-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Rn+DOzyHSxSeqCReWSOpMrju+72vaU0WSNKhpUB4kra7E1a1Slv0VQOhwUkczHcq qeLlboiEktLbuZdPA3o3pw== 0000070145-95-000086.txt : 19951221 0000070145-95-000086.hdr.sgml : 19951221 ACCESSION NUMBER: 0000070145-95-000086 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 24 CONFORMED PERIOD OF REPORT: 19950930 FILED AS OF DATE: 19951220 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NATIONAL FUEL GAS CO CENTRAL INDEX KEY: 0000070145 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 131086010 STATE OF INCORPORATION: NJ FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03880 FILM NUMBER: 95602842 BUSINESS ADDRESS: STREET 1: 10 LAFAYETTE SQ CITY: BUFFALO STATE: NY ZIP: 14203 BUSINESS PHONE: 2125417533 MAIL ADDRESS: STREET 2: 10 LAFAYETTE SQ CITY: BUFFALO STATE: NY ZIP: 14203 10-K 1 United States Securities and Exchange Commission Washington, D.C. 20549 Form 10-K Annual Report Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934 For the Fiscal Year Ended September 30, 1995 Commission File Number 1-3880 National Fuel Gas Company (Exact name of registrant as specified in its charter) New Jersey 13-1086010 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 10 Lafayette Square 14203 Buffalo, New York (Zip Code) (Address of principal executive offices) (716) 857-6980 Registrant's telephone number, including area code ----------------------------------------------------------- Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered Common Stock, $1 Par Value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES X NO --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ] The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,164,782,000 as of November 30, 1995. Common stock, $1 par value, outstanding as of November 30, 1995: 37,437,663 shares. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's Annual Report to Shareholders for 1995 are incorporated by reference into Part I of this report. Portions of the registrant's definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 15, 1996 are incorporated by reference into Part III of this report. NATIONAL FUEL GAS COMPANY FORM 10-K ANNUAL REPORT For the Fiscal Year Ended September 30, 1995 TABLE OF CONTENTS Page PART I ITEM 1. BUSINESS THE COMPANY AND ITS SUBSIDIARIES 1 RATES AND REGULATION 2 THE UTILITY OPERATION 3 THE PIPELINE AND STORAGE SEGMENT 3 THE EXPLORATION AND PRODUCTION SEGMENT 3 OTHER NONREGULATED OPERATIONS 4 SOURCES AND AVAILABILITY OF RAW MATERIALS 4 COMPETITION 5 SEASONALITY 7 CAPITAL EXPENDITURES 7 ENVIRONMENTAL MATTERS 7 MISCELLANEOUS 8 EXECUTIVE OFFICERS OF THE COMPANY 8 ITEM 2. PROPERTIES GENERAL INFORMATION ON FACILITIES 9 EXPLORATION AND PRODUCTION ACTIVITIES 9 ITEM 3. LEGAL PROCEEDINGS PARAGON/TGX PROCEEDINGS 10 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 12 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS 12 ITEM 6. SELECTED FINANCIAL DATA 13 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 14 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 28 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 59 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 59 ITEM 11. EXECUTIVE COMPENSATION 59 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 60 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 60 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K 60 SIGNATURES 65 PART I ITEM 1 Business The Company and its Subsidiaries National Fuel Gas Company (the Company or Registrant), a registered holding company under the Public Utility Holding Company Act of 1935, as amended (the Holding Company Act), was organized under the laws of the State of New Jersey in 1902. The Company is engaged in the business of owning and holding securities issued by its subsidiary companies. Except as otherwise indicated below, the Company owns all of the outstanding securities of its subsidiaries. Reference to "the Company" in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. The Company is an integrated natural gas operation consisting of three major business segments: 1. The Utility Operation is carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas and provides natural gas transportation services through a local distribution system located in western New York and northwestern Pennsylvania (principal metropolitan areas: Buffalo, Niagara Falls and Jamestown, New York; Erie and Sharon, Pennsylvania). 2. The Pipeline and Storage segment is carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation. Supply Corporation provides interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River, and (ii) 30 underground natural gas storage fields owned and operated by Supply Corporation and four other underground natural gas storage fields operated jointly with various major interstate gas pipeline companies. 3. The Exploration and Production segment is carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the Gulf Coast of Texas and Louisiana, in California and in the Appalachian region of the United States. Other Nonregulated operations are carried out by the following subsidiaries: * National Fuel Resources, Inc. (NFR), a New York corporation engaged in the marketing and brokerage of natural gas and the performance of energy management services for utilities and end-users located in the northeastern United States; * Leidy Hub, Inc. (Leidy), a New York corporation engaged in providing various natural gas hub services to customers in the northeastern, mid-Atlantic, Chicago and Los Angeles areas of the United States and Ontario, Canada, through (i) Leidy's 50% ownership of Ellisburg-Leidy Northeast Hub Company (a Pennsylvania general partnership) and (ii) Leidy's 14.5% ownership of Enerchange, L.L.C. (a Delaware limited liability company which in turn owns 50% of QuickTrade, L.L.C., another Delaware limited liability company); * Horizon Energy Development, Inc. (Horizon), a New York corporation formed in 1995 to engage in foreign and domestic energy projects through investment as a sole or partial owner in various business entities including Sceptre Power Company, a partnership which includes a team with considerable experience in developing such energy projects; * Seneca is also engaged in the marketing of timber from its Pennsylvania land holdings; * Highland Land & Minerals, Inc. (Highland), a Pennsylvania corporation which operates a sawmill and kiln in Kane, Pennsylvania; * Data-Track Account Services, Inc.(Data-Track), a New York corporation which provides collection services (principally issuing collection notices) for the Company's subsidiaries (principally Distribution Corporation); and * Utility Constructors, Inc. (UCI), a Pennsylvania corporation which discontinued its operations (primarily pipeline construction) in 1995 and whose affairs are being wound down. Financial information about each of the Company's industry segments can be found in Item 8 at Note I - "Business Segment Information." No single customer, or group of customers under common control, accounted for more than 10% of the Company's consolidated revenues in 1995. All references to years in this report are to the Company's fiscal year ended September 30 unless otherwise noted. The discussion of the Company's business segments as contained under the headings "Exploration and Production and Other Nonregulated Activities," "Utility Operation," and "Pipeline and Storage," which are included in the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K, are included in this electronic filing as Exhibit 13 and incorporated herein by reference. Rates and Regulation The Company is subject to regulation by the Securities and Exchange Commission (SEC) under the broad regulatory provisions of the Holding Company Act, including provisions relating to issuance of securities, sales and acquisitions of securities and utility assets, intra-Company transactions and limitations on diversification. The SEC has recommended to Congress the conditional repeal of the Holding Company Act, in conjunction with legislation which would allow the various state regulatory commissions to have access to such books and records of companies in a holding company system as would be necessary for effective regulation, and allow for federal audit authority and oversight of affiliate transactions. The effect of these changes if implemented, combined with other recent SEC rule changes, would be to significantly reduce the number of applications filed under the Holding Company Act, exempt routine financings and expand diversification opportunities. However, the additional proposed access to Company books and records by state regulatory commissions would correspondingly increase the amount of regulatory burden at the state level. The Company is unable to predict at this time what type of regulatory changes, if any, may result from this proposal, and therefore what the impact on the Company might be. The Utility Operation's rates, services and other matters are regulated by the Public Service Commission of the State of New York (PSC) with respect to services provided within New York, and by the Pennsylvania Public Utility Commission (PaPUC) with respect to services provided within Pennsylvania. For additional discussion of the Utility Operation's rates and regulation, see Item 7 under the heading "Rate Matters," and Item 8 at Note B-Regulatory Matters. The Pipeline and Storage segment's rates, services and other matters are regulated by the Federal Energy Regulatory Commission (FERC). For additional discussion of the Pipeline and Storage segment's rates and regulation, see Item 7 under the heading "Rate Matters," and Item 8 at Note B- Regulatory Matters. This report occasionally refers collectively to the Utility Operation and the Pipeline and Storage segment as the Regulated Operations. In addition, the Company is subject to the same federal, state and local regulations on various subjects as other companies doing business in the same locations. The Company's operations other than Supply Corporation and Distribution Corporation are not regulated as to prices or rates for services. Accordingly, this report occasionally refers collectively to the Exploration and Production segment and the Other Nonregulated operations as the Nonregulated Operations. The Utility Operation The Utility Operation contributed approximately 50% of the Company's operating income before income taxes in 1995. Additional discussion of the Utility Operation industry segment appears in the forepart of the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K under the heading "Utility Operation," which is included in this electronic filing as Exhibit 13, below under the headings "Sources and Availability of Raw Materials" and "Competition," in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A), and in Item 8 at Notes B-Regulatory Matters, H-Commitments and Contingencies and I-Business Segment Information. The Pipeline and Storage Segment The Pipeline and Storage segment contributed approximately 40% of the Company's operating income before income taxes in 1995. The Pipeline and Storage segment currently has service agreements for substantially all of its firm transportation capacity, which totals approximately 1,860 million cubic feet (MMcf) per day. The Utility Operation has contracted for approximately 1,120 MMcf per day or 60% of that capacity until 2003 and continuing year-to-year thereafter. The Pipeline and Storage segment has available for sale to customers approximately 60.8 billion cubic feet (Bcf) of firm storage capacity. The Utility Operation has contracted for 25.3 Bcf or 42% of that capacity, in service agreements with initial terms of approximately 10 years and continuing year-to-year thereafter, effective beginning in 1993 (23.3 Bcf) and 1996 (2.0 Bcf). Nonaffiliated customers were contracted for 35.5 Bcf of storage capacity throughout 1995. The primary terms of current storage service agreements, representing 23.3 Bcf of the firm storage capacity contracted for by nonaffiliated customers, expired in 1995. Service continues year-to-year and can be terminated by the customer on one year's notice. Six such customers have given notice of termination or reduction effective March 31, 1996, accounting for a reduction of 4.2 Bcf of contracted firm storage capacity at that time. The Pipeline and Storage segment is actively marketing this available capacity. Additional discussion of the Pipeline and Storage segment appears in the forepart of the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K under the heading "Pipeline and Storage," which is included in this electronic filing as Exhibit 13, below under the headings "Sources and Availability of Raw Materials," "Competition" and "Environmental Matters," Item 7 "MD&A," and Item 8 at Notes B-Regulatory Matters, H-Commitments and Contingencies and I-Business Segment Information. The Exploration and Production Segment The Exploration and Production segment contributed approximately 10% of the Company's operating income before income taxes in 1995. Additional discussion of the Exploration and Production segment appears in the forepart of the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K under the heading "Exploration and Production and Other Nonregulated Activities," which is included in this electronic filing as Exhibit 13, below under the heading "Competition," Item 7 "MD&A," and Item 8 at Notes F-Financial Instruments, I-Business Segment Information and L-Supplementary Information for Oil and Gas Producing Activities. Other Nonregulated Operations Other Nonregulated operations contributed approximately 2% of the Company's operating income before income taxes in 1995. Corporate operations reduced the Company's operating income before income taxes by approximately 2%. Horizon was formed in 1995 to engage in foreign and domestic energy projects, including foreign utility companies and exempt wholesale generators of electricity. The SEC in 1995 authorized the Company (through Horizon and intermediate companies) to (i) invest up to an aggregate of $150.0 million through December 2001 in such activities, and (ii) issue debt and equity, provide guarantees and assume liabilities up to that amount in order to finance such activities. The Company contributed $1.0 million in capital to Horizon in 1995. Horizon was at year-end 1995 considering investment opportunities in eastern Europe, South America and Asia, and is the controlling partner in Sceptre Power Company, a partnership which includes a team with considerable experience in developing such energy projects. NFR is seeking to add the brokering of electric power to its existing gas marketing business. In 1995, NFR obtained authorization from the FERC to become an electric power broker in connection with the FERC's announced restructuring of the electric power industry. NFR's application for authorization from the SEC to engage in such activities was pending at year-end 1995. Leidy recognized a loss of less than $1.0 million in 1995 from writing off Leidy's equity investment in Metscan, Inc., a developer of electronic gas meter reading devices, which ceased operations and liquidated. Leidy's business now consists exclusively of activities related to natural gas hubs as described below. The SEC in 1995 authorized Leidy to enter into a transaction (which was consummated in October 1995) by which Leidy invested less than $1.0 million to acquire a 14.5% ownership interest in Enerchange, L.L.C. (Enerchange). This investment effectively gave Leidy (i) a somewhat larger portion of the profits or losses of Ellisburg-Leidy Northeast Hub Company, (ii) a portion of the profits or losses of natural gas hubs in Chicago and Los Angeles, (iii) 14.5% of Enerchange's profits or losses in buying and selling gas at all three market hubs, and (iv) 14.5% of Enerchange's profits or losses as a 50% owner of QuickTrade, L.L.C., which is developing an on-line computer service on which subscribers will buy and sell gas at hubs and obtain related services. Additional discussion of the Other Nonregulated operations appears in the forepart of the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K under the heading "Exploration and Production and Other Nonregulated Activities," subheading "Other Nonregulated Activities," which is included in this electronic filing as Exhibit 13, below under the headings "Sources and Availability of Raw Materials" and "Competition," Item 7 "MD&A," and Item 8 at Note I-Business Segment Information. Sources and Availability of Raw Materials Natural gas is the principal raw material for the Utility Operation and some of the Other Nonregulated operations, as discussed below. The Pipeline and Storage segment transports and stores gas owned by its customers, whose gas originates in the southwestern United States, Canada and Appalachia. Some of the Other Nonregulated operations rely upon timber located on Seneca's lands, so that source and availability are not issues. The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as described in the forepart of the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K under the heading "Exploration and Production and Other Nonregulated Activities," which is included in this electronic filing as Exhibit 13, Item 7 "MD&A," and Item 8 at Notes I-Business Segment Information and L - Supplementary Information for Oil and Gas Producing Activities. In 1995, the Utility Operation purchased 130.8 Bcf of gas. Gas purchases from various producers and marketers in the southwestern United States under long-term (two years or longer) contracts accounted for 77% of these purchases. Purchases of gas in Canada under long-term contracts, purchases of gas in Canada and the United States on the spot market (contracts of less than a year) and purchases from Appalachian producers accounted for 3%, 15% and 5%, respectively, of the Utility Operation's 1995 gas purchases. Gas purchases from Vastar Resources, Inc. and Natural Gas Clearinghouse (southwest gas under long-term contract) represented 13% and 12%, respectively, of total 1995 gas purchases by the Utility Operation. No other producer or marketer provided the Utility Operation with 10% or more of its gas requirements in 1995. To move its gas from the point of purchase to its distribution system in New York and Pennsylvania, the Utility Operation purchases firm transportation and storage services from various interstate pipeline companies including Supply Corporation. See Item 8, Note H-Commitments and Contingencies, for a discussion of the Utility Operation's obligations under its nonaffiliated pipeline capacity, gas purchase and gas storage contracts. The Utility Operation also transports gas owned by others (principally industrial and commercial end-users). Gas produced by Appalachian producers, especially in Pennsylvania and New York, remained an important source of supply for the Utility Operation's transportation customers, who also purchased gas from the southwestern United States and Canadian suppliers. Other Nonregulated operations need natural gas for NFR's marketing and Leidy's hub services, but are relatively indifferent as to the source. Competition The natural gas industry was competitive in 1995 and is expected to become more competitive in the future. Competition existed among providers of natural gas, as well as between natural gas and other sources of energy. Management continues to believe that there will be increased usage of natural gas nationwide over the longer term, so that opportunities exist for increased sales. This increased use of natural gas nationwide is expected to result mainly from the increased use of natural gas as an electric generation and cogeneration fuel, conversion of home heating load from oil to gas, economic and population growth, competitive prices and technological developments. The long-term trend in natural gas will depend upon the balance of supply and demand, as well as weather (colder weather generally increases demand and thus price). As noted, demand is expected to increase over the longer term. Supply will be impacted by the potential increase in domestic supplies due to more efficient exploration and production technology and the amount of gas imported into the United States from Canada and Mexico. The continuing deregulation of the natural gas industry should also enhance the competitive position of natural gas relative to other energy sources by removing some of the regulatory impediments to adding customers and responding to market forces. In addition, the environmental advantages of natural gas compared with other fuels should increase the role of natural gas as an energy source. The potential environmental role of natural gas was enhanced by passage of the federal Clean Air Act Amendments of 1990, which United States industries have not completed implementing. Moreover, natural gas is abundantly available in North America, which makes it a dependable alternative to imported oil. The electric industry is moving toward a more competitive environment as a result of the federal Energy Policy Act of 1992 and initiatives undertaken by the FERC and others to restructure the electric industry much the same as the FERC restructured the gas industry. It is unclear at this point what impact this restructuring will have on the natural gas industry. The Company competes on the basis of price, service, quality and reliability, product performance and other factors. Sources and providers of energy, other than those described under this "Competition" heading, do not compete with the Company to any significant extent. Competition: the Utility Operation The changes precipitated by the FERC's restructuring of the gas industry in Order No. 636 are redefining the roles of the gas utility industry and the state regulatory commissions. Competition has arrived for utilities. The PSC issued an order in 1995 providing for the Utility Operation to be the first gas utility in New York to implement unbundling of its services pursuant to a 1994 PSC order on restructuring. The Utility Operation now offers unbundled flexible services to its large commercial and industrial customers. This unbundling is an important step toward the Utility Operation's goal of opening its market area to competition for all customers, including residential. Competition for large-volume customers continues, with pipeline companies increasingly attempting to sell or transport gas directly to end-users located within the Utility Operation's service territories (i.e., bypass). The FERC remains unwilling to shield local distribution companies from such bypass. In addition, competition continues with fuel oil suppliers, and may increase with electric utilities making retail energy sales. Responding to those developments, the Utility Operation is now better able to compete, through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets). The Utility Operation continues to (i) develop or promote new sources and uses of natural gas and/or new services, rates and contracts and (ii) emphasize and provide high quality service to its customers. Competition: the Pipeline and Storage Segment The Pipeline and Storage segment competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeastern United States and with other companies providing gas storage services. The Pipeline and Storage segment has some unique characteristics which enhance its competitive position. Its facilities are located adjacent to Canada and the northeastern United States, and provide part of the link between gas-consuming regions of the northeastern United States and gas-producing regions of Canada and the southwestern, southern and midwestern regions of the United States. This location offers the opportunity for increased transportation and storage services in the future. The Pipeline and Storage segment will continue to evaluate ways to take advantage of its location to open new markets and expand existing ones, especially in the gas storage business. There is, however, increased competition to provide services to the northeastern market in the form of other proposed pipeline expansions and proposed storage projects. The northeastern utilities which are currently the largest customers of transportation and storage services are showing some hesitance to enter into new long-term transportation or storage arrangements while their state commissions are considering significant restructuring of their bundled sales services. Competition: the Exploration and Production Segment The Exploration and Production segment competes with other gas and oil producers, and with fuel oil and electricity wholesalers and producers, with respect to its sales of oil and gas. The Exploration and Production segment also competes with other oil and gas exploration and production companies of various sizes for leases and drilling rights for exploration and development prospects. To compete in this environment, the Exploration and Production segment originates and acts as operator on most prospects, minimizes risk of exploratory efforts through partnership-type arrangements, applies the latest technology for both exploratory studies and drilling operations and focuses on market niches that suit its size, operating expertise and financial criteria. Competition: Other Nonregulated Operations In the Other Nonregulated operations, NFR competes with other gas marketers and energy management services providers. Leidy competes with other natural gas hub service providers. Highland competes with other sawmills in northwestern Pennsylvania. Horizon competes with other entities seeking to develop foreign and domestic energy projects. Seasonality Variations in weather conditions can materially affect the volume of gas delivered by the Utility Operation, as virtually all of its residential and commercial customers use gas for space heating. The effect on the Utility Operation in New York is mitigated somewhat by a weather normalization clause which is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers' current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers' current bills. The Pipeline and Storage segment's volumes transported and stored may vary materially depending on weather, without materially affecting its earnings. The Pipeline and Storage segment's rates are based on a straight fixed-variable rate design which allows recovery of all fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed only to reimburse the variable costs caused by actual transportation or storage of gas. Capital Expenditures A discussion of capital expenditures by business segment is included in Item 7 under the heading "Investing Cash Flow," subheading "Capital Expenditures." Environmental Matters Supply Corporation was engaged in discussions, but not formal proceedings, with the New York Department of Environmental Conservation (NYDEC) concerning the 71 plugged and abandoned gas wells located within the boundaries of the Bennington and Holland, New York underground natural gas storage fields. Before 1995, Supply Corporation voluntarily replugged 27 wells which were believed to be venting small amounts of natural gas to the atmosphere. In November 1995, the NYDEC informed Supply Corporation that it had accepted Supply Corporation's proposed monitoring program and would not require the previously contemplated replugging of wells unless those wells started to vent gas to the atmosphere. A discussion of environmental matters involving the Company is included in Item 8, Note H-Commitments and Contingencies. Miscellaneous The Company had 2,925 full-time employees at September 30, 1995, a decrease of 7% from the 3,148 employed at September 30, 1994. Agreements covering employees in collective bargaining units in New York were last renegotiated in October 1994 and are scheduled to expire in February 1998. Agreements covering most employees in collective bargaining units in Pennsylvania were renegotiated in calendar 1993 and are scheduled to expire in April and May 1996. The Company expects to begin negotiations with the Pennsylvania unions early in calendar 1996. The Company has numerous county and municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. The Company has regularly renewed such franchises at expiration and expects no difficulty in continuing to renew them. Executive Officers of the Company (1)
Age as of Company Position Date Elected Name 9/30/95 Since 1990 To Position ---- -------- ---------- ----------- Bernard J. Kennedy 64 Chairman of the Board of Directors. March 21, 1989 Chief Executive Officer. August 1, 1988 President. January 1, 1987 Director. March 29, 1978 Chairman of the Board of certain subsidiaries of the Company. August 1, 1988 Philip C. Ackerman 51 Director. March 16, 1994 Senior Vice President. June 1, 1989 President of Distribution Corporation. October 1, 1995 President of Seneca. June 1, 1989 Executive Vice President of Supply Corporation. October 1, 1994 President of Horizon. September 13, 1995 President of certain other of the Company's subsidiaries from prior to 1990. Richard Hare 57 President of Supply Corporation. June 1, 1989 Senior Vice President of Penn-York Energy Corpor- ation until its merger into Supply Corporation on July 1, 1994. June 1, 1989 William J. Hill 65 Director. September 20, 1995 President of Distribution Corporation until October 1, 1995. June 1, 1989 (1) The Company has been advised that there are no family relationships among any of the officers listed, and that there is no arrangement or understanding among any one of them and any other persons pursuant to which he was elected as an officer.
ITEM 2 PROPERTIES General Information on Facilities The investment of the Company in net property, plant and equipment was $1,649.2 million at September 30, 1995. Approximately 78% of this investment is in the Utility Operation and Pipeline and Storage segments, which are primarily located in western New York and western Pennsylvania. The remaining investment in property, plant and equipment is mainly in the Exploration and Production segment, which is primarily located in the Gulf Coast, southwestern, western and Appalachian regions of the United States. The Utility Operation has the largest net investment in property, plant and equipment, compared with the Company's other business segments. Its net investment in its gas distribution network (including 14,666 miles of distribution pipeline) and its services represent approximately 58% and 27%, respectively, of the Utility Operation's net investment of $822.8 million. The Pipeline and Storage segment represents a net investment of $463.6 million in transmission and storage facilities at September 30, 1995. Transmission pipeline, with a net cost of $145.1 million, represents 31% of this segment's total net investment and includes 2,778 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 34 storage fields, 4 of which are jointly operated with certain pipeline suppliers, and 511 miles of pipeline. Included in the storage facilities net investment is $85.6 million of base gas. The Pipeline and Storage segment has 31 compressor stations with 73,450 installed compressor horsepower. The Exploration and Production segment had a net investment in properties amounting to $340.0 million at September 30, 1995. Of this amount, Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast regions was $285.2 million, and Seneca's net investment in oil and gas properties in the Appalachian region aggregated $54.8 million. During the past five years, the Company has made significant additions to plant in order to expand and improve transmission and distribution facilities for both retail and transportation customers and to augment the reserve base of oil and gas. Net plant has increased $442.8 million, or 37%, since 1990. The Regulated Operation's facilities provided the capacity to meet its 1995 peak day sendout, including transportation service, of 1,847 MMcf, which occurred on February 5, 1995. Withdrawals from storage provided approximately 45% of the requirements on that day. Company maps, which are included in the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K, are narratively described in the Appendix to this electronic filing and are incorporated herein by reference. Exploration and Production Activities The information that follows is disclosed in accordance with SEC regulations, and relates to the Company's oil and gas producing activities. For a further discussion of oil and gas producing activities, refer to Note L-Supplementary Information for Oil and Gas Producing Activities, under Item 8 of this Form 10-K. Supply Corporation files Form 2 "Annual Report of Natural Gas Companies" and Form 15 "Annual Report of Gas Supply" with the FERC. The reserve disclosures in these reports were filed as of December 31, 1994, and represent reserves related to Supply Corporation's held for future use storage wells. These reserves are appropriately not included in reserves reported in Note L. Seneca is not regulated by the FERC, and thus is not required to file Forms 2 and 15. Seneca's oil and gas reserves reported in Note L as of September 30, 1995, were estimated by Seneca's qualified geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis, Inc. The following is a summary of certain oil and gas information taken from Seneca's records: Production
For the Year Ended September 30 1995 1994 1993 - ------------------------------- ---- ---- ---- Average Sales Price per Mcf of Gas $ 1.67 $ 2.18 $ 2.20 Average Sales Price per Barrel of Oil $16.16 $14.86 $16.78 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ .44 $ .45 $ .54
Productive Wells
At September 30, 1995 Gas Oil - --------------------- --- --- Productive Wells - gross 2,115 257 - net 1,941 202
Developed and Undeveloped Acreage
At September 30, 1995 - --------------------- Developed Acreage - gross 595,787 - net 520,849 Undeveloped Acreage - gross 624,085 - net 588,431
Drilling Activity
Productive Dry ------------------ ------------------ For the Year Ended September 30 1995 1994 1993 1995 1994 1993 ---- ---- ---- ---- ---- ---- Net Wells Completed - Exploratory 5 5 9 0 4 6 - Development 6 8 16 0 0 3
Present Activities
At September 30, 1995 - --------------------- Wells in Process of Drilling - gross 7 - net 6
There are currently no waterflood projects or pressure maintenance operations of material importance. ITEM 3 Legal Proceedings Paragon/TGX Proceedings A. New York Litigation Since November 30, 1984, Distribution Corporation has been involved in litigation against Paragon Resources, Inc. (Paragon) and TGX Corp. (collectively Paragon/TGX), in the United States District Court for the Western District of New York (the District Court). Distribution Corporation sought a declaratory judgment concerning the contract effect of a December 20, 1983 PSC order (the Disapproval Order) which, among other things, disapproved a 1974 gas purchase agreement between Distribution Corporation's predecessor in interest, Iroquois Gas Corporation, and Paragon (the Paragon Contract). Paragon/TGX counterclaimed for (i) a declaration that the Disapproval Order did not affect the Paragon Contract in any way, whatsoever, (ii) approximately $4.4 million in respect of take-or-pay claims, and (iii) unquantified amounts in respect of other alleged breaches of the Paragon Contract. Commencing with its payment for production received in September 1984, and continuing through December 1993, when Paragon/TGX purported to assign the Paragon Contract, Distribution Corporation paid Paragon/TGX for Paragon Contract gas at prices below those developed by the Paragon Contract's price formula, as the same have been impacted, from time to time, by the Natural Gas Policy Act of 1978. On December 3, 1991, the United States Court of Appeals for the Second Circuit (the Second Circuit) issued an opinion regarding a partial summary judgment granted by the District Court. The Second Circuit essentially held that the Disapproval Order had "voided the Contract's price term," but that Paragon/TGX had elected an option available to it under the Paragon Contract to continue that contract, in the aftermath of the Disapproval Order, at "a price consistent with" that order. The Second Circuit also remanded the case to the District Court for further proceedings. In a letter dated December 13, 1991, TGX demanded that Distribution Corporation pay it $21.9 million (including interest), alleged to represent the difference between the amount received by Paragon/TGX in respect of Paragon Contract gas delivered during the period September 1984 through October 1991, and the amount allegedly due TGX in respect of such gas during such period. Distribution Corporation rejected TGX's demand. On September 29, 1994, Paragon/TGX served an amended answer and counterclaim. That pleading restates Paragon/TGX's claims for unquantified money damages respecting Distribution Corporation's alleged (i) breach of contract price and "take-or-pay" provisions, (ii) "lack of good faith . . . material breach" of the contract, and (iii) repudiation of the contract. The pleading also adds two new, but unquantified claims - (i) consequential damages suffered upon the sale of properties and assignment of the Paragon Contract at less than full value, and (ii) damages related to the allegation that Distribution Corporation "tortiously and with intent injured TGX in the conduct of its business." Distribution Corporation filed a timely reply to Paragon/TGX's claims. Various motions have been heard before the District Court. A United States Magistrate Judge is now handling other preliminary matters and discovery issues before the case is ultimately set for trial. B. State Commission Proceedings In 1992, Distribution Corporation filed two petitions with the PSC that involved the Paragon Contract. Distribution Corporation sought authority from the PSC to defer, and ultimately recover through rates, a partial settlement payment made to TGX. Distribution Corporation also requested the PSC to review the prices charged by TGX in the context of the "just and reasonable" standard of Section 110(4) of the New York Public Service Law and issue a declaratory order regarding its findings. The PSC consolidated the proceedings, and, in an order issued on May 5, 1995, (i) authorized Distribution Corporation to recover through rates the amounts previously paid to TGX, and (ii) dismissed Distribution Corporation's petition regarding the New York Public Service Law Section 110(4) issues because the PSC determined there was no "properly reviewable contract" that had been filed with it. In September 1995, Distribution Corporation filed a petition with the New York Supreme Court (Albany County, Special Term) seeking judicial review of the PSC's May 1995 order regarding the dismissal of Distribution Corporation's petition for a declaratory order. ITEM 4 Submission of Matters to a Vote of Security Holders No matter was submitted to a vote of security holders during the fourth quarter of 1995. PART II ITEM 5 Market for the Registrant's Common Stock and Related Shareholder Matters Information regarding the market for the Registrant's common stock and related shareholder matters appears in Note D - Capitalization and Note K- Market for Common Stock and Related Shareholder Matters (unaudited), under Item 8 of this Form 10-K, and reference is made thereto. ITEM 6 Selected Financial Data
Year Ended September 30 1995 1994 1993 1992 1991 - ----------------------- ---- ---- ---- ---- ---- Summary of Operations (Thousands) Operating Revenues $975,496 $1,141,324 $1,020,382 $920,450 $865,131 -------- ---------- ---------- -------- -------- Operating Expenses: Purchased Gas 351,094 497,687 409,005 363,690 364,246 Operation Expense and Maintenance 292,505 291,390 283,230 263,084 245,253 Property, Franchise and Other Taxes 91,837 103,788 95,393 89,158 83,095 Depreciation, Depletion and Amortization 71,782 74,764 69,425 55,726 50,805 Income Taxes - Net 43,879 47,792 41,046 35,231 23,285 -------- ---------- ---------- -------- -------- 851,097 1,015,421 898,099 806,889 766,684 -------- ---------- ---------- -------- -------- Operating Income 124,399 125,903 122,283 113,561 98,447 Other Income 5,378 3,656 4,833 5,790 11,793 -------- ---------- ---------- -------- -------- Income Before Interest Charges 129,777 129,559 127,116 119,351 110,240 Interest Charges 53,883 47,124 51,899 59,041 61,250 -------- ---------- ---------- -------- -------- Income Before Cumulative Effect 75,894 82,435 75,217 60,310 48,990 Cumulative Effect of Changes in Accounting - 3,237 - - - -------- ---------- ---------- -------- -------- Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217 $ 60,310 $ 48,990 ======== ========== ========== ======== ======== Per Common Share Data Earnings $2.03 $2.32* $2.15 $1.94 $1.63 Dividends Declared $1.60 $1.56 $1.52 $1.48 $1.44 Dividends Paid $1.59 $1.55 $1.51 $1.47 $1.43 Dividend Rate at Year-End $1.62 $1.58 $1.54 $1.50 $1.46 Number of Common Shareholders at Year-End 21,429 22,465 22,893 23,218 22,662 ======== ========== ========== ======== ======== Net Property, Plant and Equipment (Thousands) Regulated: Utility Operation $ 822,764 $ 787,794 $ 754,466 $ 719,755 $ 678,933 Pipeline and Storage 463,647 443,622 436,547 423,383 380,008 ---------- ---------- ---------- ---------- ---------- 1,286,411 1,231,416 1,191,013 1,143,138 1,058,941 ---------- ---------- ---------- ---------- ---------- Nonregulated: Exploration and Production 339,950 295,418 273,470 261,446 248,787 Other 22,690 18,579 16,209 11,670 5,896 ---------- ---------- ---------- ---------- ---------- 362,640 313,997 289,679 273,116 254,683 ---------- ---------- ---------- ---------- ---------- Corporate 131 137 122 128 127 ---------- ---------- ---------- ---------- ---------- Total Net Plant $1,649,182 $1,545,550 $1,480,814 $1,416,382 $1,313,751 ========== ========== ========== ========== ========== Total Assets (Thousands) $2,038,302 $1,981,657 $1,801,540 $1,760,830 $1,560,834 ========== ========== ========== ========== ========== Capitalization (Thousands) Common Stock Equity $ 800,588 $ 780,288 $ 736,245 $ 632,333 $ 542,109 Long-Term Debt, Net of Current Portion 474,000 462,500 478,417 479,500 442,071 ---------- ---------- ---------- ---------- ---------- Total Capitalization $1,274,588 $1,242,788 $1,214,662 $1,111,833 $ 984,180 ========== ========== ========== ========== ========== * 1994 includes Cumulative Effect of Changes in Accounting of $.09. See Notes A and G to Consolidated Financial Statements.
ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations 1995 Compared with 1994 National Fuel's earnings were $75.9 million, or $2.03 per common share, in 1995. This compares with earnings of $82.4 million, or $2.23 per common share in 1994 (before the cumulative effect of the mandated changes in accounting for income taxes and post-employment benefits, which added a net $3.2 million, or $0.09 per common share of earnings in 1994). The earnings decrease in 1995 was attributable to lower earnings of the Company's Exploration and Production segment and Utility Operation, partly offset by higher earnings of the Pipeline and Storage segment, Other Nonregulated, and Corporate operations. Exploration and Production earnings declined because of low gas prices coupled with management's decision, based on those low gas prices, to delay Gulf Coast activity causing reduced levels of gas and oil production. The Utility Operation's earnings suffered from the warm weather and the impact of lower normalized usage per residential and commercial account. Additionally, the Utility Operation's New York jurisdiction annual reconciliation of gas costs, performed in August of each year, determined an amount of lost and unaccounted-for gas in excess of that allowed to be recovered by the Public Service Commission of the State of New York (PSC). The Pipeline and Storage segment earnings reflect the application of a final rule issued by the Federal Energy Regulatory Commission (FERC) in September 1995, which addresses and clarifies financial reporting aspects of the current practices for unbundled pipeline sales and open access transportation. The increase in earnings from the application of this rule was partly offset by higher operating and interest expense as well as the recording of a reserve for previously deferred preliminary survey and investigation charges for the Laurel Fields Storage Project. An open season held during August and September 1995 for nominations for firm storage capacity for this proposed underground natural gas storage development project failed to produce sufficient interest to proceed with the project at this time. Accordingly, this project has been delayed until at least 1997. Increased earnings in the Company's Other Nonregulated operations resulted mainly from a gain on the sale of equipment, net of accrued expenses, by the Company's pipeline construction subsidiary. This sale pertained to a strategic decision to discontinue the operations of this subsidiary. The Company's gas marketing subsidiary also increased earnings on a year-to-year basis as a result of increased margins and an increase in customers. In addition, Corporate operations benefited from cost saving measures, including the relocation of corporate headquarters. 1994 Compared with 1993 National Fuel's earnings (before the cumulative effect of the changes in accounting for income taxes and post-employment benefits, discussed above) were $82.4 million, or $2.23 per common share, in 1994. This represents an approximate 10% increase over 1993 earnings of $75.2 million and a 4% increase from 1993 earnings per common share of $2.15. Share amounts reflect a greater number of weighted average shares outstanding in 1994, principally because of the sale of 2.5 million shares of common stock in May 1993. The earnings increase in 1994 was attributable to higher earnings in the Company's Nonregulated and Utility operations, offset in part by lower earnings in the Pipeline and Storage segment. The increase in the Nonregulated operations consisted of higher earnings in the Exploration and Production segment as a result of record oil and gas production, more than compensating for a decline in oil and gas prices. Furthermore, the Company's natural gas marketing, pipeline construction and timber operations had improved earnings. The Utility Operation's earnings increased slightly because of colder weather and the impact of rate increases in New York and Pennsylvania. These increases were partly offset by an earnings decrease in the Pipeline and Storage segment, which resulted mainly because of two nonrecurring items in 1993: the settlement of a Supply Corporation rate case which resulted in a partial reduction of a provision for refund due customers; and a change in rate design, effective August 1, 1993, which increased 1993 earnings.
Operating Revenues Year Ended September 30 (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Utility Operation Retail Revenues: Residential $ 569,603 $ 677,068 $ 613,039 Commercial 137,869 177,249 156,851 Industrial 18,269 31,096 31,609 - ----------------------------------------------------------------------------- 725,741 885,413 801,499 Off-System Sales 18,255 6,930 945 Transportation 37,183 34,419 30,213 Other 4,885 4,911 3,961 - ----------------------------------------------------------------------------- 786,064 931,673 836,618 - ----------------------------------------------------------------------------- Pipeline and Storage Wholesale Revenues - - 444,142 Storage Service 59,826 58,971 41,041 Transportation 88,766 90,416 45,313 Other 15,995 3,734 4,072 - ----------------------------------------------------------------------------- 164,587 153,121 534,568 - ----------------------------------------------------------------------------- Exploration and Production 56,232 70,261 58,636 Other Nonregulated 57,075 72,036 42,099 - ----------------------------------------------------------------------------- 113,307 142,297 100,735 - ----------------------------------------------------------------------------- Less: Intersegment Revenues 88,462 85,767 451,539 - ----------------------------------------------------------------------------- Total Operating Revenues $ 975,496 $1,141,324 $1,020,382 ============================================================================= Operating Income (Loss) Before Income Taxes Year Ended September 30 (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Utility Operation $ 83,774 $ 90,584 $ 86,690 Pipeline and Storage 67,884 62,302 67,375 Exploration and Production 16,404 21,767 12,980 Other Nonregulated 3,021 2,505 (986) Corporate (2,805) (3,463) (2,730) - ----------------------------------------------------------------------------- Total Operating Income Before Income Taxes $168,278 $173,695 $163,329 =============================================================================
System Natural Gas Volumes Year Ended September 30 (in billion cubic feet) 1995 1994 1993 - ------------------------------------------------------------------------- Regulated Gas Sales Residential 79.9 90.6 86.9 Commercial 22.2 26.9 25.6 Industrial 4.8 6.5 6.5 Wholesale * - - 118.7 Off-System 9.4 3.3 0.3 - ------------------------------------------------------------------------- 116.3 127.3 238.0 - ------------------------------------------------------------------------- Nonregulated Gas Sales Gas Sales for Resale 0.4 0.3 - Production (in equivalent billion cubic feet) 25.4 29.5 24.9 - ------------------------------------------------------------------------- 25.8 29.8 24.9 - ------------------------------------------------------------------------- Total Gas Sales 142.1 157.1 262.9 - ------------------------------------------------------------------------- Transportation Utility Operation 52.8 52.2 48.9 Pipeline and Storage * 290.8 296.6 138.6 Nonregulated 2.5 1.4 - - ------------------------------------------------------------------------- 346.1 350.2 187.5 - ------------------------------------------------------------------------- Marketing Volumes 18.8 18.2 7.3 - ------------------------------------------------------------------------- Less Intersegment Volumes: Transportation 154.2 164.8 40.1 Production 5.0 2.5 4.3 Gas Sales - 0.1 112.2 - ------------------------------------------------------------------------- 159.2 167.4 156.6 - ------------------------------------------------------------------------- Total System Natural Gas Volumes 347.8 358.1 301.1 ========================================================================= * The elimination of wholesale volumes, as well as the increase in transportation volumes from 1993 to 1994 reflects Supply Corporation's adoption of FERC Order 636, effective on August 1, 1993.
Utility Operation Operating Revenues 1995 Compared with 1994 Operating revenues decreased $145.6 million in 1995 compared with 1994. This decrease reflects the recovery of decreased gas costs mainly because of lower gas sales of 11.0 billion cubic feet (Bcf) as well as a 15% decline in the average cost of purchased gas. The decline in residential and commercial gas sales of 15.4 Bcf can be attributed mainly to weather in Distribution Corporation's service territory that was, on average, 12.3% warmer than last year. The decline in industrial volumes of 1.7 Bcf reflects lower sales to a cogeneration customer. These declines were partly offset by an increase in off-system gas sales of 6.1 Bcf. Distribution Corporation, in each of its jurisdictions, has a mechanism whereby it has the opportunity to recover certain costs and retain a portion of the margin on these off-system sales. 1994 Compared with 1993 Operating revenues increased $95.1 million in 1994 compared with 1993. This increase reflects recovery of increased gas costs mainly due to higher gas sales, as well as general rate increases in the New York rate jurisdiction effective in both July 1993 and 1994 and in the Pennsylvania rate jurisdiction in December 1993 and higher revenues from off-system sales. Higher residential and commercial sales of 5.0 Bcf resulted primarily from weather in Distribution Corporation's service territory that was, on average, 6.5% colder than the prior year. Operating Income 1995 Compared with 1994 Operating income before income taxes decreased $6.8 million in 1995 compared with 1994. This decrease reflects the lower gas sales, discussed above, coupled with higher operating expenses. Although Distribution Corporation received general rate increases in New York and Pennsylvania in July 1994 and December 1994, respectively, the weather related reduction in volumes sold, especially in the Pennsylvania jurisdiction, negatively impacted margins. In both jurisdictions, lower normalized usage per residential and commercial account than was established in the ratemaking process also contributed to lower pretax operating income. In addition, Distribution Corporation's annual reconciliation of gas costs in its New York jurisdiction, performed in August each year, determined an amount of lost and unaccounted-for gas in excess of that allowed to be recovered by the PSC. The Utility Operation recognized an additional $4.3 million of gas cost expense as a result of this reconciliation. The impact of weather on Distribution Corporation's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on pretax operating income and earnings for the New York rate jurisdiction. In 1995, the WNC in New York preserved pretax operating income of $8.2 million as weather, overall, was warmer than normal for the period of October 1994 through May 1995. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact pretax operating income and earnings. In the Pennsylvania service territory, weather was 14.2% warmer than last year and 5.8% warmer than normal. The warmer weather in 1995 compared with 1994 had a negative impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction. 1994 Compared with 1993 Operating income before income taxes increased $3.9 million in 1994 compared with 1993. This increase reflects higher revenues, discussed above, partly offset by increased operating expenses. The severe cold weather during January and February 1994 necessitated an unusually high number of system repairs and related site restoration work, which increased maintenance expense. In 1994, the WNC in New York resulted in a benefit to customers of $5.8 million. In the Pennsylvania service territory, weather was 9.6% colder than the prior year and 8.4% colder than normal. The colder weather in 1994 compared with 1993 had a positive impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction.
Degree Days Percent Colder (Warmer) Than Year Ended September 30 Normal Actual Normal Last Year - ------------------------------------------------------------------------------ 1995: Buffalo 6,693 6,181 (7.6%) (11.4%) Erie 6,128 5,773 (5.8%) (14.2%) - ---------------------------------------------------------------------------- 1994: Buffalo 6,710 6,975 3.9% 3.6% Erie 6,202 6,726 8.4% 9.6% - --------------------------------------------------------------------------- 1993: Buffalo 6,723 6,730 0.1% 1.3% Erie 6,484 6,135 (5.4%) 2.5% - ---------------------------------------------------------------------------
Purchased Gas The cost of purchased gas is by far the Company's single largest operating expense. Annual variations in purchased gas costs can be attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses. Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and five upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers and for storage service with Supply Corporation and two nonaffiliated companies. In addition, Distribution Corporation can satisfy a portion of its gas requirements through spot market purchases. Distribution Corporation's average cost of purchased gas, including the cost of transportation and storage, was $3.19 per thousand cubic feet (Mcf) in 1995, a decrease of 15% from the average cost of $3.74 per Mcf in 1994. The average cost of purchased gas in 1994 was 3% lower than the $3.84 per Mcf in 1993. Pipeline and Storage Operating Revenues 1995 Compared with 1994 Operating revenues increased $11.5 million in 1995 compared with 1994. The increase reflects the application of a final rule issued by the FERC in September 1995, which addresses and clarifies financial reporting aspects of the current practices for unbundled pipeline sales and open access transportation. The Company restated interim operating revenues, operating income, net income and earnings per share in the first three quarters of fiscal 1995 to conform with the new requirements. For further details, refer to Note J - Quarterly Financial Data (unaudited), in Item 8 of this report. Management cannot predict as to whether or not comparable revenue relating to unbundled pipeline sales and open access transportation would be generated in the future, since much depends on the efficiency of transporting gas through Supply Corporation's system. 1994 Compared with 1993 Operating revenues decreased $381.4 million in 1994 compared with 1993. This decline reflects Supply Corporation's restructured operations under FERC Order 636, which became effective August 1, 1993. Under Order 636, Supply Corporation's gas purchasing and sales functions were discontinued and replaced with new transportation and storage services. Thus the recovery of purchased gas costs has been eliminated from Supply Corporation's revenues. Operating Income 1995 Compared with 1994 Operating income before income taxes increased $5.6 million in 1995 compared with 1994. This increase reflects the increase in operating revenues discussed above, offset in part by higher operating expense and the recording, in the fourth quarter of 1995, of a reserve in the amount of $3.7 million for previously deferred preliminary survey and investigation charges for the Laurel Fields Storage Project, as discussed above. 1994 Compared with 1993 Operating income before income taxes decreased $5.1 million in 1994 compared with 1993. This decrease was principally because of two nonrecurring items reflected in 1993. A rate case settlement in 1993, discussed above, resulted in Supply Corporation recording approximately $2.8 million of revenues in 1993 that related to 1992. In addition, the change to the straight fixed-variable (SFV) rate design contributed additional revenues of approximately $2.7 million for August and September 1993, when compared to Supply Corporation's former rate design. Exploration and Production Operating Revenues 1995 Compared with 1994 Operating revenues decreased $14.0 million in 1995 compared with 1994. This decrease reflects lower natural gas prices and management's decision to delay production activity in its Gulf Coast operations based on the decrease in prices. Natural gas production decreased 2.3 Bcf, or 10%, 2.0 Bcf of which occurred in the Gulf Coast operations. In addition, the weighted average price received for natural gas in fiscal 1995 decreased $0.51 per Mcf, or 23%. Oil production was down 291,000 barrels, or 28%. This drop reflects natural depletion and lower condensate production related to decreased gas production. Although the weighted average price received for oil in fiscal 1995 increased 9%, this was not enough to offset the lower production level. The fluctuations in prices denoted above do not reflect revenue from hedging activities, which contributed approximately $7.0 million in revenues during 1995. 1994 Compared with 1993 Operating revenues increased $11.6 million in 1994 compared with 1993. This increase was primarily attributable to Seneca's Gulf Coast operations and reflects the continued success of both its offshore drilling program in the Gulf of Mexico and its horizontal drilling program in central Texas. Gas production and oil production (mainly condensate from gas wells) hit record levels in 1994 and were up 34% and 59%, respectively, in the Gulf Coast Region and 17% and 24%, respectively, for all geographic regions combined. The weighted average price received for gas and oil production in 1994 as compared to 1993 decreased $0.02 per Mcf and $1.92 per barrel (bbl), respectively. Nonetheless, efforts to stabilize prices through hedging activities contributed approximately $1.6 million of operating revenues for the year.
Production Volumes Year Ended September 30 1995 1994 1993 - ---------------------------------------------------------- Gas Production (million cubic feet) Gulf Coast 14,294 16,296 12,134 West Coast 840 706 1,059 Appalachia 5,808 6,271 6,681 - ----------------------------------------------------------- 20,942 23,273 19,874 =========================================================== Oil Production (thousands of barrels) Gulf Coast 287 615 387 West Coast 433 404 431 Appalachia 19 11 13 - ----------------------------------------------------------- 739 1,030 831 ===========================================================
Weighted Average Prices Year Ended September 30 1995 1994 1993 - ---------------------------------------------------------- Weighted Average Gas Price/Mcf Gulf Coast $1.56 $2.03 $1.99 West Coast $1.33 $1.58 $1.62 Appalachia $2.01 $2.65 $2.67 Weighted Average Price $1.67 $2.18 $2.20 - ------------------------------------------------------------ Weighted Average Oil Price/bbl Gulf Coast $16.94 $15.54 $17.84 West Coast $15.66 $13.79 $15.76 Appalachia $15.72 $15.92 $18.81 Weighted Average Price $16.16 $14.86 $16.78
Operating Income 1995 Compared with 1994 Operating income before income taxes decreased $5.4 million in 1995 compared with 1994. This decrease reflects the lower revenues discussed above, partly offset by lower depletion expense, which is directly related to lower revenues. Lower operation and maintenance (O & M) expense also partly offset the decrease in revenues. The decrease in O & M was a result of decreased production. 1994 Compared with 1993 Operating income before income taxes increased $8.8 million in 1994 compared with 1993. This increase reflects the higher revenues discussed above, partly offset by higher depletion expense which is directly related to higher revenues. O & M expense remained substantially level in 1994 compared with 1993. Although O & M expense related to increased production activity in the Gulf Coast operations was higher in 1994 than 1993, it was offset by a charge to O & M in 1993 for work performed on Appalachian wells that did not recur in 1994. Other Nonregulated Operating Revenues 1995 Compared with 1994 Operating revenues decreased $15.0 million in 1995 compared with 1994. This decrease reflects lower operating revenues from UCI, the Company's pipeline construction subsidiary, as a result of management's decision to discontinue its pipeline construction operations. The decrease also reflects lower revenues from NFR, the Company's gas marketing subsidiary, largely because of lower natural gas prices in 1995 compared with 1994. 1994 Compared with 1993 Operating revenues increased $29.9 million in 1994 compared with 1993. This increase is almost entirely due to higher revenues from NFR as its gas marketing volumes more than doubled to 18.2 Bcf in 1994 from 7.3 Bcf in 1993. Operating Income 1995 Compared with 1994 Operating income before income taxes increased $0.5 million in 1995 compared with 1994. This increase can be attributed to improved performance by NFR as a result of improved margins and an increase in customers combined with better performance by UCI prior to the discontinuance of its pipeline construction operations. 1994 Compared with 1993 Operating income before income taxes increased $3.5 million in 1994 compared with 1993. This increase is due to the improved performance of UCI, which, although still operating at a loss, had higher margins than in 1993. In addition, the improved performance of NFR and the Company's timber operations enhanced operating income before income taxes of this segment. Income Taxes, Other Income and Interest Charges Income Taxes Income taxes decreased in 1995, mainly because of a decrease in pretax income. The opposite was true in 1994 as income taxes increased because of an increase in pretax income. Income taxes in 1995 reflect lower Section 29 nonconventional fuel tax credits. These credits, which relate to production from qualified gas wells, decreased to $0.9 million in 1995 from $1.7 million in 1994 and $2.6 million in 1993. These credits are a direct reduction of income tax expense. Other Income Other income increased $1.7 million in 1995, primarily because of a gain of $2.5 million recorded by UCI on the sale of its pipeline construction equipment. The sale of the equipment resulted from management's decision to discontinue its pipeline construction operations. Other income decreased $1.2 million in 1994. A portion of the decrease in 1994 was because Distribution Corporation discontinued the accrual of interest income on deferred contract reformation costs (CRC) in April 1993, in accordance with a settlement with the PSC for full recovery of CRC. In addition, the decrease in 1994 reflects lower interest income on temporary cash investments. Interest Charges Interest on long-term debt increased $4.2 million in 1995 and decreased $1.8 million in 1994. The increase in 1995 can be attributed to a higher average amount of long-term debt balance in 1995 compared to 1994. The decrease in 1994 was mainly due to refinancing activities, whereby higher-interest long-term debt was replaced with lower-interest long-term debt. Other interest charges increased $2.6 million in 1995 and decreased $3.0 million in 1994. The increase in 1995 resulted primarily from an increase in the weighted average interest rate on short-term borrowings, partly offset by lower average outstanding balances. In addition, interest in 1995 includes increased interest expense on Amounts Payable to Customers. The decline in 1994 reflects lower interest on short-term borrowings because of lower average amounts outstanding, offset in part by an increase in the weighted average interest rate. Capital Resources and Liquidity The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
Sources (Uses) of Cash Year Ended September 30 (in millions) 1995 1994 1993 - ----------------------------------------------------------------- Provided by Operating Activities $173.5 $199.2 $123.7 Capital Expenditures (182.8) (135.1) (131.9) Short-Term Debt, Net Change 35.1 (84.3) (30.2) Long-Term Debt, Net Change 4.0 80.1 (51.1) Issuance of Common Stock 2.5 9.1 78.8 Common Dividends (59.2) (57.2) (52.2) All Other-Net 10.6 3.6 0.2 - ------------------------------------------------------------------ Net Increase (Decrease) in Cash and Temporary Cash Investments $(16.3) $ 15.4 $(62.7) ==================================================================
Operating Cash Flow Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, deferred income taxes and allowance for funds used during construction. In 1994, noncash items also included the cumulative effect of required changes in accounting for income taxes and post-employment benefits. Cash provided by operating activities in the Utility Operation and Pipeline and Storage segment may vary substantially from year to year because of supplier refunds, the impact of rate cases, and for the Utility Operation, fluctuations in weather and over- or under-recovered purchased gas costs. The impact of weather on cash flow is tempered in the Utility Operation's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's SFV rate design. Net cash provided by operating activities totalled $173.5 million in 1995, a decrease of $25.7 million compared with the $199.2 million provided by operating activities in 1994. This decrease reflects lower revenues and earnings in the Exploration and Production segment, mainly from its Gulf Coast operations, coupled with lower payable balances. This was partly offset by higher cash flow from the Utility Operation because of an over-recovery of gas costs, an increase in supplier refunds received during the year, a reduction in stored gas inventory, and a decrease in receivable balances. Investing Cash Flow Capital Expenditures Capital expenditures totalled $182.8 million in 1995. The table below presents these expenditures by business segment:
1995 Year Ended September 30 (in millions) Amount Percentage - ----------------------------------------------------------------------- Utility Operation $ 64.8 35.4% Pipeline and Storage 38.7 21.2 Exploration and Production 69.7 38.1 Other Nonregulated 9.6 5.3 - -------------------------------------------------------------------- $182.8 100.0% ==================================================================== Most of the Utility Operation's capital expenditures were for the replacement of mains and main extensions, as well as for the replacement of service lines and, to a minor extent, the installation of new services. Pipeline and Storage capital expenditures included approximately $5.0 million in connection with its link with the Empire State Pipeline at Grand Island, New York and approximately $5.1 million related to compressor engine emission controls necessary to comply with the Clean Air Amendments of 1990. In addition, capital expenditures were made for additions, improvements and replacements to this segment's transmission and storage systems. The Exploration and Production segment spent approximately $49.0 million on its offshore program in the Gulf of Mexico, including offshore lease acquisitions and drilling expenditures. Lease acquisitions included a 30% working interest in an oil and gas field in West Delta Blocks 31 and 32. The majority of offshore drilling expenditures were spent on West Cameron 552, West Cameron 522, West Delta 17 and Vermillion 252. Approximately $21.0 million was spent on the Exploration and Production segment's onshore program, including horizontal onshore drilling in central Texas and the acquisition of a 240-acre oil field located in the Silverthread Field in California. Other Nonregulated capital expenditures consisted primarily of timberland purchases. The Company's estimated capital expenditures for the next three years are:
Year Ended September 30 (in millions) 1996 1997 1998 - -------------------------------------------------------------------- Utility Operation $ 60.7 $ 58.9 $ 57.9 Pipeline and Storage 21.5 20.5 20.5 Exploration and Production 90.4 91.3 95.0 Other Nonregulated 0.3 0.3 0.3 - -------------------------------------------------------------------- $172.9 $171.0 $173.7 ====================================================================
Estimated expenditures for the Utility Operation during the next three years will be concentrated in the areas of main replacements and extensions, service line replacements and, to a minor extent, the installation of new services. Estimated expenditures for the Pipeline and Storage segment in 1996 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines. Estimated capital expenditures in 1996 for the Exploration and Production segment are approximately 30% higher than capital spending in 1995 as the Company sees significant opportunities for growth in this segment. These expenditures will be directed mainly toward developing Seneca's Gulf Coast offshore prospects, reserve acquisitions and significantly expanding exploration activities. The Company's capital expenditure program is under continuous review. The amounts are subject to modification for opportunities in the natural gas industry such as the acquisition of attractive oil and gas properties or storage facilities and the expansion of transmission line capacities. While the majority of capital expenditures in the Utility Operation are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures in the Company's other business segments depends, to a large degree, upon market conditions. Expenditures in the Regulated Operations are also dependent on adequate rate relief. Other Cash received on the sale of the Company's investment in property, plant and equipment is reflected as a cash flow from investing activities. Approximately $4.0 million of cash was received during fiscal 1995 related to the sale of certain gas reserves in the Gulf of Mexico. Proceeds of this sale were credited to property, plant and equipment in accordance with the full cost method of accounting. During the third quarter of fiscal 1995, approximately $6.2 million of cash was received related to the sale of UCI's pipeline construction equipment. On August 29, 1995, the Company received SEC approval to acquire all of the issued and outstanding common stock of Horizon Energy Development, Inc. (Horizon), a New York corporation formed to engage in foreign and domestic energy projects, including foreign utility companies and exempt wholesale generators of electricity. The SEC authorized the Company (through Horizon and intermediate companies) to invest up to an aggregate of $150.0 million through December 2001 in such activities. On September 15, 1995, the Company acquired 500 shares of Horizon $1 par common stock for $1.0 million. Currently, Horizon is considering investment opportunities in eastern Europe, South America and Asia, and is the controlling partner in Sceptre Power Company, a partnership which includes a team with considerable experience in developing such energy projects. Financing Cash Flow In order to meet the Company's capital requirements, cash from external sources must periodically be obtained through short-term bank loans and commercial paper, as well as through issuances of long-term debt and equity securities. The Company expects these traditional sources of cash to continue to supplement its internally generated cash during the next several years. On May 1, 1995, the Company retired $55.0 million of 6.07% medium-term notes and $20.0 million of 6.10% medium-term notes, both of which matured on that date. On June 8, 1995 and June 23, 1995, the Company retired $20.0 million of 9.32% medium-term notes and $1.0 million of 6.10% medium-term notes, respectively, which matured on those dates. On June 12, 1995, the Company issued $50.0 million of 7.375% medium-term notes due in June 2025. After reflecting underwriting discounts and commissions, the proceeds to the Company amounted to $49.3 million. On July 3, 1995, the Company issued $50.0 million of 6.08% medium-term notes due in July 1998. After reflecting underwriting discounts and commissions, the proceeds to the Company amounted to $49.8 million. The Company's embedded cost of long-term debt was 7.3% at both September 30, 1995 and 1994. At September 30, 1995, the Company has registered under the Securities Act of 1933, as amended, and has authority under the Public Utility Holding Company Act of 1935, as amended, to issue and sell up to $120.0 million of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company. Consolidated short-term debt increased $35.1 million during 1995. The Company continues to consider short-term bank loans and commercial paper important sources of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, exploration and development expenditures and other working capital needs. The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company's covenants contained in its indenture covering its long-term debt, as amended, the Company would have been permitted to issue up to a maximum of approximately $483.0 million in additional long-term unsecured indebtedness at September 30, 1995, in light of then current long-term interest rates. In addition, at September 30, 1995, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $252.4 million of short-term debt. The Company has recently filed with the SEC for authorization to borrow on a short-term basis for a five-year period. With this request, the Company is seeking to increase its short-term borrowing limits. The filing, if approved, would increase the Company's limit on commercial paper from $105.0 million to $300.0 million and would increase the aggregate maximum short-term borrowing level from $400.0 million to $600.0 million. The Company, through Seneca, is engaged in certain price swap agreements as a means of hedging a portion of the market risk associated with fluctuations in the market price of natural gas and crude oil. These price swap agreements are not held for trading purposes. During 1995, Seneca utilized natural gas and crude oil swap agreements with notional amounts of 16.3 equivalent Bcf and 711,000 equivalent bbl, respectively. This activity resulted in net revenues of approximately $7.0 million. At September 30, 1995, Seneca had natural gas swap agreements outstanding with a notional amount of approximately 23.8 equivalent Bcf at prices ranging from $1.70 per Mcf to $2.16 per Mcf. Seneca also had crude oil swap agreements outstanding at September 30, 1995 with a notional amount of 1,780,000 equivalent bbl at prices ranging from $17.40 per bbl to $19.00 per bbl. In addition, the Company has SEC authority to enter into certain interest rate swap agreements. For further discussion, see disclosure in Note F - Financial Instruments under the heading "Derivative Financial Instruments" in Item 8 of this report. The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, in Item 8 of this report, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, neither this litigation nor these other regulatory matters are expected to materially change the Company's present liquidity position. Rate Matters Utility Operation New York Jurisdiction In November 1995, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $28.9 million with a requested return on equity of 11.5%. Proceedings in this rate case are ongoing and management cannot predict their outcome. New rates are expected to become effective in October 1996. Prior to this filing, Distribution Corporation entered into proceedings concerning a multi-year settlement, the outcome of which is uncertain at this time. In October 1994, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $56.5 million with a requested return on equity of 12.85%. In September 1995, the PSC issued an order authorizing a base rate increase of $14.2 million with a return on equity of 10.4%. The new rates became effective as of September 20, 1995. Pennsylvania Jurisdiction On March 15, 1995, Distribution Corporation filed in its Pennsylvania jurisdiction a request for an annual rate increase of $22.0 million with a return on equity of 13.25%. In September 1995, the Pennsylvania Public Utility Commission (PaPUC) approved a settlement authorizing a base rate increase of $6.0 million with no specified rate of return on equity. The new rates became effective as of September 27, 1995. On March 8, 1994, Distribution Corporation filed in its Pennsylvania jurisdiction a request for an annual rate increase of $16.0 million with a return on equity of 12.25%. A proposal for a WNC was included in this filing. On December 6, 1994, an order was issued by the PaPUC authorizing an annual rate increase of $4.8 million with a return on equity of 11.0% and without a WNC. The new rates became effective as of December 7, 1994. General rate increases in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses. State Regulatory Environment Changes precipitated by the FERC's Order 636 are redefining the roles of the utility industry and the state regulatory commissions. Competition has arrived for utilities, and similar to what was done in the pipeline sector of the natural gas industry, regulators are requiring utilities to unbundle their services. Details of these recent developments are described below. Many state regulators believe that utilities can gain efficiency through performance-based incentive ratemaking. Such ratemaking is intended to enhance the traditional cost-of-service ratemaking formula, which many believe does not provide incentives to operate efficiently. Distribution Corporation proposed several customer service performance incentives in its New York rate case filed in October 1994. In its September 1995 order concerning the October 1994 rate filing, the PSC adopted incentive mechanisms that will allow it to administer penalties determined by Distribution Corporation's ability to maintain required performance levels. The incentives relate to: response time to customer inquiries and complaints; billing accuracy; keeping appointments for service; and efficiency in the installation of new service lines. The New York and Pennsylvania regulatory commissions have instituted several generic proceedings related, among other things, to restructuring in response to the FERC's Order 636. Distribution Corporation is working closely with the state regulatory commissions to resolve the complexities of industry restructuring. The more significant proceedings, all of which are still pending, are discussed below: New York Finance Proceeding. The purpose of this proceeding is to develop a uniform method for calculating a utility's rate of return on equity. Ratesetting Proceeding. This proceeding is intended to develop guidelines for settlements, incentive ratemaking and multi-year rate filings, in addition to the traditional single-year procedure. Thus, a menu of options would be available for each utility to select the appropriate ratemaking proposal. Generic Restructuring Proceeding. This proceeding is examining the appropriate retail or end-use impacts resulting from the FERC's Order 636 pipeline restructuring. In December 1994, the PSC issued an Opinion and Order in this docket instructing the state's local distribution companies (LDC) to file tariffs that would, among other things, unbundle retail services, provide for small-customer aggregation, adopt flexible, market-based rates and divide the LDC's market into core and non-core segments. In connection with its 1994 rate case, Distribution Corporation implemented many of the policies and guidelines contained in the December 1994 Order, and now offers unbundled, flexible services to its commercial and industrial customers. In November 1995, Distribution Corporation submitted a filing designed to further comply with the December 1994 Order by (i) offering transportation service to all customers, including residential; and (ii) surcharging transportation customers for Order 636 transition costs. These latter changes are subject to approval by the PSC. Generic Affordability/Gas Cost Incentive Proceeding. This proceeding is investigating the development of guidelines for "affordable" natural gas utility service and, on a separate track, an appropriate gas cost incentive mechanism. For the Affordability track, it is expected that the PSC will issue an order adopting guidelines for, among other things, rates for low-income or payment-troubled customers. The Gas Cost Incentive track is expected to result in guidelines for designing and applying performance-based incentives for the LDC's gas purchasing function. Among the various incentives being studied are so-called "hard" price caps and mechanisms that would allow the PSC to administer rewards or penalties based on the LDC's gas purchasing practices as measured against benchmarks such as a published gas cost index. Pennsylvania FERC Order 636 Proceedings. The PaPUC has thus far responded to the FERC's Order 636 with three generic proceedings addressing different operational areas. They are proceedings on transportation services, gas procurement practices (including a gas purchase incentive mechanism) and capacity release. Distribution Corporation has already implemented many of the proposed changes in previous rate cases and expects that additional changes will not significantly alter current operations. Chairman Quain's Legislative Collaborative. In the latter part of fiscal 1995, the Chairman of the PaPUC convened a collaborative among the Commonwealth's LDCs, Staff for the PaPUC, intervenors and marketers/producers to examine existing public utility laws to determine whether they should be amended to meet the requirements of the post-Order 636 environment. Under consideration by the parties are changes to existing laws governing utility practices and development of new legislation that would allow utilities to seek deregulation of traditional services. Distribution Corporation has expressed its support for, and participated in, the drafting of many of the proposals. However, Distribution Corporation cannot determine the outcome of these proceedings at this time. Pipeline and Storage For a discussion of Supply Corporation's gathering rates, refer to Note B - Regulatory Matters in Item 8 of this report. On October 31, 1994, Supply Corporation filed for an annual rate increase of $21.0 million, with a requested return on equity of 12.6%. Settlement discussions to resolve the various issues have achieved a settlement in principle. This settlement in principle will increase Supply Corporation's revenues by approximately $6.4 million annually from current levels, with a return on equity of 11.3%. The former Penn-York Energy Corporation (Penn-York) services, which were merged into Supply Corporation effective July 1, 1994, will be rolled-in for ratemaking purposes. Approximately two-thirds of the former Penn-York service is now on year-to-year contracts and Supply Corporation has agreed not to seek recovery of revenues related to terminated Penn-York service from other storage customers for five years, as long as the terminations are not greater than approximately 30% of the terminable service. Supply Corporation is marketing and will actively market available storage capacity. Supply Corporation also agreed not to seek recovery for increased cost of service for three years. A Stipulation and Agreement incorporating the settlement in principle was filed with the FERC in September 1995 and the Administrative Law Judge certified the settlement as uncontested to the FERC on November 6, 1995. Approval is expected in early calendar year 1996 and rates are expected to become effective retroactive to June 1, 1995. Other Matters Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. It is the Company's policy to accrue estimated environmental clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. Distribution Corporation has estimated that clean-up costs related to several former manufactured gas plant sites and several other waste disposal sites are in the range of $8.1 million to $9.5 million. At September 30, 1995, Distribution Corporation has recorded the minimum liability of $8.1 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company. In New York, Distribution Corporation is recovering site investigation and remediation costs over a three-year period for each site. In Pennsylvania, Distribution Corporation expects to recover such costs in rates, as the PaPUC has allowed recovery of other environmental clean-up costs in rate cases. For further discussion, see disclosure in Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of this report. Accounting for Stock Based Compensation In October 1995, the Financial Accounting Standards Board issued SFAS 123, "Accounting for Stock Based Compensation," which establishes a fair value based method of accounting for employee stock options or similar equity instruments and encourages all companies to adopt that method of accounting for all of their employee stock compensation plans. For a further discussion of what this new accounting standard entails, see Note D - Capitalization in Item 8 of this report. Effects of Inflation Although the rate of inflation has been relatively low over the past few years, and thus has benefited both the Company and its customers, the Company's operations remain sensitive to increases in the rate of inflation because of the capital-intensive and regulated nature of its major operating segments. Delays inherent in the ratemaking process prevent the Company from obtaining immediate recovery of increased operating costs. Also, while the ratemaking process gives no recognition to the current cost of replacing property, plant and equipment, based on past practices the Company believes that it will be allowed to earn on the increased cost of its net investment when replacement of facilities occurs. ITEM 8. Financial Statements and Supplementary Data Index to Financial Statements - ----------------------------- Page ---- Financial Statements: Report of Independent Accountants 30 Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 1995 31 Consolidated Balance Sheets at September 30, 1995 and 1994 32-33 Consolidated Statement of Cash Flows, three years ended September 30, 1995 34 Notes to Consolidated Financial Statements 35-58 Financial Statement Schedules: For the three years ended September 30, 1995 II-Valuation and Qualifying Accounts 59 All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto. Supplementary Data - ------------------ Supplementary data that is included in Note J - Quarterly Financial Data (unaudited) and Note L - Supplementary Information for Oil and Gas Producing Activities, appears under this Item, and reference is made thereto. Report of Management - -------------------- Management is responsible for the preparation and integrity of the Company's financial statements. The financial statements have been prepared in accordance with generally accepted accounting principles consistently applied, and necessarily include some amounts that are based on management's best estimates and judgment. The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management's authorization. The Company's financial statements have been examined by our independent accountants, Price Waterhouse LLP, which also conducts a review of internal controls to the extent required by generally accepted auditing standards. The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors and Price Waterhouse LLP to review planned audit scope and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent accountants have direct access to the Audit Committee and periodically meet with it without management representatives present. Report of Independent Accountants To the Board of Directors and Shareholders of National Fuel Gas Company In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1995, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A and G to the consolidated financial statements, the Company adopted the new accounting standards for postretirement benefits other than pensions, income taxes and other postemployment benefits in fiscal 1994. PRICE WATERHOUSE LLP Buffalo, New York October 27, 1995
