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 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 and requires interstate pipelines to unbundle existing gas sales contracts into separate components (gas sales, transportation and storage services). Order 636 provides mechanisms that will allow customers such as the Company to reduce the level of firm services from the pipelines and "broker" excess capacity on a temporary or permanent basis. Order 636 also requires pipelines to provide transportation services that allow customers to receive the same COMMONWEALTH GAS COMPANY
level of service they had with the bundled contracts. In the past, 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 firm gas purchases and firm transportation from various pipelines. Presently, the Company has only transportation, storage, and balancing contracts with these pipelines (and other upstream pipelines that bring gas from the supply wells to the final transporting pipelines), and contracts with a variety of independent vendors for firm gas supply. Twelve new firm gas supply contracts have been negotiated with suppliers and filed with the DPU. During the interim, the Company is operating under short-term firm agreements with these same vendors to provide firm supplies under similar terms and conditions as the long-term agreements, which are presently under review. Approvals are expected during the first half of 1994.
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 agreements and new agreements which are the result of Order 636 requirements for total 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 1993, over 99% of the gas utilized by the Company was delivered by the interstate pipeline system, the remaining small quantity (approximately 360,000 MMBTU) was delivered as liquid LNG from Distrigas of Massachusetts.
The Company entered into a multi-party agreement 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 only eleven customers using this transportation service, accounting for only 1,623 BBTU of throughput in 1993 which represented approximately 3.5% 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 COMMONWEALTH GAS COMPANY
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.
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 dockets 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 and supplier 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. Future take-or-pay costs will be included in Tennessee's Temporary Gas Inventory Charge and transition costs under Tennessee's restructuring pursuant to Order 636. COMMONWEALTH GAS COMPANY
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 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 by $1.5 million to $2.5 million.
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 take-or-pay and other contract restructuring costs from its customers through the CGA as permitted by the DPU. The remaining take-or-pay costs to be billed to the Company from both Algonquin and Tennessee are estimated at approximately $431,000 as of December 31, 1993, subject to change upon FERC approval.
(c) Most Recent Rate Case Proceeding
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. The increase was necessitated by the rising costs of providing service to customers and substantial expenditures to upgrade, improve and maintain the Company's distribution system.
Environmental Matters
The Company is a potentially responsible party (PRP) in the Sullivan's Ledge Superfund site in New Bedford, Massachusetts. In 1990, the Company agreed to a settlement regarding this site and its share of clean-up costs is presently estimated to be $1.8 million and is reflected on the accompanying Balance Sheets. Sampling work at the site indicates that a more extensive clean-up than originally contemplated may be required, although the financial impact of these findings is not presently known. The settling parties for the site are now pursuing claims against a number of non-settling PRPs, and any amounts recovered through those claims will be applied to offset the settling parties' liabilities.
The Company is evaluating a former gas manufacturing plant site in COMMONWEALTH GAS COMPANY
Worcester, Massachusetts, and a proposal for a comprehensive assessment of this site has been prepared. It is possible that this site may require substantial remediation work due to the suspected presence of hazardous substances. However, the cost of remediation cannot be estimated at this time.
The Company anticipates recovery of costs associated with the clean-up of such sites from its customers through a procedure established in a generic order issued by the DPU, wherein such costs are recovered through an element of the existing CGA. These costs are expected to be recovered over a seven- year amortization period without a return on the unamortized balance.
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 765 regular employees, 526 (68.8%) 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 1993, the gas system included 2,739 miles of gas distribution lines, 161,192 services and 237,318 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, 1993
One
(c) Frequency and Amount of Dividends Declared in 1993 and 1992
1993 1992 Per Share Per Share Declaration Date Amount Declaration Date Amount
January 28, 1993 $2.17 April 16, 1992 $3.00 April 15, 1993 3.75 July 16, 1992 1.00 July 15, 1993 .50 $4.00 $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 13 through 31 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, 1993
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, 1993 and 1992, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, 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 schedules listed in the index to financial statements and schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state 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 & CO. Arthur Andersen & Co.
