in thousands)
Gas Operating Revenues $(42,052) (12.7)% $(11,353) (3.3)%
Operating Expenses -
Cost of gas sold (33,661) (17.6) (6,452) (3.3)
Other operation
and maintenance (4,493) (5.3) (4,468) (5.0)
Depreciation 497 4.7 421 4.2
Taxes -
Federal and state income (1,671) (17.3) (629) (6.1)
Local property (153) (2.4) 372 6.3
Payroll and other (320) (9.9) 840 35.2
(39,801) (13.0) (9,916) (3.1)
Operating Income (2,251) (8.9) (1,437) (5.4)
Other Income 566 83.4 (256) (27.4)
Income Before Interest Charges (1,685) (6.5) (1,693) (6.1)
Interest Charges 490 4.7 (347) (3.2)
Net Income $(2,175) (14.1) $(1,346) (8.0)
Unit Sales (BBTU)
Firm (6,711) (17.3)% (2,279) (5.6)%
Off-system, interruptible
and other 1,481 32.2 (766) (14.3)
(5,230) (12.1) (3,045) (6.6)
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COMMONWEALTH GAS COMPANY
The following is a summary of unit sales, transportation volume and
customers for the periods indicated:
Years Ended December 31,
1998 1997 1996
Unit Sales (BBTU):
Residential 19,514 22,043 22,759
Commercial 8,965 11,077 11,558
Industrial 1,843 3,483 4,468
Other 1,681 2,111 2,208
Total firm 32,003 38,714 40,993
Off-system 4,429 2,673 2,420
Interruptible and other 1,658 1,933 2,952
Total sales 38,090 43,320 46,365
Transportation 11,326 8,478 6,192
Total 49,416 51,798 52,557
Customers at End of Period:
Residential 216,951 215,757 213,474
Commercial 19,668 19,292 18,907
Industrial 910 934 930
Other 1,357 1,181 1,169
Total 238,886 237,164 234,480
Operating Revenues, Cost of Gas Sold and Unit Sales
Operating revenues decreased by $42.1 million (12.7%) in 1998 due to
the considerable decline in firm unit sales (17.3%) and a lower average cost
of gas partially offset by higher transportation revenues ($3.7 million).
During 1997, operating revenues decreased by $11.4 million or 3.3% due to a
6.6% decline in total unit sales, lower conservation and load management costs
($1.8 million) and to a lesser extent, lower gas costs.
The cost of gas sold in 1998 and 1997 reflects changes in gas prices,
sales levels, margin-sharing agreements on non-firm sales and refunds received
from gas suppliers.
The decline in firm unit sales for 1998 reflects decreases to all
customer segments including residential (11.5%), commercial (19.1%) and
industrial (47.1%) that were due primarily to milder weather experienced in
this region as compared to 1997. Degree days for 1998 totaled 5,754, 11%
lower than last year and 12.1% below the normal level of 6,541. The signifi-
cant fluctuations in non-firm sales for 1998 and 1997 continue to reflect the
competitive environment that currently exists in the natural gas industry.
Interruptible sales have no impact on net income since all of the margins from
these sales are flowed back to firm customers through the CGAC.
The number of customers increased slightly in 1998 and 1997 due mainly
to new residential and commercial construction activity, reflecting an
improving economic environment.
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COMMONWEALTH GAS COMPANY
Other Operating Expenses
Other operation and maintenance decreased by $4.5 million (5.3%) in
1998 due to the absence of a one-time charge ($6.8 million) related to a
voluntary personnel reduction program (PRP) implemented during the second
quarter of 1997, labor savings from the PRP and a decrease in the provision
for bad debts ($814,000) offset, in part, by higher costs related to the
outsourcing of the information technology, telecommunications and network
services function ($6.4 million) that includes costs associated with Year 2000
compliance and higher insurance and employee benefits costs ($1.4 million).
During 1997, other operation and maintenance decreased by $4.5 million
or 5% due to the absence of net costs associated with a 1996 labor dispute
($4.6 million), lower labor costs resulting from a decrease in the number of
employees through attrition and the PRP ($5.7 million), reduced maintenance
costs relating to distribution ($2.2 million) and lower C&LM costs ($1.8
million). These decreases were partially offset by a one-time charge ($6.8
million) related to the PRP initiated during the second quarter and higher
postretirement benefit costs ($2 million) reflecting the full recognition of
expense and amortization of previously deferred costs associated with postre-
tirement benefits.
The goal of the PRP was to achieve a reduced, more efficient and more
productive workforce in response to the significant regulatory changes facing
the Company. In 1997, approximately 15% of the Company's employees voluntari-
ly terminated employment as a result of the PRP. The payback period for the
cost of the PRP was expected to be about one year. This action followed the
consolidation of COM/Energy's electric and gas operations earlier in 1997.
Depreciation and Taxes
The 4.7% and 4.2% increase in depreciation in 1998 and 1997, respec-
tively, resulted from higher levels of depreciable plant-in-service.
The fluctuation in federal and state income taxes during 1998 and 1997
was due to the respective levels of pre-tax income. The decrease in payroll
and other taxes in 1998 reflects savings from the aforementioned PRP. The
increase in payroll and other taxes for 1997 reflects additional payroll-
related costs associated with a 1996 labor dispute. The decrease in local
property taxes in 1998 was due to changing assessments in the Company's
service territory. The increase in local property taxes during 1997 was due
to higher tax rates and assessments in the Company's service territory.
Other Income and Interest Charges
In 1998, other income increased by $566,000 (83.4%) due primarily to
increased sales of home heating protection plans. During 1997, other income
decreased $256,000 or 27.4% due primarily to a reduction in interest income
($167,000) in connection with the Company's participation in the COM/Energy
Money Pool and the absence of interest ($74,000) relating to a Massachusetts
income tax abatement received in 1996.
In 1998, total interest charges increased by $490,000 due to higher
interest costs on long-term debt ($1.5 million) related to the issuance of $35
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COMMONWEALTH GAS COMPANY
million in new long-term debt in September 1997 and an increase in interest on
deferred gas costs ($562,000). These increases were partially offset by a
decrease in short-term interest ($959,000) due to the repayment of short-term
debt in 1998. For 1997, total interest charges decreased $347,000 due
primarily to lower interest on deferred gas costs ($1 million) and a decline
in interest costs relating to long-term debt ($365,000) reflecting the impact
of a sinking fund payment and debt that was retired in October 1996. The
impact of these factors was offset, in part, by an increase in short-term
interest ($783,000) due to a higher average level of borrowings, higher
interest relating to gas refunds ($194,000) and higher interest charges
relating to contested tax issues ($115,000).
