Item 1. Business
General
Commonwealth Gas Company (the Company) is engaged in the distribution and sale of natural gas at retail to approximately 240,000 customers in a 1,067 square mile area which includes 51 communities in eastern, southeastern and central Massachusetts. The approximate year-round population of this service area is 1,128,000.
The Company, which was organized in 1851 under the laws of the Common- wealth of Massachusetts, operates under the jurisdiction of the Massachusetts Department of Telecommunication and Energy (DTE) that regulates retail rates, accounting, issuance of securities and other matters. Since the date of its organization the Company has, from time to time, acquired the property and franchises of, or merged with, other gas companies. The Company is a wholly- owned subsidiary of Commonwealth Energy System (the Parent), which, together with its subsidiaries, is collectively referred to as "COM/Energy."
The Company is the only gas distribution utility in its service area and, by virtue of its existing franchises, no other gas distribution utility may extend its operations into the Company's service area without the authori- zation of the DTE. Alternative sources of energy are available to customers within the service territory, but competition from these sources has not been a significant factor affecting the Company's firm gas sales to existing customers. Even with the higher cost of storage and liquefied natural gas (LNG), which is required to supplement pipeline supply, the overall long-term cost of gas has been competitive with the cost of alternative fuel sources for most of the Company's customers.
Of the Company's 1998 firm gas unit sales, 61% was sold to residential customers, 28% to commercial customers, 5.8% to industrial customers and 5.2% to other customers. Capital expenditures are required to bring gas into areas of anticipated growth and both the distribution capability and gas supply must be available when new development begins or potential customers will seek alternative sources of fuel. Certain industrial customers with dual-fuel capability can convert from gas to alternative fuels under terms of contracts which permit interruption of their service upon short notice or at contractu- ally scheduled times.
In December 1998, the Parent signed an agreement and Plan of Merger with BEC Energy, the parent company of Boston Edison Company, that will create an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts including more than one million electric customers in 81 communities and the Company's 240,000 customers. The merger is expected to occur shortly after the satisfaction of certain conditions, including receipt of certain regulatory approvals. The regulatory approval process is expected to be completed during the second half of 1999.
COMMONWEALTH GAS COMPANY
Gas Supply
(a) General
The Company purchases transportation, storage and balancing services from Tennessee Gas Pipeline Company (Tennessee) and Algonquin Gas Transmission Company (and other upstream pipelines that bring gas from the supply wells to the final transporting pipelines) and purchases all of its gas supplies from third-party vendors, utilizing firm contracts with terms of less than one year. The vendors vary from small independent marketers to major gas and oil companies.
In addition to firm transportation and gas supplies mentioned above, the Company utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The underground storage contracts are a combina- tion of existing and new agreements which are the result of Federal Energy Regulatory Commission (FERC) Order 636 service unbundling. The LNG facili- ties, described below, are used to liquefy and store pipeline gas during the warmer months for use during the heating season.
The Company entered into a multi-party agreement in 1992 to assume a portion of Boston Gas Company's contracts to purchase Canadian gas supplies from Alberta Northeast (ANE) and have the volumes delivered by the Iroquois Gas Transmission System and Tennessee pipelines. The ANE gas supply contract was filed with the DTE and hearings were completed in April 1993. The DTE approved the ANE gas supply contract in November 1995. The Company is presently in negotiations with the parties to allow for final execution of all pertinent agreements and contracts.
The Company began transporting gas on its distribution system in 1990 for end-users. As of December 31, 1998, there were 593 customers using this transportation service, accounting for 11,146 BBTU or approximately 24% of total throughput.
(b) Hopkinton LNG Facility
A portion of the Company's gas supply during the heating season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of the Parent. The facility consists of a liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3 million MCF of natural gas.
In addition, Hopkinton owns a satellite vaporization plant and two above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 500,000 MCF of natural gas that are filled with LNG trucked from Hopkinton.
The Company has contracts for LNG service with Hopkinton extending on a year to year basis with notice of termination required five years in advance of the anticipated termination date. The Company and Hopkinton are currently evaluating the contracts to determine if amendments to the contracts should be negotiated in light of the ongoing deregulation of the natural gas industry. Current contract payments include a demand charge sufficient to cover Hopkin- ton's fixed charges and an operating charge which covers liquefaction
COMMONWEALTH GAS COMPANY
and vaporization expenses. The Company furnishes pipeline gas during the period April 15 to November 15 each year for liquefaction and storage. As the need arises, LNG is vaporized and placed in the distribution system of the Company.
Based upon information presently available regarding projected growth in demand and estimates of availability of future supplies of pipeline gas, the Company believes that its present sources of gas supply are adequate to meet existing load and allow for future growth in sales.
Rates and Regulation
(a) Gas Industry Restructuring
The Company and eight other gas utilities initiated the Massachusetts Gas Unbundling Collaborative (the Collaborative) on September 15, 1997, to explore and develop generic principles to achieve the goals set forth by the DTE. Collaborative participants represented a broad array of stakeholder interests including the utilities, natural gas marketers, interstate pipe- lines, producers, energy consultants, labor unions, consumer advocates and representatives for the DTE, the Massachusetts Attorney General's Office, and the Massachusetts Division of Energy Resources.
On March 18, 1998, the Collaborative filed a report to the DTE that summarized its progress. The Collaborative reported that it had made substan- tial progress in the areas of rate unbundling and terms and conditions for unbundled services. The report also described at least two policy issues, capacity disposition and cost responsibility, on which the Collaborative's participants require specific regulatory guidance before completing a compre- hensive framework for the transition to a more competitive market structure. In response to this report, the DTE issued a Notice of Inquiry (NOI) to address the Collaborative's unresolved issues. On May 1, 1998, the Company filed initial written comments in the proceeding arguing in favor of a mandatory capacity assignment proposal. On June 8, 1998, the DTE, as part of the aforementioned NOI, received final comments regarding the feasibility of implementing comprehensive unbundling for all local distribution companies (LDCs) by November 1, 1998. On June 29, 1998, the Company and three other Massachusetts LDCs submitted unbundled rate settlements to the DTE for consideration.
The DTE issued a procedural order regarding the NOI on July 2, 1998 which stated that the introduction of comprehensive unbundling for all classes of customers for all LDCs is not feasible by November 1, 1998. The DTE stated that unbundled rates for the four LDCs that filed settlements on June 29, 1998 (including the Company) shall be in place by November 1, 1998 and that compre- hensive unbundling shall be implemented no later than April 1, 1999. Also, as part of the July 2, 1998 procedural order, the DTE ordered that a set of proposed Model Terms and Conditions be submitted by the Collaborative no later than July 15, 1998. A partial set of Model Terms and Conditions were submit- ted on July 10, 1998 that excluded provisions for capacity assignment as well as those related sections of the terms and conditions that required further development by the Collaborative once the issues being addressed in the NOI were resolved by the DTE.
On August 15, 1998, the DTE approved the unbundled rate settlement
COMMONWEALTH GAS COMPANY
submitted by the Company. The Company submitted compliance rates consistent with the settlement agreement on September 11, 1998, and unbundled rates became effective on November 1, 1998 as further discussed below.
On November 30, 1998, the DTE issued an order approving the partial set of Model Terms and Conditions that were submitted by the Collaborative on July 10, 1998. In response to that order, however, the ten gas companies partici- pating in the Collaborative informed the DTE that an April 1, 1999 implementa- tion date for comprehensive gas unbundling was no longer feasible due to the significant time required by the Collaborative to complete the Model Terms and Conditions once the unresolved issues in the aforementioned NOI were answered by the DTE, as well as the additional time required by the gas companies to develop the systems necessary to implement unbundling consistent with these provisions.