Boston, Massachusetts, February 17, 1994. COMMONWEALTH GAS COMPANY INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1993 and 1992
Statements of Income for the Years Ended December 31, 1993, 1992 and
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and
Notes to Financial Statements
PART IV.
SCHEDULES
V Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991
VI Accumulated Depreciation of Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991
VIII Valuation and Qualifying Accounts for the Years Ended December 31, 1993, 1992 and 1991
IX Short-Term Borrowings for the Years Ended December 31, 1993, 1992 and 1991
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, 1993 AND 1992 ASSETS
1993 1992 (Dollars in Thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $323 607 $304 877 Less - Accumulated depreciation 77 155 72 766 246 452 232 111 Add - Construction work in progress 400 565 246 852 232 676
CURRENT ASSETS Cash 1 297 10 Accounts receivable - Affiliated companies 173 221 Customers, less reserves of $3,162,000 in 1993 and $2,890,000 in 1992 33 066 28 302 Unbilled revenues 29 068 29 070 Inventories, at average cost - Natural gas 25 810 17 906 Materials and supplies 1 979 2 139 Prepaid taxes - Property 2 629 2 329 Income 1 812 6 690 Other 992 1 179 96 826 87 846
DEFERRED CHARGES Order 636 transition costs 21 938 - Other 11 067 7 084 33 005 7 084
$376 683 $327 606 COMMONWEALTH GAS COMPANY BALANCE SHEETS DECEMBER 31, 1993 AND 1992 CAPITALIZATION AND LIABILITIES
1993 1992 (Dollars in Thousands) CAPITALIZATION Common Equity - Common stock, $25 par value - Authorized and outstanding - 2,857,000 shares in 1993 and 2,407,000 in 1992, wholly-owned by Commonwealth Energy System (Parent) $ 71 425 $ 60 175 Amounts paid in excess of par value 27 739 20 989 Retained earnings 7 840 6 994 107 004 88 158 Long-term debt, including premiums, less current sinking fund requirements and maturing debt (Note 3) 95 400 64 050 202 404 152 207
CURRENT LIABILITIES Interim Financing (Note 3) - Notes payable to banks 40 975 52 475 Advances from affiliates 2 835 8 540 43 810 61 015
Other Current Liabilities - Current sinking fund requirements 3 650 3 650 Accounts payable - Affiliated companies 1 811 1 610 Other 32 944 38 712 Refundable gas costs (Note 1) 13 253 7 824 Customer deposits 1 440 1 441 Accrued local property and other taxes 2 940 2 583 Accrued interest 774 781 Other 4 447 3 617 61 259 60 218 105 069 121 233 DEFERRED CREDITS Accumulated deferred income taxes 30 176 27 120 Unamortized investment tax credits 6 270 6 480 Order 636 transition costs 13 133 - Other 19 631 20 565 69 210 54 165 COMMITMENTS AND CONTINGENCIES (Notes 5 and 8) $376 683 $327 606
The accompanying notes are an integral part of these financial statements. COMMONWEALTH GAS COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
1993 1992 1991 (Dollars in Thousands)
GAS OPERATING REVENUES $304 129 $297 233 $258 235
OPERATING EXPENSES Cost of gas sold 167 607 164 871 152 890 Other operation 71 380 69 126 62 926 Maintenance 11 929 11 611 11 608 Depreciation 8 939 8 270 7 910 Amortization 1 629 3 224 2 861 Taxes - Income (Note 2) 9 843 8 578 1 355 Local property 4 865 4 608 3 008 Payroll and other 2 779 2 632 2 755 278 971 272 920 245 313
OPERATING INCOME 25 158 24 313 12 922
OTHER INCOME (EXPENSE) 637 297 (111)
INCOME BEFORE INTEREST CHARGES 25 795 24 610 12 811
INTEREST CHARGES Long-term debt 6 345 7 004 7 523 Other interest charges 3 170 2 769 2 176 Allowance for borrowed funds used during construction (19) (18) (8) 9 496 9 755 9 691
NET INCOME $ 16 299 $ 14 855 $ 3 120