Forward-Looking Statements
This report contains statements which, to the extent they are not
recitations of historical fact, constitute "forward-looking statements" and
are 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 Company's business and financial results could cause
actual results to differ materially from those stated in the forward-looking
statements. Those factors include developments in the legislative, regulatory
and competitive environment, certain environmental matters, demands for
capital expenditures and the availability of cash from various sources.
Merger with BEC Energy
The utility industry has continued to change in response to legislative
and regulatory mandates that are aimed at lowering prices for energy by
creating a more competitive marketplace. These pressures have resulted in an
increasing trend in the utility industry to seek competitive advantages and
other benefits through business combinations. On December 5, 1998, COM/Energy
and BEC Energy (BEC), headquartered in Boston, Massachusetts, entered into an
Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger
Agreement, COM/Energy and BEC will be merged into a new holding company to be
known as NSTAR. The merger is expected to occur shortly after the satisfac-
tion of certain conditions, including the receipt of certain regulatory
approvals including that of the DTE. The regulatory approval process is
expected to be completed during the second half of 1999.
The merger will create an energy delivery company serving approximately
1.3 million customers located entirely within Massachusetts, including more
than one million electric customers in 81 communities and the Company's
240,000 gas customers in 51 communities.
Shareholder votes on the merger will be held as part of each of
COM/Energy's and BEC's annual shareholder meetings scheduled for the second
quarter of 1999. The Merger Agreement may be terminated under certain
circumstances, including by any party if the merger is not consummated by
December 5, 1999, subject to an automatic extension of six months if the
requisite regulatory approvals have not yet been obtained by such date. The
merger will be accounted for using the purchase method of accounting.
Upon effectiveness of the merger, Thomas J. May, BEC's current Chair-
man, President and Chief Executive Officer (CEO), will become the Chairman and
CEO of NSTAR. Russell D. Wright, COM/Energy's current President and CEO,
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COMMONWEALTH GAS COMPANY
will become the President and Chief Operating Officer of NSTAR and will serve
on NSTAR's board of directors. Also, upon effectiveness of the merger,
NSTAR's board of directors will consist of COM/Energy's and BEC's current
trustees.
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.
COM/Energy has been involved in Year 2000 compliancy since 1996.
COM/Energy, on a coordinated basis and with the assistance of RCG
Information Technologies and other consultants, is addressing the Year 2000
issue. COM/Energy has followed a five-phase process in its Year 2000 compli-
ance efforts, as follows: Awareness (through a series of internal announce-
ments to employees and through contacts with vendors); Inventory (all comput-
ers, applications and embedded systems that could potentially be affected by
the Year 2000 problem); Assessment (all applications or components and the
impact on overall business operations and a plan to correct deficiencies and
the cost to do so); Remediation (the modification, upgrade or replacement of
deficient hardware and software applications and infrastructure modifica-
tions); and Testing (a detailed, comprehensive testing program for the
modified critical component, system or software that involves the planning,
execution and analysis of results).
COM/Energy's inventory phase required an assessment of all date sensi-
tive information and transaction processing computer systems and determined
that approximately 90% of its software systems needed some modifications or
replacement. Plans were developed and are being implemented to correct and
test all affected systems, with priorities assigned based on the importance of
the activity. COM/Energy has identified the software and hardware installa-
tions that are necessary. All installations are expected to be completed and
tested by mid-1999.
COM/Energy 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. COM/Energy is approximately 86%
complete in its efforts to resolve non-compliance with Year 2000 requirements
related to its non-information technology systems. COM/Energy anticipates
that these systems will be updated or replaced as necessary and tested by mid-
1999.
At present, the remediation phase for information technology as it
applies to hardware and non-technology issues is scheduled for completion by
June 1, 1999. The testing phase for Year 2000 compliance is approximately 70%
complete and is scheduled to be concluded by June 30, 1999. All other phases
are complete.
<PAGE>
<PAGE 16>
COMMONWEALTH GAS COMPANY
Modifying and testing COM/Energy's information and transaction process-
ing systems from 1996 through 2000 is currently expected to cost approximately
$7 million, including approximately $900,000 incurred through 1997 and $3.1
million spent in 1998. Approximately $3 million is expected to be spent in
1999 and 2000. Year 2000 costs have been expensed as incurred and will
continue to be funded from operations.
In addition to its internal efforts, COM/Energy has initiated formal
communications with its significant suppliers to determine the extent to which
COM/Energy may be vulnerable to its suppliers' failure to correct their own
Year 2000 issues. As of February 1, 1999, COM/Energy has received responses
from approximately 75% of those entities contacted, and nearly all have
indicated that they are or will be Year 2000 compliant. Failure of
COM/Energy's significant suppliers to address Year 2000 issues could have a
material adverse effect on COM/Energy'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 COM/Energy. Contact with significant
vendors is continuing and inadequate or marginal responses are being pursued
by COM/Energy. COM/Energy is prepared to replace certain suppliers or to
initiate other contingency plans should these vendors not respond to
COM/Energy's satisfaction by July 1, 1999.
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
COM/Energy's ability to acquire energy and its ability to serve its customers
as effectively as they are now being served. COM/Energy 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 ele-
ments.
COM/Energy has started its contingency planning for critical operation-
al areas that might be effected by the Year 2000 issue if compliance by
COM/Energy is delayed. COM/Energy 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
June 30, 1999, although in certain cases, especially infrastructure failures,
there may be no practical alternative course of action available to
COM/Energy.
COM/Energy is working with other energy industry entities, both region-
ally and nationally with respect to Year 2000 readiness and is cooperating in
the development of local and wide-scale contingency planning.
While COM/Energy believes its efforts to address the Year 2000 issue
will allow it to be successful in avoiding any material adverse effect on
COM/Energy's operations or financial condition, it recognizes that failing to
<PAGE>
<PAGE 17>
COMMONWEALTH GAS COMPANY
resolve Year 2000 issues on a timely basis would, in a "most reasonably likely
worst case scenario," significantly limit its ability to acquire and distrib-
ute 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, COM/Energy 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 COM/Energy could include, among other things, business disruption,
increased costs, loss of business and other similar risks.
