Item 1. Business
General
Commonwealth Gas Company (the Company) is engaged in the distribution and sale of natural gas at retail to approximately 232,000 customers in a 1,067 square mile area which includes 49 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 Commonwealth of Massachusetts, operates under the jurisdiction of the Massachusetts Department of Public Utilities (DPU), which regulates retail rates, accounting, issuance of securities and other matters. The Company is a wholly-owned subsidiary of Commonwealth Energy System ("System"), which, together with its subsidiaries, is collectively referred to as "the system." 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 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 authorization of the DPU. 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.
Operating revenues are derived primarily from residential, commercial and industrial 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 large industrial customers who have dual fuel capability can convert from gas to alternative fuels under terms of contracts which permit interruption of their service upon short notice. The Company reserves the right to reduce or interrupt the supply of gas to this class of customer at any time.
Gas Supply
(a) General
In April 1992, the Federal Energy Regulatory Commission (FERC) issued Order No. 636 (Order 636) which became effective on November 1, 1993. The order requires interstate pipelines to unbundle existing gas sales contracts into separate components (gas sales, transportation and storage services) and to provide transportation services that allow customers to receive the same level and quality of service they had with the previous bundled contracts. Prior to the implementation of Order 636 the Company purchased the majority of its gas supplies from either Tennessee Gas Pipeline Company (Tennessee) or Algonquin Gas Transmission Company (Algonquin), supplemented with third-party
COMMONWEALTH GAS COMPANY
firm gas purchases, storage services and firm transportation from various pipelines. Presently, the Company purchases only transportation, storage and balancing services from these pipelines (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 ranging from less than one year to three or more years. 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 combination of existing and new agreements which are the result of Order 636 service unbundling. The LNG facilities, described below, are used to liquefy and store pipeline gas during the warmer months for use during the heating season. During 1994, over 98% of the gas utilized by the Company was delivered by the interstate pipeline system. The remaining small quantity (approximately 662,000 MMBTU) was delivered as liquid LNG from Distrigas of Massachusetts.
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 DPU and hearings were completed in April 1993. The Company is currently awaiting an order from the DPU.
The Company began transporting gas on its distribution system in 1990 for end-users. There are currently eleven customers using this transportation service, accounting for 3,003 BBTU of throughput in 1994 which represented approximately 5.9% of system 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 System. 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 and are filled with LNG trucked from Hopkinton.
The Company has a contract for LNG service with Hopkinton extending through 1996, thereafter renewable year to year with notice of termination due five years in advance. Contract payments include a demand charge sufficient to cover Hopkinton's fixed charges and an operating charge which covers liquefaction 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.
COMMONWEALTH GAS 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) Automatic Adjustment Clauses
The Company has a Standard Seasonal Cost of Gas Adjustment rate schedule (CGA) which provides for the recovery, from firm customers, of purchased gas costs not recovered through base rates. These schedules, which require DPU approval, are estimated semi-annually and include credits for gas pipeline refunds and profit margins applicable to interruptible sales. Actual gas costs are reconciled annually as of October 31, and any difference is included as an adjustment in the calculation of the decimals for the two subsequent six-month periods.
The DPU and the Massachusetts Energy Facilities Siting Council (the Council) were merged in 1992. The Council is now a division of the DPU. Periodically, the Company is required to file a long-range forecast of the energy needs and requirements of its market area and annual supplements thereto with the Council. To approve a long-range forecast, the Council must find, among other things, that the Company's plans for construction of new gas manufacturing or storage facilities and certain high-pressure gas pipelines are consistent with current health, environmental protection, resource use and development policies as adopted by the Commonwealth of Massachusetts. The Company filed a long-range forecast with the Council on July 20, 1990 and updated aspects of the filing in March 1991. This forecast was combined with the DPU review of the ANE contract. Both issues remain pending before the DPU.
(b) Gas Demand, Take-or-Pay Costs and Transition Costs
The Company is obligated, as part of its pipeline transportation contracts, storage contracts and gas purchase contracts, to pay monthly demand charges which are recovered from customers through the CGA.
In June 1991, Tennessee filed a settlement with the FERC dealing with a variety of contract restructuring issues, including the allocation of take-or- pay costs to Tennessee's customers, including the Company. This comprehensive settlement was approved and implemented on July 1, 1992. As part of the settlement, the allocation of take-or-pay costs was changed from a deficiency basis to a contract demand basis which increased the Company's allocation. There are still some small on-going amounts of take-or-pay costs being collected by the pipeline, however, Tennessee has nearly reached the cap of allowable collections under the settlement.
Algonquin made a series of filings with the FERC to recover from its customers take-or-pay charges imposed on it by its upstream suppliers. Algonquin billed the Company for gas supply inventory charges from Texas Eastern and others through the Algonquin commodity rate. With the implementation of Order 636, Algonquin allocated the remaining costs utilizing a formula based on actual purchases for the twelve months prior to May 1, 1993. The Company's allocation was in excess of $5 million. The Company
COMMONWEALTH GAS COMPANY
successfully appealed Algonquin's allocation method to the FERC. The change in allocation, combined with issues being settled in Algonquin's current rate case will reduce the Company's allocated share to $2.5 million. In addition, a settlement was reached with Koch Gateway Pipeline (formerly the United Gas Pipeline) whereby the Company, in October 1994, received approximately $2 million in refunds for take-or-pay costs allocated through Texas Eastern and Algonquin since 1985. This amount is currently being refunded to firm customers through the CGA.
As a direct result of implementation of Order 636, most pipeline companies are incurring transition costs which include the cost of restructuring gas supply contracts, the value of facilities that were supporting the gas sales function and are no longer used and useful for transportation only services, the cost of contracts with upstream pipeline companies and various miscellaneous costs. For additional information on these transition costs refer to Note 5(c) of Notes to Financial Statements filed under Item 8 of this report.
The Company is collecting all contract restructuring costs from its customers through the CGA as permitted by the DPU.
(c) Regulatory Matters
On April 16, 1991, the Company requested a $27.7 million (11.3%) revenue increase in a filing with the DPU using a test-year ended December 31, 1990. On September 16, 1991, the DPU approved a settlement of the revenue requirements portion of the filing authorizing a $22.8 million increase in annual revenues, approximately 82% of the original request. The agreement included a return on equity, for accounting purposes, of 13%. The DPU later ruled on the rate design portion of the request and new rates went into effect on November 1, 1991.
