<PAGE 1> 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 [FEE REQUIRED] For the fiscal year ended December 31, 1995 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] 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 15, 1996 Common Stock, $25 par value 2,857,000 shares The Company meets the conditions set forth in General Instruction J(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 34 of this report. <PAGE 2> COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1995 TABLE OF CONTENTS PART I PAGE Item 1. Business........................................ 3 General....................................... 3 Gas Supply General..................................... 3 Hopkinton LNG Facility...................... 4 Rates and Regulation.......................... 5 Competition................................... 7 Environmental Matters......................... 8 Construction and Financing.................... 8 Employees..................................... 9 Item 2. Properties...................................... 9 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 8. Financial Statements and Supplementary Data..... 14 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............. 14 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 34 Signatures.................................................. 43 <PAGE 3> 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 233,000 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. Of the Company's 1995 firm gas unit sales, 55.5% was sold to residential customers, 27.8% to commercial customers, 11.6% to industrial customers and 5.1% 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 contractually scheduled times. 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 required 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 <PAGE 4> 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. Further information concerning Order 636 is contained in Note 6(c) of the Notes to Financial Statements filed under Item 8 of this report. 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 1995, over 99% of the gas utilized by the Company was delivered by the interstate pipeline system. The remaining small quantity (approximately 150,000 MMBTU) was delivered as 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 DPU approved the ANE gas supply contract in November 1995. The Company should complete assumption of these contracts during the first half of 1996 upon final execution of all pertinent agreements and contracts. The Company began transporting gas on its distribution system in 1990 for end-users. There are currently thirty-four customers using this transportation service, accounting for 6,791 BBTU of throughput in 1995 which represented approximately 12.9% 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 <PAGE 5> COMMONWEALTH GAS COMPANY 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) 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 and conservation and load management 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 and other non-firm 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 were approved by the DPU in November 1995. (b) Gas Demand 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. 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 6(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. <PAGE 6> COMMONWEALTH GAS COMPANY (c) Regulatory Matters In May 1994, the Company requested the DPU 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 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 customers with dual-fuel capability, that provides a level of service between full firm and interruptible. In exchange for prices lower than full firm service, quasi-firm customers receive interruptible service in peak demand months and firm service in off-peak months. The Company sold 1,906 BBTU of gas to quasi-firm customers in 1995. Also in 1995, the Company was able to maximize the use of its gas supply portfolio through off-system sales and capacity release. In 1995, 4,043 BBTU of gas was sold in the off-system market and 10,352 BBTU of pipeline capacity was released. These efforts helped to reduce the cost of gas to the Company's firm customers while allowing more flexibility in supply management and pricing options. A portion of the margins realized on quasi-firm and off-system sales (approximately $2 million as of December 31, 1995) is currently being deferred pending a ruling on a margin-sharing proposal filed with the DPU in December 1995 for quasi-firm sales. A similar filing is expected to be filed for off- system sales in 1996. Both quasi-firm and off-system sales allow the Company to more efficiently utilize its gas distribution system and enable fixed costs to be spread over larger volumes of throughput. This results in a lower cost of gas for firm customers helping the Company to remain as competitive as possible in its traditional core