The foregoing discussion regarding Year 2000 project timing, effective-
ness, 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
COM/Energy's ability to respond to unforeseen Year 2000 complications.
Environmental Matters
The Company 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
the Company may be responsible for remedial actions. In April 1998, the
Company recorded an additional liability and corresponding regulatory asset of
$500,000 due to an increase in the site clean-up cost estimate for an MGP site
for which the Company was previously cited as a Potentially Responsible Party.
The DTE has approved recovery of costs associated with MGP sites.
The Company is also involved in other known or potentially contaminated
sites where the associated costs may not be recoverable in rates and have
recorded in prior years an estimated liability (and a charge to operations) of
$500,000 to cover the expected costs associated with assessment and remedia-
tion activities. These estimates are reviewed and adjusted periodically as
further investigation and assignment of responsibility occurs. The Company is
unable to estimate its ultimate liability for future environmental remediation
costs. However, in view of the Company's current assessment of its environ-
mental responsibilities, existing legal requirements and regulatory policies,
management does not believe that these matters will have a material adverse
effect on the Company's results of operations or financial position.
On January 1, 1997, the Company adopted the provisions of Statement of
Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1 pro-
vides authoritative guidance for recognition, measurement, display and
disclosure of environmental remediation liabilities in financial statements.
The Company has recorded environmental remediation liabilities net of amounts
paid of $1.9 million at December 31, 1998. The adoption of SOP 96-1 did not
have a material adverse effect on the Company's results of operations or
financial position.
<PAGE>
<PAGE 18>
COMMONWEALTH GAS COMPANY
New Accounting Principles
In June 1998, the Financial Accounting Standards Board issued 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 con-
tracts) 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 adoption of SFAS No. 133 is not expected to have a material impact
on the system's results of operations or financial condition.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Although the Company has material commodity purchase contracts and
financial instruments (debt), these instruments are not subject to market
risk. The Company has a rate making mechanism which allows for the recovery
of gas costs from customers. The gas adjustment mechanism allows the Company
to pass all costs related to the purchase of commodities to the customer,
thereby insulating the Company from market risk.
Similarly, any change in the fair market value of the Company's pru-
dently incurred debt obligations realized by the Company would be borne by
customers through future rates.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed
herewith on pages 19 through 36 of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
<PAGE>
<PAGE 19>
COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1998
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Commonwealth Gas Company:
We have audited the accompanying balance sheets of COMMONWEALTH GAS
COMPANY (a Massachusetts corporation and wholly-owned subsidiary of Common-
wealth Energy System) as of December 31, 1998 and 1997, and the related
statements of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1998. These financial statements and
the schedule referred to below are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Commonwealth Gas
Company as of December 31, 1998 and 1997, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting prin-
ciples.
Our audits were made for the purpose of forming an opinion on the
basic financial statements taken as a whole. The schedule listed in the index
to financial statements and schedule is presented for purposes of complying
with the Securities and Exchange Commission's rules and is not part of the
basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states, in all material respects, the financial data required
to be set forth therein in relation to the basic financial statements taken as
a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 18, 1999
<PAGE>
<PAGE 20>
COMMONWEALTH GAS COMPANY
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1998 and 1997
Statements of Income for the Years Ended December 31, 1998, 1997 and
1996
Statements of Retained Earnings for the Years Ended December 31, 1998,
1997 and 1996
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and
1996
Notes to Financial Statements
PART IV.
SCHEDULE
II Valuation and Qualifying Accounts for the Years Ended December 31,
1998, 1997 and 1996
SCHEDULES OMITTED
All other schedules are not submitted because they are not applicable or
not required or because the required information is included in the
financial statements or notes thereto.
<PAGE>
<PAGE 21>
COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
ASSETS
1998 1997
(Dollars in thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $392,612 $375,083
Less - Accumulated depreciation 120,811 110,661
271,801 264,422
Add - Construction work in progress 1,066 570
272,867 264,992
CURRENT ASSETS
Cash 427 1,867
Accounts receivable -
Affiliated companies 785 592
Customers, less reserves of $2,346 in 1998
and $2,853 in 1997 38,956 48,731
Unbilled revenues 10,358 19,121
Inventories, at average cost -
Natural gas 24,519 23,301
Materials and supplies 1,366 1,225
Prepaid taxes -
Property 3,135 3,176
Income 5,034 5,640
Other 874 1,234
85,454 104,887
DEFERRED CHARGES
Regulatory assets 19,616 20,873
Other 5,307 5,214
24,923 26,087
$383,244 $395,966
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 22>
COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
CAPITALIZATION AND LIABILITIES
1998 1997
(Dollars in thousands)
CAPITALIZATION
Common Equity -
Common stock, $25 par value -
Authorized and outstanding -
2,857,000 shares, wholly-owned
by Commonwealth Energy
System (Parent) $ 71,425 $ 71,425
Amounts paid in excess of par value 27,739 27,739
Retained earnings 17,998 16,871
117,162 116,035
Long-term debt, less current sinking
fund requirements 102,150 105,800
219,312 221,835
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks - 39,325
Advances from affiliates 30,825 -
30,825 39,325
Other Current Liabilities -
Current sinking fund requirements 3,650 3,650
Accounts payable -
Affiliated companies 2,527 1,869
Other 27,153 32,450
Accrued local property and other taxes 3,251 3,366
Customer deposits 1,327 1,006
Accrued interest 1,057 1,038
Other 18,073 18,551
57,038 61,930
87,863 101,255
DEFERRED CREDITS
Accumulated deferred income taxes 40,767 38,322
Unamortized investment tax credits 5,263 5,461
Other 30,039 29,093
76,069 72,876
COMMITMENTS AND CONTINGENCIES
$383,244 $395,966
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 23>
COMMONWEALTH GAS COMPANY
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
(Dollars in thousands)
GAS OPERATING REVENUES $289,083 $331,135 $342,488
OPERATING EXPENSES
Cost of gas sold 157,552 191,213 197,665
Other operation 70,453 74,402 75,279
Maintenance 10,036 10,580 14,171