National Fuel Gas Company Consolidated Statements of Income and Earnings Reinvested in the Business Year Ended September 30 (Thousands of Dollars) 1995 1994 1993 ---- ---- ---- Income Operating Revenues $ 975,496 $1,141,324 $1,020,382 ---------- ---------- ---------- Operating Expenses Purchased Gas 351,094 497,687 409,005 Operation Expense 266,786 260,411 258,918 Maintenance 25,719 30,979 24,312 Property, Franchise and Other Taxes 91,837 103,788 95,393 Depreciation, Depletion and Amortization 71,782 74,764 69,425 Income Taxes - Net 43,879 47,792 41,046 ---------- ---------- ---------- 851,097 1,015,421 898,099 ---------- ---------- ---------- Operating Income 124,399 125,903 122,283 Other Income 5,378 3,656 4,833 ---------- ---------- ---------- Income Before Interest Charges 129,777 129,559 127,116 ---------- ---------- ---------- Interest Charges Interest on Long-Term Debt 40,896 36,699 38,507 Other Interest 12,987 10,425 13,392 ---------- ---------- ---------- 53,883 47,124 51,899 ---------- ---------- ---------- Income Before Cumulative Effect 75,894 82,435 75,217 Cumulative Effect of Changes in Accounting - 3,237 - ---------- ---------- ---------- Net Income Available for Common Stock 75,894 85,672 75,217 Earnings Reinvested in the Business Balance at Beginning of Year 363,854 335,907 314,334 ---------- ---------- ---------- 439,748 421,579 389,551 Dividends on Common Stock 59,625 57,725 53,644 ---------- ---------- ---------- Balance at End of Year $ 380,123 $ 363,854 $ 335,907 ========== ========== ========== Earnings Per Common Share Income Before Cumulative Effect $2.03 $2.23 $2.15 Cumulative Effect of Changes in Accounting - .09 - ---------- ---------- ---------- Net Income Available for Common Stock $2.03 $2.32 $2.15 ========== ========== ========== Weighted Average Common Shares Outstanding 37,396,875 37,046,249 34,938,722 ========== ========== ========== See Notes to Consolidated Financial Statements
National Fuel Gas Company Consolidated Balance Sheets At September 30 (Thousands of Dollars) 1995 1994 ---- ---- Assets Property, Plant and Equipment $2,322,335 $2,169,067 Less - Accumulated Depreciation, Depletion and Amortization 673,153 623,517 ---------- ---------- 1,649,182 1,545,550 ---------- ---------- Current Assets Cash and Temporary Cash Investments 12,757 29,016 Receivables - Net 75,933 95,494 Unbilled Utility Revenue 20,838 17,311 Gas Stored Underground 25,589 31,900 Materials and Supplies - at average cost 24,374 23,796 Prepayments 29,753 20,609 ---------- ---------- 189,244 218,126 ---------- ---------- Other Assets Recoverable Future Taxes 94,053 99,742 Unamortized Debt Expense 26,976 28,396 Other Regulatory Assets 37,040 47,737 Deferred Charges 8,653 15,797 Other 33,154 26,309 ---------- ---------- 199,876 217,981 ---------- ---------- $2,038,302 $1,981,657 ========== ========== See Notes to Consolidated Financial Statements
National Fuel Gas Company Consolidated Balance Sheets At September 30 (Thousands of Dollars) 1995 1994 ---- ---- Capitalization and Liabilities Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 100,000,000 Shares; Issued and Outstanding - 37,434,363 Shares and 37,278,409 Shares, Respectively $ 37,434 $ 37,278 Paid In Capital 383,031 379,156 Earnings Reinvested in the Business 380,123 363,854 ---------- ---------- Total Common Stock Equity 800,588 780,288 Long-Term Debt, Net of Current Portion 474,000 462,500 ---------- ---------- Total Capitalization 1,274,588 1,242,788 ---------- ---------- Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 147,600 112,500 Current Portion of Long-Term Debt 88,500 96,000 Accounts Payable 53,842 68,293 Amounts Payable to Customers 51,001 38,714 Other Accruals and Current Liabilities 52,118 59,742 ---------- ---------- 393,061 375,249 ---------- ---------- Deferred Credits Accumulated Deferred Income Taxes 288,763 273,560 Taxes Refundable to Customers 23,080 31,688 Unamortized Investment Tax Credit 13,380 14,057 Other Deferred Credits 45,430 44,315 ---------- ---------- 370,653 363,620 ---------- ---------- Commitments and Contingencies - - ---------- ---------- $2,038,302 $1,981,657 ========== ========== See Notes to Consolidated Financial Statements
National Fuel Gas Company Consolidated Statement of Cash Flows Year Ended September 30 (Thousands of Dollars) 1995 1994 1993 ---- ---- ---- Operating Activities Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities Cumulative Effect of Changes in Accounting - (3,237) - Depreciation, Depletion and Amortization 71,782 74,764 69,425 Deferred Income Taxes 8,452 4,853 16,919 Other 275 5,780 5,574 Change in: Receivables and Unbilled Utility Revenue 16,034 863 (21,531) Gas Stored Underground and Materials and Supplies 5,733 (15,539) 7,156 Unrecovered Purchased Gas Costs - 20,772 (7,739) Prepayments (9,144) (3,017) (1,489) Accounts Payable (14,451) 23,774 (2,579) Amounts Payable to Customers 12,287 (2,062) (18,808) Other Accruals and Current Liabilities (1,305) 3,072 15,249 Other Assets and Liabilities - Net 7,903 3,534 (13,691) -------- -------- -------- Net Cash Provided by Operating Activities 173,460 199,229 123,703 -------- -------- -------- Investing Activities Capital Expenditures (182,826) (135,084) (131,926) Other 10,646 3,586 225 -------- -------- -------- Net Cash Used in Investing Activities (172,180) (131,498) (131,701) -------- -------- -------- Financing Activities Change in Notes Payable to Banks and Commercial Paper 35,100 (84,300) (30,200) Proceeds from Issuance of Long-Term Debt 100,000 100,000 129,000 Reduction of Long-Term Debt (96,000) (19,917) (180,083) Proceeds from Issuance of Common Stock 2,555 9,064 78,822 Dividends Paid on Common Stock (59,194) (57,157) (52,224) -------- -------- -------- Net Cash Used in Financing Activities (17,539) (52,310) (54,685) -------- -------- -------- Net Increase (Decrease) in Cash and Temporary Cash Investments (16,259) 15,421 (62,683) Cash and Temporary Cash Investments at Beginning of Year 29,016 13,595 76,278 -------- -------- -------- Cash and Temporary Cash Investments at End of Year $ 12,757 $ 29,016 $ 13,595 ======== ======== ======== See Notes to Consolidated Financial Statements
National Fuel Gas Company Notes to Consolidated Financial Statements Note A - Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated where appropriate. The preparation of the consolidated 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. Reclassification Certain prior year amounts have been reclassified to conform with current year presentation. Regulation Two of the Company's principal subsidiaries, Distribution Corporation and Supply Corporation, are subject to regulation by state and federal authorities having jurisdiction. Distribution Corporation and Supply Corporation have accounting policies which conform to generally accepted accounting principles, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note B for further discussion of regulatory matters. Revenues Revenues are recorded as bills are rendered, except that service supplied but not billed is reported as "Unbilled Utility Revenue" and is included in operating revenues for the year in which service is furnished. Unrecovered Purchased Gas Costs and Refunds Distribution Corporation's rate schedules contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Supply Corporation collects revenues subject to refund if rates in effect are pending a final rate case determination by the Federal Energy Regulatory Commission (FERC). Estimated rate refund liabilities are recorded which reflect management's current estimate as to the ultimate outcome of each rate case. Property, Plant and Equipment The principal assets, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities. Such cost includes an Allowance for Funds Used During Construction (AFUDC), which is defined in applicable regulatory systems of accounts as the net cost of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. The rates used in the calculation of AFUDC are determined in accordance with guidelines established by regulatory authorities. Included in property, plant and equipment is the cost of gas stored underground - noncurrent, representing the volume of gas required to maintain pressure levels for normal operating purposes as well as gas volumes maintained for system balancing purposes, including those needed for no-notice transportation service. Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries' property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation. Oil and gas exploration and development costs are capitalized under the full-cost method of accounting as prescribed by the Securities and Exchange Commission (SEC). All costs directly associated with property acquisition, exploration and development activities are capitalized, with the principal limitation that such capitalized amounts not exceed the present value of estimated future net revenues from the production of proved gas and oil reserves plus the lower of cost or market of unevaluated properties, net of related income tax effect. The present value of estimated future net revenues was computed based on end-of-year prices adjusted for contracted price changes. At September 30, 1995, Seneca did not experience an impairment of its oil and gas assets under the SEC full cost accounting rules. There are certain factors, including price declines, which could cause an impairment of Seneca's oil and gas assets. Depreciation, Depletion and Amortization Depreciation, depletion and amortization are computed by application of either the straight-line method or the gross revenue method, in amounts sufficient to recover costs over the estimated service lives of property in service, and for oil and gas properties, over the period of estimated gross revenues from proved reserves. The costs of unevaluated oil and gas properties are excluded from this calculation. For timber properties, depletion, determined on a property by property basis, is charged to operations based on the annual amount of timber cut in relation to the total amount of recoverable timber. The provisions for depreciation, depletion and amortization, including amounts capitalized or charged to other operating accounts, were $73.1 million in 1995, $75.7 million in 1994 and $70.6 million in 1993, and were equivalent to 3.5% in 1995, 3.9% in 1994 and 3.8% in 1993 of average depreciable property, plant and equipment for those years. Gas Stored Underground - Current Gas stored is carried at cost, on a last-in, first-out (LIFO) basis. Under present regulatory practice, the liquidation of a LIFO layer is reflected in future gas cost adjustment clauses. Based upon the average price of spot market gas purchased in September 1995, including transportation costs, the current cost of replacing the inventory of gas stored underground-current exceeded the amount stated on a LIFO basis by approximately $19.2 million at September 30, 1995. Unamortized Debt Expense Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related issues. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. Income Taxes The Company and its wholly-owned subsidiaries file a consolidated federal income tax return. Prior to its repeal in 1986, Investment Tax Credit was either reflected currently in income or deferred and amortized to income over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction. On October 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109), which changed the method of accounting for income taxes. The cumulative effect of this change increased net income for the fiscal year ended September 30, 1994 by $3.8 million as a result of the reduction in deferred income taxes associated with the Company's nonregulated operations. Financial Instruments The Company, in its Exploration and Production segment, utilizes price swap agreements that effectively hedge a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. Gains or losses from these price swap agreements are reflected in operating revenues on the Consolidated Statement of Income at the time of settlement with the other parties. Reference is made to Note F - Financial Instruments, for further discussion of financial instruments. Consolidated Statement of Cash Flows For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. Interest paid in 1995, 1994 and 1993 was $53.5 million, $46.2 million and $48.3 million, respectively. Net income taxes paid in 1995, 1994 and 1993 were $34.6 million, $37.6 million and $19.9 million, respectively. In December 1993, the Company entered into a non-cash investing activity whereby it issued shares of Company common stock for $3.2 million of natural gas production assets. Earnings Per Common Share Earnings per common share are calculated using the weighted average number of shares outstanding during each fiscal year. Common stock equivalents in the form of stock options do not have a material dilutive effect on earnings per common share. New Accounting Pronouncement In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS 121). This statement establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles and goodwill related to those assets to be held and used and for long-lived assets and certain identifiable intangibles to be disposed of. Essentially, SFAS 121 requires review of these assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. SFAS 121 also requires that a rate-regulated enterprise recognize an impairment for the amount of costs excluded when a regulator excludes all or part of a cost from an enterprise's rate base or when regulatory assets are no longer probable of recovery. The Company has adopted SFAS 121 with no impact on its results of operations for 1995. Note B - Regulatory Matters Regulatory Assets and Liabilities Distribution Corporation and Supply Corporation have incurred various costs and received various credits which have been reflected as regulatory assets and liabilities on the Company's consolidated balance sheets. Accounting for such costs and credits as regulatory assets and liabilities is in accordance with SFAS 71, "Accounting for the Effect of Certain Types of Regulation" (SFAS 71). This statement sets forth the application of generally accepted accounting principles for those companies whose rates are established by or are subject to approval by an independent third-party regulator. Under SFAS 71, regulated companies defer costs and credits on the balance sheet as regulatory assets and liabilities when it is probable that those costs and credits will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in income by an unregulated company. These deferred regulatory assets and liabilities are then flowed through the income statement in the period in which the same amounts are reflected in rates. Distribution Corporation and Supply Corporation have recorded the following regulatory assets and liabilities:
At September 30 (in thousands) 1995 1994 ---- ---- Regulatory Assets: Recoverable Future Taxes (Note C) $ 94,053 $ 99,742 Unamortized Debt Expense (Note A) 22,035 23,751 Pension and Post-Retirement Benefit Costs (Note G) 18,412 17,199 Order 636 Transition Costs* 12,358 8,417 Environmental Clean-up (Note H) 7,475 7,310 Other (1,205) 14,811 -------- -------- Total Regulatory Assets 153,128 171,230 -------- -------- Regulatory Liabilities: Amounts Payable to Customers (Note A) 51,001 38,714 Taxes Refundable to Customers (Note C) 23,080 31,688 Other 8,628 9,513 -------- -------- Total Regulatory Liabilities 82,709 79,915 -------- -------- Net Regulatory Position $ 70,419 $ 91,315 ======== ======== * Exclusive of amounts being collected through gas costs. Such amounts are included in unrecovered purchased gas costs or amounts payable to customers.
If for any reason, including deregulation, a change in the method of regulation, or a change in competitive environment, Distribution Corporation and/or Supply Corporation ceases to meet the criteria for application of SFAS 71 for all or part of their operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in income of the period in which the discontinuance of SFAS 71 occurs. Such amounts would be classified as an extraordinary item. Distribution Corporation and Supply Corporation are not currently facing a requirement to discontinue SFAS 71. Order 636 Transition Costs As a result of the industrywide restructuring under the FERC's Order 636, Distribution Corporation is incurring transition costs billed by Supply Corporation and other upstream pipeline companies. As of September 30, 1995, Distribution Corporation's estimate of its exposure to outstanding transition cost claims is in the range of $7.1 million to $71.0 million. The estimated maximum exposure is declining as transition costs are incurred and paid. At September 30, 1995, Distribution Corporation has recorded the minimum liability and corresponding regulatory asset of $7.1 million. Distribution Corporation is currently recovering transition costs from its sales customers in New York and its sales and transportation customers in Pennsylvania. Recovery of the allocable portion of transition costs related to Distribution Corporation's transportation customers in New York is expected to begin upon the Public Service Commission of the State of New York's (PSC) acceptance of a compliance filing made in November 1995. It is expected that the compliance filing will be accepted by the Spring of 1996. Distribution Corporation will continue to actively challenge relevant FERC filings made by upstream pipeline companies to ensure the eligibility and prudency of all transition cost claims. Management believes that any transition costs resulting from the implementation of Order 636 which have been determined to be both eligible and prudently incurred should be fully recoverable from customers. Gathering Rates Supply Corporation has approximately $20.0 million of net production and gathering facilities used, in part, to gather natural gas of local producers, including the Company's production in the Appalachian Region. In its restructuring orders, the FERC has directed Supply Corporation to fully unbundle the production and gathering cost of service from the transmission cost of service, and to establish a separate gathering rate. A Stipulation and Agreement complying with the FERC's directives was filed with the FERC in September 1995 and the Administrative Law Judge certified it as uncontested to the FERC. Approval is expected early in calendar 1996. If approved, it will permit Supply Corporation to fully recover its investment in production and gathering plant, as well as its gathering cost of service. Note C - Income Taxes The components of federal and state income taxes included in the Consolidated Statement of Income are as follows:
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Operating Expenses: Current Income Taxes - Federal $30,522 $36,630 $21,148 State 4,905 6,309 2,979 Deferred Income Taxes 8,452 4,853 16,919 ------- ------ ------ 43,879 47,792 41,046 Other Income: Deferred Investment Tax Credit (672) (682) (693) Cumulative Effect of Changes in Accounting: Adoption of SFAS 109 - (3,826) - Tax Effect of Adoption of SFAS 112 - (425) - ------- ------ ------ Total Income Taxes $43,207 $42,859 $40,353 ======= ======= =======
Prior to the adoption of SFAS 109 in 1994, deferred income tax expense resulted from timing differences between the recognition of revenues and expenses for income tax and financial reporting purposes except where not permitted by regulatory authorities. The sources of these timing differences and the related income tax effect of each are as follows:
Year Ended September 30 (in thousands) 1993 ---- Unrecovered Purchased Gas Costs $11,641 Excess of Tax Over Book Depreciation 6,717 Exploration and Intangible Well Drilling Costs 7,377 Revenue Refunds Payable to Customers (2,994) Debt Retirement Costs 3,780 Tax Credit Carryforward (2,608) Miscellaneous (6,994) ------- Total Deferred Income Taxes $16,919 =======
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217 Total Income Taxes 43,207 42,859 40,353 -------- -------- -------- Income Before Income Taxes $119,101 $128,531 $115,570 ======== ======== ======== Income Tax Expense, Computed at Statutory Rate of 35% in 1995 and 1994 and 34.75% in 1993 $41,685 $ 44,986 $40,161 Increase (Reduction) in Taxes Resulting from: Current State Income Taxes 3,188 4,101 1,944 Depreciation 2,397 2,174 2,221 Production Tax Credits (899) (1,658) (2,608) Adoption of SFAS 109 - (3,826) - Miscellaneous (3,164) (2,918) (1,365) ------- ------- ------ Total Income Taxes $43,207 $42,859 $40,353 ======= ======= =======
Significant components of the Company's deferred tax liabilities and assets were as follows:
At September 30 (in thousands) 1995 1994 ------------------------- ------------------------- Accumulated Deferred Accumulated Deferred Deferred Income Taxes Deferred Income Taxes Income Taxes Current* Income Taxes Current* ------------ ------------ ------------ ------------ Deferred Tax Liabilities: Excess of Tax Over Book Depreciation $185,595 $ - $ 174,006 $ - Exploration and Intangible Well Drilling Costs 84,380 - 78,224 - Other 67,831 - 64,181 - -------- ------- --------- ------- Total Deferred Tax Liabilities 337,806 - 316,411 - ======== ======= ========= ======= Deferred Tax Assets: Deferred Investment Tax Credits (7,860) - (8,388) - Overheads Capitalized for Tax Purposes (11,766) - (9,238) - Unrecovered Purchased Gas Costs - (8,322) - (4,448) Other (29,417) - (25,225) - -------- ------- --------- ------- Total Deferred Tax Assets (49,043) (8,322) (42,851) (4,448) ======== ======= ========= ======= Total Net Deferred Income Taxes $288,763 $(8,322) $ 273,560 $(4,448) ======== ======= ========= ======= * Included on the Consolidated Balance Sheets in "Other Accruals and Current Liabilities."
SFAS 109 requires the recognition of regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers. These amounted to $23.1 million and $31.7 million at September 30, 1995 and 1994, respectively. Also, SFAS 109 requires the recognition of additional deferred income taxes not previously recorded because of prior ratemaking practices. Substantially all of these deferred taxes relate to property, plant and equipment and related investment tax credits and will be amortized consistent with the depreciation and amortization of these accounts. The additional deferred taxes and corresponding regulatory assets, representing future amounts collectible from customers in the ratemaking process, amounted to $94.1 million and $99.7 million at September 30, 1995 and 1994, respectively. Note D - Capitalization
Summary of Changes in Common Stock Equity Earnings Paid Reinvested Common Stock In in the (in thousands) Shares Amount Capital Business ------ ------ ------- ---------- Balance at September 30, 1992 33,856 $33,856 $284,143 $314,334 Net Income Available for Common Stock 75,217 Dividends Declared on Common Stock ($1.52 Per Share) (53,644) Common Stock Issued: Sale of Common Stock 2,500 2,500 71,425 Stock Options and Stock Award Plans 50 50 832 401(k) Plans 115 115 3,423 Customer Stock Purchase Plan 140 140 4,101 Common Stock Issuance Costs (247) ------ ------- -------- -------- Balance at September 30, 1993 36,661 36,661 363,677 335,907 Net Income Available for Common Stock 85,672 Dividends Declared on Common Stock ($1.56 Per Share) (57,725) Common Stock Issued: Acquisition of Natural Gas Production Assets 108 108 3,523 Stock Options and Stock Award Plans 164 164 1,163 401(k) Plans 136 136 4,234 Customer Stock Purchase Plan 209 209 6,559 ------ ------- -------- -------- Balance at September 30, 1994 37,278 37,278 379,156 363,854 Net Income Available for Common Stock 75,894 Dividends Declared on Common Stock ($1.60 Per Share) (59,625) Common Stock Issued: Stock Options and Stock Award Plans 22 22 377 401(k) Plans 88 88 2,310 Customer Stock Purchase Plan 46 46 1,188 ------ ------- -------- Balance at September 30, 1995 37,434 $37,434 $383,031 $380,123* ====== ======= ======== ========= * The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 1995, $305.7 million of accumulated earnings was free of such limitations.
Common Stock The Company has various plans which allow shareholders, customers and employees to purchase shares of Company common stock. The Dividend Reinvestment and Stock Purchase Plan allows shareholders to reinvest cash dividends and/or make cash investments in the Company's common stock. The Customer Stock Purchase Plan provides residential customers the opportunity to acquire shares of Company common stock without the payment of any brokerage commission or service charges in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in Company common stock, in addition to a variety of other investment alternatives. At the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an agent. Stock Options and Stock Award Plans The Company's 1993 Award and Option Plan (1993 Plan) provides for the issuance of incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, performance units and performance shares to key employees. The 1983 Incentive Stock Option Plan (1983 Plan) provided for the issuance of incentive stock options to key employees, and the 1984 Stock Plan (1984 Plan) provided for awards of restricted stock, nonqualified stock options and stock appreciation rights to key employees. Stock options under all three plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant. Stock options outstanding do not have a materially dilutive effect on earnings per common share. Transactions involving option shares for all three plans are summarized as follows:
Number of Shares Subject Option Price to Option Per Share - ---------------------------------------------------------------------- Outstanding at September 30, 1992 618,096 $15.59 to $23.88 Granted in 1993 416,500 $25.19 and $31.50 Exercised in 1993* (78,750) $15.59 to $23.88 - ---------------------------------------------------------------------- Outstanding at September 30, 1993 955,846 $15.59 to $31.50 Granted in 1994 272,000 $31.63 Exercised in 1994* (60,509) $18.00 to $25.19 - ---------------------------------------------------------------------- Outstanding at September 30, 1994 1,167,337 $15.59 to $31.63 Granted in 1995 362,100 $27.94 Forfeited in 1995 (11,532) $25.19 to $31.63 Exercised in 1995* (17,615) $15.59 to $23.88 - ---------------------------------------------------------------------- Outstanding at September 30, 1995 1,500,290 $18.00 to $31.63 ====================================================================== Shares Exercisable at September 30, 1995 1,138,190 Shares Reserved for Future Grant at September 30, 1995 795,148 - ------------------------------------------------------------------------- * In connection with exercising these options, 3,192, 18,088 and 36,797 shares were surrendered and/or canceled during 1995, 1994 and 1993, respectively.
On October 4, 1995, an additional 140,000 stock option shares were granted at an option price per share of $28.56. During 1995, 8,000 shares of restricted stock were awarded under the 1993 Plan, bringing the total, as of September 30, 1995, to 294,308 shares of restricted stock awarded under the 1984 Plan and 1993 Plan, since inception. Restrictions have lapsed respecting 148,814 of these shares. Of the remaining 145,494 shares of restricted stock, restrictions on 113,494 shares will lapse respecting one-sixth of such shares on each January 2, 1996 through 2001. Restrictions on 8,000 shares will lapse respecting one-fourth of such shares on each January 2, 1999 through 2002. Restrictions on 8,000 shares will lapse respecting one-fourth of such shares on each January 2, 2000 through 2003. Restrictions on 8,000 shares will lapse respecting one-fourth of such shares on each January 2, 2001 through 2004. Restrictions on 8,000 shares will lapse respecting one-fourth of such shares on each January 2, 2002 through 2005. The market value of the restricted stock on the date the award was made is being recorded as compensation expense over the periods over which the restrictions lapse. During the restriction period, share certificates are held by the Company. In October 1995, the FASB issued SFAS 123, "Accounting for Stock Based Compensation" (SFAS 123). This statement establishes a fair value based method of accounting for employee stock options or similar equity instruments and encourages all companies to adopt that method of accounting for all of their employee stock compensation plans. SFAS 123 allows companies to continue to measure compensation cost for employee stock options or similar equity instruments using the method of accounting prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Companies electing to remain with this method are required to make pro forma disclosures of net income and earnings per share as if SFAS 123 accounting had been applied. The Company is required to adopt the disclosure requirements of SFAS 123 for its fiscal year ending September 30, 1997. Measurement of compensation cost under SFAS 123, if adopted, is effective for all awards granted after the beginning of the fiscal year in which that method is first applied. Management is currently reviewing the provisions of SFAS 123. If the fair value base measurement provisions are adopted, they are not expected to have a material impact on the results of operations or financial condition of the Company. Redeemable Preferred Stock As of September 30, 1995, there were 3,200,000 shares of $25 par value Cumulative Preferred Stock authorized but unissued. Long-Term Debt The outstanding long-term debt is as follows:
At September 30 (in thousands) 1995 1994 ---- ---- Debentures: 7-3/4% due February 2004 $125,000 $125,000 Medium-Term Notes: 6.07% due May 1995 - 55,000 6.10% due May 1995 - 20,000 6.10% due June 1995 - 1,000 9.32% due June 1995 - 20,000 8.875% due December 1995 20,000 20,000 8.90% due December 1995 38,500 38,500 4.53% due September 1996 30,000 30,000 6.42% due November 1997 50,000 50,000 6.08% due July 1998 50,000 - 7.25% due July 1999 50,000 50,000 6.60% due February 2000 50,000 50,000 7.395% due March 2023 49,000 49,000 8.48% due July 2024* 50,000 50,000 7.375% due June 2025 50,000 - -------- -------- 562,500 558,500 Less Current Portion 88,500 96,000 -------- -------- $474,000 $462,500 ======== ======== * Callable beginning July 1999.
The aggregate principal amounts of long-term debt maturing for the next five years, including amounts classified as Current Portion of Long-Term Debt, are: $88.5 million in 1996, none in 1997, $100.0 million in 1998, $50.0 million in 1999 and $50.0 million in 2000. During 1995, the Company issued an aggregate $100.0 million of medium-term notes. In June 1995, $50.0 million of 7.375% medium-term notes due in June 2025 were issued. After reflecting underwriting discounts and commissions, the proceeds to the Company from this issuance amounted to $49.3 million. In July 1995, $50.0 million of 6.08% medium-term notes due in July 1998 were issued. After reflecting underwriting discounts and commissions, the proceeds to the Company from this issuance amounted to $49.8 million. The Company has authority remaining under a shelf registration and has authority under the Public Utility Holding Company Act of 1935, as amended, to issue and sell up to $120.0 million of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company. Note E - Short-Term Borrowings The Company maintains uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. These lines are utilized primarily as a means of financing, on an interim basis, various working capital requirements and capital expenditures of the Company, including the Company's oil and gas exploration and development program and the purchase and storage of gas. Borrowings under these lines of credit are made at competitive money market rates, and the Company currently is authorized to borrow up to $400.0 million thereunder. These credit lines, which are callable at the option of the financial institutions, are reviewed on an annual basis and are expected to remain in place throughout 1996. The Company may also issue as much as $105.0 million of commercial paper from time to time, but in no event may its borrowings under its discretionary lines of credit, or through the issuance of commercial paper, exceed $400.0 million in the aggregate. Additionally, the Company has entered into an agreement that establishes a 364-day committed revolving credit arrangement with seven commercial banks, under which it may borrow as much as $105.0 million. This arrangement may be utilized for general corporate purposes, including to support the issuance of commercial paper. The Company pays a fee to maintain this arrangement, and may borrow through this arrangement under four interest rate options. If amounts are borrowed under this arrangement, the $400.0 million available for borrowing under the discretionary lines of credit is correspondingly reduced. No borrowings under this arrangement were outstanding at September 30, 1995. The arrangement expires on September 19, 1996, and the Company expects to renew or replace all or most of this arrangement before then. The Company has recently filed with the SEC to borrow on a short-term basis for a five year period. With this request the Company is seeking to increase its short-term borrowing limits. The filing, if approved, would increase the Company's limit on commercial paper from $105.0 million to $300.0 million and would increase the aggregate maximum short-term borrowing level from $400.0 million to $600.0 million. At September 30, 1995, the Company had outstanding notes payable to banks and commercial paper of $52.6 million and $95.0 million, respectively. At September 30, 1994, the Company had outstanding notes payable to banks and commercial paper of $102.5 million and $10.0 million, respectively. The weighted average interest rate on notes payable to banks was 6.15% and 5.13% at September 30, 1995 and 1994, respectively. The weighted average interest rate on commercial paper was 5.85% and 5.09% at September 30, 1995 and 1994, respectively. Note F - Financial Instruments Fair Values The fair market value of the Company's long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
At September 30 (in thousands) 1995 1994 ---------------------- ------------------ Carrying Fair Carrying Fair Amount Value Amount Value -------- ----- -------- ----- Long-Term Debt $562,500 $570,236 $558,500 $541,327 ======== ======== ======== ========
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Temporary cash investments, notes payable to banks and commercial paper are stated at amounts which approximate their fair value due to the short-term maturities of those financial instruments. Investments in life insurance are stated at their cash surrender values as discussed below. Investments Other assets consist principally of cash surrender values of insurance contracts. The cash surrender values of these insurance contracts amounted to $28.2 million and $21.3 million at September 30, 1995 and 1994, respectively. The insurance contracts were established as a funding mechanism for various benefit obligations the Company has to certain employees. Derivative Financial Instruments The Company, in its Exploration and Production operations, has entered into certain price swap agreements that effectively hedge a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These agreements are not held for trading purposes. The price swap agreements call for the Company to receive monthly payments from (or make payment to) other parties based upon the difference between a fixed and a variable price as specified by the agreement. The variable price is either a crude oil price quoted on the New York Mercantile Exchange or a quoted natural gas price in "Inside FERC." The following summarizes the Company's activity under swap agreements during 1995 and 1994:
Year Ended September 30 1995 1994 --------------- ------------- Natural Gas Swap Agreements: Notional Amount - Equivalent Billion Cubic Feet (Bcf) 16.3 8.0 Fixed Prices per Thousand Cubic Feet (Mcf) $1.73 - $2.38 $2.16 - $2.38 Variable Prices per Mcf $1.35 - $1.76 $1.44 - $2.44 Gain $7,157,000 $1,986,000 Crude Oil Swap Agreements: Notional Amount - Equivalent Barrels (bbl) 711,000 - Fixed Prices per bbl $16.68 - $19.60 - Variable Prices per bbl $17.16 - $19.89 - Loss $(221,000) -
The Company had the following swap agreements outstanding at September 30, 1995:
Natural Gas Swap Agreements: Notional Amount Fiscal Year (Equivalent Bcf) Fixed Price per Mcf ----------- ---------------- ------------------- 1996 17.6 $1.70 - $2.16 1997 3.9 $1.70 - $1.98 1997 1.7 (1) 1998 0.6 (1) ---- 23.8 ====
Crude Oil Swap Agreements: Notional Amount Fiscal Year (Equivalent bbl) Fixed Price per bbl ----------- ---------------- ------------------- 1996 946,000 $17.40 - $19.00 1997 738,000 $17.40 - $18.33 1998 96,000 $18.31 --------- 1,780,000 ========= (1) Price to be set according to market prices at a future date.