The accompanying notes are an integral part of these financial statements. COMMONWEALTH GAS COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
1993 1992 1991 (Dollars in Thousands)
Balance at beginning of year $ 6 994 $ 1 767 $ 4 063
Add (Deduct) Net income 16 299 14 855 3 120 Cash dividends on common stock (15 453) (9 628) (5 416)
Balance at end of year $ 7 840 $ 6 994 $ 1 767
The accompanying notes are an integral part of these financial statements. COMMONWEALTH GAS COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
1993 1992 1991 (Dollars in Thousands) OPERATING ACTIVITIES Net income $16 299 $14 855 $ 3 120 Effects of non-cash items - Depreciation and amortization 11 363 12 100 11 296 Deferred income taxes 8 018 1 478 453 Investment tax credits (210) (217) (224) Change in working capital exclusive of cash and interim financing - Accounts receivable and unbilled revenues (4 714) (4 544) (13 472) Prepaid income taxes 4 878 729 147 Local property and other taxes, net 57 136 85 Accounts payable and other (6 873) 3 032 (9 620) Uncollected postretirement benefits costs (3 062) - - Uncollected Order 636 costs (8 805) - - All other operating items (9 065) (3 003) (2 276) Net cash provided by (used for) operating activities 7 886 24 566 (10 491)
INVESTING ACTIVITIES Additions to property, plant and equipment (exclusive of AFUDC) (23 272) (20 437) (17 122) Allowance for borrowed funds used during construction (19) (18) (8) Net cash used for investing activities (23 291) (20 455) (17 130)
FINANCING ACTIVITIES Sale of common stock to Parent 18 000 - - Payment of dividends (15 453) (9 628) (5 416) Proceeds from (payment of) short-term borrowings (11 500) 14 875 6 675 Proceeds from (payment of) affiliate borrowings (5 705) 3 275 5 265 Retirement of long-term debt through sinking funds (3 650) (3 657) (3 913) Long-term debt issues refunded - (9 110) - Long-term debt issues 35 000 - 25 000 Net cash provided by (used for) financing activities 16 692 (4 245) 27 611
Net increase (decrease) in cash 1 287 (134) (10) Cash at beginning of period 10 144 154 Cash at end of period $ 1 297 $ 10 $ 144
Supplemental Disclosures of Cash Flow Information Cash paid (received) during the period for: Interest (net of amounts capitalized) $ 8 797 $ 9 377 $ 8 733 Income taxes $ 3 133 $ 6 167 $ (668)
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. At December 31, 1993, principal regulatory assets included in deferred charges were $21.9 million for transition costs associated with FERC Order No. 636 and $3.1 million for postretirement benefits costs. In addition, a regulatory liability related to income taxes, amounting to $10 million, was reflected in deferred credits.
(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.
(c) Transactions with Affiliates
Operating revenues include sales of gas to affiliated companies as follows:
(Dollars in Thousands) 1993 Cost Margin Total
Cambridge Electric $1 311 $ 76 $1 387
Cambridge Electric $1 784 $ 334 $2 118 Commonwealth Electric 100 5 105 $1 884 $ 339 $2 223
Cambridge Electric $4 207 $ 501 $4 708 Commonwealth Electric 1 195 93 1 288 $5 402 $ 594 $5 996
The margin realized on these sales together with that realized from non- affiliate interruptible sales is credited to firm customers through the Cost of Gas Adjustment Clause (CGA). COMMONWEALTH GAS COMPANY
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 $9,587,000, $8,683,000 and $8,319,000 in 1993, 1992 and 1991, 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, 1993 and 1992, the Company had overcollected $13,253,000 and $7,824,000, 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 2.95% in 1993, 2.90% in 1992 and 2.94% in 1991.