Depreciation 10,979 10,482 10,061
Taxes -
Income 7,982 9,653 10,282
Local property 6,162 6,315 5,943
Payroll and other 2,905 3,225 2,385
266,069 305,870 315,786
OPERATING INCOME 23,014 25,265 26,702
OTHER INCOME 1,246 679 935
INCOME BEFORE INTEREST CHARGES 24,260 25,944 27,637
INTEREST CHARGES
Long-term debt 8,721 7,251 7,604
Other interest charges 2,270 3,250 3,244
10,991 10,501 10,848
NET INCOME $ 13,269 $ 15,443 $ 16,789
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 24>
COMMONWEALTH GAS COMPANY
STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
(Dollars in thousands)
Balance at beginning of year $16,871 $10,856 $10,495
Add (Deduct):
Net income 13,269 15,443 16,789
Cash dividends on common stock (12,142) (9,428) (16,428)
Balance at end of year $17,998 $16,871 $10,856
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 25>
COMMONWEALTH GAS COMPANY
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
(Dollars in thousands)
OPERATING ACTIVITIES
Net income $13,269 $15,443 $16,789
Effects of noncash items -
Depreciation and amortization 13,302 13,190 12,034
Deferred income taxes (2,764) 746 4,249
Investment tax credits (198) (199) (202)
Change in working capital exclusive
of cash and interim financing -
Accounts receivable and unbilled
revenues 18,345 (230) (4,859)
Income taxes 606 (21) (5,235)
Local property and other taxes (74) 191 (342)
Accounts payable and other (5,776) 763 (31,407)
Deferred postretirement benefit costs - (414) (2,228)
All other operating items 5,504 (2,278) (3,267)
Net cash provided by (used for)
operating activities 42,214 27,191 (14,468)
INVESTING ACTIVITIES
Additions to property, plant and
equipment (inclusive of AFUDC) (19,362) (18,392) (11,696)
FINANCING ACTIVITIES
Payment of dividends (12,142) (9,428) (16,428)
Proceeds from (payment of) short-term
borrowings (39,325) (18,875) 46,000
Advances from (payments to) affiliates 30,825 (10,400) 8,550
Long-term debt issues - 35,000 -
Long-term debt issue refunded - - (10,000)
Retirement of long-term debt
through sinking funds (3,650) (3,650) (3,650)
Net cash provided by (used for)
financing activities (24,292) (7,353) 24,472
Net increase (decrease) in cash (1,440) 1,446 (1,692)
Cash at beginning of period 1,867 421 2,113
Cash at end of period $ 427 $ 1,867 $ 421
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $10,707 $ 9,162 $10,619
Income taxes $ 5,470 $ 8,916 $14,165
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 26>
COMMONWEALTH GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) General Information
Commonwealth Gas Company (the Company) is a wholly-owned subsidiary of
Commonwealth Energy System (the Parent). The Parent, together with its
subsidiaries, is referred to as "COM/Energy." The Parent is an exempt public
utility holding company under the provisions of the Public Utility Holding
Company Act of 1935 and, in addition to its investment in the Company, has
interests in other utility companies and several non-regulated companies.
The Company is engaged in the distribution and sale of natural gas at
retail to approximately 240,000 customers in a 1,067 square-mile area which
includes 51 communities in eastern, southeastern and central Massachusetts
including New Bedford, Cambridge, Plymouth and Worcester. The approximate
year-round population of this service area is 1,128,000.
The Company has 604 regular employees including 408 (68%) who are repre-
sented by three collective bargaining units covered by separate contracts with
expiration dates ranging from March 2002 through April 2003.
(2) Significant Accounting Policies
(a) Principles of Accounting
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Certain prior year amounts are reclassified from time to time to conform
with the presentation used in the current year's financial statements.
(b) Regulatory Assets and Liabilities
The Company is regulated as to rates, accounting and other matters by the
Massachusetts Department of Telecommunications and Energy (DTE).
Based on the current regulatory framework, the Company 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." The Company has established various regula-
tory assets in cases where the DTE has permitted or is expected to permit
recovery of specific costs over time. If all or a separable portion of the
Company's operations becomes no longer subject to the provisions of SFAS No.
71, a write-off of related regulatory assets and liabilities would be re-
quired, unless some form of transition cost recovery continues through rates
established and collected for the Company's remaining regulated operations.
In addition, the Company would be required to determine any impairment to the
carrying costs of deregulated plant and inventory assets.
<PAGE>
<PAGE 27>
COMMONWEALTH GAS COMPANY
The principal regulatory assets included in deferred charges at
December 31, 1998 and 1997 were as follows:
1998 1997
(Dollars in thousands)
Postretirement benefit costs $ 8,568 $ 9,607
FERC Order 636 transition costs 5,968 7,336
Environmental costs 5,080 3,930
Total regulatory assets $19,616 $20,873
The principal regulatory liability, reflected in deferred credits-other
and relating to income taxes, was $8 million and $8.3 million at December 31,
1998 and 1997, respectively. As of December 31, 1998, $16 million of the
Company's regulatory assets and all of its regulatory liabilities are reflect-
ed in rates charged to customers. Regulatory assets, including postretirement
benefit costs, are being recovered over a weighted average period of approxi-
mately 8 years.
(c) Transactions with Affiliates
Operating revenues include sales of gas to affiliate Cambridge Electric
Light Company as follows:
1998 1997 1996
(Dollars in thousands)
Cost $ - $ - $ 11
Margin - - -
Total $ - $ - $ 11
Any margin realized on these sales is credited to firm customers through
the Cost of Gas Adjustment Clause (CGAC).
Other intercompany transactions include payments by the Company for
management, accounting, data processing and other services provided by
COM/Energy Services Company. In addition, the Company incurred costs paid to
affiliate Hopkinton LNG Corp. for liquefaction and vaporization services that
amounted to $9,834,000, $10,172,000 and $10,124,000 in 1998, 1997 and 1996,
respectively. Transactions with COM/Energy companies are subject to review by
the DTE.
(d) Operating Revenues
Customers are billed for their use of gas on a cycle basis throughout the
month. To reflect revenues in the proper period, the estimated amount of
unbilled sales revenue is recorded each month.
The Company is permitted to bill customers currently for total gas costs,
certain conservation and load management costs and environmental costs through
adjustment clauses. Amounts recoverable under the adjustment clauses are
subject to review and adjustment by the DTE. The amount of such costs
incurred by the Company but not yet reflected in customers' bills is recorded
as unbilled revenues.
<PAGE>
<PAGE 28>
COMMONWEALTH GAS COMPANY
(e) Depreciation
Depreciation is provided using the straight-line method at rates intended
to amortize the original cost and the estimated cost of removal less salvage
of properties over their estimated economic lives. The Company's composite
depreciation rate, based on average depreciable property in service, was 2.95%
in both 1998 and 1997 and 2.94% in 1996.