Gains or losses from these price swap agreements are reflected in operating revenues on the Consolidated Statement of Income at the time of settlement with the other parties. Based upon the September 30, 1995 variable prices of these price swap agreements, there is an unrecognized gain of approximately $6.7 million. The actual gain or loss realized upon settlement of these price swap agreements will depend upon the variable price at the time of settlement. The Company has SEC authority to enter into interest rate swaps associated with short-term and long-term borrowings up to a notional amount of $350.0 million. However, within this combined limitation, the Company may only enter into interest rate swaps associated with short-term borrowings up to a notional amount of $200.0 million. No such agreements were entered into in 1995 and none are currently outstanding. Credit Risk Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company is at risk in the event of nonperformance by counterparties on investments, such as temporary cash investments and cash surrender values of insurance contracts, and on its derivative financial instruments. The counterparties to the Company's investments and derivative financial instruments are investment grade financial institutions. Furthermore, the Company has guarantees from counterparty affiliates on a large portion of its derivative financial instruments. Accordingly, the Company does not anticipate any material impact to its financial position, results of operations or cash flow as a result of nonperformance by counterparties. Note G - Retirement Plan and Other Post-Employment Benefits Retirement Plan The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Plan) that covers substantially all employees of the Company. The Plan uses years of service, age at retirement and earnings of employees to determine benefits. The Company's policy is to fund at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. Plan funding is subject to annual review by management and its consulting actuary. Plan assets primarily consist of equity and fixed income investments and units in commingled funds. In 1994, a plan amendment was adopted which provided for an early retirement window program which was accounted for under the rules prescribed by SFAS 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Plans and for Termination Benefits." For ratemaking purposes, pension expense equals the amount funded less amounts capitalized. Since Plan funding has not been required in recent years, the Company deferred the pension expense associated with its regulated subsidiaries. The amounts deferred are expected to be recovered in rates as contributions are made to the Plan. The actuarial valuation funding report for the 1996 Plan year indicates that a contribution to the Plan is required. Rate recovery for the Distribution Corporation portion of pension costs began with rates that went into effect on September 20, 1995 and September 27, 1995 in New York and Pennsylvania, respectively. The components of net periodic pension expense were as follows:
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Service Cost $ 9,680 $10,441 $ 9,181 Interest Cost 28,338 26,532 24,258 Actual Return on Plan Assets (47,591) (16,212) (35,657) Net Amortization and Deferral 13,570 (16,603) 4,287 Early Retirement Window - 2,855 - ------- ------- ------- Net Periodic Pension Cost 3,997 7,013 2,069 Deferred for Regulatory Purposes (3,848) (6,875) (2,012) ------- ------- ------- Pension Cost Recognized in Consolidated Statement of Income $ 149 $ 138 $ 57 ======= ======= =======
The projected benefit obligation was determined using an assumed discount rate of 8% in 1995, 8.5% in 1994 and 7.75% in 1993. The assumed rate of compensation increase was 5% for all three years. The expected long-term rate of return on Plan assets was 8.5% for all three years. The unrecognized net asset that arose from the initial application of SFAS 87, "Employers' Accounting for Pensions," is being amortized on a straight-line basis over the future working lifetime of those expected to receive benefits under the Plan. In 1995, in addition to the decrease in the discount rate from 8.5% to 8%, the mortality assumption was changed by using a more current mortality table and rates of assumed retirement were revised to more accurately reflect actual retirement experience. The effect of the discount rate change was to increase the projected benefit obligation (PBO) by $22.8 million. The effect of the mortality and retirement rate changes was to increase the PBO by $15.4 million. A reconciliation of the Plan's funded status as determined by the Company's consulting actuary is presented in the following table:
At September 30 (in thousands) 1995 1994 ---- ---- Actuarial Present Value of: Vested Benefit Obligation $287,470 $245,095 ======== ======== Accumulated Benefit Obligation $333,597 $282,340 ======== ======== Projected Benefit Obligation $404,157 $342,050 Plan Assets at Fair Value 399,608 370,150 -------- -------- Funded Status (4,549) 28,100 Unrecognized Net Asset (33,335) (37,502) Unrecognized Prior Service Cost 12,446 13,339 Unrecognized Net Loss (Gain) 5,419 (19,959) -------- -------- Pension Liability (20,019) (16,022) Deferred for Regulatory Purposes 18,849 15,001 -------- -------- Pension Liability Recognized on Consolidated Balance Sheets $ (1,170) $ (1,021) ======== ========
Other Post-Retirement Benefits In addition to providing retirement plan benefits, the Company provides health care and life insurance benefits for substantially all retired employees under a post-retirement benefit plan (Post-Retirement Plan). The Company adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), effective October 1, 1993. This statement required the Company to change its accounting for these post-retirement benefits from the "pay-as-you-go" (cash) basis to the accrual basis. The Company has established Voluntary Employees' Beneficiary Association (VEBA) trusts for collectively bargained employees and non-bargaining employees. The VEBA trusts are similar to the Company's Retirement Plan trust. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations. Contributions to the VEBA trusts are made to fund employees' post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. Post-Retirement Plan assets primarily consist of equity and fixed income investments and money market funds. The Company has elected to amortize the initial accumulated liability to net periodic post-retirement benefit cost on a straight-line basis over a 20-year period. Total post-retirement benefit cost under SFAS 106 was $24.4 million and $23.5 million in 1995 and 1994, respectively, compared with the costs based on cash payments for retiree health care and life insurance benefits of $6.0 million in 1993. The components of net periodic post-retirement benefit cost were as follows:
Year Ended September 30 (in thousands) 1995 1994 ---- ---- Service Cost $ 3,394 $ 3,974 Interest Cost 13,027 13,714 Actual Return on Post-Retirement Plan Assets (4,613) (1,035) Net Amortization and Deferral 8,739 8,628 ------- ------- Net Periodic Post-Retirement Benefit Cost 20,547 25,281 Deferred for Regulatory Purposes, Net 3,853 (1,751) ------- ------- Post-Retirement Benefit Cost Recognized in Consolidated Statement of Income $24,400 $23,530 ======= =======
The weighted-average assumed discount rate used in determining the accumulated post-retirement benefit obligation was 8% in 1995 and 8.5% in 1994. The average assumed annual rate of salary increase for the applicable life insurance plans was 5% for both years. The expected long-term rate of return on Post-Retirement Plan assets was 8.5% for both years. The annual rate of increase in the per capita cost of covered medical care benefits for the active participants and medical plans available to new retirees was assumed to be 13% for 1994 and 12% for 1995; this rate was assumed to decrease gradually to 5.5% by the year 2002 and remain at that level thereafter. The annual rate of increase in the per capita cost of covered medical care benefits for the medical plans not available to new retirees was assumed to be 8% for 1994, 7% for 1995, 6% for 1996 and 5.5% for each year after 1996. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 14% for 1994 and 10% for 1995. This rate was assumed to decrease gradually to 5.5% by the year 2005 and remain level thereafter. The annual rate increase in the per capita Medicare Part B Reimbursement was assumed to be 12.3% in 1994, 12.2% in 1995, 12% for 1996 and 5.5% for each year after 1996. In 1995, in addition to the decrease in the discount rate from 8.5% to 8%, there were plan changes to the prescription drug and life insurance post-retirement benefits. The effect of the discount rate change was to increase the accumulated post-retirement benefit obligation (APBO) by $25.8 million. The net effect of the plan changes was to reduce the APBO by $6.4 million. A reconciliation of the Post-Retirement Plan's funded status as determined by the Company's consulting actuary is in the following table:
At September 30 (in thousands) 1995 1994 ---- ---- Accumulated Post-Retirement Benefit Obligation: Inactives $ 76,272 $ 63,934 Actives Fully Eligible 36,223 31,983 Actives Not Yet Fully Eligible 70,620 60,059 -------- -------- 183,115 155,976 Fair Value of Post-Retirement Plan Assets 48,678 29,035 -------- -------- Funded Status (134,437) (126,941) Unrecognized Transition Obligation 141,561 156,210 Unrecognized Net Gain (8,930) (31,776) -------- -------- Post-Retirement Liability (1,806) (2,507) Deferred for Regulatory Purposes, Net (2,102) 1,751 --------- -------- Post-Retirement Benefit Liability Recognized on Consolidated Balance Sheets $ (3,908) $ (756) ======== ========
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the APBO as of October 1, 1994, would be increased by $23.3 million. This 1% change would also increase the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 1995 by $2.8 million. Distribution Corporation and Supply Corporation represent virtually all of the Company's total post-retirement benefit costs. Distribution Corporation and Supply Corporation are fully recovering their net periodic post-retirement benefit costs in accordance with the PSC and the Pennsylvania Public Utility Commission (PaPUC) and FERC authorization, respectively. In accordance with regulatory guidelines, the difference between the amounts of post-retirement benefit costs recoverable in rates and the amounts of post-retirement benefit costs determined by the actuary are deferred in each jurisdiction as either a regulatory asset or liability, as appropriate. Post-Employment Benefits In November 1992, the FASB issued SFAS 112, "Employers' Accounting for Postemployment Benefits" (SFAS 112), which establishes standards of financial accounting and reporting for benefits, such as salary continuation, severance pay, workers' compensation and other disability-related benefits, provided to former or inactive employees subsequent to employment but prior to retirement. The Company adopted SFAS 112 in the fourth quarter of 1994. The Consolidated Statement of Income for 1994 includes a charge of $0.6 million, net of income taxes, as a cumulative effect of a change in accounting principle. Note H - Commitments and Contingencies Leases The Company has entered into lease agreements, principally for the use of office space, business machines, transportation equipment and meters. The Company's policy is to treat all leases as operating leases for both accounting and ratemaking purposes. Total lease expense approximated $16.3 million in 1995, $17.2 million in 1994 and $16.9 million in 1993. At September 30, 1995, the future minimum payments under the Company's lease agreements for the next five years are: $13.9 million in 1996, $10.9 million in 1997, $7.6 million in 1998, $5.1 million in 1999 and $3.6 million in 2000. The future minimum lease payments attributable to later years is $9.7 million. Obligations Under Firm Contracts Distribution Corporation has agreements with five nonaffiliated upstream pipeline companies that provide for the availability of needed pipeline transportation capacity for periods that extend through 2004. These agreements provide for payment of a demand or reservation charge, at FERC-approved rates, for contracted capacity. Distribution Corporation has various gas purchase agreements with nonaffiliated gas producers that require payment of fixed monthly charges. These charges are tied to various indices. These agreements have an average term of six years. Additionally, Distribution Corporation has agreements with two nonaffiliated companies for gas storage services through 2004 that require payment of a demand charge, at FERC-approved rates, for contracted storage. At September 30, 1995, the projected aggregate amounts of such required future payments, based on current FERC-approved rates and current indices, where applicable, are approximately $97.7 million, $12.7 million and $2.0 million annually for the next five years, for pipeline capacity, gas purchases and storage service, respectively. Additionally, these agreements call for the payment of commodity charges based upon actual quantities shipped, purchased and stored. These obligations under firm contracts are considered purchased gas costs, subject to state commission review, and are being recovered in customer rates through the inclusion in Distribution Corporation's rate schedules. For the fiscal year ended September 30, 1995, total gross costs incurred under these contracts, including commodity charges on actual quantities shipped, purchased and stored, amounted to $270.7 million. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Distribution Corporation has incurred and is incurring clean-up costs at four former manufactured gas plant sites. Distribution Corporation owns two of those sites in New York and one in Pennsylvania. Distribution Corporation has been designated by the New York Department of Environmental Conservation (DEC) as a potentially responsible party (PRP) with respect to a third New York site, and is also engaged in litigation with the DEC and the party who bought the site from Distribution Corporation's predecessor. Distribution Corporation's estimated clean-up costs for all four sites have been accrued. Distribution Corporation is also currently identified by the DEC or the federal Environmental Protection Agency as one of a number of companies considered to be PRPs with respect to several waste disposal sites in New York which were operated by unrelated third parties. The PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to Distribution Corporation with respect to the remediation of these sites will depend on such factors as the remediation plan selected, the extent of the site contamination, the number of additional PRPs at each site and the portion, if any, attributed to Distribution Corporation. Distribution Corporation's estimated share of the clean-up costs has been accrued for two of these sites. It is the Company's policy to accrue estimated environmental clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. Distribution Corporation has estimated that clean-up costs related to all of the above noted sites are in the range of $8.1 million to $9.5 million. At September 30, 1995, Distribution Corporation has recorded the minimum liability of $8.1 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company. In New York, Distribution Corporation has received approval from the PSC to defer and amortize both former manufactured gas and non-manufactured gas plant site investigation and remediation costs over a three-year period for each site. These costs are then included in rate cases for recovery through base rates. Distribution Corporation is currently recovering such costs in this manner. In Pennsylvania, Distribution Corporation expects to recover such costs in rates as the PaPUC has allowed recovery of other environmental clean-up costs in rate cases. Accordingly, the Consolidated Balance Sheets at September 30, 1995, include related regulatory assets in the amount of approximately $7.5 million. The Company is in compliance with the current standards of the Clean Air Act Amendments of 1990 (the Act). Supply Corporation's compressor stations in New York and Pennsylvania were affected by the nitrogen oxide emission standards of the Act. Supply Corporation incurred capital expenditures for emission controls of approximately $0.6 million in 1994 and $5.1 million in 1995 to bring its emission controls into compliance with the Act. The Company does not anticipate incurring significant additional capital expenditures to comply with the current standards of the Act. Other The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are expected to have a material adverse effect on the financial condition of the Company at this time. Note I - Business Segment Information The Company includes operations which are rate-regulated (regulated) and operations which are not regulated as to their rates (nonregulated). The regulated operations fall primarily within two business segments: Utility Operation and Pipeline and Storage. The nonregulated operations consist principally of the Exploration and Production business segment. Other Nonregulated operations consist primarily of the Company's sawmill and dry kiln operations, natural gas marketing operations, natural gas hub operations and pipeline construction operations (which were discontinued during 1995, the effect of which was immaterial to the Company). Late in 1995, the Company formed a subsidiary for the purpose of investing in foreign and domestic energy projects. The Utility Operation is regulated by the PSC and the PaPUC and is carried out by Distribution Corporation. Distribution Corporation sells and transports gas to retail customers located in western New York and northwestern Pennsylvania. It also provides off-system sales to customers located in regions through which the upstream pipelines serving Distribution Corporation pass (i.e., from the southwestern to northeastern regions of the United States). Pipeline and Storage operations are regulated by the FERC and are carried out by Supply Corporation. Supply Corporation transports and stores natural gas for utilities and pipeline companies in the northeastern United States markets. In 1995, 48% of Supply Corporation's revenue was from affiliated companies, mainly Distribution Corporation. Seneca is engaged in exploration for, and development and purchase of, oil and natural gas reserves in the Gulf Coast, and the southwestern, western and Appalachian regions of the United States. Seneca's production is, for the most part, sold to purchasers located in the vicinity of its wells. Highland Land & Minerals, Inc. operates a sawmill and dry kiln operation in Pennsylvania. NFR is engaged in the marketing and brokerage of natural gas and performs energy management services for utilities and end-users in the northeastern United States markets. Leidy Hub, Inc. is engaged in the Company's natural gas hub operations, providing services to customers in the northeastern, mid-Atlantic, Chicago and Los Angeles areas of the United States and Ontario, Canada. Horizon Energy Development, Inc. was formed in 1995 to engage in foreign and domestic energy projects. Utility Constructors, Inc. was engaged in the Company's pipeline construction operations prior to the discontinuance of its operations in the third quarter of fiscal 1995. The data presented in the tables below reflect the Company's regulated and nonregulated business segments for the years ended September 30, 1995, 1994 and 1993. Total operating revenues by segment include both revenues from nonaffiliated customers and intersegment revenues. Operating income is total operating revenues less operating expenses, not including income taxes. The elimination of significant intercompany balances and transactions, if appropriate, is made in order to reconcile segment information with consolidated amounts. Identifiable assets of a segment are those assets that are used in the operations of that segment. Corporate assets are principally cash and temporary cash investments, receivables, deferred charges and cash surrender values of insurance contracts.
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Operating Revenues Regulated: Utility Operation $ 786,064 $ 931,673 $ 836,618 Pipeline and Storage 164,587 153,121 534,568 ---------- ---------- ---------- 950,651 1,084,794 1,371,186 ---------- ---------- ---------- Nonregulated: Exploration and Production 56,232 70,261 58,636 Other 57,075 72,036 42,099 ---------- ---------- ---------- 113,307 142,297 100,735 ---------- ---------- ---------- Intersegment Revenues* (88,462) (85,767) (451,539) ---------- ---------- ---------- $ 975,496 $1,141,324 $1,020,382 ========== ========== ========== Operating Income (Loss) Before Income Taxes Regulated: Utility Operation $ 83,774 $ 90,584 $ 86,690 Pipeline and Storage 67,884 62,302 67,375 ---------- -------- -------- 151,658 152,886 154,065 ---------- -------- -------- Nonregulated: Exploration and Production 16,404 21,767 12,980 Other 3,021 2,505 (986) ---------- -------- -------- 19,425 24,272 11,994 ---------- -------- -------- Corporate (2,805) (3,463) (2,730) ---------- -------- -------- $ 168,278 $173,695 $163,329 ========== ======== ========
Identifiable Assets At September 30 (in thousands) Regulated: Utility Operation $1,100,236 $1,106,053 $ 961,990 Pipeline and Storage 512,546 498,798 491,291 ---------- ---------- ---------- 1,612,782 1,604,851 1,453,281 ---------- ---------- ---------- Nonregulated: Exploration and Production 351,262 311,037 290,346 Other 33,734 33,357 27,867 ---------- ---------- ---------- 384,996 344,394 318,213 ---------- ---------- ---------- Corporate 40,524 32,412 30,046 ---------- ---------- ---------- $2,038,302 $1,981,657 $1,801,540 ========== ========== ========== * Represents revenue primarily from Pipeline and Storage to Utility Operation.
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Depreciation, Depletion and Amortization Regulated: Utility Operation $ 30,052 $ 28,216 $27,137 Pipeline and Storage 19,320 17,516 16,347 -------- -------- ------- 49,372 45,732 43,484 -------- -------- ------- Nonregulated: Exploration and Production 21,201 27,496 24,249 Other 1,203 1,530 1,686 -------- -------- ------- 22,404 29,026 25,935 -------- -------- ------- Corporate 6 6 6 -------- -------- ------- $ 71,782 $ 74,764 $69,425 ======== ======== ======= Capital Expenditures Regulated: Utility Operation $ 64,844 $ 61,715 $ 61,803 Pipeline and Storage 38,678 20,472 27,420 -------- -------- -------- 103,522 82,187 89,223 -------- -------- -------- Nonregulated: Exploration and Production 69,741 52,458 36,473 Other 9,563 3,603 6,229 -------- -------- -------- 79,304 56,061 42,702 -------- -------- -------- Corporate - 20 1 -------- -------- -------- $182,826 $138,268 $131,926 ======== ======== ========
Note J - Quarterly Financial Data (unaudited) In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Earnings per common share are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the earnings per common share shown on the Consolidated Statement of Income, which is based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company's heating business, there are substantial variations in operations reported on a quarterly basis. Financial data for the quarters ended December 31, 1994, March 31, 1995, and June 30, 1995 have been restated to reflect the application of a final rule issued by the FERC in September 1995, which addresses and clarifies financial reporting aspects of the current practices for unbundled pipeline sales and open access transportation. Financial data for the quarter ended September 30, 1995 reflects the recording of $4.3 million and $3.7 million of operating expenses by Distribution Corporation and Supply Corporation, respectively. Distribution Corporation recognized an additional $4.3 million of gas cost expense as a result of the annual reconciliation of gas costs in its New York jurisdiction, which is performed in August of each year. This reconciliation determined an amount of lost and unaccounted-for gas in excess of that allowed to be recovered by the PSC. Supply Corporation recorded a reserve in the amount of $3.7 million for previously deferred preliminary survey and investigation charges related to a storage project. Financial data for the quarters ended December 31, 1993 and September 30, 1994, reflect the Company's adoption of SFAS 109 and SFAS 112, respectively. As discussed in Note A - Summary of Significant Accounting Policies, the Company adopted SFAS 109 during the quarter ended December 31, 1993. The cumulative effect of this change increased net income by $3.8 million. As discussed in Note G - Retirement Plan and Other Post-Employment Benefits, the Company adopted SFAS 112 during the quarter ended September 30, 1994. The cumulative effect of this change decreased net income by $0.6 million.
Income Net Income Earnings Before Available for Per Quarter Operating Operating Cumulative Common Common Ended Revenues Income Effect Stock Share ------- --------- --------- ---------- ------------- -------- 1995 (in thousands, except earnings per common share) - ------------------------------------------------------------------------------------- 12/31/94 - As Previously Reported $271,548 $38,578 $25,861 $25,861 $ .69 - As Restated $279,332 $43,288 $30,571 $30,571 $ .82 3/31/95 - As Previously Reported $376,680 $55,197 $42,047 $42,047 $1.12 - As Restated $378,762 $56,457 $43,307 $43,307 $1.16 6/30/95 - As Previously Reported $191,480 $17,789 $ 7,783 $ 7,783 $ .21 - As Restated $193,461 $18,987 $ 8,981 $ 8,981 $ .24 9/30/95 $123,941 $ 5,667 $(6,965) $(6,965) $(.19) 1994 (in thousands, except earnings per common share) - ------------------------------------------------------------------------------------- 12/31/93 $310,131 $38,745 $27,800 $31,626* $ .86 * 3/31/94 $473,722 $54,686 $43,839 $43,839 $1.18 6/30/94 $216,281 $19,782 $ 9,833 $ 9,833 $ .26 9/30/94 $141,190 $12,690 $ 963 $ 374* $ .01 * * Includes Cumulative Effect of Changes in Accounting as discussed above.
Note K - Market for Common Stock and Related Shareholder Matters (unaudited) At September 30, 1995, there were 21,429 holders of National Fuel Gas Company common stock. The market for the common stock is the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note D - Capitalization. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 1994 and 1995, are shown below:
Price Range Dividends Quarter Ended High Low Declared - ------------- ---- --- --------- 1994 ---- 12/31/93 $36-5/8 $32-1/2 $.385 3/31/94 $36-1/4 $29-7/8 $.385 6/30/94 $32-7/8 $28-3/8 $.395 9/30/94 $31-7/8 $28-7/8 $.395 1995 ---- 12/31/94 $30 $25-1/4 $.395 3/31/95 $28-1/2 $25 $.395 6/30/95 $30-3/4 $27-1/2 $.405 9/30/95 $29-5/8 $26-1/2 $.405
Note L - Supplementary Information for Oil and Gas Producing Activities The following supplementary information is presented in accordance with SFAS 69, "Disclosures about Oil and Gas Producing Activities," and related SEC accounting rules.
Capitalized Costs Relating to Oil and Gas Producing Activities At September 30 (in thousands) 1995 1994 ---- ---- Capitalized Costs Subject to Amortization $495,802 $442,224 Capitalized Acquisition Costs Excluded from Amortization 28,565 16,636 -------- -------- 524,367 458,860 Less - Accumulated Depreciation, Depletion and Amortization 188,241 167,592 -------- -------- $336,126 $291,268 ======== ========
Certain costs excluded from amortization represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. The remaining costs, incurred during and prior to 1995, consist of individually insignificant oil and gas leases still early in their primary terms and individually insignificant unproved perpetual oil and gas rights.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Property Acquisition Costs $25,305 $ 8,215 $ 9,027 Exploration Costs 18,588 17,855 10,140 Development Costs 25,161 25,102 16,258 Other 559 259 25 ------- ------- ------- $69,613 $51,431 $35,450 ======= ======= =======
Results of Operations for Producing Activities Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $8,650, $5,456 and $11,474, respectively) $34,849 $50,803 $43,679 Oil, Condensate and Other Liquids 11,948 15,307 13,943 ------- ------- ------- Total Operating Revenues 46,797 66,110 57,622 Production/Lifting Costs 11,215 13,177 13,452 Depreciation, Depletion and Amortization ($0.44, $0.41 and $0.42, respectively, per dollar of operating revenues) 20,528 26,992 23,995 Income Tax Expense 4,301 7,907 4,311 ------- ------- ------- Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $10,753 $18,034 $15,864 ======= ======= =======
Reserve Quantity Information (unaudited) The Company's proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by qualified Company geologists and engineers and are audited by independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions.
Gas Oil Year Ended MMcf Mbbl -------------------------- ---------------------- September 30 1995 1994 1993 1995 1994 1993 ---- ---- ---- ---- ---- ---- Proved Developed and Undeveloped Reserves: Beginning of Year 247,447 175,051 179,811 17,495 18,519 19,805 Extensions and Discoveries 9,912 94,733 26,416 3,863 1,666 1,713 Revisions of Previous Estimates (21,046) (2,075) (3,962) (60) (1,660) (1,995) Production (20,942) (23,273) (19,874) (739) (1,030) (831) Sales of Minerals in Place (4,685) (32) (7,401) (474) - (173) Purchases of Minerals in Place and Other 10,773 3,043 61 2,780 - - ------- ------- ------- ------ ------ ------ End of Year 221,459 247,447 175,051 22,865 17,495 18,519 ======= ======= ======= ====== ====== ====== Proved Developed Reserves: Beginning of Year 179,291 134,712 126,176 10,110 10,801 11,437 ======= ======= ======= ====== ====== ====== End of Year 162,504 179,291 134,712 14,937 10,110 10,801 ======= ======= ======= ====== ====== ======
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited) The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company's oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under the widely fluctuating political and economic conditions of today's world. The standardized measure is intended instead to provide a somewhat better means for comparing the value of the Company's proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Future Cash Inflows $738,711 $705,874 $689,198 Less: Future Production and Development Costs 272,268 252,901 240,417 Future Income Tax Expense at Applicable Statutory Rate 129,055 131,060 132,528 -------- -------- -------- Future Net Cash Flows 337,388 321,913 316,253 Less: 10% Annual Discount for Estimated Timing of Cash Flows 92,120 106,647 106,598 -------- -------- -------- Standardized Measure of Discounted Future Net Cash Flows $245,268 $215,266 $209,655 ======== ======== ========
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $215,266 $209,655 $240,291 Sales, Net of Production Costs (35,582) (52,933) (44,170) Net Changes in Prices, Net of Production Costs 10,757 (48,149) (52,266) Purchases of Minerals in Place 18,602 2,793 61 Sales of Minerals in Place (5,688) (29) (7,286) Extensions and Discoveries 47,236 96,134 61,476 Changes in Estimated Future Development Costs (50,366) (36,466) (30,555) Previously Estimated Development Costs Incurred 39,833 22,941 30,888 Net Change in Income Taxes at Applicable Statutory Rate (6,838) 3,098 5,476 Revisions of Previous Quantity Estimates (20,934) (11,042) (25,891) Accretion of Discount and Other 32,982 29,264 31,631 -------- -------- -------- Standardized Measure of Discounted Future Net Cash Flows at End of Year $245,268 $215,266 $209,655 ======== ======== ========
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
Schedule II - Valuation and Qualifying Accounts (in thousands) ------------ Additions ---------------------- Balance at Charged to Charged to Balance at Beginning Costs and Other Deductions End of Description of Period Expenses Accounts (Note) Period - ----------- ---------- ---------- ---------- ---------- ---------- Year Ended September 30, 1995 - ----------------------------- Reserve for Doubtful Accounts $ 5,055 $15,187 $ - $14,318 $5,924 ======= ======= ====== ====== ====== Year Ended September 30, 1994 - ----------------------------- Reserve for Doubtful Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055 ======= ======= ====== ======= ======= Year Ended September 30, 1993 - ----------------------------- Reserve for Doubtful Accounts $ 5,900 $ 8,713 $ - $8,874 $ 5,739 ======= ======= ====== ====== =======
Note - Amounts represent net accounts receivable written-off. ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None PART III ITEM 10 Directors and Executive Officers of the Registrant The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 1996 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1995. The information provided in such definitive Proxy Statement is incorporated herein by reference. Information concerning the Company's executive officers can be found in Part I, Item 1, of this report. ITEM 11 Executive Compensation The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 1996 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1995. The information provided in such definitive Proxy Statement is incorporated herein by reference. ITEM 12 Security Ownership of Certain Beneficial Owners and Management The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 15, 1996 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1995. The information provided in such definitive Proxy Statement is incorporated herein by reference. ITEM 13 Certain Relationships and Related Transactions At September 30, 1995, the Company knows of no relationships or transactions required to be disclosed pursuant to Item 404 of Regulation S-K. PART IV ITEM 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) Financial Statement Schedules All financial statement schedules filed as part of this report are included in Item 8 of this Form 10-K and reference is made thereto. (b) Reports on Form 8-K None (c) Exhibits Exhibit Number Description of Exhibits ------- ----------------------- 3(i) Articles of Incorporation: * Restated Certificate of Incorporation of National Fuel Gas Company, dated March 15, 1985 (Exhibit 10-OO, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880) 3.1 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated March 9, 1987 3.2 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated February 22, 1988 * Certificate of Amendment of Restated Certificate of Incorporation, dated March 17, 1992 (Exhibit EX-3(a), Form 10-K for fiscal year ended September 30, 1992 in File No. 1-3880) 3(ii) By-Laws: * National Fuel Gas Company By-Laws as amended through June 9, 1994 (Exhibit 3.1, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) (4) Instruments Defining the Rights of Security Holders, Including Indentures: * Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796) * Ninth Supplemental Indenture dated as of January 1, 1990, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit EX-4.4, Form 10-K for fiscal year ended September 30, 1992 in File No. 1-3880) * Tenth Supplemental Indenture dated as of February 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a), Form 8-K dated February 14, 1992 in File No. 1-3880) * Eleventh Supplemental Indenture dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992 in File No. 1-3880) * Twelfth Supplemental Indenture dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992 in File No. 1-3880) * Thirteenth Supplemental Indenture dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401) * Fourteenth Supplemental Indenture dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) (10) Material Contracts: (ii) (B) Contracts upon which Registrant's business is substantially dependent: 10.1 Service Agreement with Empire State Pipeline under Rate Schedule FT, dated December 15, 1994. [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2] 10.2 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated August 1, 1993 10.3 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated September 19, 1995 10.4 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.5 Amendment dated as of May 1, 1995 to Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.6 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated August 1, 1993 10.7 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated October 1, 1993 * Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FTS, dated November 1, 1993 and executed February 13, 1994 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FSS, dated November 1, 1993 and executed February 13, 1994 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule SST, dated November 1, 1993 and executed February 13, 1994 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Gas Transportation Agreement with Tennessee Gas Pipeline Company under Rate Schedule FT-A (Zone 4), dated September 1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) * Gas Transportation Agreement with Tennessee Gas Pipeline Company under Rate Schedule FT-A (Zone 5), dated September 1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) * Service Agreement with Texas Eastern Transmission Corporation under Rate Schedule CDS, dated June 1, 1993 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) * Service Agreement with Texas Eastern Transmission Corporation under Rate Schedule FT-1, dated June 1, 1993 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) * Service Agreement with CNG Transmission Corporation under Rate Schedule FT, dated October 1, 1993 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) * Service Agreement with CNG Transmission Corporation under Rate Schedule GSS, dated October 1, 1993 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) (iii) Compensatory plans for officers: * Employment Agreement, dated September 17, 1981, with Bernard J. Kennedy (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Eighth Extension to Employment Agreement with Bernard J. Kennedy, dated September 20, 1991 (Exhibit 10-SS, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880) * National Fuel Gas Company 1983 Incentive Stock Option Plan, as amended and restated through February 18, 1993 (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) * National Fuel Gas Company 1984 Stock Plan, as amended and restated through February 18, 1993 (Exhibit 10.3, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) * National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) 10.8 Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 * Change in Control Agreement, dated May 1, 1992, with Philip C. Ackerman (Exhibit EX-10.4, Form 10-K for fiscal year ended September 30, 1992 in File No. 1-3880) * Change in Control Agreement, dated May 1, 1992, with Richard Hare (Exhibit EX-10.5, Form 10-K for fiscal year ended September 30, 1992 in File No. 1-3880) * Change in Control Agreement, dated May 1, 1992 with William J. Hill (Exhibit EX-10.6, Form 10-K for fiscal year ended September 30, 1992 in File No. 1-3880) * Agreement, dated August 1, 1989, with Richard Hare (Exhibit 10-Q, Form 10-K for fiscal year ended September 30, 1989 in File No. 1-3880) * National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) 10.9 Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 10.10 National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 * Executive Death Benefits Agreement, dated April 1, 1991, with William J. Hill (Exhibit EX-10.8, Form 10-K for fiscal year ended September 30, 1992 in File No. 1-3880) * Split Dollar Death Benefits Agreement, dated April 1, 1991, with Richard Hare (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Amendment to Split Dollar Death Benefits Agreement, dated March 15, 1994, with Richard Hare (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Split Dollar Death Benefits Agreement, dated April 1, 1991, with Philip C. Ackerman (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Amendment to Split Dollar Death Benefits Agreement, dated March 15, 1994, with Philip C. Ackerman (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Death Benefits Agreement, dated August 28, 1991, with Bernard J. Kennedy (Exhibit 10-TT, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880) 10.11 Amendment to Death Benefit Agreement of August 28, 1991 with Bernard J. Kennedy, dated March 15, 1994 * Summary of Annual at Risk Compensation Incentive Program (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) * Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of December 5, 1991 (Exhibit 10-UU, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880) (12) Computation of Ratio of Earnings to Fixed Charges (13) Discussion of the Company's business segments as contained in the 1995 Annual Report and incorporated by reference into this Form 10-K (21) Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K (23) Consents of Experts and Counsel: 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants (27) Financial Data Schedules (99) Additional Exhibits: 99.1 Report of Ralph E. Davis Associates, Inc. All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K. * Incorporated herein by reference as indicated. 