(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 3.5% in 1993, 4.25% in 1992 and 6.25% in 1991. COMMONWEALTH GAS COMPANY
(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, 1993, 1992 and 1991:
1993 1992 1991 (Dollars in Thousands) Federal - Current $1 619 $6 093 $ 964 Deferred 6 956 1 422 283 Investment tax credits (210) (217) (224) 8 365 7 298 1 023
State - Current 416 1 224 162 Deferred 1 278 343 170 1 694 1 567 332 10 059 8 865 1 355 Amortization of regulatory liability relating to deferred income taxes (216) (287) -
Total federal and state income taxes $ 9 843 $ 8 578 $ 1 355
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 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 1993 and 1992: COMMONWEALTH GAS COMPANY
1993 1992 (Dollars in Thousands) Liabilities Property-related $37 230 $34 483 Order 636 transition costs, net 3 450 - Postretirement benefits plan 1 422 - All other 1 419 1 763 43 521 36 246
Assets Investment tax credit 4 047 4 021 Pension plan 2 284 1 843 Regulatory liability 3 006 3 342 Inventory repricing 2 946 3 980 All other 2 785 3 428 15 068 16 614 Accumulated deferred income taxes, net $28 453 $19 632
The net year-end deferred income tax liability above is net of a current deferred tax asset of $1,723,000 in 1993 and $7,488,000 in 1992 which was included in prepaid income taxes in the accompanying Balance Sheets.
The following table, detailing the significant timing differences for 1991 which resulted in deferred income taxes, is required to be disclosed pursuant to accounting standards in effect prior to adoption of SFAS No. 109:
(Dollars in Thousands)
Accelerated depreciation for tax purposes $ 2 775 Capitalized interest during construction (20) Contributions in aid of construction (163) Capitalized leases (310) Repricing LNG inventory (1 025) Provision for bad debts (120) Pension costs and deferred compensation (302) Conservation and load management 167 Other (549) Deferred income tax provision $ 453
The total income tax provision set forth on the previous page represents 38% in 1993, 37% in 1992 and 30% in 1991 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages:
1993 1992 1991
Statutory federal income tax rate 35% 34% 34% Increase (Decrease) from statutory rate: State tax net of federal tax benefit 4 5 5 Amortization of investment tax credits (1) (1) (5) Amortization of excess deferred reserves - (1) (3) Other - - (1) 38% 37% 30% COMMONWEALTH GAS COMPANY
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.
(3) Long-Term Debt and Interim Financing
(a) Long-Term Debt
Long-term debt outstanding, exclusive of current maturities, current sinking fund requirements and related premiums and discounts, collateralized by substantially all of the Company's property, is as follows:
Original Balance December 31, Issue 1993 1992 (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 25 400 29 050 9.95%, Series J, due 2020 25 000 25 000 25 000 7.11%, Series K, due 2033 35 000 35 000 - $95 400 $64 050
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, 1993 are as follows:
Sinking Fund Maturing Debt Year Requirements Issues Total (Dollars in Thousands)
1994 $3 650 $ - $ 3 650 1995 3 650 - 3 650 1996 3 650 10 000 13 650 1997 3 650 - 3 650 1998 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, 1993, system companies had $115 million of committed lines of credit that will expire at varying intervals in 1994. These lines are normally renewed upon expiration and require annual fees ranging from zero to .1875% of the individual line. At December 31, 1993, the uncommitted lines of credit totaled $70 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate. The Company's notes payable to banks totaled $40,975,000 and $52,475,000 at December 31, 1993 and 1992, respectively. COMMONWEALTH GAS COMPANY
(c) Advances from Affiliates
The Company had short-term notes payable to the System totaling $355,000 and $5,780,000 at December 31, 1993 and 1992, respectively. These notes are written for a term of eleven months and twenty-nine days. Interest is at the prime rate (6% at December 31, 1993 and 1992) and is adjusted for changes in the rate during the term of the notes.