(f) Maintenance
Expenditures for repairs of property and replacement and renewal of items
determined to be less than units of property are charged to maintenance
expense. Additions, replacements and renewals of property considered to be
units of property are charged to the appropriate plant accounts. Upon
retirement, accumulated depreciation is charged with the original cost of
property units and the cost of removal less salvage.
(g) Allowance for Funds Used During Construction
Under applicable rate-making practices, the Company is permitted to
include an allowance for funds used during construction (AFUDC) as an element
of its depreciable property costs. This allowance is based on the amount of
construction work in progress that is not included in the rate base on which
the Company earns a return. An amount equal to the AFUDC capitalized in the
current period is reflected in other interest charges in the accompanying
Statements of Income and amounted to $76,000, $55,000 and $20,000 in 1998,
1997 and 1996, respectively.
While AFUDC does not provide funds currently, these amounts are recover-
able in revenues over the service life of the constructed property. The
amount of AFUDC recorded was at a weighted average rate of 4.5% in 1998, 5.75%
in 1997 and 6% in 1996.
(3) Income Taxes
For financial reporting purposes, the Company provides federal and state
income taxes on a separate return basis. However, for federal income tax
purposes, the Company's taxable income and deductions are included in the
consolidated income tax return of the Parent, and it makes tax payments or
receives refunds on the basis of its tax attributes in the tax return in
accordance with applicable regulations.
<PAGE>
<PAGE 29>
COMMONWEALTH GAS COMPANY
The following is a summary of the provisions for income taxes for the
years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
(Dollars in thousands)
Federal -
Current $ 9,166 $ 7,544 $ 5,220
Deferred (2,239) 775 3,508
Investment tax credits (198) (199) (202)
6,729 8,120 8,526
State -
Current 1,778 1,562 1,015
Deferred (373) 168 713
1,405 1,730 1,728
8,134 9,850 10,254
Amortization of regulatory liability
relating to deferred income taxes (152) (197) 28
Total federal and state
income taxes $ 7,982 $ 9,653 $10,282
Deferred tax liabilities and assets are determined based on the difference
between the financial statement basis and tax bases of assets and liabilities
using enacted tax rates in effect in the year in which the differences are
expected to reverse.
Accumulated deferred income taxes consisted of the following in 1998 and
1997:
1998 1997
(Dollars in thousands)
Liabilities
Property-related $46,950 $44,730
Postretirement benefits plan 3,360 3,877
All other 1,249 1,691
51,559 50,298
Assets
Investment tax credit 3,397 3,524
Pension plan 4,165 2,921
Regulatory liability 2,785 2,883
Inventory repricing 2,999 2,948
All other 6,042 3,359
19,388 15,635
Accumulated deferred income taxes, net $32,171 $34,663
The net year-end deferred income tax liability above is net of current
deferred tax assets of $8,596,000 in 1998 and $3,659,000 in 1997 which are
included in other deferred charges in the accompanying Balance Sheets.
<PAGE>
<PAGE 30>
COMMONWEALTH GAS COMPANY
The total income tax provision set forth on the previous page represents
38% in 1998, 1997 and 1996 of income before such taxes. The following table
reconciles the statutory federal income tax rate to these percentages:
1998 1997 1996
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory levels $ 7,438 $ 8,784 $ 9,475
Increase (Decrease) from statutory rate:
State tax net of federal tax benefit 913 1,124 1,123
Amortization of investment tax credits (198) (199) (202)
Amortization of excess deferred reserves (152) (197) 28
Tax versus book depreciation 11 19 (123)
Other (30) 122 (19)
$ 7,982 $ 9,653 $10,282
Effective federal tax rate 38% 38% 38%
(4) Long-Term Debt and Interim Financing
(a) Long-Term Debt
Long-term debt outstanding, exclusive of current maturities and current
sinking fund requirements, collateralized by substantially all of the
Company's property, is as follows:
Original Balance December 31,
Issue 1998 1997
(Dollars in thousands)
First Mortgage Bonds -
8.99%, Series I, due 2001 $40,000 $ 7,150 $ 10,800
9.95%, Series J, due 2020 25,000 25,000 25,000
7.11%, Series K, due 2033 35,000 35,000 35,000
6.54%, Series L, due 2007 10,000 10,000 10,000
7.04%, Series M, due 2017 25,000 25,000 25,000
$102,150 $105,800
Under terms of its indenture, the Company is required to make periodic
sinking fund payments for retirement of outstanding long-term debt. The
Company may purchase its outstanding bonds in advance of sinking fund require-
ments under favorable conditions. The required sinking fund payments and
balances of maturing debt issues for the five years subsequent to December 31,
1998 are as follows:
Sinking Fund Maturing Debt
Year Requirements Issues Total
(Dollars in thousands)
1999 $3,650 $ - $3,650
2000 3,650 - 3,650
2001 5,079 3,500 8,579
2002 1,429 - 1,429
2003 1,429 - 1,429
<PAGE>
<PAGE 31>
COMMONWEALTH GAS COMPANY
(b) Notes Payable to Banks
The Company and other COM/Energy companies maintain both committed and
uncommitted lines of credit for the short-term financing of their construction
programs and other corporate purposes. As of December 31, 1998, COM/Energy
companies had $122 million of committed lines that will expire at varying
intervals in 1999. These lines are normally renewed upon expiration and
require annual fees up to .1875% of the individual line. At December 31,
1998, the uncommitted lines of credit totaled $10 million. Interest rates on
the outstanding borrowings generally are at an adjusted money market rate and
averaged 5.7% and 5.8% in 1998 and 1997, respectively. The Company had no
notes payable to banks at December 31, 1998 compared to $39,325,000 at
December 31, 1997.
(c) Advances from Affiliates
The Company is a member of the COM/Energy Money Pool (the Pool), an
arrangement among the subsidiaries of the Parent, whereby short-term cash
surpluses are used to help meet the short-term borrowing needs of the utility
subsidiaries. In general, lenders to the Pool receive a higher rate of return
than they otherwise would on such investments, while borrowers pay a lower
interest rate than those available from banks. Interest rates on the out-
standing borrowings are based on the monthly average rate the Company would
otherwise have to pay banks, less one-half the difference between that rate
and the monthly average U.S. Treasury Bill weekly auction rate. The borrow-
ings are for a period of less than one year and are payable upon demand.