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. National Fuel Gas Company (Registrant) --------------------------------- By /s/ B. J. Kennedy ------------------------------- B. J. Kennedy Chairman of the Board, President Date December 13, 1995 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. Signature Title --------- ----- /s/ B. J. Kennedy Chairman of the Board, B. J. Kennedy President, Chief Executive Officer and Director Date: December 13, 1995 /s/ P. C. Ackerman Senior Vice President, Principal P. C. Ackerman Financial Officer and Director Date: December 13, 1995 /s/ R. T. Brady Director R. T. Brady Date: December 13, 1995 /s/ J. M. Brown Director J. M. Brown Date: December 13, 1995 /s/ D. N. Campbell Director D. N. Campbell Date: December 13, 1995 /s/ W. J. Hill Director W. J. Hill Date: December 13, 1995 /s/ L. F. Kahl Director L. F. Kahl Date: December 13, 1995 /s/ B. S. Lee Director B. S. Lee Date: December 13, 1995 /s/ E. T. Mann Director E. T. Mann Date: December 13, 1995 /s/ L. Rochwarger Director L. Rochwarger Date: December 13, 1995 /s/ G. H. Schofield Director G. H. Schofield Date: December 13, 1995 /s/ J. P. Pawlowski Treasurer and J. P. Pawlowski Principal Accounting Officer Date: December 13, 1995 /s/ A. M. Cellino Secretary A. M. Cellino Date: December 13, 1995 /s/ G. T. Wehrlin Controller G. T. Wehrlin Date: December 13, 1995 APPENDIX TO ITEM 2 - PROPERTIES Three maps outlining the Company's operating areas at September 30, 1995 are included on page 6 in the paper format version of the Company's combined Annual Report to Shareholders/Form 10-K, but are not included in this electronic filing. The first map identifies the Company's Exploration and Production operating area (i.e., Seneca Resources' operating area). The second map identifies the Company's Utility Operating area (i.e., Distribution Corporation's service area). The third map identifies the Company's Pipeline and Storage operating area (i.e., Supply Corporation's storage areas and pipelines). APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS A. The Revenue Dollar - 1995 Two pie graphs detailing the revenue dollar in 1995: where it came from and where it went to, broken down as follows: Where it came from: $ .581 Residential Sales .178 Commercial, Industrial and Off-System Sales .071 Transportation Revenues .048 Oil and Gas Revenues .042 Marketing Revenues .040 Storage Service Revenues .040 Other Revenues $1.000 Total Where it went to: $ .358 Gas Purchased .184 Wages, Including Benefits .138 Taxes .114 Other Materials and Services .073 Depreciation .061 Dividends - Common Stock .055 Interest .017 Reinvested in the Business $1.000 Total B. Capital Expenditures A bar graph detailing capital expenditures (millions of dollars) for the years 1991 through 1995, broken down as follows: 1991 1992 1993 1994 1995 ---- ---- ---- ---- ---- Other Nonregulated $ 1.0 $ 7.2 $ 6.2 $ 3.6 $ 9.6 Pipeline and Storage 58.6 58.7 27.4 20.5 38.7 Exploration and Production 31.7 26.3 36.5 52.5 69.7 Utility Operation 64.9 65.7 61.8 61.7 64.8 ------ ------ ------ ------ ------ $156.2 $157.9 $131.9 $138.3 $182.8 APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS (Concluded) C. Book Value Per Common Share A bar graph detailing book value per common share (dollars) for the years 1991 through 1995, as follows: 1991 - $17.53 1992 - 18.68 1993 - 20.08 1994 - 20.93 1995 - 21.39 D. Capitalization Ratios A bar graph detailing capitalization (percentage) for the years 1991 through 1995, broken down as follows: Debt (%) Equity (%) 1991 55.0 45.0 1992 54.5 45.5 1993 47.8 52.2 1994 46.2 53.8 1995 47.0 53.0 Exhibit Index ------------- 3.1 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated March 9, 1987 3.2 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated February 22, 1988 10.1 Service Agreement with Empire State Pipeline under Rate Schedule FT, dated December 15, 1994. [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2] 10.2 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated August 1, 1993 10.3 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated September 19, 1995 10.4 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.5 Amendment dated as of May 1, 1995 to Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.6 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated August 1, 1993 10.7 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated October 1, 1993 10.8 Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 10.9 Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 10.10 National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 10.11 Amendment to Death Benefit Agreement of August 28, 1991 with Bernard J. Kennedy, dated March 15, 1994 (12) Computation of Ratio of Earnings to Fixed Charges (13) Discussion of the Company's business segments as contained in the 1995 Annual Report and incorporated by reference into this Form 10-K 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants 27.1 Financial Data Schedule for 12 months ending September 30, 1995 27.2 Financial Data Schedule for 12 months ending September 30, 1994, Restated 27.3 Financial Data Schedule for 9 months ending June 30, 1995, Restated 27.4 Financial Data Schedule for 6 months ending March 31, 1995, Restated 27.5 Financial Data Schedule for 3 months ending December 31, 1994, Restated 99.1 Report of Ralph E. Davis Associates, Inc. EX-99 2 RALPH E. Davis Associates, INC. CONSULTANTS-PETROLEUM AND NATURAL GAS 3555 TIMMONS LANE-SUITE 1105 HOUSTON, TEXAS 77027 (713) 622 -8955 October 17, 1995 Seneca Resources Corporation 333 Clay Street, Suite 4150 Houston, Texas 77002 Attention: Mr. Don A. Brown Vice President Re: 0il, Condensate and Natural Gas Reserves, Seneca Resources Corporation As of October 1, 1995 Gentlemen: At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which Seneca Resources Corporation has certain interests. This report presents a summary of the Proved Developed (producing and non-producing) and Proved Undeveloped reserves anticipated to be produced from Seneca Resources' interest. Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located. The summarized results of the reserve audit are as follows: RALPH E. DAVIS ASSOCIATES, INC. Seneca Resources Corp. Mr. Don A. Brown October 17, 1995 Page 2 Estimated Proved Reserves Net to Seneca Resources Corporation As of October 1, 1995 Proved Reserves -------------------------------------------- Developed ----------------------- Remaining Reserves Producing Non-Producing Undeveloped Total Gulf Coast Division: Oil/Condensate, MBbls 704 5,122 2,062 7,888 Gas, MMSCF 41,973 39,694 47,114 128,781 West Coast Division: Oil/Condensate, MBbls 5,993 2,891 5,866 14,750 Gas, MMSCF 13,435 5,693 11,840 30,968 East Coast Division; Oil/Condensate, MBbls 227 0 0 227 Gas, MMSCF 61,317 392 0 61,709 TOTAL: Oil/Condensate, MBbls 6,924 8,013 7,928 22,865 Gas, MMSCF 116,725 45,779 58,954 221,458 DISCUSSION: The scope of this study was to audit the proved reserves attributable to the interests of Seneca Resources Corporation. Reserve estimates were prepared by Seneca using acceptable evaluation principals for each source. The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty. Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by Seneca Resources. It is our opinion that the reserves presented herein meet all the criteria of Proved Reserves. RALPH E. DAVIS ASSOCIATES, INC. Seneca Resources Corp. Mr. Don A. Brown October 17, 1995 Page 3 Neither Ralph E. Davis Associates, Inc. nor any of its employees have any interest in Seneca Resources Corporation or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves. We appreciate the opportunity to be of service to you in this matter, and will be glad to address any questions or inquiries you may have. Very truly yours, RALPH E. DAVIS ASSOCIATES, INC. /s/ Allen C. Barron Allen C. Barron, P. E. Vice President EX-10 3 CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2 FT CONTRACT NUMBER: 95005 THIS AGREEMENT entered into this 15th day of December 1994, by and between EMPIRE STATE PIPELINE, a joint venture, hereinafter referred to as "Transporter," and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter referred to as "Shipper." ARTICLE I 1. Transporter's Transportation Service hereunder shall be subject to receipt of all requisite regulatory authorizations from the New York Public Service Commission ("Commission") , or any successor regulatory authority, and any other necessary governmental authorizations, in a manner and form acceptable to Transporter. 2. Subject to the terms and provisions of this Agreement, Shipper agrees to deliver or cause to be delivered to Transporter, Gas for Transportation, and Transporter agrees to receive, transport and redeliver Equivalent Quantities of Gas to Shipper or for the account of Shipper, on a firm basis, up to an aggregate Maximum Daily Quantity of 40,112 dekatherms ("Dth") . Section I of Exhibit C, attached hereto and made a part hereof, sets forth one or more routings of Transportation provided hereunder, by designation of the Point(s) of Receipt and Point(s) of Delivery, and specifies the portion of the aggregate Maximum Daily Quantity which is related to and agreed upon relative to each such routing. 3. Transporter may, if tendered by Shipper, transport daily quantities in excess of the Maximum Daily Quantity specified in Paragraph 2, above, if it can do so without adverse effect on Transporter's operations or its ability to meet all other obligations. 4. Transportation service rendered hereunder may be wholly or partly interrupted, subject to the requirements of the General Information, when such curtailment or interruption is desirable due to operating conditions or insufficient pipeline capacity available on Transporter's system. ARTICLE II 1. Shipper shall deliver or cause to be delivered Gas hereunder at the Point(s) of Receipt set forth in Exhibit "A", which is attached hereto and made a part hereof. ARTICLE III 1. Transporter shall redeliver to Shipper or for the account of Shipper Equivalent Quantities of Gas transported hereunder at the Point(s) of Delivery set forth on Exhibit "B", which is attached hereto and made a part hereof. CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2 ARTICLE IV This Agreement shall be effective for an initial period as of [ ] until [ ]. ARTICLE V 1. Each Month, Shipper shall pay Transporter for the service hereunder, an amount determined in accordance with Transporter's Service Classification No. 1 (Rate Schedule FT), and the applicable provisions of the General Information of Transporter's New York Public Services Commission Gas Tariff, as filed with the Commission. Such Service Classification and General Information are incorporated by reference and made a part hereof. Section II of Exhibit C hereto sets forth one or more routings of Transportation provided hereunder, by designation of the Point(s) of Receipt and Point(s) of Delivery, and specifies for each such routing, the rates, differentials and any other charges applicable to service under this Service Agreement for such routing, as agreed by Transporter and Seller or as fixed by Transporter pursuant to Section 3.2 of Service Classification No. 1. Transporter may unilaterally effect an amendment to Section II of Exhibit C to reflect any changes made pursuant to said Section 3.2, which is incorporated herein by reference, and/or pursuant to Commission authorization or direction. Any rates or differentials so specified shall be increased pursuant to Section 16 of the above referenced General Information. 2. It is further agreed that Transporter may seek authorization from the Commission and/or other appropriate body for such changes to any rate(s) and terms set forth herein or in Service Classification No. 1 or in the General Information as may be found necessary to assure Transporter just and reasonable rates and terms. Nothing herein contained shall be construed to deny Shipper any rights it may have under applicable law, including the right to participate fully in rate proceedings by intervention or otherwise to contest increased rates in whole or in part. ARTICLE VI 1. Definition. The term "force majeure" as used herein shall mean acts of God, strikes, lockouts, or other industrial disturbances; acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms (including but not limited to hurricanes or hurricane warnings), crevasses, floods, washouts; arrests and restraints of the government, either Federal or State, civil or military; and civil disturbances. Relative to Transporter's service and solely to the operation of its system, force majeure shall also mean shutdowns for purposes of necessary repairs, relocation, or construction of facilities; breakage or accident to machinery or lines of pipe; the necessity for testing (as required by governmental authority or as deemed necessary by Transporter for the safe operation thereof), the necessity of making repairs or alterations to machinery or lines of pipe; failure of surface equipment or pipe lines; accidents, breakdowns, inability to obtain necessary materials, supplies or permits, or labor to perform or comply with any obligation or condition of this Agreement, rights of way; and any other causes, whether of the kind herein enumerated or otherwise which are not reasonably in Transporter's control. It is understood and agreed that the settlement of strikes or lockouts or controversies with landowners involving rights of way shall be entirely within Transporter's discretion and that the above requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts or controversies with landowners involving rights of way by acceding to the demands of the opposing party when such course is inadvisable in the discretion of Transporter. 2. Force Majeure. If by reason of force majeure either party hereto is rendered unable, wholly or in part, to carry out its obligations under this Agreement, it is agreed that if such party gives notice in full particulars of such force majeure in writing or by telecopy to the other party within a reasonable time after the occurrence of the cause relied on, the party giving such notice, so far as and to the extent that it is affected by such force majeure, shall not be liable for damages during the continuance of any inability so caused, but for no longer period, and such cause shall so far as possible be remedied with all reasonable dispatch. Transporter shall not be liable for damages to Shipper other than for acts of gross negligence or willful misconduct, and only in circumstances in which conditions of force majeure do not exist. 3. Limitations. Such force majeure affecting the performance hereunder by either Transporter or Shipper, however, shall not relieve such party of liability in the event of failure to use due diligence to remedy the situation and to remove the cause in an adequate manner and with all reasonable dispatch, nor shall such causes or contingencies affecting such performance relieve Shipper from its obligations to make payments then due or becoming due under this agreement. ARTICLE VII 1. Payment. Shipper shall pay Transporter the amount due for the preceding Month on or before the twenty-fifth (25th) Day of the Month. All payments by Shipper to Transporter shall be made in the form of wire transfer directed to a bank account designated by Transporter's Controller or by check at Transporter's general of office, or at such other address as Transporter shall designate such that funds are available on the date payment is due. If rendering of a bill by Transporter is delayed after the tenth (10th) Day of the Month, then the time of payment shall be extended accordingly unless Shipper is responsible for such delay. Should Shipper fail to pay all of the amount of any bill as herein provided when such amount is due, interest on the unpaid portion of the bill shall accrue at the prime rate or rates charged by Citibank, N.A. New York, New York to responsible commercial and industrial borrowers, plus two percentage points, for each of the Months from the due date until the date of payment. Transporter may also impose late payment or failure to pay charges not inconsistent with regulations or orders of the Commission. If such failure to pay continues for thirty (30) Days after payment is due, Transporter, in addition to any other remedy it may have hereunder, shall upon notice to Shipper, suspend further delivery of Gas until such amount is paid; provided, however, that if Shipper in good faith shall dispute the amount of any such bill or part thereof and shall pay to Transporter such amounts, if any, as it concedes to be correct and, at any time thereafter within thirty (30) Days of a demand made by Transporter, shall furnish a good and sufficient surety bond in an amount and with surety satisfactory to Transporter or other assurance acceptable to Transporter, guaranteeing payment to Transporter of the amount ultimately found due upon such bill after a final determination which may be reached either by agreement or judgment of the courts, as may be the case, then Transporter shall not be entitled to suspend further delivery of such Gas unless and until default be made in the conditions of such bond. In the event Transporter suspends delivery of Gas for non payment by Shipper, and Shipper continues non payment for thirty (30) Days after such suspension, Shipper shall be deemed to have consented to termination of its Service Agreement and abandonment of service. Written notice of any termination and abandonment shall be given to Shipper at least seventy-two (72) hours before such termination and abandonment, and shall include an adequate explanation. If there are claimed errors in a billing hereunder and Shipper and Transporter are unable to agree relative thereto, any resort by either of the parties to legal proceedings shall be commenced within fifteen (15) Months after the supposed cause of action is alleged to have arisen, or shall thereafter be forever barred. 2. Responsibility for Gas. Shipper shall be deemed in exclusive control and possession of the Gas until such Gas has been delivered to Transporter at the Point of Receipt and after such Gas has been redelivered to or for the account of Shipper at the Point of Delivery. Transporter shall be in exclusive control and possession of such Gas between the Point(s) of Receipt and the Point(s) of Delivery set forth in this Agreement. The party which shall be in exclusive control and possession of such Gas shall be responsible for all injury or damage caused thereby to any third party. 3. Indemnification of Transporter. In the absence of gross negligence or willful misconduct on the part of Transporter's officers, employees or agents, Shipper waives and indemnities against any and all claims against Transporter, its officers, employees or agents, arising out of or in any way connected with (i) the quality, use or condition of the Gas after delivery from Transporter's line for the account of such Shipper; (ii) any losses or shrinkage of Gas during or resulting from transportation hereunder; and (iii) all other claims and demands arising out of the performance of the duties of the Transporter, its officers, employees or agents. Shipper agrees to supply Transporter with a waiver of subrogation of Shipper's insurance company for all claims subject to the indemnification and the save harmless provisions covered by this paragraph. 4. Warranty. Shipper warrants for itself, its successors, and assigns, that it has, or will have, at the time of delivery of the Gas for transportation hereunder, good title to such Gas to be delivered to Transporter for Transportation, or the contractual right to allow and cause such gas to be delivered to and transported by Transporter. Shipper warrants for itself, its successors, and assigns, and any person(s) which grant such contractual right to Shipper, that the Gas it warrants hereunder shall be free and clear of all liens, encumbrances or claims, that it will indemnify and save Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses, and expenses arising from or out of any adverse claims of any and all persons to said Gas and/or to royalties, taxes, license fees, or charges thereon which are directly applicable to such delivery of Gas and that it will indemnify and save Transporter harmless from all taxes or assessments which may be directly levied and assessed upon such delivery and which are by law payable and the obligation of the party making such delivery. 5. waivers. No waiver by either Transporter or Shipper of any one or more defaults by the other in the performance of any provisions hereunder shall operate or be construed as a waiver of any future default or defaults, whether of a like or a different character. Transporter may waive enforcement of provisions of its tariff, where economically and operationally feasible. 6 Interpretation of Laws. This Agreement shall be interpreted, performed and enforced in accordance with the laws of the State of New York. 7. No Third Party Beneficiary. It is expressly agreed that there is no Third Party Beneficiary of this Agreement, and that the provisions of this Agreement and this General Information do not impart enforceable rights in anyone who is not a party or successor or assignee of any party to this Agreement. 8. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, but all of which together shall constitute but one and the same instrument. 9. Headings. The headings contained in this Agreement are for reference purposes only and shall not affect the meaning or interpretation of this Agreement. ARTICLE VIII NOTICE 1. Except as may be otherwise provided, any notice, request, demand, statement or bill provided for in this Agreement or any notice which a party may desire to give the other shall be in writing and mailed by regular mail, effective as of the postmark date, to the post office address of the party intended to receive the same, as follows: Transporter: Empire State Pipeline 500 Renaissance Center Detroit, Michigan 48243 Attention: Gas Control (Nominations) Gas Measurement (Meter Statements) Volume Management (Other Statements) Cash Control (Payments) System Marketing (All other matters) Shipper: National Fuel Gas Distribution Corporation 10 Lafayette Square Buffalo, New York 14203 Attention: Contract Administration (invoices) Walter E. DeForest, Senior V.P. (all other matters) CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2 ARTICLE IX MISCELLANEOUS 1. Transporter and Shipper further agree as follows: a. Shipper represents and warrants, to the satisfaction of the Federal Energy Regulatory Commission, Transporter and the Commission, that, until Transporter obtains the necessary regulatory authorization to transport gas in interstate commerce, all Gas transported hereunder shall be consumed in the State of New York. b. Shipper shall pay Transporter a rate for the service provided hereunder which, in no event, shall be less than the minimum rate, nor greater than the maximum rate, approved by the Commission, and as set forth in Transporter's Schedule for Gas Service. Subject to the foregoing, Shipper shall pay Transporter a total rate, which [ ]. CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2 c. It is understood and agreed that Shipper shall have the right to defer commencement of 27,300 Dth per day of the service hereunder. If Shipper defers service for such quantity, service for such quantity shall commence no later than [ ]. CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective officers or Representatives thereunto duly authorized. EMPIRE STATE PIPELINE (Transporter) By /s/ Richard A. Lietz Its Chairman of the Management Committee ATTEST: NATIONAL FUEL GAS DISTRIBUTION COMPANY (Shipper) /s/ David F. Smith By /s/ Walter E. DeForest Secretary Its Sr. Vice President EXHIBIT "A" to Agreement between Empire State Pipeline (Transporter) and NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Shipper) Dated______________________________ POINT(S) OF RECEIPT AND PRESSURES --------------------------------- Point(s) of Receipt by Transporter Maximum Allowable Measuring Operating Pressure Number Name Location Party "NMOP" - --------- --------- ---------- --------- ------------------ 012000010 CHIPPAWA CHANNEL (EMPIRE/TCPL) EXHIBIT "B" to Agreement between Empire State Pipeline (Transporter) and NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Shipper) Dated_______________________ POINT(S) OF DELIVERY BY TRANSPORTER ----------------------------------- Measuring Number Name Location Party - --------- ------------ --------- ----- 012003010 GRAND ISLAND (EMPIRE/NFGS) EXHIBIT "C" to Agreement between Empire State Pipeline (Transporter) and NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Shipper) Dated____________________________ MAXIMUM DAILY QUANTITY, TRANSPORTATION AND ADDITIONAL CHARGES ------------------------ I. MAXIMUM DAILY QUANTITY Point(s) of Receipt Point(s) of Delivery Maximum Daily Number(s) Number(s) Quantity (Dth) - ------------------- -------------------- -------------- 012000010 012003010 40,112 II. TRANSPORTATION AND ADDITIONAL CHARGES Effective Point(s) Point(s) Transportation Effective of Receipt of Delivery Charge Other Number(s) Number(s) ($ per Dth) Charges - ---------- ----------- -------------- --------- 012000010 012003010 Reservation Charge: (1) (1) Commodity Charge: (1) (1) Note: (1) Refer to Service Classification No. 1. of Transporter's New York Public Service Commission's Gas Tariff. EX-10 4 SERVICE AGREEMENT (ESS Service) AGREEMENT made this 1st day of August, 1993, by and between National Fuel Gas Supply Corporation, a Pennsylvania corporation, hereinafter called "Transporter," and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter called "Shipper." WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree that Transporter will store natural gas for Shipper during the term, at the rates and on the terms and conditions hereinafter provided. ARTICLE I Quantities Beginning on the date on which storage service is commenced hereunder and thereafter for the remaining term of this Agreement, and subject to the provisions of Transporter's ESS Rate Schedule Transporter agrees to cause to be injected into storage for Shipper's account, store, and withdraw from storage, quantities of natural gas as follows: Maximum Storage Quantity (MSQ) of 23,882,071 Dekatherms (Dth) Maximum Daily Injection Quantity (MDIQ) of 140,483 Dth Maximum Daily Withdrawal Quantity (MDWQ) of 511,633 Dth ARTICLE II Rate Unless otherwise mutually agreed in a written amendment to this Agreement, for each dekatherm of gas transported for Shipper by Transporter hereunder, Shipper shall pay Transporter the maximum rate provided under Rate Schedule ESS set forth in Transporter's effective FERC Gas Tariff. In the event that the Transporter places on file with the Federal Energy Regulatory Commission ("Commission") another rate schedule which may be applicable to transportation service rendered hereunder, then Transporter, at its option, may from and after the effective date of such rate schedule, utilize such rate schedule in performance of this Agreement. Such a rate schedule(s) or superseding rate schedule(s) and any revisions thereof which shall be filed and become effective shall apply to and be a part of this Agreement. Transporter shall have the right to propose, file and make effective with the Commission, or other body having jurisdiction, changes and revisions of any effective rate schedule(s), or to propose, file, and make effective superseding rate schedules, for the purpose of changing the rate, charges, and other provisions thereof effective as to Shipper. Shipper agrees to reimburse Transporter for the filing fees associated with this service and paid to the Commission. ARTICLE III Term of Agreement This Agreement shall be effective as of the effective date of the tariff sheets implementing the restructuring of Transporter's services in Docket No. RS92-21, and shall continue in effect until March 31, 2003, and shall continue in effect from year to year thereafter until terminated by either Shipper or Transporter effective as of April 1st of any year, upon twelve (12) months written notice to the other. ARTICLE IV Regulatory Approval Performance under this Agreement by Transporter and Shipper shall be contingent upon Transporter and Shipper receiving all necessary regulatory or other governmental approvals upon terms satisfactory to each. Should Transporter and Shipper be denied such approvals to provide the service contemplated herein or construct and operate any necessary facilities therefor upon the terms and conditions requested in the application therefor, then Transporter's and Shipper's obligations hereunder shall terminate. ARTICLE V Incorporation By Reference of Tariff Provisions To the extent not inconsistent with the terms and conditions of this agreement, the provisions of Rate Schedule FT, or any effective superseding rate schedule or otherwise applicable rate schedule, including any provisions of the General Terms and Conditions incorporated therein, and any revisions thereof that may be made effective hereafter are hereby made applicable to and a part hereof by reference. ARTICLE VI Miscellaneous 1. No change, modification or alteration of this Agreement shall be or become effective until executed in writing by the parties hereto, and no course of dealing between the parties shall be construed to alter the terms hereof, except as expressly stated herein. 2. No waiver by any party of any one or more defaults by the other in the performance of any provisions of this Agreement shall operate or be construed as a waiver of any other default or defaults, whether of a like or of a different character. 3. Any company which shall succeed by purchase, merger or consolidation of the gas related properties, substantially as an entirety, of Transporter or of Shipper, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Agreement. Either party may, without relieving itself of its obligations under this Agreement, assign any of its rights hereunder to a company with which it is affiliated, but otherwise, no assignment of this Agreement or of any of the rights or obligations hereunder shall be made unless there first shall have been obtained the consent thereto in writing of the other party. Consent shall not be unreasonably withheld. 4. Except as herein otherwise provided, any notice, request, demand, statement or bill provided for in this Agreement, or any notice which either party may desire to give the other, shall be in writing and shall be considered as duly delivered when mailed by registered or certified mail to the Post Office address of the parties hereto, as the case may be, as follows: Transporter: National Fuel Gas Supply Corporation Gas Supply - Transportation Room 1200 10 Lafayette Square Buffalo, New York 14203 Shipper: National Fuel Gas Distribution Corporation 10 Lafayette Square Buffalo, New York 14203 or at such other address as either party shall designate by formal written notice. Routine communications, including monthly statements, shall be considered as duly delivered when mailed by either registered, certified, or ordinary mail, electronic communication, or telecommunication. 5. Transporter and Shipper shall proceed with due diligence to obtain such governmental and other regulatory authorizations as may be required for the rendition of the services contemplated herein, provided that Transporter reserves the right to file and prosecute applications for such authorizations, any supplements or amendments thereto and, if necessary, any court review, in such manner as it deems to be in its best interest, including the right to withdraw the application or to file pleadings and motions (including motions for dismissal). 6. This Agreement and the respective obligations of the parties hereunder are subject to all present and future valid laws, orders, rules and regulations of constituted authorities having jurisdiction over the parties, their functions or gas supply, this Agreement or any provision hereof. Neither party shall be held in default for failure to perform hereunder if such failure is due to compliance with laws, orders, rules or regulations of any such duly constituted authorities. 7. The subject headings of the articles of this Agreement are inserted for the purpose of convenient reference and are not intended to be a part of the Agreement nor considered in any interpretation of the same. 8. No presumption shall operate in favor of or against either party hereto as a result of any responsibility either party may have had for drafting this Agreement. 9. The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Pennsylvania, without recourse to the law regarding the conflict of laws. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective Presidents or Vice Presidents thereunto duly authorized and their respective corporate seals to be hereto affixed and attested by their respective Secretaries and Assistant Secretaries, the day and year first above written. NATIONAL FUEL GAS SUPPLY CORPORATION Transporter Attest: /s/ Richard M. DiValerio By /s/ Richard Hare Secretary President (Corporate Seal) NATIONAL FUEL GAS DISTRIBUTION CORPORATION Shipper Attest: /s/ David F. Smith By /s/ Philip C. Ackerman Secretary President (Corporate Seal) EX-10 5 SERVICE AGREEMENT (ESS Service) AGREEMENT made this 19th day of September 1995, by and between NATIONAL FUEL GAS SUPPLY CORPORATION, a Pennsylvania corporation, hereinafter called "Transporter", and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter called "Shipper". WITNESSETH: That, in consideration of the mutual covenants herein contained, the parties hereto agree that Transporter will store natural gas for Shipper during the term, at the rates and on the terms and conditions hereinafter provided. ARTICLE I Quantities Beginning on the date on which storage service is commenced hereunder and thereafter for the remaining term of this Agreement, and subject to the provisions of Transporter's ESS Rate Schedule, Transporter agrees to cause to be injected into storage for Shipper's account, store, and withdraw from storage, quantities of natural gas as follows: Maximum Storage Quantity (MSQ) of 2,000,000 Dekatherms (Dth) Maximum Injection Quantity (Contract MDIQ) of 11,765 Dth Maximum Withdrawal Quantity (Contract MDWQ) of 13,245 Dth ARTICLE II Rate Unless otherwise mutually agreed in a written amendment to this Agreement, or unless a different rate is specified in the release forms attached hereto, for each dekatherm of gas transported for Shipper by Transporter hereunder, Shipper shall pay Transporter the maximum rate provided under Rate Schedule ESS set forth in Transporter's effective FERC Gas Tariff. In the event that the Transporter places on file with the Federal Energy Regulatory Commission ("Commission") another rate schedule which may be applicable to transportation service rendered hereunder, then Transporter, at its option, may from and after the effective date of such rate schedule, utilize such rate schedule in performance of this Agreement. Such a rate schedule(s) or superseding rate schedule(s) and any revisions thereof which shall be filed and become effective shall apply to and be a part of this Agreement. Transporter shall have the right to propose, file and make effective with the Commission, or other body having jurisdiction, changes and revisions of any effective rate schedule(s), or to propose, file, and make effective superseding rate schedules, for the purpose of changing the rate, charges, and other provisions thereof effective as to Shipper. Shipper agrees to reimburse Transporter for the filing fees associated with this service and paid to the Commission. ARTICLE III Term of Agreement This Agreement shall be effective as of January 1996, and shall continue in effect until April 15, 2006, and shall continue in effect thereafter until terminated by either Shipper or Transporter effective as of April 1 of any year, upon twelve (12) months' written notice to the other. ARTICLE IV Regulatory Approval Performance under this Agreement by Transporter and Shipper shall be contingent upon Transporter and Shipper receiving all necessary regulatory or other governmental approvals upon terms satisfactory to each. Should Transporter and Shipper be denied such approvals to provide the service contemplated herein or construct and operate any necessary facilities therefor upon the terms and conditions requested in the application therefor, then Transporter's and Shipper's obligations hereunder shall terminate. In particular, performance under this Agreement shall be contingent upon permanent certification of Transporter's storage facilities at Allegany State Park. ARTICLE V Incorporation By Reference of Tariff Provisions To the extent not inconsistent with the terms and conditions of this Agreement, the provisions of Rate Schedule ESS, or any effective superseding rate schedule or otherwise applicable rate schedule, including any provisions of the General Terms and Conditions incorporated therein, and any revisions thereof that may be made effective hereafter are hereby made applicable to and a part hereof by reference. ARTICLE VI Miscellaneous 1. No change, modification or alteration of this Agreement shall be or become effective until executed in writing by the parties hereto, and no course of dealing between the parties shall be construed to alter the terms hereof, except as expressly stated herein. 2. No waiver by any party of any one or more defaults by the other in the performance of any provisions of this Agreement shall operate or be construed as a waiver of any other default or defaults, whether of a like or of a different character. 3. Any company which shall succeed by purchase, merger or consolidation of the gas related properties, substantially as an entirety, of Transporter or of Shipper, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Agreement. Either party may, without relieving itself of its obligations under this Agreement, assign any of its rights hereunder to a company with which it is affiliated, but otherwise, no assignment of this Agreement or of any of the rights or obligations hereunder shall be made unless there first shall have been obtained the consent thereto in writing of the other party. Consent shall not be unreasonably withheld. 