In May 1994, the Company requested the DPU to change the backup 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 causes beyond the customer's control. The change involved an upward indexing of backup charges based on changes in the gas supply demand costs occasioned by Order 636. On December 22, 1994, the DPU approved the Company's requested change effective 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) Quasi-firm and Off-system Gas Sales Services
In late August 1994, the Company received regulatory approval for a new quasi-firm sales service, designed for larger customers, which provides a level of service between full firm and interruptible. In exchange for prices lower than full firm service, quasi-firm customers will receive interruptible service in peak demand months and firm service in off-peak months. These arrangements will give the Company and its customers more flexibility in supply management and pricing options.
Also, during 1994, the Company was able to maximize the use of its gas supply resources through off-system sales. Twenty percent of the gas
COMMONWEALTH GAS COMPANY
purchased was sold outside the Company's franchise area. These efforts helped to reduce the cost of gas to the Company's firm customers helping to make the Company more competitive in its traditional markets.
The margin realized on these sales is shared with one-half used to reduce the cost of gas to firm customers and the other deferred pending DPU approval of the Company's margin sharing proposal that is expected to be filed in 1995.
(e) Conservation and Load Management Program
The Company offers conservation measures to its residential and multi- family customers through programs approved by the DPU in June 1992. The Company recovers the costs of these programs via separately stated Conservation Charge (CC) decimals. On November 23, 1994, the DPU approved a settlement agreement extending the Company's demand-side management (DSM) programs until October 31, 1995 and allowing the recovery of "lost margins" from its customers commencing in January 1995. Specifically, the settlement allows the Company to recover through the CC decimal the portion of the lost margins related to savings resulting from installations during the twelve- month period which began in November 1994. In addition, the lost margins related to savings occurring from prior period installations will be held in an interest-bearing account pending the completion of a DSM impact evaluation proceeding currently before the DPU.
(f) Potential Impact of Regulatory Restructuring
Based on the current regulatory framework in which it operates, 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." Under SFAS No. 71, a utility is allowed to defer costs that would otherwise be expensed in recognition of the ability to recover them in future rates. As a result, the Company has accumulated $26.9 million of regulatory assets (approximately 7.1% of total assets) as of December 31, 1994. Management believes that the current regulatory framework provides for the continued recovery of these assets.
In the event that recovery of specific costs through rates becomes uncertain or unlikely in the future, either as a result of the expanding effects of competition or specific regulatory actions, the Company could be required to move away from cost-of-service ratemaking and, therefore, SFAS No. 71 would no longer apply. Discontinuation of SFAS No. 71 could lead to the write-off of various regulatory assets, which would have an adverse impact on the Company's financial position and results of operations. At this time, management believes that it is unlikely that regulatory action would lead to the discontinuation of SFAS No. 71 in the near future.
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.
COMMONWEALTH GAS COMPANY
The costs associated with the assessment and clean-up of these sites are recoverable in rates through the cost of gas adjustment clause pursuant to a 1990 DPU order over a seven-year amortization period without carrying costs. The Company has recorded a $2.3 million liability that reflects its best estimate (based on current information) of the costs to be incurred in connection with the assessment and remediation activities identified to this point. The Company has also recorded a regulatory asset in anticipation of recovery of these costs. The Company is unable to predict the total cost to ultimately resolve these matters due to significant uncertainty as to the actual site conditions and the extent of any associated remediation activities and the assignment of responsibility. However, it is expected that all such costs will continue to be recovered in rates as described above.
The Company is also involved in certain other known or potentially contaminated sites where the associated costs may not be recoverable in rates. The Company has recorded an estimated liability (and a charge to operations) of $500,000 to cover the expected costs associated with assessment and remediation activities. These estimates are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. As noted above, the Company is unable to predict at this time the ultimate cost to resolve these matters due to the uncertainties inherent in the site investigation and remediation process.
Construction and Financing
Information concerning the Company's financing and construction programs is contained in Note 5(a) of the Notes to Financial Statements filed under Item 8 of this report.
Employees
The Company has 723 regular employees which represents a 5.5% decrease from last year's level. Approximately 67% of these employees are represented by three collective bargaining units with agreements in effect until September 15, 1995, March 31, 1996 and June 30, 1996. Employee relations have generally been satisfactory.
Item 2.
Item 2. Properties
The Company's principal gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At the end of 1994, the gas system included 2,761 miles of gas distribution lines, 162,971 services and 239,302 customer meters together with the necessary 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.
The Company's property is subject to encumbrances under its Indenture of Trust and First Mortgage Bonds.
Item 3.
Item 3. Legal Proceedings
The Company is not a party to any pending material legal proceeding.
COMMONWEALTH GAS COMPANY
PART II.
Item 5.
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, 1994
One
(c) Frequency and Amount of Dividends Declared in 1994 and 1993
1994 1993 Per Share Per Share Declaration Date Amount Declaration Date Amount
January 24, 1994 $2.10 January 28, 1993 $2.17 April 21, 1994 2.50 April 15, 1993 3.75 July 15, 1994 .50 July 15, 1993 .50 $5.10 $6.42
(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.
COMMONWEALTH GAS COMPANY
Item 7.
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 facilitate an understanding of the results of operations. This discussion should be read in conjunction with the Notes to Financial Statements filed under Item 8
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed herewith on pages 14 through 32 of this report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1994
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Commonwealth Gas Company:
We have audited the accompanying balance sheets of COMMONWEALTH GAS COMPANY (a Massachusetts corporation and wholly-owned subsidiary of Commonwealth Energy System) as of December 31, 1994 and 1993, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, effective January 1, 1993, the Company changed its method of accounting for costs associated with postretirement benefits other than pensions.
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 schedules 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 Arthur Andersen LLP Boston, Massachusetts February 21, 1995
COMMONWEALTH GAS COMPANY INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1994 and 1993
Statements of Income for the Years Ended December 31, 1994, 1993 and
Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992
Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and
Notes to Financial Statements
PART IV.
SCHEDULE
II Valuation and Qualifying Accounts for the Years Ended December 31, 1994, 1993 and 1992
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.