Rates on these borrowings averaged 5.3% and 5.4% during 1998 and 1997,
respectively. The Company had $30,825,000 in borrowings from the Pool at
December 31, 1998 and none at December 31, 1997.
The Company had no notes payable to the Parent at December 31, 1998 or
1997. These notes are written for a term of up to 11 months and 29 days.
Interest is at the prime rate and is adjusted for changes in that rate during
the term of the notes. This rate averaged 8.3% and 8.5% during 1998 and 1997,
respectively.
(d) Disclosures about Fair Value of Financial Instruments
The fair value of certain financial instruments included in the accompany-
ing balance sheets as of December 31, 1998 and 1997 are as follows:
1998 1997
Carrying Fair Carrying Fair
Value Value Value Value
(Dollars in thousands)
Long-Term Debt $105,800 $118,063 $109,450 $122,744
The carrying amount of cash, notes payable to banks and advances from
affiliates approximates the fair value because of the short maturity of these
financial instruments.
<PAGE>
<PAGE 32>
COMMONWEALTH GAS COMPANY
The estimated fair value of long-term debt is based on quoted market
prices of the same or similar issues or on the current rates offered for debt
with the same remaining maturity. The fair values shown above do not purport
to represent the amounts at which those obligations would be settled.
(5) Employee Benefit Plans
(a) Pension
The Company has a noncontributory pension plan covering substantially all
regular employees who have attained the age of 21 and have completed a year of
service. Pension benefits are based on an employee's years of service and
compensation. The Company makes monthly contributions to the plan consistent
with the funding requirements of the Employee Retirement Income Security Act
of 1974.
The following tables set forth the change in the pension benefit obliga-
tion and plan assets as well as the plan's funded status reconciled to the
amount included in the financial statements:
1998 1997
(Dollars in thousands)
Change in benefit obligation
Obligation at beginning of year $ 120,179 $ 99,811
Service cost 2,398 2,252
Interest cost 8,308 7,242
Actuarial loss 11,602 17,733
Benefits paid (7,725) (6,859)
Obligation at end of year $ 134,762 $ 120,179
1998 1997
(Dollars in thousands)
Change in plan assets
Fair value of plan assets at
beginning of year $ 114,394 $ 101,182
Actual return on plan assets 8,814 17,925
Employer contributions 2,192 2,221
Transfers to affiliated companies (571) (75)
Benefits paid (7,725) (6,859)
Fair value of plan assets at
end of year $ 117,104 $ 114,394
1998 1997
(Dollars in thousands)
Funded status $ (17,658) $ (5,785)
Unrecognized transition obligation 1,848 2,477
Unrecognized prior service cost 3,794 4,317
Unrecognized net actuarial (gain) loss 3,200 (8,874)
Prepaid (accrued) benefit cost $ (8,816) $ (7,865)
<PAGE>
<PAGE 33>
COMMONWEALTH GAS COMPANY
Weighted-average assumptions as of December 31 were as follows:
1998 1997
Discount rate 6.50% 7.00%
Expected return on plan assets 9.00 8.75
Rate of increase in future compensation 3.75 3.75
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect pension
expense in future years.
Components of net periodic pension cost were as follows:
1998 1997 1996
(Dollars in thousands)
Service cost $ 2,398 $ 2,252 $ 2,310
Interest cost 8,308 7,242 7,172
Expected return on plan assets (8,715) (7,803) (7,219)
Amortization of transition obligation 616 619 619
Amortization of prior service cost 501 503 503
Total 3,108 2,813 3,385
Transfer from affiliated companies, net 379 516 487
Less: Amounts capitalized and deferred 451 375 292
Net periodic pension cost $ 3,036 $ 2,954 $ 3,580
The net periodic pension cost reflects the use of the projected unit
credit method which is also the actuarial cost method used in determining
future funding of the plan. The Company, in accordance with current rate-
making, is deferring the difference between the pension contribution that is
reflected in base rates, and pension expense.
(b) Other Postretirement Benefits
Certain employees are eligible for postretirement benefits if they meet
specific requirements. These benefits could include health and life insurance
coverage and reimbursement of Medicare Part B premiums. Under certain
circumstances, eligible employees are required to make contributions for
postretirement benefits.
To fund its postretirement benefits, the Company makes contributions to
various voluntary employees' beneficiary association trusts that were estab-
lished pursuant to section 501(c)(9) of the Internal Revenue Code (the Code).
The Company also makes contributions to a subaccount of its pension plan
pursuant to section 401(h) of the Code to fund a portion of its postretirement
benefit obligation.
<PAGE>
<PAGE 34>
COMMONWEALTH GAS COMPANY
The following tables set forth the change in the postretirement benefit
obligation and plan assets as well as the plan's funded status reconciled to
the amount included in the financial statements:
1998 1997
(Dollars in thousands)
Change in benefit obligation
Obligation at beginning of year $ 47,271 $ 38,643
Service cost 486 441
Interest cost 3,029 2,788
Actuarial loss (49) 7,553
Participant contributions 51 41
Benefits paid (2,738) (2,195)
Obligation at end of year $ 48,050 $ 47,271
1998 1997
(Dollars in thousands)
Change in plan assets
Fair value of plan assets at
beginning of year $ 16,720 $ 12,636
Actual return on plan assets 1,847 2,474
Employer contributions 3,668 3,764
Participant contributions 51 41
Transfers to affiliated companies (15) -
Benefits paid (2,738) (2,195)
Fair value of plan assets at
end of year $ 19,533 $ 16,720
Funded status $ (28,517) $ (30,551)
Unrecognized transition obligation 23,763 25,501
Unrecognized net actuarial loss 4,754 5,050
Prepaid (accrued) benefit cost $ - $ -
Weighted-average assumptions as of December 31 were as follows:
1998 1997
Discount rate 6.50% 7.00%
Expected return on plan assets 9.00 8.75
Rate of increase in future compensation 3.75 3.75
For measurement purposes, a 6.50% annual rate of increase in the per
capita cost of covered medical claims was assumed for 1999. The rates were
assumed to decrease gradually to 4.5% for 2007 and remain at that level
thereafter. Dental claims and Medicare Part B premiums are expected to
increase at 4.5% and 3.1%, respectively.