market. (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. The programs have been extended through subsequent DPU approvals, the most noteworthy being the settlement agreement approved on November 23, 1994 which enabled the Company to recover "lost margins" from customers effective January 1995. Specifically, the settlement allows the Company to remain whole while it offers programs that reduce sales, by recovering through the CC decimal the portion of the lost margins revenue associated with all saved therms resulting from conservation program installations. As a result, the Company collected $1.4 million in lost margins during 1995, and has obtained approval to collect $2.1 million in lost margins during 1996. <PAGE 7> COMMONWEALTH GAS COMPANY (f) Potential Impact of Regulatory Restructuring 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 DPU has permitted or is expected to permit recovery of specific costs over time. These regulatory assets amounted to $22 million (5.9% of total assets) as of December 31, 1995. Similarly, the regulatory liability established by the Company is required to be refunded to customers over time. In March 1995, the Financial Accounting Standards Board issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. Management does not expect that the effects of SFAS No. 121, which the Company adopted on January 1, 1996, will have a material impact on its financial position or results of operations. 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. Innovative pricing mechanisms have been developed and will continue to be developed to retain existing customers, add new retail and wholesale customers and expand beyond current markets. Aggressive marketing efforts have increased our residential heating customer base by more than 1,500 during 1995. In addition, there are vast opportunities in natural gas engine-driven cooling systems and absorption chillers which are being actively and successfully pursued by the Company and will add desirable off-peak summer load. The Company has also expanded existing services such as the merchandising of water-heaters and heating systems. FERC Order 636 marked the beginning of the deregulation and restructuring of the natural gas industry. In addition to opening up customer markets to competition, the regulations shifted many supply-related responsibilities to local distribution companies 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 very sophisticated purchasing and tracking systems. This ability, coupled with aggressive planning and procurement strategies, will help to 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. <PAGE 8> COMMONWEALTH GAS COMPANY The Company continues to reduce costs and improve service through state- of-the-art technology. Some of the examples of cost-effective technology presently in use include: (1) Automated Meter Reading (AMR) which has dramatically lowered meter reading costs, improved the rate at which meters are read, and enhanced customer convenience. To date, 80% of the Company's meters are equipped with AMR technology and the read rate has improved to nearly 100%; (2) a new trenchless technology that enables the Company to maintain or upgrade its distribution system with a minimum of cost and disturbance with a device known as a "bullet" that allows the replacement of old gas lines with polyethylene pipe, eliminating the need for costly and time-consuming street excavations; and (3) the use of a miniature camera that inspects the inside walls of low pressure mains without interrupting service to customers and replaces the more traditional method which involved costly digging and manual inspection to find problem areas. 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. 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 $2.6 million liability that reflects its best estimate (based on current information) of the costs to be incurred in connection with 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. In 1994 the Company 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 estimate its ultimate liability for future environmental remediation costs. However, in view of the Company's current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, management does not believe that these matters will have a material adverse impact on the Company's results of operations or financial position. 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. <PAGE 9> COMMONWEALTH GAS COMPANY Employees The Company has 699 regular employees which is 3.3% lower than last year's level. Approximately 64% of these employees are represented by three collective bargaining units with agreements in effect through March 31, 1996, June 30, 1996 and September 18, 1998. Employee relations have generally been satisfactory. 