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 that available from banks. The Company had borrowings from the Pool of $2,480,000 and $2,760,000 at December 31, 1993 and 1992, 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, 1993 and 1992 are as follows:
1993 1992 (Dollars in Thousands)
Carrying Fair Carrying Fair Value Value Value Value
Long-Term Debt $99 050 $111 718 $67 700 $74 964
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 upon 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 and Postretirement Benefits
(a) Pension
The Company has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed a year of service. Pension benefits are based on an employee's years of service and compensation. The Company makes monthly contributions to the plan consistent with the funding requirements of the Employee Retirement Income Security Act of 1974. COMMONWEALTH GAS COMPANY
Components of pension expense were as follows:
1993 1992 1991 (Dollars in Thousands)
Service cost $ 1 904 $ 1 720 $ 1 632 Interest cost 6 037 5 478 5 179 Return on plan assets (10 821) (7 278) (13 853) Net amortization and deferral 6 317 3 001 10 387 Total pension expense 3 437 2 921 3 345 Transfers from affiliated companies, net 37 77 72 Less: Amounts capitalized and deferred 328 371 334 Net pension expense $ 3 146 $ 2 627 $ 3 083
The following economic assumptions were used to measure year-end obligations and the estimated pension expense for the subsequent year:
1993 1992 1991
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:
1993 1992 (Dollars in Thousands) Accumulated benefit obligation: Vested $(61 668) $(50 331) Nonvested (8 297) (2 649) $(69 965) $(52 980)
Projected benefit obligation $(85 269) $(66 893) Plan assets at fair market value 79 553 71 045 Projected benefit obligation less (greater) than plan assets (5 716) 4 152 Unamortized transition obligation 4 955 5 574 Unrecognized prior service cost 5 115 2 773 Unrecognized gain (9 141) (16 317) Accrued pension cost $ (4 787) $ (3 818)
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. The increase in the accumulated benefit obligation and the projected benefit obligation from December 31, 1992 to December 31, 1993 was primarily due to a reduction of the discount rate in light of current interest rates. COMMONWEALTH GAS COMPANY
(b) Other Postretirement Benefits
Through December 31, 1992, the Company provided postretirement health care and life insurance benefits to all 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 another 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 under the traditional pay-as-you-go method totaled $1,910,000 in 1992 and $1,603,000 in 1991.
In 1993, the Company began making contributions to various voluntary employee beneficiary association (VEBA) trusts that were established pursuant to section 501(c)9 of the Internal Revenue Code (the Code). The Company also made contributions to a sub-account 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 $3,780,000 to these trusts during 1993.
The net periodic postretirement benefit cost for the year ended December 31, 1993 included the following components:
(Dollars in Thousands)
Service cost $ 535 Interest cost 2 858 Return on plan assets (203) Amortization of transition obligation over 20 years 1 700 Net amortization and deferral 22 Total postretirement benefit cost 4 912 Less: Amounts capitalized and deferred 3 196 Net postretirement benefit cost $ 1 716 COMMONWEALTH GAS COMPANY
The funded status of the Company's postretirement benefit plan using a measurement date of December 31, 1993 is as follows:
(Dollars in Thousands)
Accumulated postretirement benefit obligation: Retirees $(20 779) Active participants (14 999) (35 778) Plan assets at fair market value 3 296 Projected postretirement benefit obligation greater than plan assets (32 482) Unamortized transition obligation 32 304 Unrecognized gain 178 $ -
In determining its estimated APBO and the funded status of the plan, the Company assumed a discount rate of 7.25%, an expected long-term rate of return on plan assets of 8.5%, and a medical care cost trend rate of 9%, which gradually decreases to 5% in the year 2007 and remains at that level thereafter. The estimate also reflects a trend rate of 14.9% for reimbursement of Medicare Part B premiums which decreases to 5% by 2007 and a dental care trend rate of 5% in all years. A one percent change in the medical trend rate would have a $479,000 impact on the Company's annual expense (interest component-$357,000; service cost-$122,000) and would change the accumulated benefit obligation by approximately $4.4 million.
Plan assets consist primarily of fixed income and equity securities. Fluctuations in the fair market value of plan assets will affect postretirement benefit expense in future years.