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect the periodic
postretirement benefit cost in future years.
<PAGE>
<PAGE 35>
COMMONWEALTH GAS COMPANY
Components of net periodic postretirement benefit cost were as follows:
1998 1997 1996
(Dollars in thousands)
Service cost $ 486 $ 441 $ 551
Interest cost 3,029 2,788 2,878
Expected return on plan assets (1,544) (1,165) (866)
Amortization of transition obligation 1,697 1,700 1,700
Total 3,668 3,764 4,263
Transfers from affiliates, net 403 484 520
Add: Net amortization of deferrals 1,039 779 -
Less: Amounts capitalized and deferred 419 865 2,612
Net periodic postretirement
benefit cost $ 4,691 $ 4,162 $ 2,171
Assumed healthcare cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage point change in
assumed healthcare cost trend rates would have the following effects:
One-Percentage-Point
Increase Decrease
(Dollars in thousands)
Effect on total of service and
interest cost components $ 469 $ (381)
Effect on postretirement
benefit obligation $ 5,656 $ (5,358)
On April 15, 1997, the DTE issued an accounting ruling allowing the
Company to include postretirement benefits costs in cost-of-service and to
amortize the deferred balance of $10.5 million at March 31, 1997 associated
with these costs over a period not to exceed ten years that began in April
1997.
(c) Savings Plan
The Company has an Employees Savings Plan that provides for Company
contributions equal to contributions by eligible employees of up to four
percent of each employee's compensation rate. Effective January 1, 1993, the
rate was increased to five percent for those employees no longer eligible for
postretirement health benefits. The Company's contribution was $1,312,000 in
1998, $1,366,000 in 1997 and $1,100,000 in 1996.
(6) Commitments and Contingencies
(a) Construction and Financing Program
The Company is engaged in a continuous construction program presently
estimated at $93.4 million for the five-year period 1999 through 2003. Of
that amount, $18.6 million is estimated for 1999. The program is subject to
periodic review and revision because of factors such as changes in business
conditions, rates of customer growth, effects of inflation, equipment delivery
schedules, licensing delays, availability and cost of capital and environmen-
tal factors.
<PAGE>
<PAGE 36>
COMMONWEALTH GAS COMPANY
(b) LNG Service Contract
The Company has long-term contracts with Hopkinton LNG Corp., a wholly-
owned subsidiary of the Parent, for liquefaction and vaporization services.
The contracts extend on a year-to-year basis, subject to the giving of a
notice to terminate by the Company at least five years in advance of the
anticipated termination date.
(7) Gas Refunds
During 1998, 1997 and 1996, the Company received refunds from its gas
suppliers in settlement of several rate cases that had been pending before the
FERC. Operating revenues and the cost of gas sold have been reduced by the
amounts refunded to firm customers totaling $4,439,000 in 1998, $2,374,000 in
1997 and $7,656,000 in 1996.
(8) Lease Obligations
The Company leases equipment and office space under arrangements that are
classified as operating leases. These lease agreements are for terms of one
year or longer. Leases currently in effect contain no provisions that
prohibit the Company from entering into future lease agreements or obliga-
tions.
Future minimum lease payments, by period and in the aggregate, of non-
cancelable operating leases consisted of the following at December 31, 1998:
Operating Leases
(Dollars in thousands)
1999 $ 3,601
2000 2,533
2001 2,140
2002 2,140
2003 2,140
Beyond 2003 5,229
Total future minimum lease payments $17,783
Total rent expense for all operating leases, except those with terms of a
month or less, amounted to $4,842,000 in 1998, $4,866,000 in 1997, and
$5,027,000 in 1996. There were no contingent rentals and no sublease rentals
for the years 1998, 1997 and 1996.
(9) Environmental Matters
The Company is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment. These
regulations authorize federal and state regulatory agencies to identify and
remediate hazardous waste sites and to seek recovery from statutorily liable
parties (usually referred to as potentially responsible parties or PRPs), or
to order these PRPs to undertake the clean-up themselves. (Refer to "Environ-
mental Matters" filed under Item 7 of this report for additional information.)
<PAGE>
<PAGE 37>
COMMONWEALTH GAS COMPANY
PART IV.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Index to Financial Statements
Financial statements and notes thereto of the Company together with
the Report of Independent Public Accountants, are filed under Item 8
of this report and listed on the Index to Financial Statements and
Schedule (page 20).
(a) 2. Index to Financial Statement Schedules
Filed herewith at page indicated is the following financial state-
ment schedule of the Company:
Schedule II - Valuation and Qualifying Accounts - Years Ended
December 31, 1998, 1997 and 1996 (page 37).
(a) 3. Exhibits:
Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are incor-
porated by reference to the appropriate exhibit numbers and the
Securities and Exchange Commission file numbers indicated in
parentheses.
b. The following is a glossary of acronyms used throughout the
Exhibit Index:
CES Commonwealth Energy System
CG Commonwealth Gas Company
CNG CNG Transmission Corporation
TGP Tennessee Gas Pipeline Company
Exhibit Index:
Exhibit 3. Articles of incorporation and by-laws.
3.1.1 Articles of incorporation of CG (Exhibit 1 to the CG 1991 Form 10-
K, File No. 2-1647).
3.1.2 By-laws of CG, as amended (Exhibit 2 to the CG 1992 Form 10-K,
File No. 2-1647).
Exhibit 4. Instruments defining the rights of security holders, including
indentures.
4.1. Indentures of Trust or Supplemental Indenture of Trust
(as filed by the Registrant, except First Supplemental which was
filed by the Parent)
4.1.1. Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File
No. 2-7820).
4.1.2. First Supplemental on Form S-1 (Mar., 1950) (Exhibit 7(a), File
No. 2-8418).
<PAGE>
<PAGE 38>
COMMONWEALTH GAS COMPANY
4.1.3. Second Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(2),
File No. 2-10445).
4.1.4. Third Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(3), File
No. 2-10445).
4.1.5. Fourth Supplemental on Form S-9 (Oct. 1954) (Exhibit 2(b)(5), File
No. 2-15089).
4.1.6. Fifth Supplemental on Form S-9 (Mar., 1956) (Exhibit 2(b)(6), File
No. 2-15089).
4.1.7. Sixth Supplemental on Form S-9 (Apr., 1957) (Exhibit 2(b)(7), File
No. 2-15089).