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 1995, the gas system included 2,778 miles of gas distribution lines, 164,697 services and 240,948 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. Legal Proceedings The Company is not a party to any pending material legal proceeding. <PAGE 10> 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, 1995 One (c) Frequency and Amount of Dividends Declared in 1995 and 1994 1995 1994 Per Share Per Share Declaration Date Amount Declaration Date Amount January 25, 1995 $1.75 January 24, 1994 $2.10 April 21, 1995 2.65 April 21, 1994 2.50 $4.40 July 15, 1994 .50 $5.10 (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. <PAGE 11> 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 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 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, 1995 and 1994 and unit sales for these periods is shown below: Years Ended Years Ended December 31, December 31, 1995 and 1994 1994 and 1993 Increase (Decrease) (Dollars in Thousands) Gas Operating Revenues $(16 804) (5.2)% $21 597 7.1 % Operating Expenses - Cost of gas sold (19 657) (10.4) 21 162 12.6 Other operation and maintenance (2 756) (3.1) 2 745 3.3 Depreciation 97 1.0 620 6.9 Taxes - Federal and state income 1 686 21.1 (1 860) (18.9) Local property 462 8.7 471 9.7 Payroll and other 103 3.8 (64) (2.3) (20 065) (6.6) 23 074 8.3 Operating Income 3 261 13.8 (1 477) (5.9) Other Income 812 192.9 (216) (33.9) Income Before Interest Charges 4 073 16.9 (1 693) (6.6) Interest Charges 1 412 13.4 1 038 10.9 Net Income $ 2 661 19.6 $(2 731) (16.8) Unit Sales (BBTU) Firm (81) (0.2) % (680) (1.7)% Interruptible (1 437) (52.0) 302 12.3 Off-system (2 358) (36.8) 6 401 - Quasi-firm 1 419 291.4 487 - (2 457) (5.1) 6 510 15.6 <PAGE 12> COMMONWEALTH GAS COMPANY The following is a summary of unit sales, transportation volume and customers for the periods indicated: Years Ended December 31, 1995 1994 1993 Unit Sales (BBTU): Residential 21 336 21 515 22 252 Commercial 10 710 10 728 10 931 Industrial 4 445 4 401 4 205 Other 1 967 1 895 1 831 Total firm 38 458 38 539 39 219 Off-System 4 043 6 401 - Quasi-Firm 1 906 487 - Interruptible 1 324 2 761 2 459 Total sales 45 731 48 188 41 678 Transportation 6 791 3 003 3 171 Total 52 522 51 191 44 849 Customers at End of Period: Residential 212 329 211 075 211 877 Commercial 18 761 18 466 18 323 Industrial 933 928 920 Other 1 168 1 140 1 093 Total 233 191 231 609 232 213 Operating Revenues, Cost of Gas Sold and Unit Sales In 1995, operating revenues decreased by $16.8 million or 5.2% mainly due to a decrease in the cost of gas sold ($19.7 million), lower conservation and load management (C&LM) costs ($910,000) and a decrease in unit sales. Partially offsetting these decreases were higher transportation revenues ($2.3 million). In 1994, operating revenues increased by $21.6 million or 7.1% mainly due to a $21 million increase in the cost of gas sold, revenues associated with off-system and quasi-firm sales, which were non-existent in 1993, and higher transportation revenues ($478,000). Also contributing to the increase were higher C&LM costs ($2.6 million). Partially offsetting these increases was a decrease in firm unit sales of 1.7%. The cost of gas sold in 1995 and 1994 reflects prices and sales levels as well as the amortization of Order 636 transition costs ($1.3 million in 1995, $3.6 million in 1994 and $396,000 in 1993) and refunds received from gas suppliers ($9.1 million in 1995, $6.1 million in 1994 and $7 million in 1993). Despite extremely mild weather conditions experienced throughout the region during the first quarter of 1995, a very cold fourth quarter left unit sales virtually unchanged for the year. Firm unit sales decreased by 1.7% in 1994 due to the unseasonably warm weather conditions experienced throughout the region in the fourth quarter. This more than offset a 5.4% increase in the first quarter of 1994 resulting from the colder than normal weather. Interruptible sales decreased by 52% in 1995 and increased by approximately 12% in 1994 reflecting the competitive market conditions for energy resources that exists today as well as the conversion of interruptible sales to quasi- firm. Interruptible sales have no impact on net income since all of the margins from these sales are flowed back to firm customers through the CGA. <PAGE 13> COMMONWEALTH GAS COMPANY Off-system sales and quasi-firm sales fluctuated but are expected to continue as important elements of the Company's total gas service options. The Company anticipates that the aforementioned margin-sharing proposal for these sales will have a positive impact on earnings while continuing to reduce the cost of gas to firm customers. The customer level increased slightly in 1995 mainly due to new home construction and conversion activity and was virtually unchanged in 1994. Other Operating Expenses In 1995, other operation and maintenance decreased by $2.8 million or 3.1% mainly due to lower C&LM costs ($910,000), lower distribution expenses due