On February 1, 1999, the DTE issued an order in the NOI with regard to capacity assignment and cost responsibility. The DTE found in favor of mandatory capacity assignment, where gas marketers would be required to accept the full cost and contractual obligations of the capacity that the gas companies had historically procured to serve their common customers. In support of its decision, the DTE determined that the capacity market in Massachusetts was not yet workably competitive to allow it to remove tradi- tional regulatory controls that were designed to ensure the reliability of gas service to customers. The DTE further reaffirmed that the LDCs must continue with their obligation to plan for and procure sufficient upstream capacity. Finally, the DTE found that alternative approaches to mandatory capacity assignment would result in transition costs that would conflict with the well-established policy on cost allocation.
On February 17, 1999, the Collaborative reconvened to continue its work in completing the Model Terms and Conditions consistent with the DTE's order on capacity assignment with a goal to begin the implementation of comprehen- sive unbundling for all LDCs beginning in 1999.
(b) Unbundled Rates
New unbundled rates for the Company went into effect on November 1, 1998. The unbundled rates were developed in accordance with the settlement agreement reached by participants in the Collaborative that was filed with the DTE on June 29, 1998 and approved on August 15, 1998. The new unbundled rates reflect the separation of the Company's gas supply function from its local distribution function.
Commencing with the billing month of November 1998, the Company has a Seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC) that provide for the recovery, from firm customers or default service customers, of certain costs previously recovered through base rates. The CGAC provides for rates that must be approved semi-annually by the DTE. The LDAC provides for rates that require annual approval.
As part of its new unbundled rates, the Company modified its existing CGAC to allow for the following changes: (a) the addition of provisions that allow for the recovery of certain bad-debt expenses; (b) new formulas that no longer adjust the Gas Adjustment Factors for the seasonal embedded gas costs that were in existing sales rates; (c) updated language reflecting the
COMMONWEALTH GAS COMPANY
ratemaking requirements for non-core revenue margins; and (d) the removal of provisions for the recovery of environmental remediation costs and FERC Order 636 transition costs, which will instead be recovered through the LDAC.
The Company's new LDAC recovers conservation charges, environmental remediation costs, balancing penalty revenue credits, and costs associated with the its participation in the Collaborative.
(c) Regulatory Matters
In May 1994, the Company requested the DTE to change the back-up service charges under its firm transportation rate. Back-up charges result when the Company sells gas from its system supplies to a customer whose off-system gas supply has failed or is temporarily unavailable for reasons beyond the customer's control. The change involved an upward indexing of back-up charges based on changes in the gas supply demand costs occasioned by FERC Order 636. On December 22, 1994, the DTE approved the Company's requested change effec- tive January 1, 1995. This change, which has no effect on revenue, results in a more equitable recovery of pipeline capacity costs between Commonwealth Gas' total requirements and transportation customers.
(d) Off-system Gas Sales and Capacity Release Services
The Company utilizes the off-system sales and capacity release markets as a means to sell excess resources. Off-system sales totaled 3,255 BBTU in 1998, while 25,796 BBTU of capacity was sold in the capacity release market. A margin-sharing agreement for these sales was approved by the DTE on February 14, 1996 allowing the Company to retain 25% of the gross margins realized above a certain threshold amount as set from year to year with the remaining margins credited to firm customers through the CGAC. As a result of this margin-sharing agreement, the Company retained approximately $118,000 in 1998.
(e) Conservation and Load Management Program
In 1998, the Company's gas conservation programs transitioned from a comprehensive, traditional array of programs offered in all customer sectors and funded via a stand-alone Conservation Charge mechanism to a market transformation-oriented program funded via the Company's new LDAC. Where once all conservation activities were implemented company-by-company, now such programs as residential and commercial/industrial equipment rebates are being pursued collaboratively with other gas utilities in the state. An additional feature of the new gas conservation strategy is to minimize commercial/indus- trial programs and customer conservation surcharges. The conservation budget has remained fairly stable at $5.4 million, including $2.9 million in program expenses and $2.5 million in lost margins and incentives.
Competition
The Company faces competition from suppliers of fuel oil, propane and electricity and also, for large commercial and industrial customers, from other suppliers of natural gas. The Company is continuously developing and implementing strategies to deal with the increasingly competitive environment.
FERC Order 636 marked the beginning of the deregulation and restructur- ing of the natural gas industry. In addition to opening up customer
COMMONWEALTH GAS COMPANY
markets to competition, the regulations shifted many supply-related responsi- bilities to LDCs including direct gas purchases from suppliers, pipelines and producers, transportation services and storage services. The Company has developed a gas control and information system that has purchasing and tracking systems. This ability, coupled with aggressive planning and procure- ment strategies, will secure the Company's existing market share and permit the expansion of core and non-core supply capabilities.
The Company's substantial LNG and storage capabilities provide it with the reliability needed during the coldest winter days and the flexibility to sell capacity when supply and pricing conditions are favorable. Through expanding non-firm and transportation sales, the Company has been able to maximize the use of its gas supply and transportation system resulting in a lower cost of gas for firm customers helping the Company to remain competitive in its traditional markets.
On February 6, 1997, due to the dramatically changing nature of the electric and gas industries, COM/Energy announced the consolidation of management personnel of affiliated companies Cambridge Electric Light Company (Cambridge Electric), Commonwealth Electric Company (Commonwealth Electric), COM/Energy Services Company and the Company effective on that date. The Company and these affiliates continue to operate under their existing company names. The consolidation process for these companies involved the merging of similar functions and activities to eliminate duplication in order to create the most efficient and cost-effective operation possible. As part of this consolidation effort, the Company initiated a voluntary Personnel Reduction Program that ultimately resulted in a decrease of 100 regular employees (approximately 15%) in 1997.
Construction and Financing
Information concerning the Company's financing and construction programs is contained in Note 6(a) of the Notes to Financial Statements filed under Item 8 of this report.
Employees
The Company has 604 regular employees including 408 (68%) who are repre- sented by three collective bargaining units covered by separate contracts with expiration dates ranging from March 2002 through April 2003. Although a labor dispute with one collective bargaining unit occurred during 1996, employee relations have generally been satisfactory since the dispute was resolved in September 1996.
Item 2.
Item 2. Properties
The Company's principal gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31, 1998, the gas system included 2,826 miles of gas distribution lines, 168,188 services and 247,560 customer meters together with the neces- sary measuring and regulating equipment.
In addition, the Company owns a central headquarters and service building in Southborough, Massachusetts, five district office buildings and various natural gas receiving and take stations.
COMMONWEALTH GAS COMPANY
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, 1998
One
(c) Frequency and Amount of Dividends Declared in 1998 and 1997
1998 1997 Per Share Per Share Declaration Date Amount Declaration Date Amount
May 11, 1998 $3.75 April 25, 1997 $2.00 July 30, 1998 .50 December 22, 1997 1.30 $4.25 $3.30
(d) Future dividends may vary depending upon the Company's earnings and capital requirements as well as financial and other conditions existing at that time.
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 facili- tate an understanding of the results of operations. This discussion should be read in conjunction with the Notes to Financial Statements filed under Item 8 of this report.