COMMONWEALTH GAS COMPANY BALANCE SHEETS DECEMBER 31, 1994 AND 1993 ASSETS
1994 1993 (Dollars in Thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $339 476 $323 607 Less - Accumulated depreciation 85 162 77 155 254 314 246 452 Add - Construction work in progress 719 400 255 033 246 852
CURRENT ASSETS Cash 4 862 1 297 Accounts receivable - Affiliated companies 462 173 Customers, less reserves of $2,827,000 in 1994 and $3,162,000 in 1993 32 890 33 066 Unbilled revenues 20 892 29 068 Inventories, at average cost - Natural gas 24 161 25 810 Materials and supplies 1 593 1 979 Prepaid taxes - Property 2 861 2 629 Income 619 1 812 Other 1 076 992 89 416 96 826
DEFERRED CHARGES Order 636 transition costs 19 201 21 938 Other 17 155 11 067 36 356 33 005
$380 805 $376 683
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY BALANCE SHEETS DECEMBER 31, 1994 AND 1993 CAPITALIZATION AND LIABILITIES
1994 1993 (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 6 837 7 840 106 001 107 004 Long-term debt, less current sinking fund requirements 91 750 95 400 197 751 202 404
CURRENT LIABILITIES Interim Financing - Notes payable to banks 24 950 40 975 Advances from affiliates 11 220 2 835 36 170 43 810
Other Current Liabilities - Current sinking fund requirements 3 650 3 650 Accounts payable - Affiliated companies 2 669 1 811 Other 33 214 32 944 Refundable gas costs 27 832 13 253 Customer deposits 1 433 1 440 Accrued local property and other taxes 3 317 2 940 Accrued interest 749 774 Other 4 746 4 447 77 610 61 259 113 780 105 069 DEFERRED CREDITS Accumulated deferred income taxes 32 699 30 176 Unamortized investment tax credits 6 065 6 270 Order 636 transition costs 7 811 13 133 Other 22 699 19 631 69 274 69 210 COMMITMENTS AND CONTINGENCIES $380 805 $376 683
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
1994 1993 1992 (Dollars in Thousands)
GAS OPERATING REVENUES $325 726 $304 129 $297 233
OPERATING EXPENSES Cost of gas sold 188 769 167 607 164 871 Other operation 74 636 71 776 69 126 Maintenance 11 809 11 929 11 611 Depreciation 9 559 8 939 8 270 Amortization 1 238 1 233 3 224 Taxes - Income 7 983 9 843 8 578 Local property 5 336 4 865 4 608 Payroll and other 2 715 2 779 2 632 302 045 278 971 272 920
OPERATING INCOME 23 681 25 158 24 313
OTHER INCOME 421 637 297
INCOME BEFORE INTEREST CHARGES 24 102 25 795 24 610
INTEREST CHARGES Long-term debt 8 488 6 345 7 004 Other interest charges 2 073 3 170 2 769 Allowance for borrowed funds used during construction (27) (19) (18) 10 534 9 496 9 755
NET INCOME $ 13 568 $ 16 299 $ 14 855
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
1994 1993 1992 (Dollars in Thousands)
Balance at beginning of year $ 7 840 $ 6 994 $ 1 767
Add (Deduct): Net income 13 568 16 299 14 855 Cash dividends on common stock (14 571) (15 453) (9 628)
Balance at end of year $ 6 837 $ 7 840 $ 6 994
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
1994 1993 1992 (Dollars in Thousands) OPERATING ACTIVITIES Net income $13 568 $16 299 $14 855 Effects of noncash items - Depreciation and amortization 15 159 11 363 12 100 Deferred income taxes 3 883 8 018 1 478 Investment tax credits (205) (210) (217) Change in working capital exclusive of cash and interim financing - Accounts receivable and unbilled revenues 8 063 (4 714) (4 544) Prepaid income taxes 1 193 4 878 729 Local property and other taxes, net 145 57 136 Accounts payable and other 17 925 (6 873) 3 032 Deferred postretirement benefit costs (2 306) (3 062) - Deferred Order 636 transition costs, net (2 585) (8 805) - All other operating items (7 393) (9 065) (3 003) Net cash provided by operating activities 47 447 7 886 24 566
INVESTING ACTIVITIES Additions to property, plant and equipment (exclusive of AFUDC) (17 994) (23 272) (20 437) Allowance for borrowed funds used during construction (27) (19) (18) Net cash used for investing activities (18 021) (23 291) (20 455)
FINANCING ACTIVITIES Sale of common stock to Parent - 18 000 - Payment of dividends (14 571) (15 453) (9 628) Proceeds from (payment of) short-term borrowings (16 025) (11 500) 14 875 Proceeds from (payment of) affiliate borrowings 8 385 (5 705) 3 275 Retirement of long-term debt through sinking funds (3 650) (3 650) (3 657) Long-term debt issues refunded - - (9 110) Long-term debt issues - 35 000 - Net cash provided by (used for) financing activities (25 861) 16 692 (4 245)
Net increase (decrease) in cash 3 565 1 287 (134) Cash at beginning of period 1 297 10 144 Cash at end of period $ 4 862 $ 1 297 $ 10
Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $ 9 799 $ 8 797 $ 9 377 Income taxes $ 4 636 $ 3 133 $ 6 167
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY NOTES TO FINANCIAL STATEMENTS
(1) Significant Accounting Policies
(a) General and Regulatory
Commonwealth Gas Company (the Company) is a wholly-owned subsidiary of Commonwealth Energy System. The parent company is referred to in this report as the "System" and together with its subsidiaries, is referred to as "the system." The Company is regulated as to rates, accounting and other matters by the Massachusetts Department of Public Utilities (DPU). The System is an exempt 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 has established various regulatory assets in cases where the DPU has permitted or is expected to permit recovery of specific costs over time. Similarly, the regulatory liability established by the Company is required to be refunded to customers over time. The principal regulatory assets included in deferred charges at December 31, 1994 and 1993 were as follows:
1994 1993 (Dollars in Thousands)
FERC Order 636 transition costs $19,201 $21,938 Postretirement benefit costs including pensions 5,367 3,062 Environmental costs 2,346 1,768 Total regulatory assets $26,914 $26,768
Regulatory assets as a percent of total assets 7.1% 7.1%
The principal regulatory liability, reflected in deferred credits-other and relating to income taxes, was $9.9 million and $10 million at December 31, 1994 and 1993, respectively.
(b) Reclassifications
Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements.
COMMONWEALTH GAS COMPANY
(c) Transactions with Affiliates
Operating revenues include sales of gas to affiliated companies as follows: (Dollars in Thousands) 1994 Cost Margin Total
Cambridge Electric $1 493 $ 220 $1 713
Cambridge Electric $1 311 $ 76 $1 387
Cambridge Electric $1 784 $ 334 $2 118 Commonwealth Electric 100 5 105 $1 884 $ 339 $2 223
The margin realized on these sales is credited to firm customers through the CGA.
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 $10,126,000, $9,587,000 and $8,683,000 in 1994, 1993 and 1992, respectively. Transactions with other system companies are subject to review by the DPU.
(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 DPU.
The amount of such costs incurred by the Company but not yet reflected in customers' bills is recorded as unbilled revenues. However, as of December 31, 1994 and 1993, the Company had overcollected $27,832,000 and $13,253,000, respectively, which is reflected as a liability in the accompanying balance sheets. These overcollected amounts, which include interest, are returned to customers in subsequent months.