to fewer leak repair activities ($699,000), a decreased provision for bad debts ($640,000), lower insurance and employee benefit costs ($471,000) and decreased engineering expenses ($392,000). Also contributing to the decrease was net savings in several areas resulting primarily from the implementation of automated meter reading (AMR) ($100,000). These decreases were partially offset by increased labor costs ($1.2 million). Other operation and maintenance increased by approximately 3.3%, or $2.7 million, in 1994 due mainly to higher C&LM charges ($2.6 million) and higher insurance and employee benefit costs ($821,000). These increases were offset, in part, by a decline in the cost of services rendered by affiliate COM/Energy Services Company attributable to a second quarter 1993 work force reduction and a 2% ($683,000) decline in payroll costs reflecting a lower work force level achieved through attrition and reduced overtime. Depreciation and Taxes The increase in depreciation expense in both 1995 and 1994 resulted from higher levels of depreciable plant-in-service. The increase in federal and state income taxes in 1995 and the decrease in 1994 was due to the respective levels of pretax income. The change in payroll and other taxes in both periods reflects the level of payroll costs in each period. The increase in local property taxes during both 1995 and 1994 was due to higher tax rates and assessments in the Company's service territory. Other Income and Interest Charges In 1995, other income increased by $812,000 due primarily to interest income received by the Company in connection with its participation in the COM/Energy Money Pool. Other income decreased by $216,000 in 1994 due primarily to the absence of a litigation settlement received in 1993 ($193,000) and lower sales of design heating systems offset, in part, by interest related to a Massachusetts sales tax abatement ($58,000). Total interest charges increased by $1.4 million in 1995 mainly due to higher interest on deferred gas costs partially offset by a decrease in short- term interest charges reflecting lower levels of debt. <PAGE 14> COMMONWEALTH GAS COMPANY Total interest charges increased by more than $1 million in 1994 mainly due to the issuance of $35 million in new long-term debt in December 1993 and, to a lesser extent, higher interest rates and interest to be refunded to the Company's customers in connection with the aforementioned sales tax abatement. These increases were partially offset by a lower average level of short-term borrowings. Item 8. Financial Statements and Supplementary Data The Company's financial statements required by this item are filed herewith on pages 15 through 33 of this report. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. <PAGE 15> COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1995 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 Commonwealth Energy System) as of December 31, 1995 and 1994, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, 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 16, 1996. <PAGE 16> COMMONWEALTH GAS COMPANY INDEX TO FINANCIAL STATEMENTS AND SCHEDULE PART II. FINANCIAL STATEMENTS Balance Sheets at December 31, 1995 and 1994 Statements of Income for the Years Ended December 31, 1995, 1994 and 1993 Statements of Retained Earnings for the Years Ended December 31, 1995, 1994 and 1993 Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993 Notes to Financial Statements PART IV. SCHEDULE II Valuation and Qualifying Accounts for the Years Ended December 31, 1995, 1994 and 1993 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 17> COMMONWEALTH GAS COMPANY BALANCE SHEETS DECEMBER 31, 1995 AND 1994 ASSETS 1995 1994 (Dollars in Thousands) PROPERTY, PLANT AND EQUIPMENT, at original cost $348 284 $339 476 Less - Accumulated depreciation 92 881 85 162 255 403 254 314 Add - Construction work in progress 738 719 256 141 255 033 CURRENT ASSETS Cash 2 113 4 862 Accounts receivable - Affiliated companies 188 462 Customers, less reserves of $2,691,000 in 1995 and $2,827,000 in 1994 40 317 32 890 Unbilled revenues 22 850 20 892 Inventories, at average cost - Natural gas 17 339 24 161 Materials and supplies 1 286 1 593 Prepaid taxes - Property 3 094 2 861 Income 384 619 Other 1 138 1 076 88 709 89 416 DEFERRED CHARGES Order 636 transition costs 11 711 19 201 Other 18 054 17 155 29 765 36 356 $374 615 $380 805 The accompanying notes are an integral part of these financial statements. <PAGE 18> COMMONWEALTH GAS COMPANY BALANCE SHEETS DECEMBER 31, 1995 AND 1994 CAPITALIZATION AND LIABILITIES 1995 1994 (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 10 495 6 837 109 659 106 001 Long-term debt, less maturing issues and current sinking fund requirements 78 100 91 750 187 759 197 751 CURRENT LIABILITIES Interim Financing - Notes payable to banks 12 200 24 950 Advances from affiliates 1 850 11 220 Maturing