4.1.8. Seventh Supplemental on Form S-9 (June 1959) (Exhibit 2(b)(8),
File No. 2-20532).
4.1.9. Eighth Supplemental on Form S-9 (Sept. 1961) (Exhibit 2(b)(9),
File No. 2-20532).
4.1.10. Ninth Supplemental on Form 8-K (Aug. 1962) (Exhibit A, File No. 2-
1647).
4.1.11. Tenth Supplemental on Form 10-K (1970) (Exhibit 2, File No. 2-
1647).
4.1.12. Eleventh Supplemental on Form S-1 (June, 1972) (Exhibit 4(b)(2),
File No. 2-48556).
4.1.13. Twelfth Supplemental on Form S-1 (Aug., 1973) (Exhibit
4(b)(3), File No. 2-48556).
4.1.14. Thirteenth Supplemental on Form 10-K (1992) (Exhibit 1, File No.
2-1647).
4.1.15. Fourteenth Supplemental on Form 10-K (1990) (Exhibit 1, File No.
2-1647).
4.1.16. Fifteenth Supplemental on Form 10-K (1982) (Exhibit 1, File No. 2-
1647).
4.1.17. Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2-
1647).
4.1.18. Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No.
2-1647).
4.1.19. Eighteenth Supplemental on Form 10-Q (March, 1994) (Exhibit 1,
File No. 2-1647).
4.1.20. Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1, File No.
2-1647).
Exhibit 10. Material Contracts.
10.1. Natural Gas Purchase Contracts.
10.1.1 Transportation Agreement between CNG and CG to provide for trans-
portation of natural gas on a daily basis from Steuben Gas Storage
Company to TGP, dated September 24, 1991 (Exhibit 10 to the CG
1991 Form 10-K, File No. 2-1647).
10.2 Other Agreements.
10.2.1 Pension Plan for Employees of Commonwealth Energy System and
Subsidiary Companies as amended and restated January 1, 1993
(Filed as Exhibit 1 to the Parent's Form 10-Q (September 1993),
File No. 1-7316).
10.2.2 Employees Savings Plan for Employees of Commonwealth Energy System
and Subsidiary Companies as amended and restated January 1, 1993
(Filed as Exhibit 2 to the Parent's Form 10-Q (September 1993),
File No. 1-7316).
<PAGE>
<PAGE 39>
COMMONWEALTH GAS COMPANY
10.2.2.1 First Amendment to the Employees Savings Plan of Commonwealth
Energy System and Subsidiary Companies, as amended and restated as
of January 1, 1993, effective October 1, 1994. (Exhibit 1 to CES
Form S-8 (January 1995), File No. 1-7316).
10.2.2.2 Second Amendment to the Employees Savings Plan of Commonwealth
Energy System and Subsidiary Companies, as amended and restated as
of January 1, 1993, effective April 1, 1996. (Exhibit 1 to CES
Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316).
10.2.2.3 Third Amendment to the Employees Savings Plan of Commonwealth
Energy System and Subsidiary Companies, as amended and restated as
of January 1, 1993, effective January 1, 1997. (Exhibit 1 to CES
Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316).
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the three months ended
December 31, 1998.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 1 is the Financial Data Schedule for the
year ended December 31, 1998
<PAGE>
<PAGE 40>
SCHEDULE II
COMMONWEALTH GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 and 1996
(Dollars in thousands)
Additions
Balance Provision Deductions Balance
Beginning Charged to Accounts at End
Description of Year Operations Recoveries Written Off of Year
Allowance for
Doubtful Accounts Year Ended December 31, 1998
$ 2,853 $ 4,145 $ 1,527 $ 6,179 $ 2,346
Year Ended December 31, 1997
$ 2,738 $ 4,979 $ 1,333 $ 6,197 $ 2,853
Year Ended December 31, 1996
$ 2,691 $ 4,381 $ 1,213 $ 5,547 $ 2,738
<PAGE>
<PAGE 41>
COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1998
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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 GAS COMPANY
(Registrant)
By: R. D. WRIGHT
Russell D. Wright
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Principal Executive Officers:
R. D. WRIGHT March 31, 1999
Russell D. Wright
Chairman of the Board and
Chief Executive Officer
DEBORAH A. MCLAUGHLIN March 31, 1999
Deborah A. Mclaughlin,
President and Chief Operating Officer
Principal Financial and Accounting Officer:
JAMES D. RAPPOLI March 31, 1999
James D. Rappoli,
Financial Vice President and Treasurer
A majority of the Board of Directors:
DEBORAH A. MCLAUGHLIN March 31, 1999
Deborah A. McLaughlin, Director
JAMES D. RAPPOLI March 31, 1999
James D. Rappoli, Director
R. D. WRIGHT March 31, 1999
Russell D. Wright, Director
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
balance sheet, statement of income, statement of retained earnings and
statement of cash flows contained in Form 10-K of Commonwealth Gas Company for
fiscal year ended December 31, 1998 and is qualified in its entirety by
reference to such financial statements.
</LEGEND>
<CIK> 0000022620
<NAME> COMMONWEALTH GAS COMPANY
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 272,867
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 85,454
<TOTAL-DEFERRED-CHARGES> 24,923
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 383,244
<COMMON> 71,425
<CAPITAL-SURPLUS-PAID-IN> 27,739
<RETAINED-EARNINGS> 17,998
<TOTAL-COMMON-STOCKHOLDERS-EQ> 117,162
0
0
<LONG-TERM-DEBT-NET> 102,150
<SHORT-TERM-NOTES> 30,825
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 3,650
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 129,457
<TOT-CAPITALIZATION-AND-LIAB> 383,244
<GROSS-OPERATING-REVENUE> 289,083
<INCOME-TAX-EXPENSE> 7,982
<OTHER-OPERATING-EXPENSES> 258,087
<TOTAL-OPERATING-EXPENSES> 266,069
<OPERATING-INCOME-LOSS> 23,014
<OTHER-INCOME-NET> 1,246
<INCOME-BEFORE-INTEREST-EXPEN> 24,260
<TOTAL-INTEREST-EXPENSE> 10,991
<NET-INCOME> 13,269
0
<EARNINGS-AVAILABLE-FOR-COMM> 13,269
<COMMON-STOCK-DIVIDENDS> 12,142
<TOTAL-INTEREST-ON-BONDS> 8,721
<CASH-FLOW-OPERATIONS> 42,214
<EPS-PRIMARY> 0
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</TABLE>