A summary of the period to period changes in the principal items included in the accompanying Statements of Income for the years ended December 31, 1998 and 1997 and unit sales for these periods is shown below:
Years Ended Years Ended December 31, December 31, 1998 and 1997 1997 and 1996 Increase (Decrease) (Dollars in thousands)
Gas Operating Revenues $(42,052) (12.7)% $(11,353) (3.3)%
Operating Expenses - Cost of gas sold (33,661) (17.6) (6,452) (3.3) Other operation and maintenance (4,493) (5.3) (4,468) (5.0) Depreciation 497 4.7 421 4.2 Taxes - Federal and state income (1,671) (17.3) (629) (6.1) Local property (153) (2.4) 372 6.3 Payroll and other (320) (9.9) 840 35.2 (39,801) (13.0) (9,916) (3.1)
Operating Income (2,251) (8.9) (1,437) (5.4)
Other Income 566 83.4 (256) (27.4)
Income Before Interest Charges (1,685) (6.5) (1,693) (6.1)
Interest Charges 490 4.7 (347) (3.2)
Net Income $(2,175) (14.1) $(1,346) (8.0)
Unit Sales (BBTU)
Firm (6,711) (17.3)% (2,279) (5.6)% Off-system, interruptible and other 1,481 32.2 (766) (14.3) (5,230) (12.1) (3,045) (6.6)
COMMONWEALTH GAS COMPANY
The following is a summary of unit sales, transportation volume and customers for the periods indicated:
Years Ended December 31, 1998 1997 1996
Unit Sales (BBTU): Residential 19,514 22,043 22,759 Commercial 8,965 11,077 11,558 Industrial 1,843 3,483 4,468 Other 1,681 2,111 2,208 Total firm 32,003 38,714 40,993 Off-system 4,429 2,673 2,420 Interruptible and other 1,658 1,933 2,952 Total sales 38,090 43,320 46,365 Transportation 11,326 8,478 6,192 Total 49,416 51,798 52,557
Customers at End of Period: Residential 216,951 215,757 213,474 Commercial 19,668 19,292 18,907 Industrial 910 934 930 Other 1,357 1,181 1,169 Total 238,886 237,164 234,480
Operating Revenues, Cost of Gas Sold and Unit Sales
Operating revenues decreased by $42.1 million (12.7%) in 1998 due to the considerable decline in firm unit sales (17.3%) and a lower average cost of gas partially offset by higher transportation revenues ($3.7 million). During 1997, operating revenues decreased by $11.4 million or 3.3% due to a 6.6% decline in total unit sales, lower conservation and load management costs ($1.8 million) and to a lesser extent, lower gas costs.
The cost of gas sold in 1998 and 1997 reflects changes in gas prices, sales levels, margin-sharing agreements on non-firm sales and refunds received from gas suppliers.
The decline in firm unit sales for 1998 reflects decreases to all customer segments including residential (11.5%), commercial (19.1%) and industrial (47.1%) that were due primarily to milder weather experienced in this region as compared to 1997. Degree days for 1998 totaled 5,754, 11% lower than last year and 12.1% below the normal level of 6,541. The signifi- cant fluctuations in non-firm sales for 1998 and 1997 continue to reflect the competitive environment that currently exists in the natural gas industry. Interruptible sales have no impact on net income since all of the margins from these sales are flowed back to firm customers through the CGAC.
The number of customers increased slightly in 1998 and 1997 due mainly to new residential and commercial construction activity, reflecting an improving economic environment.
COMMONWEALTH GAS COMPANY
Other Operating Expenses
Other operation and maintenance decreased by $4.5 million (5.3%) in 1998 due to the absence of a one-time charge ($6.8 million) related to a voluntary personnel reduction program (PRP) implemented during the second quarter of 1997, labor savings from the PRP and a decrease in the provision for bad debts ($814,000) offset, in part, by higher costs related to the outsourcing of the information technology, telecommunications and network services function ($6.4 million) that includes costs associated with Year 2000 compliance and higher insurance and employee benefits costs ($1.4 million).
During 1997, other operation and maintenance decreased by $4.5 million or 5% due to the absence of net costs associated with a 1996 labor dispute ($4.6 million), lower labor costs resulting from a decrease in the number of employees through attrition and the PRP ($5.7 million), reduced maintenance costs relating to distribution ($2.2 million) and lower C&LM costs ($1.8 million). These decreases were partially offset by a one-time charge ($6.8 million) related to the PRP initiated during the second quarter and higher postretirement benefit costs ($2 million) reflecting the full recognition of expense and amortization of previously deferred costs associated with postre- tirement benefits.
The goal of the PRP was to achieve a reduced, more efficient and more productive workforce in response to the significant regulatory changes facing the Company. In 1997, approximately 15% of the Company's employees voluntari- ly terminated employment as a result of the PRP. The payback period for the cost of the PRP was expected to be about one year. This action followed the consolidation of COM/Energy's electric and gas operations earlier in 1997.
Depreciation and Taxes
The 4.7% and 4.2% increase in depreciation in 1998 and 1997, respec- tively, resulted from higher levels of depreciable plant-in-service.
The fluctuation in federal and state income taxes during 1998 and 1997 was due to the respective levels of pre-tax income. The decrease in payroll and other taxes in 1998 reflects savings from the aforementioned PRP. The increase in payroll and other taxes for 1997 reflects additional payroll- related costs associated with a 1996 labor dispute. The decrease in local property taxes in 1998 was due to changing assessments in the Company's service territory. The increase in local property taxes during 1997 was due to higher tax rates and assessments in the Company's service territory.
Other Income and Interest Charges
In 1998, other income increased by $566,000 (83.4%) due primarily to increased sales of home heating protection plans. During 1997, other income decreased $256,000 or 27.4% due primarily to a reduction in interest income ($167,000) in connection with the Company's participation in the COM/Energy Money Pool and the absence of interest ($74,000) relating to a Massachusetts income tax abatement received in 1996.
In 1998, total interest charges increased by $490,000 due to higher interest costs on long-term debt ($1.5 million) related to the issuance of $35
COMMONWEALTH GAS COMPANY
million in new long-term debt in September 1997 and an increase in interest on deferred gas costs ($562,000). These increases were partially offset by a decrease in short-term interest ($959,000) due to the repayment of short-term debt in 1998. For 1997, total interest charges decreased $347,000 due primarily to lower interest on deferred gas costs ($1 million) and a decline in interest costs relating to long-term debt ($365,000) reflecting the impact of a sinking fund payment and debt that was retired in October 1996. The impact of these factors was offset, in part, by an increase in short-term interest ($783,000) due to a higher average level of borrowings, higher interest relating to gas refunds ($194,000) and higher interest charges relating to contested tax issues ($115,000).
Forward-Looking Statements
This report contains statements which, to the extent they are not recitations of historical fact, constitute "forward-looking statements" and are intended to be subject to the safe harbor protection provided by the Private Securities Litigation Reform Act of 1995. A number of important factors affecting the Company's business and financial results could cause actual results to differ materially from those stated in the forward-looking statements. Those factors include developments in the legislative, regulatory and competitive environment, certain environmental matters, demands for capital expenditures and the availability of cash from various sources.
Merger with BEC Energy
The utility industry has continued to change in response to legislative and regulatory mandates that are aimed at lowering prices for energy by creating a more competitive marketplace. These pressures have resulted in an increasing trend in the utility industry to seek competitive advantages and other benefits through business combinations. On December 5, 1998, COM/Energy and BEC Energy (BEC), headquartered in Boston, Massachusetts, entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, COM/Energy and BEC will be merged into a new holding company to be known as NSTAR. The merger is expected to occur shortly after the satisfac- tion of certain conditions, including the receipt of certain regulatory approvals including that of the DTE. The regulatory approval process is expected to be completed during the second half of 1999.
The merger will create an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts, including more than one million electric customers in 81 communities and the Company's 240,000 gas customers in 51 communities.
Shareholder votes on the merger will be held as part of each of COM/Energy's and BEC's annual shareholder meetings scheduled for the second quarter of 1999. The Merger Agreement may be terminated under certain circumstances, including by any party if the merger is not consummated by December 5, 1999, subject to an automatic extension of six months if the requisite regulatory approvals have not yet been obtained by such date. The merger will be accounted for using the purchase method of accounting.