long-term debt 10 000 - 24 050 36 170 Other Current Liabilities - Current sinking fund requirements 3 650 3 650 Accounts payable - Affiliated companies 2 229 2 669 Other 37 471 33 214 Refundable gas costs 33 034 27 832 Customer deposits 1 354 1 433 Accrued local property and other taxes 3 435 3 317 Accrued interest 1 938 749 Other 3 535 4 746 86 646 77 610 110 696 113 780 DEFERRED CREDITS Accumulated deferred income taxes 35 586 32 699 Unamortized investment tax credits 5 862 6 065 Order 636 transition costs 11 711 7 811 Other 23 001 22 699 76 160 69 274 COMMITMENTS AND CONTINGENCIES $374 615 $380 805 The accompanying notes are an integral part of these financial statements. <PAGE 19> COMMONWEALTH GAS COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 1995 1994 1993 (Dollars in Thousands) GAS OPERATING REVENUES $308 922 $325 726 $304 129 OPERATING EXPENSES Cost of gas sold 169 112 188 769 167 607 Other operation 72 138 74 636 71 776 Maintenance 11 577 11 809 11 929 Depreciation 9 656 9 559 8 939 Amortization 1 212 1 238 1 233 Taxes - Income 9 669 7 983 9 843 Local property 5 798 5 336 4 865 Payroll and other 2 818 2 715 2 779 281 980 302 045 278 971 OPERATING INCOME 26 942 23 681 25 158 OTHER INCOME 1 233 421 637 INCOME BEFORE INTEREST CHARGES 28 175 24 102 25 795 INTEREST CHARGES Long-term debt 8 174 8 488 6 345 Other interest charges 3 827 2 073 3 170 Allowance for borrowed funds used during construction (55) (27) (19) 11 946 10 534 9 496 NET INCOME $ 16 229 $ 13 568 $ 16 299 The accompanying notes are an integral part of these financial statements. <PAGE 20> COMMONWEALTH GAS COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 1995 1994 1993 (Dollars in Thousands) Balance at beginning of year $ 6 837 $ 7 840 $ 6 994 Add (Deduct): Net income 16 229 13 568 16 299 Cash dividends on common stock (12 571) (14 571) (15 453) Balance at end of year $10 495 $ 6 837 $ 7 840 The accompanying notes are an integral part of these financial statements. <PAGE 21> COMMONWEALTH GAS COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 1995 1994 1993 (Dollars in Thousands) OPERATING ACTIVITIES Net income $16 229 $13 568 $16 299 Effects of noncash items - Depreciation and amortization 12 983 15 159 11 363 Deferred income taxes (4 026) 3 883 8 018 Investment tax credits (203) (205) (210) Change in working capital exclusive of cash and interim financing - Accounts receivable and unbilled revenues (9 111) 8 063 (4 714) Prepaid income taxes 235 1 193 4 878 Local property and other taxes, net (115) 145 57 Accounts payable and other 15 985 17 925 (6 873) Deferred postretirement benefit costs (2 376) (2 306) (3 062) Transition costs, net 11 390 (2 585) (8 805) All other operating items 10 908 (7 393) (9 065) Net cash provided by operating activities 51 899 47 447 7 886 INVESTING ACTIVITIES Additions to property, plant and equipment (exclusive of AFUDC) (16 252) (17 994) (23 272) Allowance for borrowed funds used during construction (55) (27) (19) Net cash used for investing activities (16 307) (18 021) (23 291) FINANCING ACTIVITIES Sale of common stock to Parent - - 18 000 Payment of dividends (12 571) (14 571) (15 453) Payment of short-term borrowings (12 750) (16 025) (11 500) Proceeds from (payment of) affiliate borrowings (9 370) 8 385 (5 705) Retirement of long-term debt through sinking funds (3 650) (3 650) (3 650) Long-term debt issue - - 35 000 Net cash provided by (used for) financing activities (38 341) (25 861) 16 692 Net increase (decrease) in cash (2 749) 3 565 1 287 Cash at beginning of period 4 862 1 297 10 Cash at end of period $ 2 113 $ 4 862 $ 1 297 Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $11 035 $ 9 799 $ 8 797 Income taxes $ 8 118 $ 4 636 $ 3 133 The accompanying notes are an integral part of these financial statements. <PAGE 22> 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 company is referred to in this report as the "System" and, together with its subsidiaries, is referred to as "the system." The System is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935 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 233,000 customers in a 1,067 square-mile area which includes 49 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 699 regular employees including 447 (64%) who are repre- sented by three collective bargaining units. Agreements with two units representing approximately 63% of regular employees are scheduled to expire in 1996. Employee relations have generally been satisfactory. (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 Public Utilities (DPU). 