4. Except as herein otherwise provided, any notice, request, demand, statement or bill provided for in this Agreement, or any notice which either party may desire to give the other, shall be in writing and shall be considered as duly delivered when mailed by registered or certified mail to the Post Office address of the parties hereto, as the case may be, as follows: Transporter: National Fuel Gas Supply Corporation Gas Supply - Transportation Room 1200 10 Lafayette Square Buffalo, New York 14203 Shipper: National Fuel Gas Distribution Corporation 10 Lafayette Square Buffalo, New York 14203 or at such other address as either party shall designate by formal written notice. Routine communications, including monthly statements, shall be considered as duly delivered when mailed by either registered, certified, or ordinary mail, electronic communication, or telecommunication. 5. Transporter and Shipper shall proceed with due diligence to obtain such governmental and other regulatory authorizations as may be required for the rendition of the services contemplated herein, provided that Transporter reserves the right to file and prosecute applications for such authorizations, any supplements or amendments thereto and, if necessary, any court review, in such manner as it deems to be in its best interest, including the right to withdraw the application or to file pleadings and motions (including motions for dismissal). 6. This Agreement and the respective obligations of the parties hereunder are subject to all present and future valid laws, orders, rules and regulations of constituted authorities having jurisdiction over the parties, their functions or gas supply, this Agreement or any provision hereof. Neither party shall be held in default for failure to perform hereunder if such failure is due to compliance with laws, orders, rules or regulations of any such duly constituted authorities. 7. The subject headings of the articles of this Agreement are inserted for the purpose of convenient reference and are not intended to be a part of the Agreement nor considered in any interpretation of the same. 8. No presumption shall operate in favor of or against either party hereto as a result of any responsibility either party may have had for drafting this Agreement. 9. The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Pennsylvania, without recourse to the law regarding the conflict of laws. 10. Upon the date performance commences under this Agreement, the ESS Service Agreement dated June 23, 1994 (Agreement #36604) between Transporter and Shipper shall terminate. The parties hereto have caused this Agreement to be signed by their respective Presidents or Vice Presidents thereunto duly authorized and their respective corporate seals to be hereto affixed and attested by their respective Secretaries and Assistant Secretaries, the day and year first above written. NATIONAL FUEL GAS SUPPLY CORPORATION (Transporter) /s/ William A. Ross William A. Ross Vice President NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Shipper) /s/ Walter E. DeForest Walter E. DeForest Senior Vice President EX-10 6 SERVICE AGREEMENT (EFT Service) AGREEMENT made this 1st day of August, 1993, by and between NATIONAL FUEL GAS SUPPLY CORPORATION, a Pennsylvania corporation, hereinafter called "Transporter" and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter called "Shipper." WHEREAS, Shipper has requested that Transporter transport natural gas; and WHEREAS, Transporter has agreed to provide such transportation for Shipper subject to the terms and conditions hereof. WITNESSETH: That, in consideration of the mutual covenants herein contained, the parties hereto agree that Transporter will transport for Shipper, on a firm basis, and Shipper will furnish, or cause to be furnished, to Transporter natural gas for such transportation during the term hereof, at the prices and on the terms and conditions hereinafter provided. ARTICLE I Quantities Beginning on the date on which deliveries of gas are commenced hereunder and thereafter for the remaining term of this Agreement, and subject to the provisions of Transporter's EFT Rate Schedule, Transporter agrees to transport for Shipper's account up to the following quantities of natural gas: Contract Maximum Daily Transportation Quantity (MDTQ) of 1,148,648 Dekatherms (Dth) ARTICLE II Rate Unless otherwise mutually agreed in a written amendment to this Agreement, for each dekatherm of gas transported for Shipper by Transporter hereunder, Shipper shall pay Transporter the maximum rate provided under Rate Schedule EFT set forth in Transporter's effective FERC Gas Tariff. In the event that the Transporter places on file with the Federal Energy Regulatory Commission ("Commission") another rate schedule which may be applicable to transportation service rendered hereunder, then Transporter, at its option, may from and after the effective date of such rate schedule, utilize such rate schedule in performance of this Agreement. Such a rate schedule(s) or superseding rate schedule(s) and any revisions thereof which shall be filed and become effective shall apply to and be a part of this Agreement. Transporter shall have the right to propose, file and make effective with the Commission, or other body having jurisdiction, changes and revisions of any effective rate schedule(s), or to propose, file, and make effective superseding rate schedules, for the purpose of changing the rate, charges, and other provisions thereof effective as to Shipper. Shipper agrees to reimburse Transporter for the filing fees associated with this service and paid to the Commission. ARTICLE III Term of Agreement This Agreement shall be effective as of the effective date of the tariff sheets implementing the restructuring of Transporter's services in Docket No. RS92-21, and shall continue in effect until March 31, 2003, and shall continue in effect from year to year thereafter until terminated by either Shipper or Transporter upon twelve (12) months written notice to the other. ARTICLE IV Points of Receipt and Delivery The Point(s) of Receipt for all gas that may be received for Shipper's account for transportation by Transporter, and the receipt entitlements applicable to each point of receipt, or combinations of receipt points, are set forth in Appendix A. The Point(s) of Delivery for all gas to be delivered by Transporter for Shipper's account are set forth in Appendix B. ARTICLE V Incorporation By Reference of Tariff Provisions To the extent not inconsistent with the terms and conditions of this agreement, the provisions of Rate Schedule EFT, or any effective superseding rate schedule or otherwise applicable rate schedule, including any provisions of the General Terms and Conditions incorporated therein, and any revisions thereof that may be made effective hereafter are hereby made applicable to and a part hereof by reference. ARTICLE VI Cancellation of Prior Contracts If this Agreement becomes effective as an executed service agreement, it shall supersede and cancel all prior firm sales agreements between the parties, including but not limited to the Service Agreement dated November 1, 1974 between National Fuel Gas Distribution Corporation as Buyer and National Fuel Gas Supply Corporation as Seller, and the agreement dated October 3, 1952, between United Natural Gas Company and Mercer Gas Light and Fuel Company. ARTICLE VII Miscellaneous 1. No change, modification or alteration of this Agreement shall be or become effective until executed in writing by the parties hereto, and no course of dealing between the parties shall be construed to alter the terms hereof, except as expressly stated herein. 2. No waiver by any party of any one or more defaults by the other in the performance of any provisions of this Agreement shall operate or be construed as a waiver of any other default or defaults, whether of a like or of a different character. 3. Any company which shall succeed by purchase, merger or consolidation of the gas related properties, substantially as an entirety, of Transporter or of Shipper, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Agreement. Either party may, without relieving itself of its obligations under this Agreement, assign any of its rights hereunder to a company with which it is affiliated, but otherwise, no assignment of this Agreement or of any of the rights or obligations hereunder shall be made unless there first shall have been obtained the consent thereto in writing of the other party. Consent shall not be unreasonably withheld. 4. Except as herein otherwise provided, any notice, request, demand, statement or bill provided for in this Agreement, or any notice which either party may desire to give the other, shall be in writing and shall be considered as duly delivered when mailed by registered or certified mail to the Post Office address of the parties hereto, as the case may be, as follows: Transporter: National Fuel Gas Supply Corporation Gas Supply - Transportation Room 1200 10 Lafayette Square Buffalo, New York 14203 Shipper: National Fuel Gas Distribution Corporation 10 Lafayette Square Buffalo, New York 14203 or at such other address as either party shall designate by formal written notice. Routine communications, including monthly statements, shall be considered as duly delivered when mailed by either registered, certified, or ordinary mail, electronic communication, or telecommunication. 5. Transporter and Shipper shall proceed with due diligence to obtain such governmental and other regulatory authorizations as may be required for the rendition of the services contemplated herein, provided that Transporter reserves the right to file and prosecute applications for such authorizations, any supplements or amendments thereto and, if necessary, any court review, in such manner as it deems to be in its best interest, including the right to withdraw the application or to file pleadings and motions (including motions for dismissal). 6. This Agreement and the respective obligations of the parties hereunder are subject to all present and future valid laws, orders, rules and regulations of constituted authorities having jurisdiction over the parties, their functions or gas supply, this Agreement or any provision hereof. Neither party shall be held in default for failure to perform hereunder if such failure is due to compliance with laws, orders, rules or regulations of any such duly constituted authorities. 7. The subject headings of the articles of this Agreement are inserted for the purpose of convenient reference and are not intended to be a part of the Agreement nor considered in any interpretation of the same. 8. No presumption shall operate in favor of or against either party hereto as a result of any responsibility either party may have had for drafting this Agreement. 9. The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Pennsylvania, without recourse to the law regarding the conflict of laws. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their duly authorized personnel and attested by their respective Secretaries or Assistant Secretaries, the day any year first above written. NATIONAL FUEL GAS SUPPLY CORPORATION Transporter Attest: /s/ R. M. DiValerio By /s/ Richard Hare Secretary President (Corporate Seal) NATIONAL FUEL GAS DISTRIBUTION CORPORATION Shipper Attest: /s/ David F. Smith By /s/ P.C. Ackerman Secretary President (Corporate Seal) Appendix A to EFT Service Agreement Between NATIONAL FUEL GAS SUPPLY CORPORATION AND NATIONAL FUEL GAS DISTRIBUTION CORPORATION RECEIPT POINTS AND RECEIPT ENTITLEMENTS Appendix B to EFT Service Agreement Between NATIONAL FUEL GAS SUPPLY CORPORATION AND NATIONAL FUEL GAS DISTRIBUTION CORPORATION Appendix A is a list of about 2,000 receipt points including some information on each receipt point. Appendix B is a list of about 2,000 delivery points including some information on each delivery point. Both Appendices are omitted from this filing but are available from the Company on request. EX-10 7 AMENDMENT 5/1/95 TO SERVICE AGREEMENT (EFT Service) AGREEMENT made as of May 1, 1995, by and between NATIONAL FUEL GAS SUPPLY CORPORATION, a Pennsylvania corporation, hereinafter called "Transporter" and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter called "Shipper." WHEREAS, Transporter and Shipper are parties to a Service Agreement (EFT Service) dated August 1, 1993 (the "Agreement"); and WHEREAS, Transporter's effective FERC Gas Tariff provides that Shipper may request changes in the Primary Receipt Points under the Agreement, which changes shall be accomplished by amendment of the Agreement; and WHEREAS, Article II of the Agreement provides that Shipper shall pay Transporter the maximum rate provided under Rate Schedule EFT set forth in Transporter's effective FERC Gas Tariff, unless otherwise agreed in a written amendment to the Agreement; and WHEREAS, Transporter offered to its qualifying shippers a discounted rate for the quantity of gas which a shipper requested, within a window period which expired December 13, 1994, to allocate to the interconnection between the facilities of Transporter and the facilities of Empire State Pipeline at Grand Island, New York ("Grand Island") as a primary receipt point; and WHEREAS, Shipper within the window period accepted Transporter's offer to discount for a Maximum Daily Transportation Quantity under the Agreement ("MDTQ") of 12,812 Dth/day (the "Grand Island Quantity", subject to reduction as described in Section 2 below); and WHEREAS, Shipper and Transporter desire to amend the Agreement to provide for a different rate and different Primary Receipt Points as set forth below; WITNESSETH: That, in consideration of the mutual covenants herein contained, the parties hereto agree as follows: 1. The first three pages of Appendix A to the Agreement, which identify some of Shipper's Primary Receipt Points, are hereby deleted and replaced by the three pages contained in the attached Appendix A. 2. As of May 1, 1995, the discount described below (the "Discount") shall be effective. To the extent Shipper thereafter requests and receives a reduction of the portion of his MDTQ which is attributed to Grand Island as the primary receipt point, the Grand Island Quantity shall be reduced accordingly. 3. The Discount shall consist of : (a) first, to the extent permitted by then-current FERC order, a discount of any applicable Gas Research Institute surcharges; and then (b) second, the reduction of Shipper's Reservation Charge (which is a charge per month per Dth of MDTQ), such that the total amount of the Discount shall be one dollar and sixty-seven cents ($1.67) per month per Dth times the Grand Island Quantity. (c) The Discount shall consist of a reduction of the then-currently effective rate which would, absent the Discount, be charged to Shipper. If, for a month Shipper is charged a motioned-in rate subject to refund, Shipper shall thereafter receive a refund which takes into account the amount Shipper actually paid for that month, to place Shipper in the same position he would have been by computing the Discount with respect to the finally approved rate. (d) Transporter and Shipper agree not to seek before the FERC any change to the methodology for (i) calculating the rate applicable to quantities subject to the Discount (the "Discounted Rate") or (ii) allocating costs or imputing revenues to the service which is subject to the Discounted Rate (the "Discounted Service"), including the allocation of additional system costs to said rate and/or service. If FERC imputes different revenues and/or allocates different costs to the Discounted Service in future rate proceedings, the amount of the Discount shall be subject to decrease on a prospective basis from the date of the FERC order to fully reflect such changes. If any such rate proceeding results in a settlement which does not identify the applicable costs and revenues for the Discounted Service, but if the written litigation position of the FERC Staff does expressly identify such costs and revenues, such litigation position shall be the basis for the adjustment. 4. The Discount shall begin on May 1, 1995, and shall continue in effect so long as the Grand Island Quantity remains more than zero, but for no longer than the earlier to occur of: (a) the effective date of termination of the Agreement (for this purpose the Agreement shall not be considered as effectively terminated if it is renewed or rolled over into another service agreement); or (b) October 31, 2014. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their duly authorized personnel and attested by their respective Secretaries or Assistant Secretaries, as of the day and year first above written. NATIONAL FUEL GAS SUPPLY CORPORATION Transporter Attest: By /s/ Richard Hare - --------------------- ------------------------------ Secretary President (Corporate Seal) NATIONAL FUEL GAS DISTRIBUTION CORPORATION Shipper Attest: By /s/ Philip C. Ackerman - --------------------- ----------------------------- Secretary President (Corporate Seal) APPENDIX A Replacement Pages to Exhibit A
National Fuel Gas Supply Corporation Pipeline Receipt Points Available to National Fuel Gas Distribution Corporation Line Meter Name Meter Number Designation Township County State Columbia Gas Transmission Corporation Ellwood City 600065 N Franklin Beaver PA First Fork 632291 YM7 Grove Cameron PA Smethport 630202 D-6 Smethport McKean PA Sugar Grove 617733 R,U Franklin Warren PA Ward 622885 PY Ward Allegany NY Waterford 620549 Q Waterford Erie PA Wellsville Domestic Accounts 606000 Various Domestic Customers Wellsville Allegany NY CNG Transmission Corporation Allegany Domestic Accounts Q38000 Various Domestic Customers Amity Allegany NY Allegheny National Forest 51051 L Spring Creek Elk PA Belmont 60185 6" Amity Allegany NY Caledonia 60154 W/WM2 Caledonia Livingston NY Consolidated ( Horton ) 9871 ZW384 Horton Elk PA Donovan 60178 63 Wellsville Allegany NY East Emporium 601040 FM100 Wharton Potter PA Ellisburg Station 60288 YM54 Allegany Potter PA Ellisburg Storage NFSTG Storage Allegany Potter PA Eshbaugh 51052 C Limestone Clarion PA Johnsonburg 60047 3" Sheldon Wyoming NY Porterville 60051 Porterville Station Elma Erie NY Reef Well 602220 4" Fremont Steuben NY Sanford 60181 A,B,C Genesee Allegany NY Silver Springs 60049 8" Genesee Falls Wyoming NY West Wellsville 60179 67 Wellsville Allegany NY Wyoming 60050 V Perry Wyoming NY Tennessee Gas Pipeline Corporation Zone 5 points Clarence 2-0497 XM-2 Clarence Erie NY Colden Storage 6-0003 T Eden Erie NY East Aurora 2-0077 X Wales Erie NY Hamburg(E.Eden) 2-0076 T,X Eden Erie NY Lewiston 2-0092 8" Lewiston Niagara NY Mayville 2-0088 6" Chautauqua Chautauqua NY Nashville Storage 2-0243 RM-32 Hanover Chautauqua NY Pekin 2-0326 Z Lewiston Niagara NY Sherman 2-0428 4" Sherman Chautauqua NY Zone 4 points Cochranton 2-0314 S-M2 E. Fairfield Crawford PA Coudersport 2-0074 Y-M2 Hebron Potter PA Cranberry Sales 2-0703 H Cranberry Venango PA Hebron Storage 6-0001 Storage Hebron Potter PA Lamont 2-0072 K Highland Elk PA Mercer 2-0069 N-M44 Jefferson Mercer PA Pettis 2-0071 H-M2 Wayne Crawford PA Rose Lake 2-0527 Y-M2 Allegany Potter PA Russel City 2-0301 L Highland Elk PA Sharon 2-0496 N-M51 Pulaski Lawrence PA Townville 2-0390 4" Townville Crawford PA Union City 2-0200 Q Union Erie PA Wattsburg 2-0075 D-20 Wayne Erie PA East Aurora, NY ( Enserch ) East Aurora 2-0077 X Wales Erie NY Rate Schedule T - 1 Zone 5 points Clarence 2-0497 XM-2 Clarence Erie NY Colden Storage 6-0003 T Eden Erie NY East Aurora 2-0077 X Wales Erie NY Hamburg(E.Eden) 2-0076 T,X Eden Erie NY Zone 4 points Coudersport 2-0074 Y-M2 Hebron Potter PA Cranberry Sales 2-0703 H Cranberry Venango PA Lamont 2-0072 K Highland Elk PA Mercer 2-0069 N-M44 Jefferson Mercer PA Pettis 2-0071 H-M2 Wayne Crawford PA Wattsburg 2-0075 D-20 Wayne Erie PA Texas Eastern Transmission Corporation Bristoria 70015 N Rich Hill Greene PA Empire State Pipeline Grand Island 012003010 SUPPLY Grand Island Erie NY Transcontinental Gas Pipeline Corporation Wharton 6172 YM7 Wharton Potter PA
Receipt Entitlements National Fuel Gas Distribution Corporation ------------------------------------------ ( all Quantities in Dth ) Upstream Receipts Empire State Pipeline 40,122 CNG Transmission Corp. 150,107 Columbia Gas Transmission Corp. 26,165 Texas Eastern Transmission Corp. 72,652 TGP East Aurora, NY 16,300 Zone 4 Points 158,812 Zone 5 Points 82,119 Rate Schedule T-1 Points 30,750 Transcontinental Gas Pipe Line Corp. 26,332 Total Upstream Receipts 603,359 Appalachian Production New York Production Central 941 Lakeshore 297 Northern 297 PY3 644 Southeast 340 Pennsylvania Production Lines L & D 11736 Line Q Erie-Meadville 991 Clarion 248 Dubois 1981 Line Q Forest 594 Hebron 248 Elk County 1685 Eldred 1979 Lines M & N 22253 Lewis Run 2078 Sharon-Mercer 346 --- Total Appalachian Production 46,658 Deliveries from Storage 511,633 ------- Total Receipt Entitlements 1,161,650 =========
EX-10 8 SERVICE AGREEMENT THIS AGREEMENT entered into this first day of August, 1993, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller," first party, and National Fuel Gas Distribution Corporation, hereinafter referred to as "Buyer," second party, WITNESSETH WHEREAS, pursuant to the requirements of Order Nos. 636, 636-A and 636-B, issued by the Federal Energy Regulatory Commission, National Fuel Gas Supply Corporation ("National") has assigned to one of its customers upstream capacity previously provided under Seller's FT Rate Schedule Contract #0.3698; and WHEREAS, upon the effective date of this Agreement, the contractual arrangement between National and Seller is terminated and abandonment of service under the FT Rate Schedule Contract #0.3698 is automatically authorized; and WHEREAS, Buyer has been assigned all National's capacity previously provided under FT Rate Schedule Contract #0.3698, and agrees to such assignment and assumes National's obligations pursuant to the Service Agreement and Seller's FT Rate Schedule of Vol. 1 of its FERC Gas Tariff; and WHEREAS, Seller will provide service hereunder to Buyer pursuant to Seller's blanket certificate authorization and Rate Schedule FT for the assigned capacity designated hereinbelow. NOW, THEREFORE, Seller and Buyer agree as follows: ARTICLE I GAS TRANSPORTATION SERVICE 1. Subject to the terms and provisions of this agreement and of Seller Is Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity ("TCQ") of 25,442 Mcf per day. 2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Seller's FERC Gas Tariff. ARTICLE II POINT(S) OF RECEIPT Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline system at the varying pressures that may exist in such system from time to time; provided, however, the pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressures) of Seller's pipeline system at such point(s) of receipt. In the event the maximum operating pressure(s) of Seller's pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon SERVICE AGREEMENT (Continued) written notification of Seller to Buyer. The point (s) of receipt for natural gas received for transportation pursuant to this agreement shall be: See Exhibit A, attached hereto, for points of receipt. ARTICLE III POINT(S) OF DELIVERY Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point (s) of delivery and at a pressure (s) of: See Exhibit B, attached hereto, for points of delivery and pressures. ARTICLE IV TERM OF AGREEMENT This agreement shall be effective as of August 1, 1993 and shall remain in force and effect until 8:00 a.m. Eastern Standard Time October 31, 2004 and thereafter until terminated by Seller or Buyer upon at least three (3) years prior written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 8.3 of Seller's Rate Schedule FT. As set forth in Section 8 of Article II of Seller's August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et.al., (a) pregranted abandonment under Section 284.221(d) of the Commission's Regulations shall not apply to any long term conversions from firm sales service to transportation service under Seller's Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service. ARTICLE V RATE SCHEDULE AND PRICE 1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Seller's Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof. 2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Seller's Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff which relates to service under this agreement and which is incorporated herein. SERVICE AGREEMENT (Continued) 3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Seller' s Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyer's request for service under Seller's Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction. ARTICLE VI MISCELLANEOUS 1. This Agreement supersedes and cancels as of the effective date hereof the following contracts): National Fuel Gas Supply Corporation/Transcontinental Gas Pipe Line Corporation former FT Service Agreement Contract #0.3698, dated February 1, 1992. 2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character. 3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities. 4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns. 5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address: (a) If to Seller: Transcontinental Gas Pipe Line Corporation P. 0. Box 1396 Houston, Texas 77251 Attention: Customer Services, Northern Market Area (b) If to Buyer: National Fuel Gas Distribution Corporation 10 Lafayette Square Buffalo, NY 14203 Attention: Mr. Walter DeForest Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail. SERVICE AGREEMENT (Continued) IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized. TRANSCONTINENTAL GAS PIPE LINE CORPORATION (seller) By /s/ Thomas E. Skains Thomas E. Skains, Senior Vice President Transportation and Customer Services NATIONAL FUEL GAS DISTRIBUTION CORPORATION By /s/ S. Dennis Holbrook S. Dennis Holbrook, Vice President EXHIBIT "A" (FT) System Contract #.6487 Buyer's Cumulative Mainline Capacity Entitlement Point(s) of Receipt (Mcf/day)* 1. Suction Side of Seller's Compressor 4,325 station 30 at the Existing Point of Interconnection between Seller's Central Texas Lateral and Seller's Mainline at Wharton County, Texas. (Station 30 TP#7133) 2. Existing Point of Interconnection 4,325 between Seller and Valero Transmission company (Seller Meter No. 3396) at Wharton County, Texas. (Wharton Valero TP#6690) 3. Existing Point of Interconnection 4,325 between Seller and Meter named Spanish Camp (Seller Meter No. 3365) Wharton County, Texas. (Spanish Camp-Delhi TP#6895) 4. Existing Point of Interconnection 4,325 between Seller and Meter named Denton Cooley #1 (Seller Meter No. 3331), in Fort Bend County, Texas. (Denton Cooley #1 TP#1106) 5. Existing Point of Interconnection between 4,325 Seller and Meter named Randon East (Fulshear) (Seller Meter No. 1427), in Fort Bend County, Texas. (Randon East (Fulshear) TP#299) 6. Existing Point of Interconnection 4,325 between Seller and Meter named Katy- Enserch (Seller Meter No. 4259), in Fort Bend County, Texas. (Katy- Enserch TP#5518) 7. Existing Point of Interconnection 4,325 between Seller and Houston Pipeline Company (Seller Meter No. 3364) at Fulshear, Fort Bend County, Texas. (Fulshear-HPL TP#6097) Buyer's Cumulative Mainline Capacity Entitlement Point(s) of Receipt (Mcf/day)* 8. Existing Point of Interconnection between 4,325 Seller and Meter named White Oak Bayou- Exxon Gas System, Inc. (Seller Meter No. 3545), in Harris County, Texas. (White Oak Bayou-EGSI TP#1036) 9. Existing Point of Interconnection 4,325 between Seller and Houston Pipeline Company (Seller Meter No. 4359) at Bammel, Harris County, Texas. (Bammei-HPL TP#6014) 10. Existing Point of Interconnection 4,325 between Seller and Delhi Pipeline Company (Seller Meter No. 3346) at Hardin County, Texas. (Hardin-Delhi TP#6696) 11. Existing Point of Interconnection between 4,325 Seller and Meter named Vidor Field Junction (Seller Meter No. 3554), in Jasper County, Texas. (Vidor Field Junction TP#2337) 12. Existing Point of Interconnection between 4,325 Seller and Meter named Starks McConathy (Seller Meter No. 3535), in Calcasieu Parish, Louisiana. (Starks McConathy TP#7346) 13. Existing Point of Interconnection between 4,325 Seller and Meter named DeQuincy Intercon (Seller Meter No. 2698), in Calcasieu Parish, Louisiana. (DeQuincy Intercon TP#7035) 14. Existing Point of Interconnection between 4,325 Seller and Meter named DeQuincy Great Scott (Seller Meter No. 3357), in Calcasieu Parish, Louisiana. (DeQuincy Great Scott TP#6809) 15. Existing Point of Interconnection between 4,325 Seiler and Meter named Perkins-Phillips (Seller Meter No. 3532), in Calcasieu Parish, Louisiana. (Perkins-Phillips TP#7508) Buyer's Cumulative Mainline capacity Entitlement Point(s) of Receipt (Mcf/day)* 16. Existing Point of Interconnection between 4,325 seller and Meter named Perkins (Intercon) (Seller Meter No. 3395), in Calcasieu Parish, Louisiana. (Perkins (Intercon) TP#7036) 17. Existing Point of Interconnection between 4,325 seller and Meter named Perkins East (Seller Meter No. 2369), in Beauregard Parish, Louisiana. (Perkins East TP#139) 18. Discharge Side of Seller's Compressor 10,686 station 45 at the Existing point of Interconnection between Seller's Southwest Louisiana Lateral and Seller's Mainline Beauregard Parish, Louisiana. (Station 45 TP#7101) 19. Existing Point of Interconnection between 10,686 Seller and Texas Eastern Transmission Corporation. (Seller Meter No. 4198) at Ragley, Beauregard Parish, Louisiana. (Ragley-TET TP#6217) 20. Existing Point of Interconnection between 10,686 Seller and Trunkline Gas Company (Seller Meter No. 4215) at Racjley, Beauregard Parish, Louisiana. (Ragley-Trunkline TP#6218) 21. Existing Point of Interconnection between 10,686 Seller and Tennessee Gas Transmission Company (Seller Meter No. 3371) at Kinder, Allen Parish, Louisiana. (Kinder-TGT TP#6149)** 22. Existing Point of Interconnection between 10,686 Seller and Texas Gas Transmission Corporation (Seller Meter Nos. 3227, 4314, 4457) at Eunice, Evangeline Parish, Louisiana. (Eunice Mamou Tx Gas TP#6923) 23. Suction Side of Seller's Compressor Station 50 15,520 at the Existing Point of Interconnection between Seller's Central Louisiana Lateral and Seller's Mainline Evangeline Parish, Louisiana. (Station 50 TP#6948) Buyer's Cumulative Mainline Capacity Entitlement Point(s) of Receipt (Mcf/day)* 24. Existing Point of Interconnection between 15,520 Seller and Columbia Gulf Transmission Corporation (Seller Meter No. 3142) at Eunice, Evangeline Parish, Louisiana. (Eunice Evangeline Col. Gulf TP#6414) 25. Discharge Side of Seller's Compressor 15,520 Station 54 at Seller's Washington Storage Field, St. Landry Parish, Louisiana. (Station 54 TP#6768) 26. Existing Point of Interconnection between 15,520 Seller and Acadian Pipeline (Seller Meter No. 3506) in Pointe Coupee Parish, Louisiana. (Morganza-Acadian Pipeline TP#7060) 27. Existing Point of Interconnection (Seller 15,520 Meter No. 3272) at M.P. 566.92, Morganza Field, Pointe Coupee Parish, Louisiana. (Morganza Field TP#576) 28. Existing Point of Interconnection between Seller 15,520 and Meter named West Feliciana Parish-Creole (Seller Meter No. 4464), in West Feliciana Parish, Louisiana. (West Feliciana Parish-Creole TP#7165) 29. Existing Point of Interconnection between Seller 15,520 and Mid-Louisiana Gas Company (Seller Meter Nos. 4137, 4184, 3229) at Ethei, East Feliciana Parish, Louisiana. (Ethel-Mid LA TP#6083) 30. Existing Point of Interconnection between Seller 15,520 and Meter named Liverpool Northwest (Seller Meter No. 3390), in St. Helena Parish, Louisiana. (Liverpool Northwest TP#6757) 31. Suction Side of Seller's Compressor Station 62 on 9,922 Seller's Southeast Louisiana Lateral in Terrabonne Parish, Louisiana. (Station 62 TP#7141) 32. Existing Point of Interconnection between Seller 9,922 and Meter named Terrebonne - LIG in Terrebonne Parish, Louisiana.(Terrebonne-LIG TP#4123) Buyer's Cumulative Mainline capacity Entitlement Point(s) of Receipt (Mcf/day)* 33. Existing Point of Interconnection between Seller 9,922 and Meter named Texas Gas - TLIPCO - Thibodeaux (Seller Meter No. 3533), in Lafourche Parish, Louisiana. (TXGT-TLIPCO-Thibodeaux TP#7206) 34. Existing Point of Interconnection between 9,922 Seller and Meter named Romeville-Monterey Pipeline (Seller Meter No. 4410), in St. James Parish, Louisiana. (Romeville-Monterey Pipeline TP#580) 35. Existing Point of Interconnection between 9,922 Seller and Meter named St. James CCIPC (Seller Meter No. 4462), in St. James Parish, Louisiana. (St. James CCIPC TP#7164)** 36. Existing Point of Interconnection between 9,922 Seller and Meter named St. James Faustina- (St. Amelia) (Seller Meter No. 3328), in St. James Parish, Louisiana. (St. James Faustina (St. Amelia) TP#6268)** 37. Existing Point of Interconnection between 9,922 Seller and Meter named St. James Acadian (Seller Meter No. 4366), in St. James Parish, Louisiana. (St. James Acadian TP#6677)** 38. Existing Point of Interconnection between 9,922 Seller and Meter named Livingston-Flare (Seller Meter No. 3540), in Livingston Parish, Louisiana. (Livingston-Flare TP#8739) 39. Existing Point of Interconnection between 9,922 Seller and Florida Gas Transmission Company (Seller Meter No. 3217) at St. Helena, St. Helena Parish, Louisiana. (St. Helena FGT TP#6267) 40. Existing Point of Interconnection between 9,922 Seller and Meter named Beaver Dam Creek (Seller Meter No. 3536), in St. Helena Parish, Louisiana. (Beaver Dam Creek TP#8218) 41. Suction Side of Seller's Compressor Station 25,442 65 at the Existing Point of Interconnection between Seller's Southeast Louisiana Lateral and Seller's Mainline St. Helena Parish, Louisiana. (Station 65 TP#6685) Buyer's Cumulative Mainline capacity Entitlement Point(s) of Receipt (Mcf/day)* 42. Existing Point of Interconnection between 25,442 Seller and Meter named Amite County/Koch (Seller Meter No. 3332), in Amite County, Mississippi. (Amite County/Koch TP#6701) 43. Existing Point of Interconnection between 25,442 Seller and Meter named McComb (Seller Meter No. 3461), in Pike County, Mississippi. (McComb TP#6446) 44. Existing Point of Interconnection between 25,442 Seller and United Gas Pipeline Company at Holmesville (Seller Meter No. 3150), Pike County, Mississippi. (Holmesville-United TP#6128) 45. Discharge Side of Seiler's Compressor Station 25,442 70 at M.P. 661.77 in Walthall County, Mississippi. (M.P. 661.77-Station 70 Discharge TP#7142) 46. Existing Point of Interconnection between 25,442 Seller and United Gas Pipeline Company at Walthall (Seller Meter No. 3095), Walthall County, Mississippi. (Walthall-UGPL TP#6310) 47. Existing Point of Interconnection between 25,442 Seller and Meter named Darbun-Pruett 34-10 (Seller Meter No. 3446) at M.P. 668.46 on Seller's Main Transmission Line, Darbun Field, Walthall County, Mississippi. (Darbun-Pruett TP#6750) 48. Existing Point of Interconnection between 25,442 Seller and Meter named Ivy Newsome (Seller Meter No. 3413) in Marion County, Mississippi. (Ivy Newsome TP#6179) 49. Existing Point of Interconnection between 25,442 Seller and West Oakvale Field at M.P. 680.47- Marion County, Mississippi. (M.P. 680.47-West Oakvale Field TP#7144) Buyer's Cumulative Mainline Capacity Entitlement Point(s) of Receipt (Mcf/day)* 50. Existing Point of Interconnection between 25,442 Seiler and East Morgantown Field at M.P. 680.47 in Marion County, Mississippi. (M.P. 680.47-East Morgantown Field TP#7145) 51. Existing Point of Interconnection between 25,442 Seller and Greens Creek Field, at M.P. 681.84 Marion County, Mississippi. (M.P. 681.84 Greens Creek Field TP#7146) 52. Existing Point of Interconnection between 25,442 Seller and Meter named M.P. 685.00-Oakvale Unit 6-6 in Jefferson Davis County, Mississippi. (M.P. 685.00-Oakvale Unit 6-6 TP#1376) 53. Existing Point of Interconnection between 25,442 Seller and Meter named M.P. 687.23-Oakvale Field in Marion County, Mississippi. (M.P. 687.23-Oakvale Field TP#7147) 54. Existing Point of Interconnection between 25,442 Seller and Bassfield at named M.P. 696.40 in Marion County, Mississippi. (M.P. 696.40 Bassfield TP#9439) 55. Existing Point of Interconnection between 25,442 Seller and Meter named Lithium/Holiday Creek -Frm (Seller Meter No. 3418), in Jefferson Davis County, Mississippi. (Lithium/Holiday Creek-Frm TP#7041) 56. Existing Point of Interconnection between 25,442 Seller and S.W. Sumrall Field and Holiday Creek at M.P. 692.05-Holiday Creek in Jefferson Davis, Mississippi. (M.P. 692.05-Holiday Creek TP#7159) 57. Existing Point of Interconnection between 25,442 Seller and ANR Pipe Line Company at Holiday Creek (Seller Meter No. 3241), Jefferson Davis County, Mississippi. (Holiday Creek-ANR TP#398) Buyer's Cumulative Mainline Capacity Entitlement Point(s) of Receipt (Mcf/day)* 58. Existing Point of Interconnection between 25,442 Seller and Mississippi Fuel Company at Jeff Davis (Seller Meter No. 3252), Jefferson Davis County, Mississippi. (Jefferson Davis County-Miss Fuels TP#6579) 59. Existing Point of Interconnection between 25,442 Seller and Meter named Jefferson Davis-Frm (Seller Meter No. 4420), in Jefferson Davis County, Mississippi. (Jefferson Davis-Frm TP#7033) 60. Existing Point of Interconnection between 25,442 Seller and Carson Dome Field M.P. 696.41, in Jefferson Davis County, Mississippi. (M.P. 696.41-Carson Dome Field TP#7148) 61. Existing Point of Interconnection between 25,442 Seller and Meter Station named Bassfield-ANR Company at M.P. 703.17 on Seller's Main Transmission Line (Seller Meter No. 3238), Covington County, Mississippi. (Bassfield-ANR TP#7029) 62. Existing Point of Interconnection between 25,442 Seller and Meter named Patti Bihm #1 (Seller Meter No. 3468), in Covington County, Mississippi. (Patti Bihm #1TP#7629) 63. Discharge Side of Seller's Compressor at 25,442 Seller's Eminence Storage Field (Seller Meter No. 4166 and 3160) at Covington County, Mississippi. (Eminence Storage TP#5561) 64. Existing Point of Interconnection between 25,442 Seller and Dont Dome Field at M.P. 713.39 in Covington County, Mississippi. (M.P. 713.39-Dont Dome TP#1396) 65. Existing Point of Interconnection between 25,442 Seller and Endevco in Covington County, Mississippi. (Hattiesburg-Interconnect Storage TP#1686) Buyer's Cumulative Mainline Capacity Entitlement Point(s) of Receipt (Mcf/day)* 66. Existing Point at M.P. 719.58 on Seller's 25,442 Main Transmission Line (Seller Meter No. 3544), Centerville, Dome Field, Jones County, Mississippi. (Centerville Dome Field TP#1532) 67. Existing Point of Interconnection between 25,442 Seller and Meter named Calhoun (Seller Meter No. 3404), in Jones County, Mississippi. (Calhoun TP#378) 68. Existing Point at M.P. 727.78 on Seller's 25,442 Main Transmission Line, Jones County, Mississippi. (Jones County-Gitano TP#7166) 69. Existing Point of Interconnection between 25,442 Seller and a Meter named Koch Reedy Creek (Seller Meter No. 3333), Jones County, Mississippi. (Reedy Creek-Koch TP#670) 70. Existing Point of Interconnection between 25,442 Seller and Meter named Sharon Field (Seller Meter No. 3000), in Jones County, Mississippi. (Sharon Field TP#419) 71. Existing Point of Interconnection between 25,442 Seller and Tennessee Gas Transmission Company at Heidelberg (Seller Meter No. 3109), Jasper County, Mississippi. (Heidelberg-Tennessee TP#6120) 72. Existing Point of Interconnection between 25,442 Seller and Mississippi Fuel Company at Clarke (Seller Meter No. 3254), Clarke County, Mississippi. (Clarke County-Miss Fuels TP#6047) 73. Existing Point of Interconnection between 25,442 Seller and Meter named Clarke County-Koch at M.P. 757.29 in Clarke County, Mississippi. (Clarke County-Koch TP#5566) Buyer's Cumulative Mainline Capacity Entitlement Point(s) of Receipt (Mcf/day)* 74. Existing Point of Interconnection 25,442 between Seiler's mainline and Mobil Bay Lateral at M.P. 784.66 in Choctaw County, Alabama. (Station 85-Mainline Pool TP#6971) 75. Existing Point of Interconnection between 25,442 Seller and Magnolia Pipeline in Chilton County, Alabama.