Upon effectiveness of the merger, Thomas J. May, BEC's current Chair- man, President and Chief Executive Officer (CEO), will become the Chairman and CEO of NSTAR. Russell D. Wright, COM/Energy's current President and CEO,
COMMONWEALTH GAS COMPANY
will become the President and Chief Operating Officer of NSTAR and will serve on NSTAR's board of directors. Also, upon effectiveness of the merger, NSTAR's board of directors will consist of COM/Energy's and BEC's current trustees.
Year 2000
The Year 2000 issue is the result of computer programs being written using two digits rather than four to define the applicable year. Any computer program that has date sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a temporary inability to process transactions or engage in normal business activities. COM/Energy has been involved in Year 2000 compliancy since 1996.
COM/Energy, on a coordinated basis and with the assistance of RCG Information Technologies and other consultants, is addressing the Year 2000 issue. COM/Energy has followed a five-phase process in its Year 2000 compli- ance efforts, as follows: Awareness (through a series of internal announce- ments to employees and through contacts with vendors); Inventory (all comput- ers, applications and embedded systems that could potentially be affected by the Year 2000 problem); Assessment (all applications or components and the impact on overall business operations and a plan to correct deficiencies and the cost to do so); Remediation (the modification, upgrade or replacement of deficient hardware and software applications and infrastructure modifica- tions); and Testing (a detailed, comprehensive testing program for the modified critical component, system or software that involves the planning, execution and analysis of results).
COM/Energy's inventory phase required an assessment of all date sensi- tive information and transaction processing computer systems and determined that approximately 90% of its software systems needed some modifications or replacement. Plans were developed and are being implemented to correct and test all affected systems, with priorities assigned based on the importance of the activity. COM/Energy has identified the software and hardware installa- tions that are necessary. All installations are expected to be completed and tested by mid-1999.
COM/Energy has also inventoried its non-information technology systems that may be date sensitive (facilities, electric and gas operations, energy supply/production and distribution) that use embedded technology such as micro-controllers and micro-processors. COM/Energy is approximately 86% complete in its efforts to resolve non-compliance with Year 2000 requirements related to its non-information technology systems. COM/Energy anticipates that these systems will be updated or replaced as necessary and tested by mid- 1999.
At present, the remediation phase for information technology as it applies to hardware and non-technology issues is scheduled for completion by June 1, 1999. The testing phase for Year 2000 compliance is approximately 70% complete and is scheduled to be concluded by June 30, 1999. All other phases are complete.
COMMONWEALTH GAS COMPANY
Modifying and testing COM/Energy's information and transaction process- ing systems from 1996 through 2000 is currently expected to cost approximately $7 million, including approximately $900,000 incurred through 1997 and $3.1 million spent in 1998. Approximately $3 million is expected to be spent in 1999 and 2000. Year 2000 costs have been expensed as incurred and will continue to be funded from operations.
In addition to its internal efforts, COM/Energy has initiated formal communications with its significant suppliers to determine the extent to which COM/Energy may be vulnerable to its suppliers' failure to correct their own Year 2000 issues. As of February 1, 1999, COM/Energy has received responses from approximately 75% of those entities contacted, and nearly all have indicated that they are or will be Year 2000 compliant. Failure of COM/Energy's significant suppliers to address Year 2000 issues could have a material adverse effect on COM/Energy's operations, although it is not possible at this time to quantify the amount of business that might be lost or the costs that could be incurred by COM/Energy. Contact with significant vendors is continuing and inadequate or marginal responses are being pursued by COM/Energy. COM/Energy is prepared to replace certain suppliers or to initiate other contingency plans should these vendors not respond to COM/Energy's satisfaction by July 1, 1999.
In addition, parts of the global infrastructure, including national banking systems, electrical power grids, gas pipelines, transportation facilities, communications and governmental activities, may not be fully functional after 1999. Infrastructure failures could significantly reduce COM/Energy's ability to acquire energy and its ability to serve its customers as effectively as they are now being served. COM/Energy is identifying elements of the infrastructure that are critical to its operations and is obtaining information as to the expected Year 2000 readiness of these ele- ments.
COM/Energy has started its contingency planning for critical operation- al areas that might be effected by the Year 2000 issue if compliance by COM/Energy is delayed. COM/Energy gas and electric operations currently have emergency operating plans as well as information technology disaster recovery plans as components of its standard operating procedures. These plans will be enhanced to identify potential Year 2000 risks to normal operations and the appropriate reaction to these potential failures including contingency plans that may be required for any third parties that fail to achieve Year 2000 compliance. All necessary contingency plans are expected to be completed by June 30, 1999, although in certain cases, especially infrastructure failures, there may be no practical alternative course of action available to COM/Energy.
COM/Energy is working with other energy industry entities, both region- ally and nationally with respect to Year 2000 readiness and is cooperating in the development of local and wide-scale contingency planning.
While COM/Energy believes its efforts to address the Year 2000 issue will allow it to be successful in avoiding any material adverse effect on COM/Energy's operations or financial condition, it recognizes that failing to
COMMONWEALTH GAS COMPANY
resolve Year 2000 issues on a timely basis would, in a "most reasonably likely worst case scenario," significantly limit its ability to acquire and distrib- ute energy and process its daily business transactions for a period of time, especially if such failure is coupled with third party or infrastructure failures. Similarly, COM/Energy could be significantly effected by the failure of one or more significant suppliers, customers or components of the infrastructure to conduct their respective operations after 1999. Adverse affects on COM/Energy could include, among other things, business disruption, increased costs, loss of business and other similar risks.
The foregoing discussion regarding Year 2000 project timing, effective- ness, implementation and costs includes forward-looking statements that are based on management's current evaluation using available information. Factors that might cause material changes include, but are not limited to, the availability of key Year 2000 personnel, the readiness of third parties, and COM/Energy's ability to respond to unforeseen Year 2000 complications.
Environmental Matters
The Company is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether the Company may be responsible for remedial actions. In April 1998, the Company recorded an additional liability and corresponding regulatory asset of $500,000 due to an increase in the site clean-up cost estimate for an MGP site for which the Company was previously cited as a Potentially Responsible Party. The DTE has approved recovery of costs associated with MGP sites.
The Company is also involved in other known or potentially contaminated sites where the associated costs may not be recoverable in rates and have recorded in prior years an estimated liability (and a charge to operations) of $500,000 to cover the expected costs associated with assessment and remedia- tion activities. These estimates are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. The Company is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of the Company's current assessment of its environ- mental responsibilities, existing legal requirements and regulatory policies, management does not believe that these matters will have a material adverse effect on the Company's results of operations or financial position.
On January 1, 1997, the Company adopted the provisions of Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1 pro- vides authoritative guidance for recognition, measurement, display and disclosure of environmental remediation liabilities in financial statements. The Company has recorded environmental remediation liabilities net of amounts paid of $1.9 million at December 31, 1998. The adoption of SOP 96-1 did not have a material adverse effect on the Company's results of operations or financial position.
COMMONWEALTH GAS COMPANY
New Accounting Principles
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts possibly including fixed-price fuel supply and power con- tracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999 and may be implemented as of the beginning of any fiscal quarter after issuance but cannot be applied retroactively. SFAS No. 133 must be applied to derivative instruments and certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1997 and, at the Company's election, before January 1, 1998.
The adoption of SFAS No. 133 is not expected to have a material impact on the system's results of operations or financial condition.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Although the Company has material commodity purchase contracts and financial instruments (debt), these instruments are not subject to market risk. The Company has a rate making mechanism which allows for the recovery of gas costs from customers. The gas adjustment mechanism allows the Company to pass all costs related to the purchase of commodities to the customer, thereby insulating the Company from market risk.
Similarly, any change in the fair market value of the Company's pru- dently incurred debt obligations realized by the Company would be borne by customers through future rates.