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 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. In March 1995, the Financial Accounting Standards Board issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. Management does not expect that the effects of SFAS No. 121, which the Company adopted on <PAGE 23> COMMONWEALTH GAS COMPANY January 1, 1996, will have a material impact on its financial position or results of operations. The principal regulatory assets included in deferred charges at December 31, 1995 and 1994 were as follows: 1995 1994 (Dollars in Thousands) Transition costs $11 711 $19 201 Postretirement benefit costs including pensions 7 744 5 367 Environmental costs 2 551 2 346 Total regulatory assets $22 006 $26 914 The principal regulatory liability, reflected in deferred credits-other and relating to income taxes, was $8.6 million and $9.9 million at December 31, 1995 and 1994, respectively. (c) Transactions with Affiliates Operating revenues include sales of gas to affiliate Cambridge Electric Light Company as follows: (Dollars in Thousands) 1995 1994 1993 Cost $ 289 $1 493 $1 311 Margin 64 220 76 Total $ 353 $1 713 $1 387 The margin realized on these sales is credited to firm customers through the Cost of Gas Adjustment (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 $9,988,000, $10,126,000 and $9,587,000 in 1995, 1994 and 1993, respectively. Transactions with 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, 1995 and 1994, the Company had overcollected $33,034,000 and $27,832,000, respectively, which is reflected as a liability in the <PAGE 24> COMMONWEALTH GAS COMPANY 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 2.90% in 1995, 2.98% in 1994 and 2.95% in 1993. (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 6.50% in 1995, 4.75% in 1994 and 3.50% in 1993. (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 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. <PAGE 25> COMMONWEALTH GAS COMPANY The following is a summary of the provisions for income taxes for the years ended December 31, 1995, 1994 and 1993: 1995 1994 1993 (Dollars in Thousands) Federal - Current $11 602 $3 585 $1 619 Deferred (3 155) 3 405 6 956 Investment tax credits (203) (205) (210) 8 244 6 785 8 365 State - Current 2 296 720 416 Deferred (618) 667 1 278 1 678 1 387 1 694 9 922 8 172 10 059 Amortization of regulatory liability relating to deferred income taxes (253) (189) (216) Total federal and state income taxes $ 9 669 $ 7 983 $ 9 843 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 1995 and 1994: 1995 1994 (Dollars in Thousands) Liabilities Property-related $42 361 $39 768 Transition costs, net - 4 094 Postretirement benefits plan 2 933 2 101 All other 1 734 3 075 47 028 49 038 Assets Investment tax credit 3 783 3 914 Pension plan 3 099 2 739 Regulatory liability 2 992 3 155 Inventory repricing 4 047 4 285 All other 3 707 2 828 17 628 16 921 Accumulated deferred income taxes, net $29 400 $32 117 The net year-end deferred income tax liability above is net of current deferred tax assets of $6,186,000 in 1995 and $582,000 in 1994 which are included in other deferred charges in the accompanying balance sheets. <PAGE 26> COMMONWEALTH GAS COMPANY The total income tax provision set forth on the previous page represents 37% in 1995, 37% in 1994 and 38% in 1993 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages: 1995 1994 1993 Federal statutory rate 35% 35% 35% Federal income tax expense at statutory levels $9 064 $7 543 $9 150 Increase (Decrease) from statutory rate: State tax net of federal tax benefit 1 091 902 1 101 Amortization of investment tax credits (203) (205) (210) Amortization of excess deferred reserves (253) (189) (216) Other (30) (68) 18 $9 669 $7 983 $ 9 843 Effective federal tax rate 37% 37% 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 1995 1994 (Dollars in Thousands) First Mortgage Bonds - 8.99%, Series H, due 1996 $10 000 $ - $10 000 8.99%, Series I, due 2001 40 000 18 100 21 750 9.95%, Series J, due 2020 25 000 25 000 25 000 7.11%, Series K, due 2033 35 000 35 000 35 000 $78 100 $91 750 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, 1995 are as follows: Sinking Fund Maturing Debt Year Requirements Issues Total (Dollars in Thousands) 1996 $3 650 $10 000 $13 650 1997 3 650 - 3 650 1998 3 650 - 3 650 1999 3 650 - 3 650 2000 3 650 - 3 650 <PAGE 27> COMMONWEALTH GAS COMPANY (b) Notes Payable to Banks The Company and other system companies maintain both committed and uncommitted lines of credit for the short-term financing of their construction programs, on a short-term basis, and for other corporate purposes. As of December 31, 1995, system companies had $80 million of committed lines that will expire at varying intervals in 1996. These lines are normally renewed upon expiration and require annual fees up to .1875% of the individual line. At December 31, 1995, the uncommitted lines of credit totaled $70 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 6.1% and 4.4% in 1995 and 1994, respectively. The Company's notes payable to banks totaled $12,200,000 and $24,950,000 at December 31, 1995 and 1994, respectively. (c) Advances from Affiliates The Company had short-term notes payable to the System totaling $1,425,000 and $2,935,000 at December 31, 1995 and 1994, respectively. 