(Magnolia Pipeline-Interconnect TP#1808) 76. Existing Point of Interconnection between 25,442 Seller and Southern Natural Gas Company, (Seller Meter No. 4087) at Jonesboro, Clayton County, Georgia. (Jonesboro-SNG TP#6141) 77. Existing Point of Interconnection between 25,442 Seller and Columbia Gas Transmission (Seller Meter No. 7157) at Dranesville, Fairfax County, Virginia.(Dranesville-Colgas TP#6068)** 78. Existing Point of Interconnection between 25,442 Seller and Columbia Gas Transmission (Seller Meter No. 4080) at Rockville, Baltimore County, Maryland.(Rockville-Colgas TP#6227)** 79. Existing Point of Interconnection between 25,442 Seller and Columbia Gas Transmission (Seller Meter No. 3088) at Downington, Chester County, Pennsylvania.(Downington-Colgas TP#6067)** 80. Existing Point of Interconnection between 25,442 Seller and Texas Eastern Transmission Corporation (Seller Meter No. 4233) at Skippack, Montgomery County, Pennsylvania. (Skippack-TET TP#6249) Buyer shall not tender, without the prior consent of Seller, at any point(s) of receipt on any day a quantity in excess of the applicable Buyer's Cumulative Mainline Capacity Entitlement for such point(s) of receipt. * These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. ** Receipt of gas by displacement only. Exhibit B 1. Seller's Eminence Storage Field, Prevailing pressure in Covington County, Mississippi. Seller's pipeline system not to exceed maximum allowable operating pressure. 2. Existing points of interconnection Not less than the available Between Buyer and Seller near pipeline pressure on Wharton, Pennsylvania.** Seller's transmission system at the points of delivery to Buyer. 3. Existing points of interconnection Not less than the available between Buyer and Seller at Leidy pipeline pressure on Clinton, Pennsylvania.* Seller's transmission system at the points of delivery to Buyer. *Receipt of gas by displacement only. **Including Wharton Storage. EX-10 9 SERVICE AGREEMENT THIS AGREEMENT entered into this first, day of October, 1993, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller," first party, and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter referred to as "Buyer," second party, WITNESSETH WHEREAS, pursuant to the requirements of Order Nos. 636, 636-A and 636-B, issued by the Federal Energy Regulatory Commission, Consolidated Natural Gas Transmission Corporation ("CNG") has assigned to several of its customers upstream capacity previously provided under Seller's FT Rate Schedule Service Agreement #.6156; and WHEREAS, upon the effective date of this agreement, the contractual arrangement between CNG and Seller is terminated and abandonment of service under the FT Rate Schedule Service Agreement #.6156 is automatically authorized; and WHEREAS, Buyer has been assigned a portion of CNG's capacity previously provided under FT Rate Schedule Service Agreement #.6156, and agrees to such assignment and assumes, in part, CNG's obligations pursuant to the Service Agreement and Seller's FT Rate Schedule of Vol. I of its FERC Gas Tariff; and WHEREAS, Seller will provide service hereunder to Buyer pursuant to Seller's blanket certificate authorization and Rate Schedule FT for the assigned capacity designated hereinbelow. NOW, THEREFORE, Seller and Buyer agree as follows: ARTICLE I GAS TRANSPORTATION SERVICE 1. Subject to the terms and provisions of this agreement and of Seller's Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm Basis, up to the dekatherm equivalent of a Transportation Contract Quantity ("TCQ") of 11,390 Mcf per day. 2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Seller's FERC Gas Tariff. ARTICLE II POINT(S) OF RECEIPT Buyer shall deliver or cause to be delivered gas at the points of receipt hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline system at the varying pressures that may exist in such system from time to time; provided, however, the pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressures of Seller's pipeline system at such point(s) of receipt. In the event the maximum operating pressures of Seller's pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon SERVICE AGREEMENT (Continued) written notification of Seller to Buyer. The point (s) of receipt for natural gas received for transportation pursuant to this agreement shall be: See Exhibit A, attached hereto, for points of receipt. ARTICLE III POINT(S) OF DELIVERY Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressures) of: See Exhibit B, attached hereto, for points of delivery and pressures. ARTICLE IV TERM OF AGREEMENT This agreement shall be effective as of October 1, 1993 and shall remain in force and effect until 8:00 a.m. Eastern Standard Time October 31, 2012 and thereafter until terminated by Seller or Buyer upon at least one year prior written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 8.3 of Seller's Rate Schedule FT. As set forth in Section 8 of Article II of Seller's August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et.al., (a) pregranted abandonment under Section 284.221(d) of the Commission's Regulations shall not apply to any long term conversions from firm sales service to transportation service under Seller's Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service. ARTICLE V RATE SCHEDULE AND PRICE 1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Seller's Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof. 2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Seller's Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. I of this Tariff which relates to service under this agreement and which is incorporated herein. SERVICE AGREEMENT (Continued) 3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyer's request for service under Seller's Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction. ARTICLE VI MISCELLANEOUS 1. This agreement supersedes and cancels as of the effective date hereof the following contract(s): Consolidated Natural Gas Transmission Corporation and Transcontinental Gas Pipe Line Corporation former FT Service Agreement #.6156, dated November 1, 1992. 2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character. 3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities. 4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns. 5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address: (a) If to Seller: Transcontinental Gas Pipe Line Corporation P. 0. Box 1396 Houston, Texas 77251 Attention: Customer Services, Northern Market Area (b) If to Buyer: National Fuel Gas Distribution Corporation 1O Lafayette Square Buffalo, NY 14203 Attention: Mr. S. Dennis Holbrook Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail. SERVICE AGREEMENT (Continued) IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized. TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Seller) By /s/ Thomas E. Skains Thomas E. Skains, Senior Vice President Transportation and Customer Services NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Buyer) By /s/ Philip C. Ackerman Philip C. Ackerman, ExecuTive Vice President EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 1. Existing Point of Interconnection 11,144 between Seller's Central Louisiana and UTOS (Seller's Meter No. 3500) in Cameron Parish, Louisiana. (UTOS-TGPL Meter-TP#6402) 2. Existing Point of Interconnection 11,144 between Seller and Florida Gas Transmission at Vinton (Seller Meter No. 4381) in Calcasieu Parish, Louisiana. (Vinton-FGT-TP #6304)** 3. Existing Point of Interconnection 11,144 between Seller and Fina at Vinton (Seller Meter No. 2778) in Calcasieu Parish, Louisiana. (Vinton-Fina TP#927)** 4. Existing Point of Interconnection 11,144 between Seller and United Gas Pipe Line at Vinton (Seller Meter No. 4348) in Calcasieu Parish, Louisiana. (Vinton-UGPL (Starks) TP#6306)** 5. Existing Point of Interconnection 11,144 between Seller and Tennessee Gas Transmission at Vinton (Seller Meter No. 4374) in Calcasieu Parish, Louisiana. (Vinton-TGT (Starks) TP#6349) * * 6. Existing Point of Interconnection 11,144 between Seller and Meter named Starks McConathy (Seller Meter No. 3535) in Calsasieu Parish, Louisiana. ( Starks McConathy-TP-#6349) 7. Existing Point of Interconnection 11,144 between Seller and Meter named DeQuincy Intercon (Seller Meter No. 2698) in Calcasieu Parish, Louisiana. (DeQuincy Intercon-TP#7O35) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 8. Existing Point of Interconnection 11,144 between Seller and Meter named De Quincy Great Scott (Seller Meter No. 3357) in Calcasieu Parish, Louisiana. (DeQuincy Great Scott-TP#6809) 9. Existing Point of Interconnection 11,144 between Seller and Meter named Perkins-Phillips (Seller Meter No. 3532) in Calcasieu Parish, Louisiana. (Perkins-Phillips-TP#7508) 10. Existing Point of Interconnection 11,144 between Seller and Meter named Perkins (Intercon) (Seller Meter No. 3395) in Calcasieu Parish, Louisiana. (Perkins(Intercon) TP#7036) 11. Existing Point of Interconnection 11,144 between Seller and Meter named Perkins East (Seller Meter No. 2369) in Beauregard Parish, Louisiana. (Perkins - East TP#139) 12. Discharge Side of Seller's 11,144 Compressor Station 45 at the existing point of Interconnection between Seller's South west Louisiana Lateral and Seller's Mainline Beauregard Parish, Louisiana. (Station 45 TP#7101) 13. Existing Point of Interconnection 11,390 between Seller and Texas Eastern Transmission Corporation, (Seller Meter No. 4198) in Ragley, Beauregard Parish, Louisiana. (Ragley-TET TP#6217) 14. Existing Point of Interconnection 11,390 between Seller and Trunkline Gas Company (Seller Meter No. 4215) in Ragley, Beauregard Parish, Louisiana. (Ragley-Trunkline TP#6218) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 15. Existing Point of Interconnection 11,390 between Seller and Tennessee Gas Transmission Company (Seller Meter No. 3371) in Kinder, Allen Parish, Louisiana. (Kinder TET-TP#6149) 16. Existing Point of Interconnection 11,390 between Seller and Texas Gas Transmission Corporation (Seller Meter No.3227,4314,4457) in Eunice, Evangeline Parish, Louisiana. (Eunice Mamou Tx Gas TP#6923) 17. Existing Point of Interconnection 11,390 between Seller and Meter named Fenris, East (Seller Meter No. 2394) in Evangeline Parish, Louisiana. (Fenris East TP#159) 18. Existing Point of Interconnection 159 between Seller and Vermilion Block 16 (Seller Meter No. 4477) in Offshore Louisiana. (Vermilion Block 16 TP#53) 19. Existing Point of Interconnection 159 between Seller and Meter named Pecan Island (Seller Meter No. 2716) in Vermilion Parish, Louisiana. (Pecan-Island TP#6924) 20. Existing point of Interconnection 748 between Seller and Cow Island Gas Processing Plant in Vermilion Parish, Louisiana. (Cow Island Plant TP#6511) 21. Existing Point of Interconnection 748 between Seller and Meter named Kaplan-Sabine in Vermilion Parish, Louisiana. (Kaplan-Sabine TP#6388) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 22. Existing Point of Interconnection 748 between Seller and Meter named LeLeux-Fla Exploration (Seller Meter No. 3293) in Vermilion Parish, Louisiana. (Leleux-Fla Exploration-TP#169) 23. Existing Point of Interconnection 748 between Seller and Tennessee Gas Transmission at Crowley (Seller Meter No. 3222) in Acadia Parish, Louisiana. (Crowley-TGT TP#6058) 24. Existing Point of Interconnection 9,074 between Seller and Meter named Egan-C Con Gas Con Gas/Col Gulf (Seller Meter No. 3168) in Acadia Parish, Louisiana. (Egan-C Con Gas/Col Gul-TP#6076) 25. Existing Point of Interconnection 9,822 between Seller and Texas Gas Transmission at Ritchie South (Seller Meter No. 3517) in Acadia Parish, Louisiana. (Ritchie South-TXG TP#7330) 26. Existing Point of Interconnection 9,822 between Seller and ANR at Eunice (Seller Meter No. 3136 and No. 4136) in Acadia Parish, Louisiana. (Eunice - ANR TP#6085) 27. Suction side of Seller's Compressor 11,390 Station 50 at the Existing Point of Interconnection between Seller's Central Louisiana Lateral and Seller's Mainline Evangeline Parish, Louisiana. (Station 50 TP#6948) 28. Existing Point of Interconnection 11,390 between Seller and Columbia Gulf Transmission Corporation (Seller Meter No. 3142) in Eunice, Evangeline Parish. (Eunice-Evangeline Col. Gulf TP#6414) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 29. Existing Point of Interconnection 11,390 between Seller and Acadian Pipeline (Seller Meter No. 3506) in Pointe Coupee Parish, Louisiana. (Morganza - Acadian TP#7060) 30. Existing Point of Interconnection 11,390 (Seller Meter No. 3272) at M.P. 566.92, Morganza Field, Pointe Coupee Parish, Louisiana. (Morganza Field-TP#576) 31. Existing Point of Interconnection 11,390 between Seller and Meter named West Feliciana Parish-Creole (Seller Meter No. 4464) in West Feliciana Parish Louisiana. (West Feliciana Parish-Creole TP#7165) 32. Existing Point of Interconnection 11,390 between Seller and Mid-Louisiana Gas Company (Seller Meter Nos. 4137,4184 3229) in Ethel, Feliciana Parish, Louisiana. (Ethel-Mid LA TP#6083) 33. Existing Point of Interconnection 955 between Seller and Eugene Island Block. 205 (Seller Meter Nos. 2498 and 2535) Offshore Louisiana. (Eugene Island Block 205 - TP# 9) 34. Existing Point of Interconnection 955 between Seller and Eugene Island Block 195, Offshore Louisiana. (Eugene Island Block 195-TP#2884) 35. Existing Point of Interconnection 955 between Seller and Eugene Island Block 126 Mobil, (Seller Meter No. 4229) Offshore Louisiana. (Eugene Island Block 128 Mobil TP-#6788) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 36. Existing Point of Interconnection 955 between Seller and Eugene Island Block 79 Interconnect (Sellers Meter No. 3380) Offshore Louisiana. (Eugene Island Block 79 Interconnect TP# 6893) 37. Existing Point of Interconnection 955 between Seller and Meter named Mosquito Bay-Peltex (Seller Meter No. 2659) in Terrebonne Parish, Louisiana. (Mosquito Bay Peltex TP#207) 38. Existing Point of Interconnection 955 between Seller and Meter named Bayou Penchant (Seller Meter No. 2631) in Terrebonne Parish, Louisiana. (Bayou Penchant TP#6650) 39. Existing Point of Interconnection 955 between Seller and Meter named Bayou Piquant (Seller Meter No. 2191) in Terrebone Parish, Louisiana. (Bayou Puquant TP#506) 40. Existing Point of Interconnection 4,776 between Seller and Ship Shoal Block 222/224 (Seller Meter Nos. 2492,2555 2575) Offshore Louisiana. (Ship Shoal Block 222/224-TP#42) 41. Existing Point of Interconnection 4,776 between Sellers and Ship Shoal Block 190 Junction, Offshore Louisiana. (Ship Shoal Block 190 Junction - TP #991 42. Existing Point of Interconnection 5,763 between Seller and Ship Shoal Block 185 (186), (Seller Meter No. 2529) offshore Louisiana. (Ship Shoal Block 185 (186)-TP#6925) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 43. Existing Point of Interconnection 5,763 between Seller and Ship Shoal Block 70 Junction, Offshore Louisiana. (Ship Shoal Block 70 JunctionTP#6242) 44. Existing Point of Interconnection 5,763 between Seller and Meter named Lake Decade East-Tenneco (Seller Meter No. 2686 and No. 3528) in Terrebonne Parish, Louisiana. (Lake Decade East-Tenneco TP#6843) 45. Existing Point of Interconnection 5,763 between Seller and Meter named Lake Hatch (Seller Meter No. 3291) in Terrebonne Parish, Louisiana. (Lake Hatch TP#569) 46. Suction side of Seller's Compressor 6,718 Station 62 on Seller's Southeast Louisiana Lateral in Terrebonne Parish, Louisiana. (Station 62 TP#7141) 47. Existing Point of Interconnection 6,718 between Seller and Meter named Terrebonne - LIG in Terrebonne Parish, Louisiana. (Terrebonne - LIG TP#4123 48. Existing Point of Interconnection 6,718 between Seller and United Gas Pipe Line at Gibson, (Seller Meter No. 3156) in Terrebonne Parish, Louisiana. (Gibson-UGPL TP#6101) 49. Existing Point of Interconnection 6,718 between Seller and Louisiana Interstate at Hebert (Seller Meter No. 4368) in Terrebonne Parish, Louisiana. (Hebert-Lig TP#6392) 50. Existing Point of Interconnection 6,718 between Seller and Meter named Texas Gas-TLIPCO Thibodeaux (Seller Meter No. 3533) in Lafourche Parish, Louisiana. (TXGT-TLIPCO-Thibodeaux P#7206) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 51. Existing Point of Interconnection 6,718 between Seller and Meter named St. James CCIPC (Seller Meter No. 4462) in St James Parish, Louisiana. (St. James CCPIC TP# 7164)** 52. Existing Point of Interconnection 6,718 between Seller and Meter named St. James Faustina (St. Amelia)(Seller No. 3328) in St. James Parish, Louisiana. (St. James Faustina (St. Amelia)TP#6268)** 53. Existing Point of Interconnection 6,718 between Seller and Meter named St James Acadian (Seller Meter No. 4366) in St. James Parish, Louisiana. (St. James Acadian-TP#6677)** 54. Existing Point of Interconnection 6,718 between Seller and Meter named Romeville Monterey Pipeline (Seller Meter No. 4410) in St James Parish, Louisiana. (Romeville Monterey Pipeline-TP#580) 55. Existing Point of Interconnection 6,718 between Seller and Meter named Livingston Flare (Seller Meter No. 3450) in Livingston Parish, Louisiana. (Livingston-Flare-TP#8739) 56. Existing Point of Interconnection 6,718 between Seller and Florida Gas Transmission Company (Seller Meter No. 3217 and No. 4305) in St. Helena, St. Helena Parish, Louisiana. (St. Helena FGT-TP#6267) 57. Existing Point of interconnection 6,718 between Seller and Meter named Beaver Dam Creek (Seller Meter No. 3536) in St. Helena Parish, Louisiana. (Beaver Dam Creek TP#8218) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 58. Existing Point of Interconnection 6,718 between seller and Meter named Liverpool Northwest (Seller Meter No. 3390) in St. Helena Parish, Louisiana. (Liverpool Northwest-TP#6757) 59. Suction side of Seller's 11,390 compressor Station 65 at the Existing Point of Interconnection between Seller's Southeast Louisiana Lateral and Seller's Mainline St. Helena Parish, Louisiana. (Station 65 TP#6685) 60. Existing Point of Interconnection 11,390 between Seller and Meter named Amite County/Koch (Seller Meter No. 3332) in Amite County, Mississippi. (Amite County Koch-TP#6701) 61. Existing Point of Interconnection 11,390 between Seller and Meter named McComb (Seller Meter No. 3461) in Pike County, Mississippi. (McComb TP#6446) 62. Existing Point of Interconnection 11,390 between Seller and United Gas Pipe Line company at Holmesville (Seller Meter no. 3150) Pike County, Mississippi. (Holmesville-United TP#6128) 63. Discharge Side of Seller's 11,390 Compressor Station 70 at M.P. 661.77 in Walthall County, Mississippi. (M.P. 661.77Station 70 Discharge TP#7142) 64. Existing Point of Interconnection 11,390 between Seller and United Gas Pipeline Company A Walthall (Seller Meter No. 3095) in Walthall County, Mississippi. (Walthall - UGPL TP#-6310) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 65. Existing Point of Interconnection 11,390 between Seller and Meter named Darbun- Pruett 34-10 (Seller Meter No. 3446) at M.P. 668.46 on Seller's Main Transmission Line, Darbun Field, Walthall County, Mississippi. (Darbun Pruett TP#6750) 66. Existing Point of Interconnection 11,390 between Seller and Meter named Ivy Newsome (Seller Meter No. 3413) in Marion County, Mississippi. (Ivy Newsome-TP#6179) 67. Existing Point of Interconnection 11,390 between Seller and West Oakvale Field at M.P. 680.47 Marion County, Mississippi.(M.P. 680.47-West Oakvale Field-TP#7144) 68. Existing Point of Interconnection 11,390 between Seller and East Morgantown Field at M.P. 680.47 in Marion county, Mississippi. (M.P. 680.47 E. Morgantown Field-TP#7145) 69. Existing Point of Interconnection 11,390 between Seller and Greens Creek Field, at M.P. 681.84 Marion County, Mississippi. (M.P. 681.84 Greens Creek Field TP-#7l46) 70. Existing Point of Interconnection 11,390 between Seller and Meter named M.P. 685.00-Oakville Unit 6-6 in Jefferson Davis County, Mississippi. (M.P. 685. 00 Oakville Unit 6-6 T.P.#1376) 71. Existing Point of Interconnection 11,390 between Seller and Meter named M.P. 687.23 Oakvale Field in Marion County, Mississippi. (M.P. 687.23 Oakvale Field TP#7l47) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 72. Existing Point of Interconnection 11,390 between Seller and Bassfield at named M.P. 696.40 in Marion County, Mississippi. (M.P. 696.40 Bassfield- TP#9439) 73. Existing Point of Interconnection 11,390 between Seller and Meter named Lithium- Holiday Creel:-Frm (Seller Meter No. 3418) in Jefferson Davis County, Mississippi. (Lithium Holiday Creek-Frm-TP#7041) 74. Existing Point of Interconnection 11,390 between Seller and S. W. Sumrall Field and Holiday creek at M.P. 692. 05-Holiday Creek in Jefferson Davis County, Mississippi. (M.P. 692.05 Holiday Creek TP#7159) 75. Existing Point of Interconnection 11,390 between Seller and ANR Pipe Line Company at Holiday Creek (Seller Meter No. 3241) Jefferson Davis County, Mississippi. (Holiday Creek-ANR TPM#398) 76. Existing Point of Interconnection 11,390 between Seller and Mississippi Fuel Company at Jeff Davis (Seller Meter No. 3252) in Jefferson Davis County, Mississippi. (Jefferson Davis County - Miss Fuels TP#6579) 77. Existing Point of Interconnection 11,390 between Seller and Meter named Jefferson Davis-Frm (Seller Meter No. 4420) in Jefferson Davis County, Mississippi. (Jefferson Davis-Frm-TP#7033) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 78. Existing Point of Interconnection 11,390 between Seller and Carson Dome Field M.P. 696.41, in Jefferson Davis County, Mississippi. (M.P. 696.41 Carson Dome Field TP#7148) 79. Existing Point of Interconnection 11,390 between Seller and Meter Station named Bassfield-ANR Company at M.P. 703.17 on Seller's Main Transmission Line (Seller Meter No. 3238) in Covington County, Mississippi. (Bassfield ANR TP#7029) 80. Existing Point of Interconnection 11,390 between Seller and Meter named Patti Bihm #1 (Seller Meter No. 3468) in Covington County, Mississippi. (Patty Bihm #1-TP#7629) 81. Discharge Side of Seller's Compressor 11,390 at Seller's Eminence Storage Field (Seller Meter 4166 and 3160) Covington County, Mississippi. (Eminence Storage TP#4103) 82. Existing Point of Interconnection 11,390 between Seller and Dont Dome Field at M.P. 713.39 in Covington, County Mississippi. (M.P. 713.39-Dont Dome TP#1396) 83. Existing Point of Interconnection 11,390 between Seller and Endevco in Covington County, Mississippi. (Hattiesburg-Interconnect Storage TP#1686) 84. Existing Point at M.P. 719.58 on 11,390 Seller's Main Transmission Line (Seller Meter No. 3544) in Centerville Dome Field, Jones County, Mississippi. (Centerville Dome Field-TP#1532) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 85. Existing Point of Interconnection 11,390 between Seller and Meter named Calhoun (Seller Meter No. 3404) in Jones County, Mississippi. (Calhoun - TP# 378) 86. Existing Point at M.P. 727.78 on 11,390 Seller's Main Transmission Line, Jones County, Mississippi. (Jones County - Gitano TP#7166) 87. Existing Point of Interconnection 11,390 between Seller and a Meter named Koch Reedy Creek (Seller Meter No. 333) in Jones County, Mississippi. (Reedy Creek Koch TP#670) 88. Existing Point of Interconnection 11,390 between Seller and Meter named Sharon Field (Seller Meter No. 3000) in Jones County, Mississippi. (Sharon Field TP#419) 89. Existing Point of Interconnection 11,390 between Seller and Tennessee Gas Transmission Company at Heidelberg (Seller Meter No. 3109) in Jasper County, Mississippi. (Heidelberg Tennessee TP#6120) 90. Existing Point of Interconnection 11,390 between Seller and Mississippi Fuel Company at Clarke (Seller Meter No. 3254) in Clarke County, Mississippi. (Clarke County Miss Fuels TP#6047) 91. Existing Point of Interconnection 11,390 between Seller and Meter named Clarke County-Koch at M.P. 7575.29 in Clarke County, Mississippi. (Clarke County Koch-TP#5566) EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- 92. Existing Point of Interconnection 11,390 between Seller's Mainline and Mobile Bay Lateral at M.P. 784.66 in Choctaw County, Alabama. (Station 85 Mainline Pool TP# 6971) 93. Existing Point of Interconnection 11,390 between Seller and Magnolia Pipeline in Chilton County, Alabama. (Magnolia Pipeline Interconnect TP# 1808) 94. Existing Point at M.P. 719.58 on 11,390 Seller and Southern Natural Gas Company (Seller Meter No. 4087) in Jonesboro Clayton County, Georgia. (Jonesboro SNG TP#6141) 95. Existing Point of Interconnection 11,390 between Seller and Columbia Gas Transmission (Seller Meter No. 7157) in Dranesville, Fairfax County, Virginia (Dranesville Colgas-TP#6068)** 96. Existing Point of Interconnection 11,390 between Seller and Columbia Gas Transmission (Seller Meter No. 4080) in Rockville, Baltimore County, Maryland. (Rockville-Colgas-TP#6227)** 97. Existing Point of Interconnection 11,390 between Seller and Columbia Gas Transmission (Seller Meter No. 3088) in Downington, Chester County, Pennsylvania. (Downington-Colgas-TP#6O67)** 98. Existing Point of Interconnection 11,390 between Seller and Texas Eastern Transmission Corporation (Seller Meter no. 4133) in Skippack, Montgomery County, Pennsylvania. (Skippack-TET-TP#6249)** EXHIBIT A BUYER'S CUMULATIVE MAINLINE CAPACITY POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)* - ------------------- -------------------- Buyer shall not tender, without the prior consent of Seller, at any point(s) of receipt on any day a quantity in excess of the applicable Buyer's Cumulative Mainline Capacity Entitlement for such point(s) of receipt. - --------------------------------------- * These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article, V, 2 hereof. ** Receipt of gas by displacement only. Exhibit B Point (s) of Delivery Pressure(s) - --------------------- ----------- 1. Seller's Eminence Storage Field Prevailing pressure in Covington County, Mississippi. Seller's pipeline system not to exceed maximum allowable operating pressure. 2. The point of interconnection Not less than one between Seller and CNG Transmission thousand (100) pounds Corporation near Leidy Storage per square inch gauge Field, Clinton County, Pennsylvania. or at such other pressure as may be agreed upon in the day to day operations of Buyer and Seller. 3. The point of interconnection Prevailing pressure between Seller and CNG Transmission in Seller's pipeline Corporation near Nokesville in system not to exceed Prince William County, Virginia maximum allowable provided that deliveries to such operating pressure. interconnection shall be limited to the offpeak months of April through October of each calendar year. EX-10 10 AMENDMENT TO NATIONAL FUEL GAS COMPANY 1993 AWARD AND OPTION PLAN I, Bernard J. Kennedy, pursuant to the authorization granted by the National Fuel Gas Company Board of Directors on September 20, 1995, do hereby execute the following amendment to the National Fuel Gas Company 1993 Award and Option Plan ("1993 Plan"), effective August 29, 1995. Section 17 of the 1993 Plan is hereby amended to read as follows: "No award under the Plan shall be subject in any manner to alienation, anticipation, sale, transfer (except by will or the laws of the descent and distribu-tion, or pursuant to a qualified domestic relations order), assignment, pledge or encumbrance, except that, unless the Committee specifies otherwise, awards of nonqualified stock options or SAR's granted on or after August 29, 1995 to the Chief Executive Officer of the Company, or to the President of National Fuel Gas Distribution Corporation, National Fuel Gas Supply Corporation or Seneca Resources Corporation, shall be transferable without consideration, subject to all the terms and conditions to which such non-qualified stock options or SARs are otherwise subject, to members of a Participant's immediate family as defined in SEC Rule 16a-1 promulgated under the Exchange Act, trusts for the benefit of the Participant or such family members, and entities which are wholly-owned by the Participant or such family members. If and when the SEC amends Rule 16b-3 promulgated under the Exchange Act to permit transferability of certain awards under plans intended to satisfy Rule 16b-3, all nonqualified stock option and SAR awards under the Plan shall also be transferable, subject to all the terms and conditions to which such awards are other-wise subject, to the maximum extent permitted by 16b-3, as so amended and as from time to time in effect, unless the Committee specifies otherwise. Except as expressly permitted by this paragraph, an Award shall be exercisable during the Participant's lifetime only by him." NATIONAL FUEL GAS COMPANY October 27, 1995 /s/ Bernard J. Kennedy - ----------------- -------------------------------------- Dated Bernard J. Kennedy President, Chief Executive Officer and Chairman of the Board of Directors EX-10 11 AMENDMENT TO NATIONAL FUEL GAS COMPANY DEFERRED COMPENSATION PLAN I, Bernard J. Kennedy, am duly authorized by Section 10.3 of the National Fuel Gas Company Deferred Compensation Plan ("Plan") to amend the Plan under certain circumstances, and I was also duly authorized by the Board of Directors of National Fuel Gas Company ("Company") on September 20, 1995, to amend the Plan to permit me to receive my full employer matching contribution under the National Fuel Gas Company Tax-Deferred Savings Plan for Nonunion Employees ("TDSP") through the tophat mechanism without contributing to the TDSP, and to permit me or my successor as President to accord this treatment to other employees of the Company and its subsidiaries from time to time. Accordingly, I do hereby amend Section 9.2 of the Plan as follows, effective August 1, 1995 (i.e., effective beginning with the Plan's Deferral Period beginning on such date): 1. Paragraphs (b) - (d) are hereby relabeled as paragraph (c) - (e). 2. A new paragraph (b) is hereby added: "(b) In addition to the tophats described above, Bernard J. Kennedy, President of the Company, shall receive the following benefit, and the President of the Company may from time to time designate in writing other employees of the Company and its subsidiaries to receive the following benefit, which shall be a "tophat" in addition to those described above. Such persons shall receive, or be credited with, for each pay period in a Plan Year for which they are eligible for this benefit, an amount equal to their Maximum Matching Contribution Percentage for each such pay period times their Base Salary with respect to each such pay period, adjusted as of the end of the Plan Year to reflect the increased value of their TDSP accounts had such amounts been actually contributed as additional employer matching contributions to the TDSP, less the amounts paid or credited for such Plan Year or part thereof pursuant to Paragraph (a), clauses (i) - (ii) of this Section 9.2. The purpose of this tophat is to enable employees (including the President), who might or would otherwise be later forced to pay the 15 percent excise tax under Section 4980A of the Code, if they continue to contribute to the TDSP (and have employer matching contributions contributed to the TDSP for their account), to minimize or eliminate the risk of paying that avoidable and excessive tax. The following example illustrates how the tophat provisions of this paragraph (b) shall work in conjunction with the paragraph (a) (iii) example and shall assume that a participant is eligible for this paragraph (b) benefit for an entire Plan Year. Using the same assumptions as set forth in (a) (iii), the participant's Maximum Matching Contribution Percentage times Base Salary for the Plan Year is $25,200. The participant already received $16,867 by virtue of the other tophats in section 9.2, and thus would receive $8,333 by virtue of this paragraph (b) tophat. As previously noted in the paragraph (a) (iii) example, this paragraph (b) tophat, like the others, would be adjusted for changes in the value of Company common stock. As can be seen by this illustration, this paragraph (b) tophat basically permits an eligible employee to obtain, through the tophat mechanism, what he would have obtained as a TDSP matching contribution, without having to contribute to the TDSP." Dated: September 27, 1995 /s/ Bernard J. Kennedy ---------------------- Bernard J. Kennedy President, Chief Executive Officer and Chairman of the Board of Directors EX-10 12 EXECUTIVE RETIREMENT PLAN As adopted on July 10, 1987 (effective February 19, 1987); and as amended on the following dates: Amended and Restated March 1, 1988; Amended and Restated April 25, 1988; Amended and Restated May 2, 1988; Amended September 13, 1993; Amended November 18, 1993; Amended February 17, 1994; Amended September 27, 1995 This Plan Document is current as of November 1, 1995. NATIONAL FUEL GAS COMPANY AND PARTICIPATING SUBSIDIARIES EXECUTIVE RETIREMENT PLAN TABLE OF CONTENTS ARTICLE PAGE NO. - ------- -------- ARTICLE I Purpose . . . . . . . . . . . . . . . . . . . . . 1 ARTICLE II Definitions . . . . . . . . . . . . . . . . . . . 3 ARTICLE III Determination of Retirement Benefits . . . . . . 9 ARTICLE IV Vesting; Forfeiture . . . . . . . . . . . . . . . 15 ARTICLE V Form of Payment of Benefits . . . . . . . . . . . 17 ARTICLE VI Source of Payment . . . . . . . . . . . . . . . . 19 ARTICLE VII Administration of the Plan . . . . . . . . . . . 20 ARTICLE VIII Amendment and Termination . . . . . . . . . . . . 22 ARTICLE IX General Provisions. . . . . . . . . . . . . . . . 23 ARTICLE 1 Purpose 1.1 National Fuel Gas Company established this National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan effective as of February 19, 1987 for the purpose of attracting and retaining executives, and for these additional purposes: (1) to provide retirement benefits to eligible employees in addition to basic retirement benefits provided them under the National Fuel Gas Company Retirement Plan as it may be amended and restated; (2) to provide retirement benefits to such employees to make up for benefit reductions, if any, under the National Fuel Gas Company Retirement Plan caused by participation in the National Fuel Gas Company Deferred Compensation Plan, as it may be amended and restated; (3) to provide retirement benefits to such employees without regard to the $200,000 limit on qualified plans' covered compensation that became effective respecting the National Fuel Gas Company Retirement Plan effective July 1, 1989 (and as that limit may change from time to time); and (4) to provide to such employees benefits which would have been payable from the tax-exempt trust under the National Fuel Gas Company Retirement Plan but for the limitations placed by Section 415 of the Internal Revenue Code of 1986, as it may be amended, on benefits payable and contributions made with respect to such employees under such plans. 1.2 The National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan is intended to constitute an unfunded deferred compensation plan under Section 201(2) of the Act and the Company's obligation to pay benefits hereunder, if any, is unfunded and unsecured. ARTICLE 2 Definitions When used herein, the following terms shall have the following meanings: 2.1 Act means the Employee Retirement Income Security Act of 1974, as amended from time to time. 2.2 Basic Pension Plan means the National Fuel Gas Company Retirement Plan, as amended and restated from time to time. 2.3 Beneficiary means the person or persons entitled to receive the amount, if any, payable under the Basic Pension Plan upon the death of a member or retired member thereof who also is a Member in the Plan. 2.4 Benefit Limitations means (i) the maximum "annual benefit" payable under the Basic Pension Plan in accordance with Section 415 of the Code and the implementing provisions of the Basic Pension Plan (as they operate in conjunction with the relevant provisions of other Company employee benefit plans), and (ii) the maximum amount of annual compensation of an employee that may be taken into account under the Basic Pension Plan in accordance with Section 401(a)(17) of the Code, as amended and supplemented, and the implementing provisions of the Basic Pension Plan. 2.5 Board of Directors means the Board of Directors of National Fuel Gas Company. 2.6 Change in Control shall mean the happening of any of the following: (a) the acquisition by any party or parties of the beneficial ownership of 30% or more of the voting shares of National Fuel Gas Company; or (b) the occurrence of a transaction requiring shareholders' approval for the acquisition of National Fuel Gas Company through purchase of stock or assets, or by merger, or otherwise; or (c) the election during any period of 24 months, or less, of 40% or more of the members of the Board of Directors, without the approval of three-fourths of the members of the Board of Directors as constituted at the beginning of the period. 2.7 Code means the Internal Revenue Code of 1986, as amended from time to time. 2.8 Committee means the committee appointed from time to time by the Board of Directors to administer the Plan. 2.9 Company means National Fuel Gas Company and each of the following subsidiaries, which participate in the Plan: National Fuel Gas Distribution Corporation, National Fuel Gas Supply Corporation, Penn-York Energy Corporation and Empire Exploration, Inc., each of which has adopted or has indicated that it will adopt the Plan. 2.10 Early Retirement Date shall be the Retirement Date selected by the Member that is no earlier than the first day of the calendar month immediately following or coinciding with the Member's 55th birthday, or any first of a month thereafter, but prior to the Member's Normal Retirement Date, provided the Member is Vested. 2.11 Employment Year is the consecutive 12-month period commencing on the date in which the Member was hired by a Company, and each subsequent 12-month period commencing on each anniversary thereof. 2.12 Final Average Pay shall mean an amount equal to the average of the Annual Cash Compensation payable by a Company or Companies to a Member for the 60 consecutive month period during the 120 consecutive month period immediately preceding the date the Member retires (or in the event of a Change in Control, terminates employment), which produces the highest average. The Member's Annual Cash Compensation shall include the Member's base salary, whether or not the receipt of a portion thereof has been deferred, plus the Member's compensation (whether or not the receipt of all or a portion thereof has been deferred) under National Fuel Gas Company's short-term annual incentive program, known as the Annual At Risk Compensation Incentive Program (AARCIP") or any successor program thereto, when paid or deferred. The Member's Annual Cash Compensation shall exclude all commissions, stock, option, or SAR awards, special allowances, supplemental compensation, and any other extra compensation or incentives or bonuses not provided under the AARCIP. If an AARCIP award is paid following the Member's retirement date, that award shall be used in determining the Member's Final Average Pay, if it is payable in connection with employment periods included in the 60 month period referred to above. In this event, the Member's Retirement Benefits shall be increased, once the effect of such award is determined, and the increase shall be made retroactive to the Member's retirement date, without interest. Notwithstanding the above, if such a post-retirement AARCIP award is used in determining Final Average Pay hereunder, AARCIP payments relating to no more than five of National Fuel Gas Company's fiscal years may be used in determining Final Average Pay." An example of the effect of this provision is as follows. Assume that a Member retires on October 1, 1999, and that his salary and AARCIP bonuses were as follows for the following calendar year: AARCIP Bonus (relating to fiscal year ending that September 30 but paid in December) Salary 1994 $480,000 $120,000 1995 $540,000 $150,000 1996 $600,000 $180,000 1997 $660,000 $210,000 1998 $780,000 $240,000 1999 $840,000 $270,000 This Member's Final Average Pay would be $876,000, computed as follows: [9/12 ($840,000) + 12/12 ($780,000) + 12/12 ($660,000) + 12/12 ($600,000) + 12/12 ($540,000) + 3/12 ($480,000) + $270,000 + $240,000 + $210,000 + $180,000 + $150,000] divided by 5. 