(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 2.98% in 1994, 2.95% in 1993 and 2.90% in 1992.
COMMONWEALTH GAS COMPANY
(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 the accompanying statements of income.
While AFUDC does not provide funds currently, these amounts are recoverable in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 4.75% in 1994, 3.5% in 1993 and 4.25% in 1992.
(2) 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 System, and it makes tax payments or receives refunds on the basis of its tax attributes in the tax return in accordance with applicable regulations.
The following is a summary of the provisions for income taxes for the years ended December 31, 1994, 1993 and 1992:
1994 1993 1992 (Dollars in Thousands) Federal - Current $3 585 $1 619 $6 093 Deferred 3 405 6 956 1 422 Investment tax credits (205) (210) (217) 6 785 8 365 7 298
State - Current 720 416 1 224 Deferred 667 1 278 343 1 387 1 694 1 567 8 172 10 059 8 865 Amortization of regulatory liability relating to deferred income taxes (189) (216) (287)
Total federal and state income taxes $ 7 983 $ 9 843 $ 8 578
COMMONWEALTH GAS COMPANY
Effective January 1, 1992, the Company adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109). SFAS No. 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement basis and tax basis 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 1994 and 1993: 1994 1993 (Dollars in Thousands) Liabilities Property-related $39 768 $37 230 Order 636 transition costs, net 4 094 3 450 Postretirement benefits plan 2 101 1 422 All other 3 075 1 419 49 038 43 521
Assets Investment tax credit 3 914 4 047 Pension plan 2 739 2 284 Regulatory liability 3 155 3 006 Inventory repricing 4 285 2 946 All other 2 828 2 785 16 921 15 068 Accumulated deferred income taxes, net $32 117 $28 453
The net year-end deferred income tax liability above is net of current deferred tax assets of $582,000 in 1994 and $1,723,000 in 1993 which are included in prepaid income taxes in the accompanying balance sheets.
The total income tax provision set forth on the previous page represents 37% in 1994, 38% in 1993 and 37% in 1992 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages:
1994 1993 1992
Federal statutory rate 35% 35% 34%
Federal income tax expense at statutory levels $7 543 $9 150 $7 967 Increase (Decrease) from statutory rate: State tax net of federal tax benefit 902 1 101 1 064 Amortization of investment tax credits (205) (209) (217) Amortization of excess deferred reserves (189) (216) (140) Other (68) 17 (96) $8 572 $9 843 $11 989
Effective federal tax rate 37% 38% 37%
As a result of the Revenue Reconciliation Act of 1993, the Company's federal income tax rate was increased to 35% effective January 1, 1993.
COMMONWEALTH GAS COMPANY
(3) Long-Term Debt and Interim Financing
(a) Long-Term Debt
Long-term debt outstanding, exclusive of current sinking fund requirements, collateralized by substantially all of the Company's property, is as follows:
Original Balance December 31, Issue 1994 1993 (Dollars in Thousands) First Mortgage Bonds - 8.99%, Series H, due 1996 $10 000 $10 000 $10 000 8.99%, Series I, due 2001 40 000 21 750 25 400 9.95%, Series J, due 2020 25 000 25 000 25 000 7.11%, Series K, due 2033 35 000 35 000 35 000 $91 750 $95 400
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 requirements under favorable conditions. The required sinking fund payments and balances of maturing debt issues for the five years subsequent to December 31, 1994 are as follows:
Sinking Fund Maturing Debt Year Requirements Issues Total (Dollars in Thousands)
1995 $3 650 $ - $ 3 650 1996 3 650 10 000 13 650 1997 3 650 - 3 650 1998 3 650 - 3 650 1999 3 650 - 3 650
(b) Notes Payable to Banks
The Company and other system companies maintain both committed and uncommitted lines of credit for the financing of their construction programs, on a short-term basis, and for other corporate purposes. As of December 31, 1994, system companies had $90 million of committed lines that will expire at varying intervals in 1995. These lines are normally renewed upon expiration and require annual fees ranging from zero to .1875% of the individual line. At December 31, 1994, the uncommitted lines of credit totaled $90 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 4.4% and 3.3% in 1994 and 1993, respectively. The Company's notes payable to banks totaled $24,950,000 and $40,975,000 at December 31, 1994 and 1993, respectively.
(c) Advances from Affiliates
The Company had short-term notes payable to the System totaling $2,935,000 and $355,000 at December 31, 1994 and 1993, respectively. These notes are written for a term of up to 11 months and 29 days. Interest is at
COMMONWEALTH GAS COMPANY
the prime rate and is adjusted for changes in that rate during the term of the notes. This rate averaged 7.3% and 6% in 1994 and 1993, respectively.
The Company is a member of the COM/Energy Money Pool (the Pool), an arrangement among the subsidiaries of the System, 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 outstanding 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 borrowings are for a period of less than one year and are payable upon demand. Rates on these borrowings averaged 4.3% and 3.2% in 1994 and 1993, respectively. The Company had borrowings from the Pool of $8,285,000 and $2,480,000 at December 31, 1994 and 1993, respectively.
(d) Disclosures about Fair Value of Financial Instruments
As required by Statement of Financial Accounting Standards No. 107, "Disclosures about Fair Value of Financial Instruments," the fair value of certain financial instruments included in the accompanying balance sheets as of December 31, 1994 and 1993 are as follows:
1994 1993 (Dollars in Thousands)
Carrying Fair Carrying Fair Value Value Value Value
Long-Term Debt $95 400 $93 134 $99 050 $111 718
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.
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.
(4) 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 one 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.
COMMONWEALTH GAS COMPANY
Components of pension expense and related assumptions to develop pension expense were as follows: 1994 1993 1992 (Dollars in Thousands)
Service cost $ 2 278 $ 1 904 $ 1 720 Interest cost 6 378 6 037 5 478 Return on plan assets - (gain)/loss 1 345 (10 821) (7 278) Net amortization and deferral (6 297) 6 317 3 001 Total pension expense 3 704 3 437 2 921 Transfers from affiliated companies, net 478 453 466 Less: Amounts capitalized and deferred 336 328 370 Net pension expense $ 3 846 $ 3 562 $ 3 017
1994 1993 1992
Discount rate 7.25% 8.50% 8.50% Assumed rate of return 8.50 8.50 8.50 Rate of increase in future compensation 4.50 5.50 5.50
Pension expense 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 funded status of the Company's pension plan (using a measurement date of December 31) is as follows:
1994 1993 (Dollars in Thousands) Accumulated benefit obligation: Vested $(58 636) $(61 668) Nonvested (6 767) (8 297) $(65 403) $(69 965)
Projected benefit obligation $(81 747) $(85 269) Plan assets at fair market value 75 568 79 553 Projected benefit obligation less (greater) than plan assets (6 179) (5 716) Unamortized transition obligation 4 336 4 955 Unrecognized prior service cost 5 830 5 115 Unrecognized gain (9 934) (9 141) Accrued pension liability $ (5 947) $ (4 787)
The following actuarial assumptions were used in determining the plan's year-end funded status: 1994 1993
Discount rate 8.50% 7.25% Rate of increase in future compensation 5.00 4.50
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.