Item 8.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed herewith on pages 19 through 36 of this report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1998
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Commonwealth Gas Company:
We have audited the accompanying balance sheets of COMMONWEALTH GAS COMPANY (a Massachusetts corporation and wholly-owned subsidiary of Common- wealth Energy System) as of December 31, 1998 and 1997, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1998. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Commonwealth Gas Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting prin- ciples.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index to financial statements and schedule is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts February 18, 1999
COMMONWEALTH GAS COMPANY INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1998 and 1997
Statements of Income for the Years Ended December 31, 1998, 1997 and
Statements of Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and
Notes to Financial Statements
PART IV.
SCHEDULE
II Valuation and Qualifying Accounts for the Years Ended December 31, 1998, 1997 and 1996
SCHEDULES OMITTED
All other schedules are not submitted because they are not applicable or not required or because the required information is included in the financial statements or notes thereto.
COMMONWEALTH GAS COMPANY BALANCE SHEETS DECEMBER 31, 1998 AND 1997 ASSETS
1998 1997 (Dollars in thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $392,612 $375,083 Less - Accumulated depreciation 120,811 110,661 271,801 264,422 Add - Construction work in progress 1,066 570 272,867 264,992
CURRENT ASSETS Cash 427 1,867 Accounts receivable - Affiliated companies 785 592 Customers, less reserves of $2,346 in 1998 and $2,853 in 1997 38,956 48,731 Unbilled revenues 10,358 19,121 Inventories, at average cost - Natural gas 24,519 23,301 Materials and supplies 1,366 1,225 Prepaid taxes - Property 3,135 3,176 Income 5,034 5,640 Other 874 1,234 85,454 104,887
DEFERRED CHARGES Regulatory assets 19,616 20,873 Other 5,307 5,214 24,923 26,087
$383,244 $395,966
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY BALANCE SHEETS DECEMBER 31, 1998 AND 1997 CAPITALIZATION AND LIABILITIES
1998 1997 (Dollars in thousands) CAPITALIZATION Common Equity - Common stock, $25 par value - Authorized and outstanding - 2,857,000 shares, wholly-owned by Commonwealth Energy System (Parent) $ 71,425 $ 71,425 Amounts paid in excess of par value 27,739 27,739 Retained earnings 17,998 16,871 117,162 116,035 Long-term debt, less current sinking fund requirements 102,150 105,800 219,312 221,835
CURRENT LIABILITIES Interim Financing - Notes payable to banks - 39,325 Advances from affiliates 30,825 - 30,825 39,325
Other Current Liabilities - Current sinking fund requirements 3,650 3,650 Accounts payable - Affiliated companies 2,527 1,869 Other 27,153 32,450 Accrued local property and other taxes 3,251 3,366 Customer deposits 1,327 1,006 Accrued interest 1,057 1,038 Other 18,073 18,551 57,038 61,930 87,863 101,255
DEFERRED CREDITS Accumulated deferred income taxes 40,767 38,322 Unamortized investment tax credits 5,263 5,461 Other 30,039 29,093 76,069 72,876 COMMITMENTS AND CONTINGENCIES $383,244 $395,966
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996 (Dollars in thousands)
GAS OPERATING REVENUES $289,083 $331,135 $342,488
OPERATING EXPENSES Cost of gas sold 157,552 191,213 197,665 Other operation 70,453 74,402 75,279 Maintenance 10,036 10,580 14,171 Depreciation 10,979 10,482 10,061 Taxes - Income 7,982 9,653 10,282 Local property 6,162 6,315 5,943 Payroll and other 2,905 3,225 2,385 266,069 305,870 315,786
OPERATING INCOME 23,014 25,265 26,702
OTHER INCOME 1,246 679 935
INCOME BEFORE INTEREST CHARGES 24,260 25,944 27,637
INTEREST CHARGES Long-term debt 8,721 7,251 7,604 Other interest charges 2,270 3,250 3,244 10,991 10,501 10,848
NET INCOME $ 13,269 $ 15,443 $ 16,789
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996 (Dollars in thousands)
Balance at beginning of year $16,871 $10,856 $10,495
Add (Deduct): Net income 13,269 15,443 16,789 Cash dividends on common stock (12,142) (9,428) (16,428)
Balance at end of year $17,998 $16,871 $10,856
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996 (Dollars in thousands) OPERATING ACTIVITIES Net income $13,269 $15,443 $16,789 Effects of noncash items - Depreciation and amortization 13,302 13,190 12,034 Deferred income taxes (2,764) 746 4,249 Investment tax credits (198) (199) (202) Change in working capital exclusive of cash and interim financing - Accounts receivable and unbilled revenues 18,345 (230) (4,859) Income taxes 606 (21) (5,235) Local property and other taxes (74) 191 (342) Accounts payable and other (5,776) 763 (31,407) Deferred postretirement benefit costs - (414) (2,228) All other operating items 5,504 (2,278) (3,267) Net cash provided by (used for) operating activities 42,214 27,191 (14,468)
INVESTING ACTIVITIES Additions to property, plant and equipment (inclusive of AFUDC) (19,362) (18,392) (11,696)
FINANCING ACTIVITIES Payment of dividends (12,142) (9,428) (16,428) Proceeds from (payment of) short-term borrowings (39,325) (18,875) 46,000 Advances from (payments to) affiliates 30,825 (10,400) 8,550 Long-term debt issues - 35,000 - Long-term debt issue refunded - - (10,000) Retirement of long-term debt through sinking funds (3,650) (3,650) (3,650) Net cash provided by (used for) financing activities (24,292) (7,353) 24,472
Net increase (decrease) in cash (1,440) 1,446 (1,692) Cash at beginning of period 1,867 421 2,113 Cash at end of period $ 427 $ 1,867 $ 421
Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $10,707 $ 9,162 $10,619 Income taxes $ 5,470 $ 8,916 $14,165
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH GAS COMPANY NOTES TO FINANCIAL STATEMENTS
(1) General Information
Commonwealth Gas Company (the Company) is a wholly-owned subsidiary of Commonwealth Energy System (the Parent). The Parent, together with its subsidiaries, is referred to as "COM/Energy." The Parent is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935 and, in addition to its investment in the Company, has interests in other utility companies and several non-regulated companies.
The Company is engaged in the distribution and sale of natural gas at retail to approximately 240,000 customers in a 1,067 square-mile area which includes 51 communities in eastern, southeastern and central Massachusetts including New Bedford, Cambridge, Plymouth and Worcester. The approximate year-round population of this service area is 1,128,000.
The Company has 604 regular employees including 408 (68%) who are repre- sented by three collective bargaining units covered by separate contracts with expiration dates ranging from March 2002 through April 2003.
(2) Significant Accounting Policies
(a) Principles of Accounting
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements.
(b) Regulatory Assets and Liabilities
The Company is regulated as to rates, accounting and other matters by the Massachusetts Department of Telecommunications and Energy (DTE).
Based on the current regulatory framework, the Company accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." The Company has established various regula- tory assets in cases where the DTE has permitted or is expected to permit recovery of specific costs over time. If all or a separable portion of the Company's operations becomes no longer subject to the provisions of SFAS No. 71, a write-off of related regulatory assets and liabilities would be re- quired, unless some form of transition cost recovery continues through rates established and collected for the Company's remaining regulated operations. In addition, the Company would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets.