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 8.8% and 7.3% in 1995 and 1994, 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 5.8% and 4.3% in 1995 and 1994, respectively. The Company had borrowings from the Pool of $425,000 and $8,285,000 at December 31, 1995 and 1994, respectively. (d) Disclosures about Fair Value of Financial Instruments The fair value of certain financial instruments included in the accompanying balance sheets as of December 31, 1995 and 1994 are as follows: 1995 1994 (Dollars in Thousands) Carrying Fair Carrying Fair Value Value Value Value Long-Term Debt $91 750 $103 055 $95 400 $ 93 134 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 28> 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 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. Components of pension expense and related assumptions to develop pension expense were as follows: 1995 1994 1993 (Dollars in Thousands) Service cost $ 1 912 $ 2 278 $ 1 904 Interest cost 7 094 6 378 6 037 Return on plan assets - (gain)/loss (18 598) 1 345 (10 821) Net amortization and deferral 12 909 (6 297) 6 317 Total pension expense 3 317 3 704 3 437 Transfers from affiliated companies, net 463 478 453 Less: Amounts capitalized and deferred 342 336 328 Net pension expense $ 3 438 $ 3 846 $ 3 562 Discount rate 8.50% 7.25% 8.50% Assumed rate of return 9.00 8.50 8.50 Rate of increase in future compensation 5.00 4.50 5.50 <PAGE 29> COMMONWEALTH GAS COMPANY 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: 1995 1994 (Dollars in Thousands) Accumulated benefit obligation: Vested $(71 818) $(58 636) Nonvested (7 805) (6 767) $(79 623) $(65 403) Projected benefit obligation $(96 032) $(81 747) Plan assets at fair market value 91 168 75 568 Projected benefit obligation greater than plan assets (4 864) (6 179) Unamortized transition obligation 3 717 4 336 Unrecognized prior service cost 5 327 5 830 Unrecognized gain (10 685) (9 934) Accrued pension liability $ (6 505) $ (5 947) The following actuarial assumptions were used in determining the plan's year-end funded status: 1995 1994 Discount rate 7.25% 8.50% Rate of increase in future compensation 4.25 5.00 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. (b) Other Postretirement Benefits Historically, 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 the Company or 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. The Company adopted the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106) as of January 1, 1993 and the cumulative effect of implementation of SFAS No. 106 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. <PAGE 30> COMMONWEALTH GAS COMPANY The Company makes 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 $4.4 million and $4.5 million to these trusts during 1995 and 1994, respectively. The net periodic postretirement benefit cost for the years ended December 31, 1995 and 1994 include the following components and related assumptions: 1995 1994 (Dollars in Thousands) Service cost $ 452 $ 581 Interest cost 2 848 2 572 Return on plan assets (1 408) (47) Amortization of transition obligation over 20 years 1 700 1 700 Net amortization and deferral 811 (320) Total postretirement benefit cost 4 403 4 486 Transfers to affiliated companies, net 524 539 Less: Amounts capitalized and deferred 2 834 2 785 Net postretirement benefit cost $ 2 093 $ 2 240 Discount rate 8.50% 7.25% Assumed rate of return 9.00 8.50 Rate of increase in future compensation 5.00 4.50 The funded status of the Company's postretirement benefit plan using a measurement date of December 31, 1995 and 1994 is as follows: 1995 1994 (Dollars in Thousands) Accumulated postretirement benefit obligation: Retirees $ (24 263) $ (20 304) Fully eligible active plan participants (3 848) (4 060) Other active plan participants (11 318) (10 082) (39 429) (34 446) Plan assets at fair market value 9 086 5 681 Accumulated postretirement benefit obligation greater than plan assets (30 343) (28 765) Unamortized transition obligation 28 904 30 604 Unrecognized (gain) loss 1 439 (1 839) $ - $ - <PAGE 31> COMMONWEALTH GAS COMPANY The following actuarial assumptions were used in determining the plan's estimated accumulated postretirement benefit obligation (APBO) and funded status for 1995 and 1994: 1995 1994 Discount rate 7.25% 8.50% Rate of increase in future compensation 4.25 5.00 Medicare part B premiums 12.20% 12.30% Medical care 8.00 8.50 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 $393,000 impact on the Company's annual expense and would change the APBO by approximately $4.3 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. The Company defers its SFAS No. 106 costs and intends to seek recovery in its next rate proceeding. While the Company is unable to predict the outcome of this proceeding, it believes the DPU will authorize similar treatment as was provided to affiliate