COMMONWEALTH GAS COMPANY
(b) Other Postretirement Benefits
Through December 31, 1992, the Company provided postretirement health care and life insurance benefits to eligible retired employees. Employees became eligible for these benefits if their age plus years of service at retirement equaled 75 or more, provided, however, that such service was performed for a subsidiary of the System. As of January 1, 1993, the Company eliminated postretirement health care benefits for those non-bargaining employees who were less than 40 years of age or had less than 12 years of service at that date. Under certain circumstances, eligible employees are now required to make contributions for postretirement benefits. Certain bargaining employees are also participating under these new eligibility requirements.
Effective January 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106). This new standard requires the accrual of the expected cost of such benefits during the employees' years of service and the recognition of an actuarially determined postretirement benefit obligation earned by existing retirees. The assumptions and calculations involved in determining the accrual and the accumulated postretirement benefit obligation (APBO) closely parallel pension accounting requirements. The cumulative effect of implementation of SFAS No. 106 as of January 1, 1993 was approximately $34 million, which is being amortized over 20 years. Prior to 1993, the cost of postretirement benefits was recognized as the benefits were paid. The cost of retiree medical care and life insurance benefits totaled $1,910,000 during 1992.
In 1993, the Company began making contributions to various voluntary employees' beneficiary association (VEBA) trusts that were established 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 satisfy a portion of its postretirement benefit obligation. The Company contributed approximately $4.5 million and $3.8 million to these trusts during 1994 and 1993, respectively.
The net periodic postretirement benefit cost for the years ended December 31, 1994 and 1993 include the following components and related assumptions:
1994 1993 (Dollars in Thousands)
Service cost $ 581 $ 535 Interest cost 2 572 2 858 Return on plan assets (47) (203) Amortization of transition obligation over 20 years 1 700 1 700 Net amortization and deferral (320) 22 Total postretirement benefit cost 4 486 4 912 Transfers to affiliated companies, net 539 540 Less: Amounts capitalized and deferred 2 785 3 564 Net postretirement benefit cost $ 2 240 $ 1 888
COMMONWEALTH GAS COMPANY
1994 1993
Discount rate 7.25% 8.50% Assumed rate of return 8.50 8.50 Rate of increase in future compensation 4.50 4.50
The funded status of the Company's postretirement benefit plan using a measurement date of December 31, 1994 and 1993 is as follows:
1994 1993 (Dollars in Thousands)
Accumulated postretirement benefit obligation: Retirees $ (20 304) $ (20 779) Fully eligible active plan participants (4 060) (4 152) Other active plan participants (10 082) (10 847) (34 446) (35 778) Plan assets at fair market value 5 681 3 296 Accumulated postretirement benefit obligation greater than plan assets (28 765) (32 482) Unamortized transition obligation 30 604 32 304 Unrecognized (gain) loss (1 839) 178 $ - $ -
The following actuarial assumptions were used in determining the plan's year-end funded status:
1994 1993
Discount rate 8.50% 7.25% Rate of increase in future compensation 5.00 4.50
In determining its estimated APBO and the funded status of the plan for 1994 and 1993, the Company assumed estimated health care trend rates as follows:
1994 1993
Medicare part B premiums 12.30% 14.90% Medical care 8.50 9.00 Dental care 5.00 5.00
The above rates, with the exception of the dental rate, which remains constant, decrease to five percent in the year 2007 and remain at that level thereafter. A one percent change in the medical trend rate would have a $446,000 impact on the Company's annual expense (interest component - $318,000; service cost - $128,000) and would change the transition obligation by approximately $1.3 million.
Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect post- retirement benefit expense in future years.
COMMONWEALTH GAS COMPANY
The DPU's policy on postretirement benefits is to allow in rates the maximum tax deductible contributions made to trusts that have been established specifically to pay postretirement benefits. The Company intends to seek regulatory approval to recover these costs and, while the outcome cannot be predicted, it is likely that the DPU will authorize similar rate treatment as was provided to Cambridge Electric and other Massachusetts electric and gas companies. A deferral representing the difference between what is being collected in rates and the SFAS No. 106 accrual amounted to approximately $5.4 million in 1994 and $3.1 million in 1993.
(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 other than pensions. The Company's contribution was $1,447,000 in 1994, $1,444,000 in 1993 and $1,284,000 in 1992.
(5) Commitments and Contingencies
(a) Construction and Financing Program
The Company is engaged in a continuous construction program presently estimated at $106.4 million for the five-year period 1995 through 1999. Of that amount, $21.2 million is estimated for 1995. 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 environmental factors. The Company expects to finance future expenditures on an interim basis with internally generated funds and short-term borrowings which are ultimately expected to be repaid with the proceeds from the issuance of long-term debt and/or equity securities.
(b) LNG Service Contract
The Company has contracted with Hopkinton LNG Corp., a wholly-owned subsidiary of the System, for liquefaction and vaporization services over a period ending in 1996, thereafter, renewable year to year with notice of termination due five years in advance. The Company is obligated to pay demand charges throughout the contract periods in addition to charges for operating costs.
(c) FERC Order No. 636
As a result of implementing FERC Order 636 (Order 636), each interstate pipeline company is allowed to collect certain transition costs from its customers that resulted from the pipelines' need to buy out gas supply contracts entered into prior to the issuance of Order 636. The Company has been billed a total of approximately $21.7 million from Tennessee Gas
COMMONWEALTH GAS COMPANY
Pipeline Company, Algonquin Gas Transmission Company and Texas Eastern Transmission Company through December 31, 1994.
As of October 29, 1993, the Company received preliminary DPU autho- rization to recover these costs, with carrying charges, through the cost of gas adjustment (CGA) over a four-year period that began in November 1993. As a result, a regulatory asset totaling $19.2 million is reflected in deferred charges as of December 31, 1994. In addition, a related liability of $7.8 million is reflected in deferred credits. Final DPU approval for recovery was received in March 1995.