COMMONWEALTH GAS COMPANY
The principal regulatory assets included in deferred charges at December 31, 1998 and 1997 were as follows: 1998 1997 (Dollars in thousands)
Postretirement benefit costs $ 8,568 $ 9,607 FERC Order 636 transition costs 5,968 7,336 Environmental costs 5,080 3,930 Total regulatory assets $19,616 $20,873
The principal regulatory liability, reflected in deferred credits-other and relating to income taxes, was $8 million and $8.3 million at December 31, 1998 and 1997, respectively. As of December 31, 1998, $16 million of the Company's regulatory assets and all of its regulatory liabilities are reflect- ed in rates charged to customers. Regulatory assets, including postretirement benefit costs, are being recovered over a weighted average period of approxi- mately 8 years.
(c) Transactions with Affiliates
Operating revenues include sales of gas to affiliate Cambridge Electric Light Company as follows: 1998 1997 1996 (Dollars in thousands)
Cost $ - $ - $ 11 Margin - - - Total $ - $ - $ 11
Any margin realized on these sales is credited to firm customers through the Cost of Gas Adjustment Clause (CGAC).
Other intercompany transactions include payments by the Company for management, accounting, data processing and other services provided by COM/Energy Services Company. In addition, the Company incurred costs paid to affiliate Hopkinton LNG Corp. for liquefaction and vaporization services that amounted to $9,834,000, $10,172,000 and $10,124,000 in 1998, 1997 and 1996, respectively. Transactions with COM/Energy companies are subject to review by the DTE.
(d) Operating Revenues
Customers are billed for their use of gas on a cycle basis throughout the month. To reflect revenues in the proper period, the estimated amount of unbilled sales revenue is recorded each month.
The Company is permitted to bill customers currently for total gas costs, certain conservation and load management costs and environmental costs through adjustment clauses. Amounts recoverable under the adjustment clauses are subject to review and adjustment by the DTE. The amount of such costs incurred by the Company but not yet reflected in customers' bills is recorded as unbilled revenues.
COMMONWEALTH GAS COMPANY
(e) Depreciation
Depreciation is provided using the straight-line method at rates intended to amortize the original cost and the estimated cost of removal less salvage of properties over their estimated economic lives. The Company's composite depreciation rate, based on average depreciable property in service, was 2.95% in both 1998 and 1997 and 2.94% in 1996.
(f) Maintenance
Expenditures for repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expense. Additions, replacements and renewals of property considered to be units of property are charged to the appropriate plant accounts. Upon retirement, accumulated depreciation is charged with the original cost of property units and the cost of removal less salvage.
(g) Allowance for Funds Used During Construction
Under applicable rate-making practices, the Company is permitted to include an allowance for funds used during construction (AFUDC) as an element of its depreciable property costs. This allowance is based on the amount of construction work in progress that is not included in the rate base on which the Company earns a return. An amount equal to the AFUDC capitalized in the current period is reflected in other interest charges in the accompanying Statements of Income and amounted to $76,000, $55,000 and $20,000 in 1998, 1997 and 1996, respectively.
While AFUDC does not provide funds currently, these amounts are recover- able in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 4.5% in 1998, 5.75% in 1997 and 6% in 1996.
(3) Income Taxes
For financial reporting purposes, the Company provides federal and state income taxes on a separate return basis. However, for federal income tax purposes, the Company's taxable income and deductions are included in the consolidated income tax return of the Parent, and it makes tax payments or receives refunds on the basis of its tax attributes in the tax return in accordance with applicable regulations.
COMMONWEALTH GAS COMPANY
The following is a summary of the provisions for income taxes for the years ended December 31, 1998, 1997 and 1996:
1998 1997 1996 (Dollars in thousands) Federal - Current $ 9,166 $ 7,544 $ 5,220 Deferred (2,239) 775 3,508 Investment tax credits (198) (199) (202) 6,729 8,120 8,526
State - Current 1,778 1,562 1,015 Deferred (373) 168 713 1,405 1,730 1,728 8,134 9,850 10,254 Amortization of regulatory liability relating to deferred income taxes (152) (197) 28
Total federal and state income taxes $ 7,982 $ 9,653 $10,282
Deferred tax liabilities and assets are determined based on the difference between the financial statement basis and tax bases of assets and liabilities using enacted tax rates in effect in the year in which the differences are expected to reverse.
Accumulated deferred income taxes consisted of the following in 1998 and 1997: 1998 1997 (Dollars in thousands) Liabilities Property-related $46,950 $44,730 Postretirement benefits plan 3,360 3,877 All other 1,249 1,691 51,559 50,298
Assets Investment tax credit 3,397 3,524 Pension plan 4,165 2,921 Regulatory liability 2,785 2,883 Inventory repricing 2,999 2,948 All other 6,042 3,359 19,388 15,635 Accumulated deferred income taxes, net $32,171 $34,663
The net year-end deferred income tax liability above is net of current deferred tax assets of $8,596,000 in 1998 and $3,659,000 in 1997 which are included in other deferred charges in the accompanying Balance Sheets.
COMMONWEALTH GAS COMPANY
The total income tax provision set forth on the previous page represents 38% in 1998, 1997 and 1996 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages:
1998 1997 1996
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory levels $ 7,438 $ 8,784 $ 9,475 Increase (Decrease) from statutory rate: State tax net of federal tax benefit 913 1,124 1,123 Amortization of investment tax credits (198) (199) (202) Amortization of excess deferred reserves (152) (197) 28 Tax versus book depreciation 11 19 (123) Other (30) 122 (19) $ 7,982 $ 9,653 $10,282
Effective federal tax rate 38% 38% 38%
(4) Long-Term Debt and Interim Financing
(a) Long-Term Debt
Long-term debt outstanding, exclusive of current maturities and current sinking fund requirements, collateralized by substantially all of the Company's property, is as follows:
Original Balance December 31, Issue 1998 1997 (Dollars in thousands) First Mortgage Bonds - 8.99%, Series I, due 2001 $40,000 $ 7,150 $ 10,800 9.95%, Series J, due 2020 25,000 25,000 25,000 7.11%, Series K, due 2033 35,000 35,000 35,000 6.54%, Series L, due 2007 10,000 10,000 10,000 7.04%, Series M, due 2017 25,000 25,000 25,000 $102,150 $105,800
Under terms of its indenture, the Company is required to make periodic sinking fund payments for retirement of outstanding long-term debt. The Company may purchase its outstanding bonds in advance of sinking fund require- ments under favorable conditions. The required sinking fund payments and balances of maturing debt issues for the five years subsequent to December 31, 1998 are as follows:
Sinking Fund Maturing Debt Year Requirements Issues Total (Dollars in thousands)
1999 $3,650 $ - $3,650 2000 3,650 - 3,650 2001 5,079 3,500 8,579 2002 1,429 - 1,429 2003 1,429 - 1,429
COMMONWEALTH GAS COMPANY
(b) Notes Payable to Banks
The Company and other COM/Energy companies maintain both committed and uncommitted lines of credit for the short-term financing of their construction programs and other corporate purposes. As of December 31, 1998, COM/Energy companies had $122 million of committed lines that will expire at varying intervals in 1999. These lines are normally renewed upon expiration and require annual fees up to .1875% of the individual line. At December 31, 1998, the uncommitted lines of credit totaled $10 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 5.7% and 5.8% in 1998 and 1997, respectively. The Company had no notes payable to banks at December 31, 1998 compared to $39,325,000 at December 31, 1997.
(c) Advances from Affiliates
The Company is a member of the COM/Energy Money Pool (the Pool), an arrangement among the subsidiaries of the Parent, whereby short-term cash surpluses are used to help meet the short-term borrowing needs of the utility subsidiaries. In general, lenders to the Pool receive a higher rate of return than they otherwise would on such investments, while borrowers pay a lower interest rate than those available from banks. Interest rates on the out- standing borrowings are based on the monthly average rate the Company would otherwise have to pay banks, less one-half the difference between that rate and the monthly average U.S. Treasury Bill weekly auction rate. The borrow- ings are for a period of less than one year and are payable upon demand. Rates on these borrowings averaged 5.3% and 5.4% during 1998 and 1997, respectively. The Company had $30,825,000 in borrowings from the Pool at December 31, 1998 and none at December 31, 1997.