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 recovery in their next rate proceeding. While the Company is unable to predict the outcome of these rate proceedings, it believes the DPU will authorize similar rate treatment as provided to Cambridge Electric and other Massachusetts electric and gas companies for the recovery of the cost of these benefits. Further, based on recent DPU action and discussions with regulators, the Company believes that it is appropriate to record the difference between the amount included in rates and SFAS No. 106 costs as a regulatory asset. At December 31, 1993, this deferral amounted to approximately $3,062,000.
(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 benefits other than pensions. The Company's contribution was $1,444,000 in 1993, $1,284,000 in 1992 and $1,207,000 in 1991. COMMONWEALTH GAS COMPANY
(5) Commitments and Contingencies
(a) Construction and Financing Program
The Company is engaged in a continuous construction program presently estimated at $112.4 million for the five-year period 1994 through 1998. Of that amount, $21.9 million is estimated for 1994. 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
On April 8, 1992, the Federal Energy Regulatory Commission (FERC) issued Order No. 636 (Order 636), requiring interstate pipelines to unbundle (separate) existing gas sales contracts into separate components (gas sales, transportation and storage services). Order 636 provides mechanisms that will allow customers such as the Company to reduce the level of firm services from pipelines and permits the "brokering" of excess capacity on a temporary or permanent basis. Order 636 also requires pipelines to provide transportation services which allow customers to receive the same level of service they had with bundled contracts. Pipelines were required to be operating under Order 636 by November 1, 1993.
As a result of implementing Order 636, each pipeline company is allowed to collect certain "transition costs" from their customers. The Company has been billed a total of approximately $16.9 million from Tennessee Gas Pipeline Company, Algonquin Gas Transmission Company and Texas Eastern Transmission Company through December 31, 1993. It is anticipated that as much as $45 million in transition costs could be sought by these suppliers through a series of FERC filings over the 12 to 24 month period that began on June 1, 1993. The largest element of the aforementioned transition costs results from the pipelines' need to buy out gas supply contracts entered into prior to Order 636. The total amount of such costs ultimately billed to the Company will vary depending on the success of the pipelines in negotiating settlements with their former suppliers, and final review by the FERC. The Company is actively reviewing the prudency of transition costs billed in order to minimize costs to its customers. The Company has recorded its estimated liability based on amounts incurred by the respective pipelines as of December 31, 1993. COMMONWEALTH GAS COMPANY
On October 29, 1993, the Company received preliminary DPU authorization to recover these costs, with carrying charges, through the CGA over a four- year period that began in November 1993. As a result, a regulatory asset totaling $21.9 million, net of $400,000 recovered during the fourth quarter, was recorded as of December 31, 1993 and reflected in deferred charges. In addition, a related liability of $13.1 million was reflected in deferred credits. Also, approximately $7.9 million of the amount paid to the pipeline companies relates to gas inventory costs being allocated new storage services under Order 636. The Company will recover these inventory costs through the CGA.
(6) Gas Refunds
During 1993, 1992 and 1991, the Company received refunds from its gas suppliers in settlement of several rate cases which 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 $6,965,000 in 1993, $7,012,000 in 1992 and $9,409,000 in 1991.
(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 which prohibit the Company from entering into future lease agreements or obligations.
Future minimum lease payments, by period and in the aggregate, of non- cancelable operating leases consisted of the following at December 31, 1993:
Operating Leases (Dollars in Thousands)
1994 $ 3 183 1995 2 879 1996 1 994 1997 600 1998 159 Beyond 1998 477 Total future minimum lease payments $ 9 292
Total rent expense for all operating leases, except those with terms of a month or less, amounted to $3,435,000 in 1993, $3,171,000 in 1992 and $3,059,000 in 1991. There were no contingent rentals and no sublease rentals for the years 1993, 1992 and 1991.
(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 COMMONWEALTH GAS COMPANY
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 14).
(a) 2. Index to Financial Statement Schedules
Filed herewith at page(s) indicated are financial statement schedules of the Company:
Schedule V - Property, Plant and Equipment - Years Ended December 31, 1993, 1992 and 1991 (pages 40-42).
Schedule VI - Accumulated Depreciation of Property, Plant and Equipment - Years Ended December 31, 1993, 1992 and 1991 (page 43).