After extensive negotiations between Texas Eastern, Tennessee and their customers (including the Company), settlements were reached regarding a number of transition obligation issues. The settlement with Texas Eastern, which was recently approved by FERC, calls for the pipeline to absorb approximately 20% of all transition costs incurred from June 1993 forward. This agreement also provides for an extended billing period and annual caps on the collection of future costs. The Company believes that the absorption requirement will give the pipeline incentive to minimize future costs. The settlement resulted in a refund of $2.7 million to the Company, which will be refunded to firm customers beginning in 1995.
The proposed settlement with Tennessee will lower one element of the Company's transition obligation by approximately $1 million and enhance certain services the Company receives from Tennessee. Further negotiations are underway with Tennessee to craft a total settlement similar to that achieved with Texas Eastern.
The Company is continuing to negotiate with the pipelines on several other issues. As a result, the Company is unable to predict its final transition obligation at this time; however, based on these and subsequent settlement activities, the Company will adjust its regulatory asset and liability accounts accordingly.
(6) Gas Refunds
During 1994, 1993 and 1992, 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 $6,077,000 in 1994, $6,965,000 in 1993 and $7,012,000 in 1992.
(7) 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 obligations.
COMMONWEALTH GAS COMPANY
Future minimum lease payments, by period and in the aggregate, of non- cancelable operating leases consisted of the following at December 31, 1994:
Operating Leases (Dollars in Thousands)
1995 $ 3 321 1996 2 607 1997 1 249 1998 780 1999 324 Beyond 1999 517 Total future minimum lease payments $ 8 798
Total rent expense for all operating leases, except those with terms of a month or less, amounted to $3,699,000 in 1994, $3,435,000 in 1993 and $3,171,000 in 1992. There were no contingent rentals and no sublease rentals for the years 1994, 1993 and 1992.
(8) 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 "Environmental Matters" filed under Item 1 of this report for additional information.)
COMMONWEALTH GAS COMPANY
PART IV.
Item 14.
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 Schedules (page 15).
(a) 2. Index to Financial Statement Schedules
Filed herewith at page indicated is financial statement schedule of the Company:
Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1994, 1993 and 1992 (page 41).
(a) 3. Exhibits:
Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are incorporated by reference to the appropriate exhibit numbers and the Securities and Exchange Commission file numbers indicated in parentheses.
b. During 1981, New Bedford Gas and Edison Light Company sold its gas business and properties to the Company and changed its corporate name to Commonwealth Electric Company.
c. The following is a glossary of acronyms used throughout the Exhibit Index:
COMMONWEALTH GAS COMPANY
AGT Algonquin Gas Transmission Company CE Commonwealth Electric Company CEC Canal Electric Company CEL Cambridge Electric Light Company CES Commonwealth Energy System CG Commonwealth Gas Company CNG CNG Transmission Corporation CRC Citizens Resources Corporation HOPCO Hopkinton LNG Corp. NBGEL New Bedford Gas and Edison Light Company TET Texas Eastern Transmission Corporation TGP Tennessee Gas Pipeline Company TGT Tennessee Gas Transmission Corporation
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 System)
1. Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File No. 2-7820). 2. First Supplemental on Form S-1 (Mar., 1950) (Exhibit 7(a), File No. 2-8418). 3. Second Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(2), File No. 2-10445). 4. Third Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(3), File No. 2-10445). 5. Fourth Supplemental on Form S-9 (Oct. 1954) (Exhibit 2(b)(5), File No. 2-15089). 6. Fifth Supplemental on Form S-9 (Mar., 1956) (Exhibit 2(b)(6), File No. 2-15089). 7. Sixth Supplemental on Form S-9 (Apr., 1957) (Exhibit 2(b)(7), File No. 2-15089). 8. Seventh Supplemental on Form S-9 (June 1959) (Exhibit 2(b)(8), File No. 2-20532). 9. Eighth Supplemental on Form S-9 (Sept. 1961) (Exhibit 2(b)(9), File No. 2-20532). 10. Ninth Supplemental on Form 8-K (Aug. 1962) (Exhibit A, File No. 2- 1647). 11. Tenth Supplemental on Form 10-K (1970) (Exhibit 2, File No. 2- 1647).
COMMONWEALTH GAS COMPANY
12. Eleventh Supplemental on Form S-1 (June, 1972) (Exhibit 4(b)(2), File No. 2-48556). 13. Twelfth Supplemental on Form S-1 (Aug., 1973) (Exhibit 4(b)(3), File No. 2-48556). 14. Thirteenth Supplemental on Form 10-K (1992) (Exhibit 1, File No. 2-1647). 15. Fourteenth Supplemental on Form 10-K (1990) (Exhibit 1, File No. 2-1647). 16. Fifteenth Supplemental on Form 10-K (1982) (Exhibit 1, File No. 2- 1647). 17. Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2- 1647). 18. Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No. 2-1647). 19. Eighteenth Supplemental on Form 10-Q (March, 1994) (Exhibit 1, File No. 2-1647)
Exhibit 10. Material Contracts.
10.1. Natural Gas Purchase Contracts.
10.1.3 Gas Service Contract between HOPCO and NBGEL dated September 1, 1971 for the performance of liquefaction, storage and vaporization services and the operation and maintenance of an LNG Facility located at Acushnet, MA (Exhibit 8 to the CG 1984 Form 10-K, File No. 2-1647).
10.1.3.1 Supplement 1 to Gas Service Contract between HOPCO and NBGEL dated September 1, 1973 and September 14, 1977 (Exhibit 5(c)5 to the CES Form S-16 (June 1979), File No. 2-64731).
10.1.4 Gas Service Contract between HOPCO and CG dated September 1, 1971 for the performance of liquefaction, storage and vaporization services and the operation of LNG facilities located in Hopkinton, MA (Exhibit 9 to the CG 1984 Form 10-K, File No. 2-1647).
10.1.4.1 Amendments to 10.1.3 and 10.1.4 as amended December 1, 1976 (Exhibits 2 and 3 to the CG 1986 Form 10-K, File No. 2-1647).
10.1.4.2 Supplement 2 to 10.1.4 dated September 30, 1982 (Exhibit 2 to the CG 1992 Form 10-K, File No. 2-1647).
10.1.5 Supplement 1 to Gas Service Contract between HOPCO and CG dated September 14, 1977 (Exhibit 5(c)6 to the CES Form S-16 (June 1979), File No. 2-64731).
10.1.6 Firm Storage Service Transportation Contract by and between TGT and CG providing for firm transportation of natural gas from Consolidated Gas Transmission Corporation dated December 15, 1985 (Exhibit 1 to the CG 1985 Form 10-K, File No. 2-1647).