The Company had no notes payable to the Parent at December 31, 1998 or 1997. These notes are written for a term of up to 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in that rate during the term of the notes. This rate averaged 8.3% and 8.5% during 1998 and 1997, respectively.
(d) Disclosures about Fair Value of Financial Instruments
The fair value of certain financial instruments included in the accompany- ing balance sheets as of December 31, 1998 and 1997 are as follows:
1998 1997 Carrying Fair Carrying Fair Value Value Value Value (Dollars in thousands)
Long-Term Debt $105,800 $118,063 $109,450 $122,744
The carrying amount of cash, notes payable to banks and advances from affiliates approximates the fair value because of the short maturity of these financial instruments.
COMMONWEALTH GAS COMPANY
The estimated fair value of long-term debt is based on quoted market prices of the same or similar issues or on the current rates offered for debt with the same remaining maturity. The fair values shown above do not purport to represent the amounts at which those obligations would be settled.
(5) Employee Benefit Plans
(a) Pension
The Company has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed a year of service. Pension benefits are based on an employee's years of service and compensation. The Company makes monthly contributions to the plan consistent with the funding requirements of the Employee Retirement Income Security Act of 1974.
The following tables set forth the change in the pension benefit obliga- tion and plan assets as well as the plan's funded status reconciled to the amount included in the financial statements: 1998 1997 (Dollars in thousands) Change in benefit obligation Obligation at beginning of year $ 120,179 $ 99,811 Service cost 2,398 2,252 Interest cost 8,308 7,242 Actuarial loss 11,602 17,733 Benefits paid (7,725) (6,859) Obligation at end of year $ 134,762 $ 120,179
1998 1997 (Dollars in thousands)
Change in plan assets Fair value of plan assets at beginning of year $ 114,394 $ 101,182 Actual return on plan assets 8,814 17,925 Employer contributions 2,192 2,221 Transfers to affiliated companies (571) (75) Benefits paid (7,725) (6,859) Fair value of plan assets at end of year $ 117,104 $ 114,394
1998 1997 (Dollars in thousands)
Funded status $ (17,658) $ (5,785) Unrecognized transition obligation 1,848 2,477 Unrecognized prior service cost 3,794 4,317 Unrecognized net actuarial (gain) loss 3,200 (8,874) Prepaid (accrued) benefit cost $ (8,816) $ (7,865)
COMMONWEALTH GAS COMPANY
Weighted-average assumptions as of December 31 were as follows:
1998 1997
Discount rate 6.50% 7.00% Expected return on plan assets 9.00 8.75 Rate of increase in future compensation 3.75 3.75
Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect pension expense in future years.
Components of net periodic pension cost were as follows:
1998 1997 1996 (Dollars in thousands)
Service cost $ 2,398 $ 2,252 $ 2,310 Interest cost 8,308 7,242 7,172 Expected return on plan assets (8,715) (7,803) (7,219) Amortization of transition obligation 616 619 619 Amortization of prior service cost 501 503 503 Total 3,108 2,813 3,385 Transfer from affiliated companies, net 379 516 487 Less: Amounts capitalized and deferred 451 375 292 Net periodic pension cost $ 3,036 $ 2,954 $ 3,580
The net periodic pension cost reflects the use of the projected unit credit method which is also the actuarial cost method used in determining future funding of the plan. The Company, in accordance with current rate- making, is deferring the difference between the pension contribution that is reflected in base rates, and pension expense.
(b) Other Postretirement Benefits
Certain employees are eligible for postretirement benefits if they meet specific requirements. These benefits could include health and life insurance coverage and reimbursement of Medicare Part B premiums. Under certain circumstances, eligible employees are required to make contributions for postretirement benefits.
To fund its postretirement benefits, the Company makes contributions to various voluntary employees' beneficiary association trusts that were estab- lished pursuant to section 501(c)(9) of the Internal Revenue Code (the Code). The Company also makes contributions to a subaccount of its pension plan pursuant to section 401(h) of the Code to fund a portion of its postretirement benefit obligation.
COMMONWEALTH GAS COMPANY
The following tables set forth the change in the postretirement benefit obligation and plan assets as well as the plan's funded status reconciled to the amount included in the financial statements:
1998 1997 (Dollars in thousands) Change in benefit obligation Obligation at beginning of year $ 47,271 $ 38,643 Service cost 486 441 Interest cost 3,029 2,788 Actuarial loss (49) 7,553 Participant contributions 51 41 Benefits paid (2,738) (2,195) Obligation at end of year $ 48,050 $ 47,271
1998 1997 (Dollars in thousands) Change in plan assets Fair value of plan assets at beginning of year $ 16,720 $ 12,636 Actual return on plan assets 1,847 2,474 Employer contributions 3,668 3,764 Participant contributions 51 41 Transfers to affiliated companies (15) - Benefits paid (2,738) (2,195) Fair value of plan assets at end of year $ 19,533 $ 16,720
Funded status $ (28,517) $ (30,551) Unrecognized transition obligation 23,763 25,501 Unrecognized net actuarial loss 4,754 5,050 Prepaid (accrued) benefit cost $ - $ -
Weighted-average assumptions as of December 31 were as follows:
1998 1997
Discount rate 6.50% 7.00% Expected return on plan assets 9.00 8.75 Rate of increase in future compensation 3.75 3.75
For measurement purposes, a 6.50% annual rate of increase in the per capita cost of covered medical claims was assumed for 1999. The rates were assumed to decrease gradually to 4.5% for 2007 and remain at that level thereafter. Dental claims and Medicare Part B premiums are expected to increase at 4.5% and 3.1%, respectively.
Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect the periodic postretirement benefit cost in future years.
COMMONWEALTH GAS COMPANY
Components of net periodic postretirement benefit cost were as follows:
1998 1997 1996 (Dollars in thousands)
Service cost $ 486 $ 441 $ 551 Interest cost 3,029 2,788 2,878 Expected return on plan assets (1,544) (1,165) (866) Amortization of transition obligation 1,697 1,700 1,700 Total 3,668 3,764 4,263 Transfers from affiliates, net 403 484 520 Add: Net amortization of deferrals 1,039 779 - Less: Amounts capitalized and deferred 419 865 2,612 Net periodic postretirement benefit cost $ 4,691 $ 4,162 $ 2,171
Assumed healthcare cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage point change in assumed healthcare cost trend rates would have the following effects:
One-Percentage-Point Increase Decrease (Dollars in thousands)
Effect on total of service and interest cost components $ 469 $ (381) Effect on postretirement benefit obligation $ 5,656 $ (5,358)
On April 15, 1997, the DTE issued an accounting ruling allowing the Company to include postretirement benefits costs in cost-of-service and to amortize the deferred balance of $10.5 million at March 31, 1997 associated with these costs over a period not to exceed ten years that began in April 1997.
(c) Savings Plan
The Company has an Employees Savings Plan that provides for Company contributions equal to contributions by eligible employees of up to four percent of each employee's compensation rate. Effective January 1, 1993, the rate was increased to five percent for those employees no longer eligible for postretirement health benefits. The Company's contribution was $1,312,000 in 1998, $1,366,000 in 1997 and $1,100,000 in 1996.
(6) Commitments and Contingencies
(a) Construction and Financing Program
The Company is engaged in a continuous construction program presently estimated at $93.4 million for the five-year period 1999 through 2003. Of that amount, $18.6 million is estimated for 1999. The program is subject to periodic review and revision because of factors such as changes in business conditions, rates of customer growth, effects of inflation, equipment delivery schedules, licensing delays, availability and cost of capital and environmen- tal factors.