Schedule VIII - Valuation and Qualifying Accounts - Years Ended December 31, 1993, 1992 and 1991 (page 44).
Schedule IX - Short-Term Borrowings - Years Ended December 31, 1993, 1992 and 1991 (page 45).
(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. If applicable, as designated by an asterisk, certain documents previously filed by the Company have been disposed of by the Commission pursuant to its Records Control Schedule and are hereby being refiled by the Company.
c. 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.
d. 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).
Exhibit 10. Material Contracts.
10.1. Natural Gas Purchase Contracts.
10.1.1 Natural gas purchase contracts between AGT and NBGEL dated October 28, 1969 and August 14, 1968 for Firm and Winter Service, respectively (Exhibits 1 and 2 to the CG 1984 Form 10-K, File No. 2-1647).
10.1.2 Natural gas purchase contracts between AGT and CG dated July 10, 1972 for Firm and Winter Service applicable to Rate Schedule WS-1 (Exhibits 3 and 4 to the CG 1984 Form 10-K, File No. 2-1647).
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). COMMONWEALTH GAS COMPANY
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).
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). COMMONWEALTH GAS COMPANY
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).
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). COMMONWEALTH GAS COMPANY
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).
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). COMMONWEALTH GAS COMPANY
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).
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). COMMONWEALTH GAS COMPANY
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).
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).
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the three months ended December 31, 1993.
SCHEDULE VIII
COMMONWEALTH GAS COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 and 1991
(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, 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
Year Ended December 31, 1991
$ 1 878 $ 5 208 $ 952 $ 5 767 $ 2 271 SCHEDULE IX
COMMONWEALTH GAS COMPANY SHORT-TERM BORROWINGS (A) FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Dollars in Thousands)
Maximum Weighted Weighted Month-End Average Average Category of Average Amount Amount Interest Aggregate Balance Interest Outstanding Outstanding Rate Short-Term at End Rate at End During During the During the Borrowings of Period of Period the Period Period(B) Period(C)
December 31, 1993 Notes Payable to Banks $40 975 3.3% $74 225 $49 133 3.3%
Notes Payable to System $ 355 6.0% $ 9 630 $ 2 375 6.0%
COM/Energy Money Pool $ 2 480 3.2% $18 640 $ 8 370 3.2%
December 31, 1992 Notes Payable to Banks $52 475 3.8% $52 475 $29 460 4.0%
Notes Payable to System $ 5 780 6.0% $ 6 260 $ 2 825 6.2%
COM/Energy Money Pool $ 2 760 3.4% $ 2 760 $ 1 406 3.7%
December 31, 1991 Notes Payable to Banks $37 600 5.6% $39 025 $17 365 6.3%
Notes Payable to System $ 3 725 6.5% $ 3 725 $ 679 7.5%
COM/Energy Money Pool $ 1 540 4.6% $ 1 540 $ 458 5.7%
(A) Refer to Note 3 of Notes to Financial Statements filed under Item 8 of this report for the general terms of each category of short-term borrowings.
(B) The average amount outstanding during the period is determined by averaging the level of month-end principal balances outstanding for the prior thirteen-month period ending December 31.
(C) The weighted average interest rate during the period is determined by averaging the interest rates in effect on all loans transacted for the twelve-month period ended December 31. COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1993
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 30, 1994 William G. Poist, Chairman of the Board and Chief Executive Officer
KENNETH M. MARGOSSIAN March 28, 1994 Kenneth M. Margossian, President and Chief Operating Officer
Principal Financial Officer: JAMES D. RAPPOLI March 30, 1994 James D. Rappoli, Financial Vice President and Treasurer
Principal Accounting Officer:
JOHN A. WHALEN March 28, 1994 John A. Whalen, Comptroller
A majority of the Board of Directors:
WILLIAM G. POIST March 30, 1994 William G. Poist, Director
JAMES D. RAPPOLI March 30, 1994 James D. Rappoli, Director
KENNETH M. MARGOSSIAN March 28, 1994 Kenneth M. Margossian, Director