10.1.7 Agency Agreement for Certain Transportation Arrangements by and between CG and CRC whereby CRC arranges for a third party transportation of natural gas acquired by CG dated April 14, 1986 (Exhibit 1 to the CG Form 10-Q (June 1986), File No. 2-1647).
COMMONWEALTH GAS COMPANY
10.1.8 Natural Gas Sales Agreement between CG and CRC dated April 14, 1986 (Exhibit 2 to the CG Form 10-Q (June 1986), File No. 2-1647).
10.1.9 Gas Sales Agreement by and between Enron Gas Marketing, Inc. and CG relating to the sale and purchase of natural gas on an interruptible basis, dated June 17, 1986 (Exhibit 3 to the CG Form 10-Q (June 1986), File No. 2-1647).
10.1.10 Agency Agreement for Certain Transportation Arrangements dated June 18, 1985 and Gas Purchase and Sales Agreement dated August 6, 1985 by and between CG and Tenngasco Corporation and other related entities (Exhibit 4 to the CG Form 10-Q (June 1986), File No. 2- 1647).
10.1.11 Service Agreement dated December 14, 1985 and an amendment thereto dated May 15, 1986 by and between TET and CG to receive, transport and deliver to points of delivery natural gas for the account of the CG dated December 14, 1985 (Exhibit 5 to the CG Form 10-Q (June 1986), File No. 2-1647).
10.1.12 Gas Transportation Agreement by and between TET and CG to receive transport and deliver on an interruptible basis, certain quantities of natural gas for the account of CG dated January 31, 1986 (Exhibit 6 to the CG Form 10-Q (June 1986), File No. 2-1647).
10.1.13 Gas Sales Agreement by and between Texas Eastern Gas Trading Company and CG providing for the sale of certain quantities of natural gas to CG dated May 15, 1986 (Exhibit 7 to the CG Form 10- Q (June 1986), File No. 2-1647).
10.1.14 Service Agreement Applicable to Rate Schedule between AGT and CG dated April 11, 1985 for the purchase of certain quantities of natural gas acquired by AGT from Consolidated Gas Supply Corporation (Exhibit 2 to the CG Form 10-Q (March 1987), File No. 2-1647).
10.1.15 Service Agreement Applicable to Rate Schedule between AGT and CG dated April 11, 1985 for the purchase of certain quantities of natural gas acquired by AGT from National Fuel Gas Supply Corporation (Exhibit 3 to the CG Form 10-Q (March 1987), File No. 2-1647).
10.1.16 Service Agreement Applicable to Rate Schedule between AGT and CG dated December 26, 1985 for the purchase of certain quantities of natural gas acquired by AGT from TET (Exhibit 4 to the CG Form 10-Q (March 1987), File No. 2-1647).
10.1.17 Service Agreement Applicable to Rate Schedule TS-3 between TET and CG dated April 16, 1987 for Firm natural gas service (Exhibit 1 to the CG Form 10-Q (June 1987), File No. 2-1647).
10.1.18 Natural Gas Sales Agreement between Summit Pipeline and Producing Company and CG dated April 16, 1987 (Exhibit 2 to the CG Form 10-Q (June 1987), File No. 2-1647).
COMMONWEALTH GAS COMPANY
10.1.19 Natural Gas Sales Agreement between Natural Gas Supply Company and CG dated May 12, 1987 (Exhibit 3 to the CG Form 10-Q (June 1987), File No. 2-1647).
10.1.20 Natural Gas Sales Agreement between Stellar Gas Company and CG dated April 15, 1988 (Exhibit 1 to the CG Form 10-Q (March 1988), File No. 2-1647).
10.1.21 1986 Consolidating Supplement to CG Service Contract and NBGEL by and between CG and HOPCO dated December 31, 1986 amending and consolidating the CG Service Contract and the New Bedford Gas Service Contract both as amended December 1, 1976 and supplemented September 14, 1977 (Exhibit 2 to the CG Form 10-Q (March 1988), File No. 2 -1647).
10.1.22 Natural Gas Sales Agreement between Amalgamated Gas Pipeline Company and CG dated April 5, 1988 (Exhibit 1 to the CG Form 10-Q (June 1988), File No. 2-1647).
10.1.23 Natural Gas Sales Agreement between Gulf Ohio Pipeline Corporation and CG dated May 18, 1988 (Exhibit 2 to the CG Form 10-Q (June 1988), File No. 2-1647).
10.1.24 Natural Gas Sales Agreement between Phillips Petroleum Company and CG dated May 18, 1988 (Exhibit 3 to the CG Form 10-Q (June 1988), File No. 2-1647).
10.1.25 Service Agreement dated May 19, 1988, by and between TET and CG, whereby TET agrees to receive, transport and deliver natural gas to CG (Exhibit 1 to the CG Form 10-Q (September 1988), File No. 2- 1647).
10.1.26 Natural Gas Sales Agreement between TXO Gas Marketing Corp. and CG dated April 25, 1988 (Exhibit 1 to the CG 1988 Form 10-K, File No. 2-1647).
10.1.27 Gas Transportation Agreement by and between AGT and CG to receive, transport and deliver certain quantities of natural gas on a firm basis for the account of CG dated December 1, 1988 (Exhibit 2 to the CG 1988 Form 10-K, File No. 2-1647).
10.1.28 Natural Gas Sales Agreement between Enermark Gas Gathering Corporation and CG dated January 6, 1989 (Exhibit 3 to the CG 1988 Form 10-K, File No. 2-1647).
10.1.29 Gas Sales Agreement between BP Gas Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated March 31, 1989 with a contract term of at least one year (Exhibit 1 to the CG Form 10-Q (March 1989), File No. 2 -1647).
10.1.30 Gas Sales Agreement between Tejas Power Corporation (seller) and CG (purchaser) for the purchase of spot market gas, dated February 21, 1989 with a contract term of at least one year (Exhibit 2 to the CG Form 10-Q (March 1989), File No. 2-1647).
COMMONWEALTH GAS COMPANY
10.1.31 Gas Sales Agreement between Catamount Natural Gas, Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated April 5, 1988, with a contract term of at least one year (Exhibit 1 to the CG Form 10-Q (June 1989), File No. 2-1647).
10.1.32 Gas Sales Agreement between Transco Energy Marketing Company (seller) and CG (purchaser) for the purchase of spot market gas, dated March 1, 1989, with a contract term of at least one year (Exhibit 2 to the CG Form 10-Q (June 1989), File No. 2-1647).