COMMONWEALTH GAS COMPANY
(b) LNG Service Contract
The Company has long-term contracts with Hopkinton LNG Corp., a wholly- owned subsidiary of the Parent, for liquefaction and vaporization services. The contracts extend on a year-to-year basis, subject to the giving of a notice to terminate by the Company at least five years in advance of the anticipated termination date.
(7) Gas Refunds
During 1998, 1997 and 1996, the Company received refunds from its gas suppliers in settlement of several rate cases that had been pending before the FERC. Operating revenues and the cost of gas sold have been reduced by the amounts refunded to firm customers totaling $4,439,000 in 1998, $2,374,000 in 1997 and $7,656,000 in 1996.
(8) Lease Obligations
The Company leases equipment and office space under arrangements that are classified as operating leases. These lease agreements are for terms of one year or longer. Leases currently in effect contain no provisions that prohibit the Company from entering into future lease agreements or obliga- tions.
Future minimum lease payments, by period and in the aggregate, of non- cancelable operating leases consisted of the following at December 31, 1998:
Operating Leases (Dollars in thousands)
1999 $ 3,601 2000 2,533 2001 2,140 2002 2,140 2003 2,140 Beyond 2003 5,229 Total future minimum lease payments $17,783
Total rent expense for all operating leases, except those with terms of a month or less, amounted to $4,842,000 in 1998, $4,866,000 in 1997, and $5,027,000 in 1996. There were no contingent rentals and no sublease rentals for the years 1998, 1997 and 1996.
(9) Environmental Matters
The Company is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These regulations authorize federal and state regulatory agencies to identify and remediate hazardous waste sites and to seek recovery from statutorily liable parties (usually referred to as potentially responsible parties or PRPs), or to order these PRPs to undertake the clean-up themselves. (Refer to "Environ- mental Matters" filed under Item 7 of this report for additional information.)
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 Schedule (page 20).
(a) 2. Index to Financial Statement Schedules
Filed herewith at page indicated is the following financial state- ment schedule of the Company:
Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1998, 1997 and 1996 (page 37).
(a) 3. Exhibits:
Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are incor- porated by reference to the appropriate exhibit numbers and the Securities and Exchange Commission file numbers indicated in parentheses.
b. The following is a glossary of acronyms used throughout the Exhibit Index:
CES Commonwealth Energy System CG Commonwealth Gas Company CNG CNG Transmission Corporation TGP Tennessee Gas Pipeline Company
Exhibit Index:
Exhibit 3. Articles of incorporation and by-laws.
3.1.1 Articles of incorporation of CG (Exhibit 1 to the CG 1991 Form 10- K, File No. 2-1647).
3.1.2 By-laws of CG, as amended (Exhibit 2 to the CG 1992 Form 10-K, File No. 2-1647).
Exhibit 4. Instruments defining the rights of security holders, including indentures.
4.1. Indentures of Trust or Supplemental Indenture of Trust (as filed by the Registrant, except First Supplemental which was filed by the Parent)
4.1.1. Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File No. 2-7820).
4.1.2. First Supplemental on Form S-1 (Mar., 1950) (Exhibit 7(a), File No. 2-8418).
COMMONWEALTH GAS COMPANY
4.1.3. Second Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(2), File No. 2-10445). 4.1.4. Third Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(3), File No. 2-10445). 4.1.5. Fourth Supplemental on Form S-9 (Oct. 1954) (Exhibit 2(b)(5), File No. 2-15089). 4.1.6. Fifth Supplemental on Form S-9 (Mar., 1956) (Exhibit 2(b)(6), File No. 2-15089). 4.1.7. Sixth Supplemental on Form S-9 (Apr., 1957) (Exhibit 2(b)(7), File No. 2-15089). 4.1.8. Seventh Supplemental on Form S-9 (June 1959) (Exhibit 2(b)(8), File No. 2-20532). 4.1.9. Eighth Supplemental on Form S-9 (Sept. 1961) (Exhibit 2(b)(9), File No. 2-20532). 4.1.10. Ninth Supplemental on Form 8-K (Aug. 1962) (Exhibit A, File No. 2- 1647). 4.1.11. Tenth Supplemental on Form 10-K (1970) (Exhibit 2, File No. 2- 1647). 4.1.12. Eleventh Supplemental on Form S-1 (June, 1972) (Exhibit 4(b)(2), File No. 2-48556). 4.1.13. Twelfth Supplemental on Form S-1 (Aug., 1973) (Exhibit 4(b)(3), File No. 2-48556). 4.1.14. Thirteenth Supplemental on Form 10-K (1992) (Exhibit 1, File No. 2-1647). 4.1.15. Fourteenth Supplemental on Form 10-K (1990) (Exhibit 1, File No. 2-1647). 4.1.16. Fifteenth Supplemental on Form 10-K (1982) (Exhibit 1, File No. 2- 1647). 4.1.17. Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2- 1647). 4.1.18. Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No. 2-1647). 4.1.19. Eighteenth Supplemental on Form 10-Q (March, 1994) (Exhibit 1, File No. 2-1647). 4.1.20. Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1, File No. 2-1647).
Exhibit 10. Material Contracts.
10.1. Natural Gas Purchase Contracts.
10.1.1 Transportation Agreement between CNG and CG to provide for trans- portation of natural gas on a daily basis from Steuben Gas Storage Company to TGP, dated September 24, 1991 (Exhibit 10 to the CG 1991 Form 10-K, File No. 2-1647).
10.2 Other Agreements.
10.2.1 Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Filed as Exhibit 1 to the Parent's Form 10-Q (September 1993), File No. 1-7316).
10.2.2 Employees Savings Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Filed as Exhibit 2 to the Parent's Form 10-Q (September 1993), File No. 1-7316).
COMMONWEALTH GAS COMPANY
10.2.2.1 First Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective October 1, 1994. (Exhibit 1 to CES Form S-8 (January 1995), File No. 1-7316).
10.2.2.2 Second Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective April 1, 1996. (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316).
10.2.2.3 Third Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective January 1, 1997. (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316).
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the three months ended December 31, 1998.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 1 is the Financial Data Schedule for the year ended December 31, 1998
SCHEDULE II
COMMONWEALTH GAS COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 and 1996
(Dollars in thousands)
Additions Balance Provision Deductions Balance Beginning Charged to Accounts at End Description of Year Operations Recoveries Written Off of Year
Allowance for Doubtful Accounts Year Ended December 31, 1998
$ 2,853 $ 4,145 $ 1,527 $ 6,179 $ 2,346
Year Ended December 31, 1997
$ 2,738 $ 4,979 $ 1,333 $ 6,197 $ 2,853
Year Ended December 31, 1996
$ 2,691 $ 4,381 $ 1,213 $ 5,547 $ 2,738
COMMONWEALTH GAS COMPANY FORM 10-K DECEMBER 31, 1998
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
COMMONWEALTH GAS COMPANY (Registrant)
By: R. D. WRIGHT Russell D. Wright Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Principal Executive Officers:
R. D. WRIGHT March 31, 1999 Russell D. Wright Chairman of the Board and Chief Executive Officer
DEBORAH A. MCLAUGHLIN March 31, 1999 Deborah A. Mclaughlin, President and Chief Operating Officer
Principal Financial and Accounting Officer: JAMES D. RAPPOLI March 31, 1999 James D. Rappoli, Financial Vice President and Treasurer
A majority of the Board of Directors:
DEBORAH A. MCLAUGHLIN March 31, 1999 Deborah A. McLaughlin, Director
JAMES D. RAPPOLI March 31, 1999 James D. Rappoli, Director
R. D. WRIGHT March 31, 1999 Russell D. Wright, Director