Cambridge Electric and other Massachusetts electric and gas companies for the recovery of the cost of these benefits. Further, based on historical DPU action, the Company believes that it is appropriate to continue deferring the SFAS No. 106 expense as a regulatory asset. At December 31, 1995 and 1994, the Company's deferral amounted to approximately $7.7 million and $5.4 million. (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 $1,439,000 in 1995, $1,447,000 in 1994 and $1,444,000 in 1993. (6) Commitments and Contingencies (a) Construction and Financing Program The Company is engaged in a continuous construction program presently estimated at $92 million for the five-year period 1996 through 2000. Of that amount, $17.7 million is estimated for 1996. 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. <PAGE 32> COMMONWEALTH GAS COMPANY (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 No. 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 $23.8 million from Tennessee Gas Pipeline Company, Algonquin Gas Transmission Company and Texas Eastern Transmission Company through December 31, 1995. The Company's pipeline suppliers have made certain filings with the FERC for the collection of their respective transition costs. The Company's current best estimate of the total remaining transition costs is approximately $11.7 million. This balance has been recorded as a liability with a corresponding regulatory asset. The ultimate level of costs is dependent upon future events, including the market price of natural gas and final settlements between the FERC and the pipeline suppliers. In May 1995, the DPU allowed the Company to accelerate recovery of its Order 636 transition costs that were incurred to date. These costs had been deferred as a regulatory asset and were being recovered through the CGA over a four-year period that began in November 1993. The costs are now being recovered through the CGA over a one-year period that began May 1, 1995. The accelerated recovery was permitted by the DPU due to the minimal impact on customers' bills. Any further transition costs are expected to be recovered by the Company through the CGA as incurred. (7) Gas Refunds During 1995, 1994 and 1993, 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 $9,061,000 in 1995, $6,077,000 in 1994 and $6,965,000 in 1993. (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 obligations. <PAGE 33> 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, 1995: Operating Leases (Dollars in Thousands) 1996 $ 3 070 1997 1 699 1998 1 084 1999 531 2000 347 Beyond 2000 1 387 Total future minimum lease payments $ 8 118 Total rent expense for all operating leases, except those with terms of a month or less, amounted to $3,626,000 in 1995, $3,699,000 in 1994 and $3,435,000 in 1993. There were no contingent rentals and no sublease rentals for the years 1995, 1994 and 1993. (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 "Environmental Matters" filed under Item 1 of this report for additional information.) <PAGE 34> 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 Schedules (page 14). (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, 1995, 1994 and 1993 (page 42). (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: <PAGE 35> 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). <PAGE 36> 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). <PAGE 37> 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 F-2 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 F-3 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 F-4 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). <PAGE 38> 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). <PAGE 39> 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). <PAGE 40> 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 F-1, 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). <PAGE 41> 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, 1995 (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, 1995. <PAGE 42> SCHEDULE II COMMONWEALTH GAS COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 and 1993 (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, 1995 $ 2 827 $ 4 855 $ 1 375 $ 6 366 $ 2 691 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 <PAGE 43> COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1995 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 28, 1996 William G. Poist, Chairman of the Board and Chief Executive Officer KENNETH M. MARGOSSIAN March 29, 1996 Kenneth M. Margossian, President and Chief Operating Officer Principal Financial and Accounting Officer: JAMES D. RAPPOLI March 28, 1996 James D. Rappoli, Financial Vice President and Treasurer A majority of the Board of Directors: WILLIAM G. POIST March 28, 1996 William G. Poist, Director JAMES D. RAPPOLI March 28, 1996 James D. Rappoli, Director KENNETH M. MARGOSSIAN March 29, 1996 Kenneth M. Margossian, Director