10.1.33 Gas Storage Agreement between Steuben Gas Storage Company and CG (customer) for the storage and delivery of customer's natural gas to and from underground gas storage facilities, dated May 23, 1989, with a contract term of at least one year (Exhibit 4 to the CG Form 10-Q (June 1989), File No. 2-1647).
10.1.34 Gas Sales Agreement between V.H.C. Gas Systems, L.P. (seller) and CG (purchaser) for the purchase of spot market gas, dated June 2, 1989, with a contract term of at least one year (Exhibit 3 to the CG Form 10-Q (June 1989), File No. 2-1647).
10.1.35 Gas Sales Agreement between End-Users Supply System (seller) and CG (purchaser) for the purchase of spot market gas, dated June 29, 1989, with a contract term of at least one year (Exhibit 1 to the CG Form 10-Q (September 1989), File No. 2-1647).
10.1.36 Gas Sales Agreement between Entrade Corporation (seller) and CG (purchaser) for the purchase of spot market gas, dated August 14, 1989, with a contract term of at least one year (Exhibit 2 to the CG Form 10-Q (September 1989), File No. 2-1647).
10.1.36.1 Amendment to 10.1.36 dated August 28, 1989 (Exhibit 5 to the CG Form 10-Q (September 1989), File No. 2-1647).
10.1.37 Gas Sales Agreement between Fina Oil and Chemical Company (seller) and CG (purchaser) for the purchase of spot market gas, dated July 10, 1989, with a contract term of at least one year (Exhibit 3 to the CG Form 10-Q (September 1989), File No. 2-1647).
10.1.38 Gas Sales Agreement between Mobil Natural Gas, Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated August 14, 1989, with a contract term of at least one year (Exhibit 4 to the CG Form 10-Q (September 1989), File No. 2-1647).
10.1.39 Gas Sales Agreement between PSI, Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated September 25, 1989, with a contract term of at least one year (Exhibit 1 to the CG 1989 Form 10-K, File No. 2-1647).
COMMONWEALTH GAS COMPANY
10.1.40 Gas Sales Agreement between Hadson Gas Systems (seller) and CG (purchaser) for the purchase of firm gas, dated August 15, 1990, with a contract term of at least six years (Exhibit 1 to the CG Form 10-Q (September 1990), File No. 2-1647).
10.1.41 Gas Sales Agreement between Odeco Oil Company (seller) and CG (purchaser) for the purchase of firm gas, dated August 15, 1990, with a contract term of at least five years (Exhibit 2 to the CG Form 10-Q (September 1990), File No. 2-1647).
10.1.42 AGT, CG, and Distrigas of Massachusetts Corporation have entered into an agreement in connection with the deliveries of regasified liquified natural gas into the Algonquin J-system dated August 1, 1990 (Exhibit 3 to the CG Form 10-Q (September 1990), File No. 2- 1647).
10.1.43 Gas Sales Agreement between TEX/CON Marketing Gas Company (seller) and CG (purchaser) for the purchase of firm gas, dated September 12, 1990, with a contract term of five years (Exhibit 3 to the CG 1990 Form 10-K, File No. 2-1647).
10.1.44 Transportation Agreement between AGT and CG to provide for firm transportation of natural gas on a daily basis, dated December 1, 1988 (Exhibit 3 to the CG 1991 Form 10-K, File No. 2-1647).
10.1.45 Transportation Assignment Agreement between AGT and CG regarding Rate Schedule ATAP Agreement No. 9020016 which provides for the assignment, on an interruptible basis, of firm service rights on TET's system under Rate Schedule FT-1, dated January 3, 1990, for a term ending October 31, 1999 (Exhibit 4 to the CG 1991 Form 10- K, File No. 2-1647).
10.1.46 Gas Sales Agreement between AGT and CG to reduce the volume of Rate Schedule, dated October 15, 1990 (Exhibit 5 to the CG 1991 Form 10-K, File No. 2-1647).
10.1.47 Transportation Agreement between AGT and CG for Rate Schedule AFT- 1, Agreement No. 90103, dated November 1, 1990 (Exhibit 6 to the CG 1991 Form 10-K, File No. 2-1647).
10.1.48 Transportation Assignment Agreement between AGT and CG regarding Rate Schedule ATAP Agreement No. 90202, which provides for the assignment, on a firm basis, of firm service rights on TET's system under Rate Schedule FT-1, dated November 1, 1990 (Exhibit 7 to the CG 1991 Form 10-K, File No. 2-1647).
10.1.49 Gas Sales Agreement Between TGP and CG under TGP's CD-6 Rate Schedules dated September 1, 1991, (Exhibit 8 to the CG 1991 Form 10-K, File No. 2-1647).
10.1.50 Transportation Agreement between TGP and CG dated September 1, 1991 (Exhibit 9 to the CG 1991 Form 10-K, File No. 2-1647).
COMMONWEALTH GAS COMPANY
10.1.51 Transportation Agreement between CNG and CG to provide for transportation 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).
10.1.52 Service Line Agreement by and between CG and Milford Power Limited Partnership dated March 12, 1992 for a term ending January 1, 2013 (Exhibit 1 to the CG Form 10-Q (March 1992), 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 System'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 System's Form 10-Q (September 1993), File No. 1-7316).
Filed herewith:
Exhibit 27. Financial Data Schedule for the year ended December 31, 1994 (Filed herewith as Exhibit 1)
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the three months ended December 31, 1994.
SCHEDULE II
COMMONWEALTH GAS COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 and 1992
(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, 1994
$ 3 162 $ 5 496 $1 405 $ 7 236 $ 2 827
Year Ended December 31, 1993
$ 2 890 $ 5 585 $ 1 079 $ 6 392 $ 3 162
Year Ended December 31, 1992
$ 2 271 $ 5 678 $ 1 063 $ 6 122 $ 2 890
COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1994
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: WILLIAM G. POIST William G. Poist, 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:
WILLIAM G. POIST March 29, 1995 William G. Poist, Chairman of the Board and Chief Executive Officer
KENNETH M. MARGOSSIAN March 30, 1995 Kenneth M. Margossian, President and Chief Operating Officer
Principal Financial Officer: JAMES D. RAPPOLI March 29, 1995 James D. Rappoli, Financial Vice President and Treasurer
Principal Accounting Officer:
JOHN A. WHALEN March 29, 1995 John A. Whalen, Comptroller
A majority of the Board of Directors:
WILLIAM G. POIST March 29, 1995 William G. Poist, Director
JAMES D. RAPPOLI March 29, 1995 James D. Rappoli, Director
KENNETH M. MARGOSSIAN March 30, 1995 Kenneth M. Margossian, Director