2.13 Member means any person employed by a Company who is designated as a Member by the Chief Executive Officer of National Fuel Gas Company. 2.14 Normal Retirement Date is the first day of the month coinciding with or immediately following the Member's 65th birthday. A Member may retire and begin to receive a Retirement Benefit, payable commencing on his Normal Retirement Date, equal to his Additional Benefit Base. 2.15 Plan means the National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as set forth herein and as amended and restated from time to time. 2.16 Retirement Date is the date with respect to which Retirement Benefits under the Plan commence. 2.17 Retirement Benefits means the benefits payable under this Plan. 2.18 Vesting with respect to a Member occurs on the latter of (i) the first of the month coinciding with or immediately following his 55th birthday or (ii) the date on which the Member has completed five Years of Service with a Company. A "Vested" Member is a Member with respect to whom "Vesting" has occurred. 2.19 Years of Service equals the number of Employment Years completed by a Member. An Employment Year in which a Member completed 1,000 or more but less than the normal number of Hours of Service (as such term is defined in the Basic Pension Plan) for a full-time employee of the Company shall be credited as a partial Year of Service equal to the number of Hours of Service credited in such Employment Year divided by the normal number of Hours of Service for a full-time employee of the Company. Years of Service shall not exceed 40. No more than one Year of Service shall be credited in any Employment Year. 2.20 In construing the Plan, masculine pronouns shall refer to both males and females, as appropriate. ARTICLE 3 Determination of Retirement Benefits 3.1 Total Benefit Base. The Total Benefit Base of a Vested Member shall be a monthly annuity for his life, commencing at his Normal Retirement Date, under which the annual payments shall equal an amount calculated by adding the products of .0197 times the Member's Years of Service not in excess of 30 and .0132 times his Years of Service, if any, in excess of 30 (but not to exceed 10), and multiplying the sum thereof by his Final Average Pay. 3.2 Social Security Benefit means the annual Primary Insurance Amount estimated by the Committee to be payable to the Member under the Social Security Act of 1935, as amended, at his Retirement Date, calculated on the assumption that the Member will not receive any future wages that would be treated as such for purposes of that act. If a Member's Retirement Date precedes his attainment of age 62, the Primary Insurance Amount estimated to be payable to the Member at age 62 (without assuming any cost of living increases) shall be reduced by .75% per month for the first 24 months, and by .5% per month for the remaining months, if any, by which the Member's Retirement Date precedes his attainment of age 62. The Social Security Benefit, once calculated, will be frozen as of the Member's Retirement Date. 3.3 Additional Benefit Base for Member Retiring at Normal Retirement Date. The Additional Benefit Base of a Vested Member who retires on a Normal Retirement Date shall be a monthly annuity for his life, commencing at his Normal Retirement Date, under which the annual payments shall equal the Member's Total Benefit Base less the sum of (i) .0125 times his Years of Service times his Social Security Benefit and (ii) the Member's Benefit Base (as reduced, if at all, on account of Benefit Limitations) under the Basic Pension Plan. If the remainder is negative, the Additional Benefit Base shall be zero. 3.4 Additional Benefit Base for Members Retiring on an Early Retirement Date. The Additional Benefit Base of a Vested Member who retires on an Early Retirement Date shall be a monthly annuity for the Member's life, commencing on such Early Retirement Date, under which the annual payments shall equal (i) the Member's Adjusted Basic Pension Plan Benefit Base as determined in (a) below, plus (ii) the Early Retirement Percentage as determined in (b) below times the remainder of his Total Benefit Base less his Adjusted Basic Pension Plan Benefit Base, minus (iii) .0125 times his Years of Service times his Social Security Benefit, minus (iv) the Member's Benefit Base (as reduced, if at all, on account of Benefit Limitations) under the Basic Pension Plan. (a) Adjusted Basic Pension Plan Benefit Base equals the Benefit Base as determined under the Basic Pension Plan without reduction on account of Benefit Limitations and adjusted as if deferrals under the National Fuel Gas Company Deferred Compensation Plan were not excluded from the definition of Final Average Pay under the Basic Pension Plan, and multiplied by the appropriate Early Retirement Percentage, if applicable, as provided for in Section 4.02 of the Basic Pension Plan. (b) The Early Retirement Percentage under the Plan is determined in accordance with the following scale: Retirement Age Early Retirement Percentage -------------- --------------------------- 65 100 64 94 63 88 62 82 61 70 60 58 59 46 58 34 57 22 56 10 55 years and 2 months 0 The Early Retirement Percentage determined in accordance with the above scale respecting ages 62, 63 and 64, shall be increased by 1/2 of 1% for each whole calendar month by which a Member's Early Retirement Date follows the first of the month coinciding with or immediately following his 62nd, 63rd, or 64th birthday, as the case may be. The Early Retirement Percentage determined in accordance with the above scale respecting ages 55 years and 2 months, 56, 57, 58, 59, 60, and 61, shall be increased by 1% for each whole calendar month by which his Early Retirement Date follows the first of the month coinciding with or immediately following his 55 year and 2 month, 56th, 57th, 58th, 59th, 60th and 61st birthdays, as the case may be. Furthermore, the Early Retirement Percentage shall be increased by .125% for each whole calendar month by which a Member's Years of Service exceed 30; provided, however, that this shall never result in an Early Retirement Percentage in excess of 100%. (In the event a Member desires to retire on the earliest possible Early Retirement Date, i.e., on the first of the month coinciding with or immediately following his 55th birthday, the increase in percentage as a result of Years of Service in excess of 30 shall be made from a base percentage of -2%, in computing Early Retirement Percentage.) (c) The benefit a Member will receive through the Plan if he retires early consists of two parts. The first part will make him whole for any reduction in the regular pension he receives under the Basic Pension Plan resulting from Internal Revenue Code limitations and his participation in the National Fuel Gas Company Deferred Compensation Plan. This is frequently called a "tophat." The second part is a benefit equal to a percentage of the Plan benefit normally paid at age 65. This normal Plan benefit is calculated by subtracting the amount received under the Basic Pension Plan and the "tophat" from the Total Benefit Base. The percentages are set forth in Section 3.4(b) on page 10. The benefit payable under this second part but not the "tophat" will be reduced by a lesser Social Security offset. The offset is .0125 times Years of Service times Social Security Benefit (as defined in 3.2). For example, if an employee had 30 Years of Service under this Plan (29 under the Basic Pension Plan) and a Final Average Salary of $100,000; if he desired to retire at age 58 (10% reduction under the Basic Pension Plan); if the applicable limits under Section 415 of the Code capped the Basic Pension Plan annual benefits expressed as a Benefit Base equivalent, at $85,000; and if his Social Security Benefit as determined hereunder were $10,000; the formula would work as follows: (i) Adjusted Basic Pension Benefit Base = [(.0125) ($7,800) + (.015) ($92,200)] (29) (.90) = $38,641.05 (ii) Early Retirement Percentage times [Total Benefit Base minus (i)] = (.34) [(.591) ($100,000) - $38,641.05] = $6,956.04 (iii) Additional Benefit Base = $38,641.05 + $6,956.04 - [(.0125) (30) ($10,000)] - $38,641.05 = $3,206.04 (d) If, respecting any Member, his Early Retirement Percentage times the remainder of Total Benefit Base less Adjusted Basic Pension Plan Benefit Base, results in a figure which is less than or equal to .0125 times his Years of Service times his Social Security Benefit, Additional Benefit Base shall equal Adjusted Basic Pension Plan Benefit Base less the Member's Benefit Base (as reduced, if at all, on account of Benefit Limitations) under the Basic Pension Plan. This provides that, if the bonus for Early Retirement under the Plan is less valuable than the Social Security offset provided hereunder, the Member will not be prejudiced thereby; i.e., will not lose any portion of the benefits provided for under the Plan to undo the impact of Benefit Limitations. 3.5 Late Retirement. A Member's Years of Service shall be credited if they extend beyond his Normal Retirement Date, (but shall not exceed 40 in total), and the Final Average Pay determination shall reflect such Years of Service. However, there shall be no actuarial adjustment to his Additional Benefit Base on account of a Member's retirement after Normal Retirement Date; for such purpose Additional Benefit Base hereunder shall be computed as if his late retirement date were his Normal Retirement Date. 3.6 Adjustment of Retirement Benefit. The amount of Retirement Benefits payable to or in respect of a Member shall be reduced by the amount of any increases in the benefits payable under the Basic Pension Plan to or in respect of such Member (whether due to increases in the Benefit Limitations or otherwise) subsequent to the Member's Retirement Date, and shall be increased by the amount of any such decrease subsequent to the Member's Retirement Date, as the case may be. Notwithstanding the above, (i) any increase in benefits payable under the Basic Pension Plan due to a full or partial cost of living adjustment or (ii) any increase in Basic Pension Plan benefits due to a change in benefit formula thereunder shall not cause a reduction in Retirement Benefits. Moreover, any such increase in (i) or (ii) above, if and to the extent ineffective respecting a Member due to Benefit Limitations, shall be provided through this Plan. ARTICLE 4 Vesting; Forfeiture 4.1 Time of Vesting. No Retirement Benefits will be payable to or in respect of any Member unless (i) that Member remains employed by the Company until he is Vested under this Plan; or (ii) Section 4.4 applies. 4.2 Misconduct. Notwithstanding Section 4.1 hereof, no Retirement Benefits will be payable to or in respect of a Member whose employment is terminated by the Company for serious, willful misconduct in respect of his obligations to the Company, including but not limited to the commission of a felony or a perpetration of a common law fraud which has damaged, or is likely to result in damage to, the Company. 4.3 Competition. If and so long as a Member or retired Member shall be employed by any corporation, entity or individual which is then engaged in a business competitive with the Company, or shall be engaged in any such business, or shall aid, advise or assist or attempt to aid, advise or assist any corporation, individual or entity in engaging in any such business, or shall endeavor, directly or indirectly, to interfere with the relations between the Company and any customer or engage in any activity that would be deemed by the Committee in its sole discretion to be detrimental to the Company's best interests, the rights of such Member or retired Member to Retirement Benefits, including the rights of any Beneficiary, shall be forfeited with the same full force and effect as though the Retirement Benefits had not been granted under any of the provisions of the Plan, unless the Committee determines that such activity is not detrimental to the best interests of the Company; provided that from and after 60 days following cessation by the Member or retired Member of such activity and written notice by him to the Committee, his right to receive Retirement Benefits hereunder shall be restored, unless the Committee, in its sole discretion, determines that the prior activity has caused substantial damage to the Company. No action under the Section shall be taken upon or after the occurrence of a Change in Control. 4.4 In the Event of a Change in Control. If a Change in Control occurs, and a Member hereof at that time or within three years thereafter shall no longer be an officer of, or employed by, a Company, his Retirement Benefit shall vest at the time of his cessation of employment with a Company, and shall be payable to him or for his benefit in the form of a lump sum, based upon his accrued Additional Benefit Base at Normal Retirement Date and discounting same by using the interest assumption(s) then used by the Pension Benefit Guaranty Corporation for computing the value of immediate annuities upon the termination of a tax-qualified defined benefit plan such as the Basic Pension Plan. ARTICLE 5 Form of Payment of Benefits 5.1 Coordination with Basic Pension Plan. Retirement Benefits shall be payable to or in respect of a Member eligible therefor at the same time, in the same manner and form, and subject to the same terms and conditions as stated in Sections 5.02 to 5.06 of the Basic Pension Plan, except that there shall be no disability benefit under this Plan. If Retirement Benefits are to be paid after the Member's or retired Member's death to his Beneficiary, Retirement Benefits shall be payable to such Beneficiary in the same time, manner and form as payments under the Basic Pension Plan. 5.2 Right to Adjust. The Committee shall have the right to adjust Retirement Benefits payable under this Plan to correct errors, and/or to provide uniform treatment of Members, retired Members or Beneficiaries. 5.3 Spouse's Benefit. In the event of a Vested Member's death, his spouse shall receive Retirement Benefits hereunder equal to the greater of (i) or (ii): (i) .50 times the Member's Additional Benefit Base computed under Section 3.3, except that if the Member's surviving spouse is more than five years younger than the Member, the .50 multiplier described in this clause shall be reduced by .00125 for each month in excess of 60 that the surviving spouse's age is less than that of the Member. Thus, for example, the multiplier declines to .30 if the surviving spouse is 220 months younger than the Member. (ii) 50% of the Retirement Benefit which the Member would have received had payment thereof commenced on the day before the date of his death in the form of the Automatic Joint and Survivor Annuity (as defined and described in the Basic Pension Plan). 5.4 Lump Sum Payment Option. There shall be one exception to Section 5.1: A Member may elect to receive Retirement Benefits in the form of a lump sum payment even if he does not or may not select such option under the Basic Pension Plan. Such election may only be made by means of an irrevocable election executed in the calendar year prior to the year in which the Member's Retirement Date occurs. The most recently published mortality table that is generally accepted by American actuaries and reasonably applicable to the Plan, and a 6 percent annual interest rate or discount rate, shall be used to convert the Member's Additional Benefit Base to a lump sum equivalent. (However, with respect to other forms of benefit available under the Plan, the mortality table used in the Basic Pension Plan and described in Section 1.01 thereof, or a successor section, shall continue to be used.) If the Member's Additional Benefit Base, had it been paid in the form of an annuity, would otherwise have been expected to increase or decrease subsequent to the Member's Retirement Date, (for example, due to cost of living increases that effectively raise the maximum amounts that may be paid from the Basic Pension Plan as a result of the operation of Code Section 415 limits, or due to expected post-retirement AARCIP awards), the Company may adjust such lump sum payment accordingly and shall later true it up either by paying an additional sum to the Member or by receiving a refund of any excess from the Member. ARTICLE 6 Source of Payment 6.1 All payments provided for under the Plan shall be paid in cash from the general funds of the Company; provided, however, that such payments shall be reduced by the amount of any payments made to or in respect of a Member from any trust or special or separate fund established by the Company to assure such payments. The Company shall not be required to establish a special or separate fund or other segregation of assets to assure such payments, and, if the Company shall make any investments to aid it in meeting its obligations hereunder, the Member and his Beneficiary shall have no right, title, or interest whatever in or to any such investments except as may otherwise be expressly provided in a separate written instrument relating to such investments. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind between the Company and any Member or Beneficiary. To the extent that any Member or Beneficiary acquires a right to receive payments from the Company hereunder, such right shall be no greater than the right of an unsecured creditor of the Company. ARTICLE 7 Administration of the Plan 7.1 Committee to Administer. The Plan shall be administered by the Committee which shall have full power and authority to interpret, construe and administer the Plan, and review claims for benefits under the Plan, and the Committee's interpretations and constructions of the Plan and actions thereunder shall be binding and conclusive on all persons and for all purposes. 7.2 Agents. For purposes of the Act, the members of the Committee shall be the named fiduciaries of the Plan for administration of the Plan (including but not limited to complying with reporting and disclosure requirements and establishing and maintaining Plan records), and shall engage such certified public accountants, who may be accountants for the Company, as it shall require or may deem advisable for purposes of the Plan. The Committee may arrange for the engagement of such legal counsel, who may be counsel for the Company, and make use of such agents and clerical or other personnel as they each shall require or may deem advisable for purposes of the Plan. The Committee may rely upon the written opinion of such counsel and the accountants engaged by the Committee and may delegate to any agent, who may be a Company employee, or to any sub-committee or member of the Committee, its authority to perform any act hereunder, including without limitation those matters involving the exercise of discretion, provided that such delegation shall be subject to revocation at any time at the discretion of the Committee. 7.3 Liability; Indemnity. To the maximum extent permitted by the Act, no member of the Committee, nor any of their agents, including Company officers or employees, shall be personally liable by reason of any contract or other instrument executed by any of them in their capacity as members of the Committee or otherwise, nor for any mistake of judgment made in good faith, and the Company shall indemnify and hold harmless, directly from its own assets, each member of the Committee and each other officer, employee, or director of the Company to whom any duty or power relating to the administration or interpretation of the Plan or to the management or control of the assets of the Plan may be delegated or allocated, against any cost or expense (including counsel fees) or liability (including any sum paid in settlement of a claim with the approval of the Company) arising out of any act or omission to act in connection with the Plan unless arising out of such person's own fraud or bad faith. Said persons shall be entitled to rely conclusively upon, and shall be fully protected in any action taken by them or any of them in good faith in reliance upon, any table, valuation, certificate, opinion or report which shall be furnished to them or any of them by an actuary, accountant, counsel or other expert who shall be employed or engaged by them. 7.4 Binding Effect of Decisions. The decision or action of this Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final, conclusive and binding upon all persons having any interest in the Plan. ARTICLE 8 Amendment and Termination 8.1 Subject to the application of Article 4 in the situations therein enumerated, the Plan may be amended, suspended or terminated, in whole or in part, by the Board of Directors, and Members may be adversely affected thereby provided that such actions may not deprive Vested Members of Retirement Benefits accrued until the date of such actions. However, any amendment that changes the interest rate described in Section 5.4 or otherwise changes the methods for computing lump sum equivalents thereunder, or that otherwise reduces or eliminates the lump sum payment option or any other form of benefit payment option under the Plan, shall not be considered to be a deprivation of the accrued Retirement Benefits of Vested Members. In addition, prior to a Change in Control, the rights of Vested Members may be affected if failing to make changes would be administratively burdensome and if the Member voluntarily consents to such change in writing, or if changes are required by law. ARTICLE 9 General Provisions 9.1 Effect of Corporate Reorganization. This Plan shall be binding upon and inure to the benefit of the Company and its successors and assigns and the Member, and his designees, Beneficiaries, legal representatives and estate. Nothing in this Plan shall preclude the Company from consolidating or merging into or with, or transferring all or substantially all of its assets to, another corporation which assumes this Plan and all obligations of the Company hereunder. Upon such a consolidation, merger or transfer of assets, and assumption of the Plan, the term "Company" shall refer to such other corporation and this Plan shall continue in full force and effect. 9.2 Right to Discharge Member. Neither the Plan nor any action taken hereunder shall be construed as giving to a Member the right to be retained in the employ of the Company or as affecting the right of the Company to discharge any Member, at any time without regard to the effect such discharge would have upon his eligibility for or receipt of benefits under the Plan. 9.3 Withholding. The Company may withhold from any benefits payable under this Plan all federal, state, city or other taxes as shall be required (as determined by the Company) pursuant to any law or governmental regulation or ruling. 9.4 Assignability. No right to any amount payable at any time under the Plan may be assigned, transferred, pledged, or encumbered, either voluntarily or by operation of law, except as provided expressly herein as to payments to a Beneficiary or as may otherwise be required by law. If, by reason of any attempted assignment, transfer, pledge, or encumbrance, or any bankruptcy or other event happening at any time, any amount payable under the Plan would be made subject to the debts or liabilities of the Member or his Beneficiary or would otherwise not be enjoyed by him, then the Committee, if it so elects, may terminate such person's interest in any such payment and direct that the same be held and applied to or for the benefit of the Member, his Beneficiary, or any other person deemed to be the natural objects of his bounty, taking into account the expressed wishes of the Member (or, in the event of his death, his Beneficiary). 9.5 Inability to Utilize Benefits. If the Committee shall find that any person to whom any amount is or was payable hereunder is unable to care for his affairs because of illness or accident or other reasons, or has died, then the Committee, if it so elects, may direct that any payment or any part thereof due such person shall be paid to his estate (unless a prior claim therefor has been made by a duly appointed legal representative) or be paid or applied for the benefit of such person or to or for the benefit of his spouse, children or other dependents, an institution maintaining or having custody of such person, any other person deemed by the Committee to be a proper recipient on behalf of such person otherwise entitled to payment, or any of them, in such manner and proportion as the Committee may deem proper. Any such payment shall be in complete discharge of the liability therefor of the Company, the Plan or the Committee or any member, officer or employee thereof. The Committee may withhold the payment of any amount that shall be payable in accordance with the provisions of the Plan to a person under legal disability until a representative of such person competent to receive such payment on his behalf shall have been properly appointed. 9.6 Actuarial Equivalents. Except as otherwise set forth in Section 5.4, whenever, under this Plan, it is necessary to determine whether one benefit is less than, equal to, or larger than another, or whether one benefit is the actuarial equivalent of another whether or not such benefits are provided under this Plan, such determination shall be made using mortality, interest and any other assumptions used at the time in determining actuarial equivalents under the Basic Pension Plan. 9.7 Health Information. The Member shall provide to the Company, if so requested and as a precondition for remaining a Member, all health information and other information as the Company may require should it decide to purchase life insurance policies or annuity contracts. 9.8 Additional Benefit. The benefits payable under this Plan shall be in addition to all other benefits provided for Employees of the Company, except as otherwise provided in this Plan. 9.9 Headings. The captions preceding the sections and articles hereof have been inserted solely as a matter of convenience and in no way define or limit the scope or intent of any provisions of the Plan. 9.10 Governing Law. This Plan shall be governed by the laws of the State of New York as from time to time in effect. EX-12 13
COMPUTATION OF RATIO OF EXHIBIT 12 EARNINGS TO FIXED CHARGES (UNAUDITED) Fiscal Year Ended September 30 ------------------------------------------------- 1995 1994 1993 1992 1991 ------------------------------------------------- EARNINGS: Income Before Interest Charges (2) $128,061 $127,885 $125,742 $118,222 $110,240 Allowance for Borrowed Funds Used in Construction 195 209 174 1,088 2,278 Federal Income Tax 30,522 36,630 21,148 17,680 (3,929) State Income Tax 4,905 6,309 2,979 3,426 341 Deferred Inc. Taxes - Net (3) 8,452 4,853 16,919 14,125 26,873 Investment Tax Credit - Net (672) (682) (693) (706) (738) Rentals (1) 5,422 5,730 5,621 5,857 4,915 $176,885 $180,934 $171,890 $159,692 $139,980 FIXED CHARGES: Interest & Amortization of Premium and Discount of Funded Debt $40,896 $36,699 $38,507 $39,949 $41,916 Interest on Commercial Paper and Short-Term Notes Payable 6,745 5,599 7,465 12,093 11,933 Other Interest (2) 4,721 3,361 4,727 6,958 9,679 Rentals (1) 5,422 5,730 5,621 5,857 4,915 $57,784 $51,389 $56,320 $64,857 $68,443 RATIO OF EARNINGS TO FIXED CHARGES 3.06 3.52 3.05 2.46 2.05 Notes: (1) Rentals shown above represent the portion of all rentals (other than delay rentals) deemed representative of the interest factor. (2) Fiscal 1995, 1994, 1993 and 1992 reflect the reclassification of $1,716, $1,674, $1,374 and $1,129, respectively, representing the loss on reacquired debt amortized during each period, from Other Interest Charges to Operation Expense. (3) Deferred Income Taxes - Net for fiscal 1994 excludes the cumulative effect of changes in accounting.
EX-23 14 RALPH E. Davis Associates, INC. CONSULTANTS-PETROLEUM AND NATURAL GAS 3555 TIMMONS LANE-SUITE 1105 HOUSTON, TEXAS 77027 (713) 622 -8955 CONSENT OF ENGINEER ------------------- We hereby consent to the reproduction of our audit report dated October 17, 1995, and to the reference to our estimate dated October 1, 1995, appearing in this National Fuel Gas Company Annual Report on Form 10-K. We also consent to the incorporation by reference in (i) the Registration Statement (Form S-8, No. 2-95439), as amended, relating to the National Fuel Gas Company 1983 incentive Stock Option Plan and the National Fuel Gas Company 1984 Stock Plan, and in the related Prospectuses, (ii) the Registration Statements (Form S-8, No. 33-28037, and Nos. 2-97641 and 33-17341), as as amended, relating to the National Fuel Gas Company TaxDeferred Savings Plan and the National Fuel Gas Company Tax-Deferred Savings Plan for Non-Union Employees, respectively, and in the related Prospectuses, (iii) the Registration Statement (Form S-3, No. 33-49401), as amended, relating to $350,000,000 of National Fuel Gas Company debentures and/or medium term notes and in the related Prospectus, (iv) the Registration Statement (Form S-3, No. 33-51881), as amended, relating to the National Fuel Gas Company Dividend Reinvestment and Stock Purchase Plan, and in the related Prospectuses, (v) the Registration Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel Gas Company Customer Stock Purchase Plan, and in the related Prospectus, and (vi) the Registration Statement (Form S-8, No. 33-49693), as amended, relating to the National Fuel Gas Company 1993 Award and Option Plan, and in the related Prospectus; of the reproduction of our report dated October 17, 1995, appearing in this National Fuel Gas Company Annual Report on Form 10-K. RALPH E. DAVIS ASSOCIATES, INC. /s/ Allen C. Barron ------------------------------- Allen C. Barron, P.E. Vice President Houston, Texas October , 1995 EX-23 15 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Prospectuses consituting part of the Registration Statements on Form S-3 (No. 33-51881), Form S-3 (No. 33-49401), Form S-3 (No. 33-36868), Form S-8 (No. 2-97641), Form S-8 (No. 33-17341), Form S-8 (No. 33-28037), Form S-8 (No. 2-94539) and Form S-8 (No. 33-49693) of National Fuel Gas Company of our report dated October 27, 1995 appearing on page 46 of this Form 10-K. PRICE WATERHOUSE LLP Buffalo, New York December 15, 1995 EX-3 16 CERTIFICATE OF AMENDMENT OF RESTATED CERTIFICATE OF INCORPORATION (As Restated March 15, 1985) OF NATIONAL FUEL GAS COMPANY Pursuant to the provisions of Chapters 7 and 9 of Title 14A of the New Jersey statutes and particularly Sections 14A:7-2(4) and 14A:9-4 thereof, National Fuel Gas Company, a corporation organized under the laws of the State of New Jersey, hereby certifies: FIRST: The name of the Corporation is NATIONAL FUEL GAS COMPANY (the "Company"). SECOND: The Board of Directors of the Company ("the Board"), at a meeting duly called and held on December 11, 1986, adopted, inter alia, the following resolutions: RESOLVED: That the first sentence of Article FOURTH of the Company's Restated Certificate of Incorporation ("Certificate"), be amended to read as follows: The total authorized capital stock of this Corporation shall consist of Three Million Two Hundred Thousand (3,200,000) shares of Preferred Stock having the par value of Twenty-Five Dollars ($25) per share and One Hundred Million (100,000,000) shares of Common Stock having no par value per share; and it is FURTHER RESOLVED: That the above proposed amendment to the Company's Restated Certificate of Incorporation, as hereby approved by the Board of Directors, be submitted to a vote of the Company's common stockholders, at the Annual Meeting of Stockholders to be held on February 19, 1987, or any adjournment thereof, with the recommendation that they approve same; and it is FURTHER RESOLVED: That pursuant to Article FOURTH, paragraph 7 of the Certificate and New Jersey Statutes, Annotated, 14A:7-2, effective upon the issuance of the necessary Order in connection with the U-1 described in the resolution below, and such other necessary filing described in said resolution, the number of authorized shares, $25 par value, of the Company's Cumulative Preferred Stock, 9.20% Series, none of which shares are currently outstanding, be, and hereby is, reduced from 1,200,000 to 0; that all of the heretofore authorized shares of such series be, and hereby are, reclassified as, and restored to the status of, shares of Preferred Stock, $25 par value, which are not part of any series; and that Article FOURTH of the Certificate be, and hereby is, amended to delete, in its entirety, the unnumbered paragraph headed "Cumulative Preferred Stock, 9.20% Series"; and it is FURTHER RESOLVED: That all actions heretofore taken, and which may hereafter be taken as they deem necessary or appropriate, by the President and officers of the Company in connection with the above proposed amendments to the Certificate, including, but not limited to, the filing of an Application- Declaration on Form U-1 and amendments thereto, with the Securities and Exchange Commission ("Commission"), receipt of an Order in connection therewith, and necessary filings with the Secretary of State of the State of New Jersey be, and they hereby are, in all respects authorized, approved, ratified and confirmed. THIRD: That said Annual Meeting of Common Stockholders of the Company was held on the 19th day of February, 1987, pursuant to written notice of the time, place and purposes of said meeting, including the taking of action upon the first-mentioned amendment to the Restated Certificate of Incorporation of the Company approved by the Board as aforesaid. FOURTH: Said written notice of said Annual Meeting was mailed to each stockholder of record entitled to vote thereon in accordance with the Company's By-Laws and not less than 10 nor more than 60 days before the date of said Annual Meeting. FIFTH: The number of shares of Common Stock of the Company entitled to vote as a class at said Annual Meeting was 11,928,496, and each such share entitled the registered holder thereof to abstain from voting or to vote one vote for or against the adoption of the first above-mentioned amendment. SIXTH: At said Annual Meeting, the following votes were registered with respect to the first above-mentioned amendment set out in paragraph SECOND above: For - 9,470,278 shares of Common Stock Against - 538,602 shares of Common Stock Abstain - 390,656 shares of Common Stock A quorum of the holders of Common Stock was present and voting at said Annual Meeting, and the amendment was duly adopted by the affirmative vote of a majority of the votes cast by holders of outstanding shares of Common Stock entitled to vote thereon. SEVENTH: Article FOURTH of the Restated Certificate of Incorporation of the Company is also amended so that (i) all of the heretofore authorized shares of Cumulative Preferred Stock, 9.20% Series, are reclassified as and restored to the status of shares of Preferred Stock, $25 par value, which are not part of any series and (ii) the unnumbered paragraph of said Article FOURTH headed "Cumulative Preferred Stock, 9.20% Series*, is deleted from that Article, as provided in the second above-mentioned amendment set forth in paragraph SECOND above. EIGHTH: The amendments shall become effective on the date of filing. Dated: March 9, 1987 NATIONAL FUEL GAS COMPANY By: /s/ Bernard J. Kennedy Bernard J. Kennedy, President EX-27 17
UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 12-MOS SEP-30-1995 OCT-01-1994 SEP-30-1995 PER-BOOK 1,649,182 0 189,244 8,653 191,223 2,038,302 37,434 383,031 380,123 800,588 0 0 474,000 52,600 0 95,000 88,500 0 0 0 527,614 2,038,302 975,496 43,879 807,218 851,097 124,399 5,378 129,777 53,883 75,894 0 75,894 59,625 40,896 173,460 2.03 2.03
EX-10 18 AMENDMENT TO DEATH BENEFITS AGREEMENT National Fuel Gas Company ("Company"), by action of its Board of Directors at its September 15, 1993 meeting, authorized the president of the Company to amend certain existing executive benefit agreements to reflect compensation that has been or will be provided under the Company's Annual At Risk Compensation Incentive Program ("AARCIP"). Accordingly, the Company, and Bernard J. Kennedy ("Executive"), do hereby amend the death benefit agreement, dated August 28, 1991 respecting the Executive, which was previously executed by the parties hereto ("Agreement"), as follows: 1. The last two sentences of Article II, paragraph (a) of the Agreement are hereby amended to read as follows: "Then, the Policies shall pay to the beneficiary or beneficiaries of the Executive or any successor owner he has designated thereunder ("Beneficiary") (i) 72 times the base monthly salary provided by the Company to the Executive ("Base Monthly Salary") at the time of Executive's death, plus six times the most recent annual award to the Executive under the Company's Annual At Risk Compensation Incentive Program ("AARCIP"), if the Executive dies while employed by the Company, or (ii) 72 times the Base Monthly Salary for the month prior to the Executive's commencement of retirement, plus six times the most recent annual award to the Executive under the AARCIP. If the payments from the Policies hereunder are not sufficient to pay the above amounts in full, Policy 4 (as described in Article III) and Policy 5 (as described in an addendum to the Agreement) shall pay the difference to the Beneficiary." 2. Article II, paragraph (c) is amended and restated to read as follows: "An example of the Company's recovery from the Policies' proceeds hereunder is as follows. If the Company had paid a total of $650,000 in premiums on the Policies, at the time Executive died, and the Policies paid death benefits of $6,500,000, the Company would first recover its $650,000. Then if the Executive's salary were $60,000.00 per month, Beneficiary would receive 72 times that amount, or $4,320,000. And, if the most recent award to the Executive under the AARCIP were $250,000, Beneficiary would receive six times that amount, or $1,500,000. Then, Company and Beneficiary would share the $30,000 excess equally. ($6,500,000 - $650,000 - $4,320,000 - $1,500,000 = $30,000.) Thus, the Company would recover $650,000 plus $15,000, or $665,000 in total, and the Beneficiary would receive $15,000 in addition to the $5,820,000 death benefit provided for in paragraph (a)." In all other respects, the Agreement, and subsequent amendments or addenda thereto, shall remain unchanged. In WITNESS WHEREOF, the parties hereto have executed this amendment at Buffalo, New York, on the 15th day of March, 1994. NATIONAL FUEL GAS COMPANY /s/ Robert J. Dauer By: /s/ Bernard J. Kennedy - ------------------- --------------------------------- Witness Bernard J. Kennedy President, Chief Executive Officer and Chairman of the Board of Directors /s/ Robert J. Dauer By: /s/ Bernard J. Kennedy - ------------------- --------------------------------- Witness Bernard J. Kennedy EX-13 19 EXPLORATION AND PRODUCTION AND OTHER NONREGULATED ACTIVITIES Management's decisions to delay production, drilling, workovers and recompletions due to extremely low gas prices, as well as those low prices, caused 1995 operating income before taxes to decrease to $16.4 million from $21.8 million in 1994. Natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX) have become a valuable tool, not only in hedging the price of our production, but also in evaluating probable price trends. Last year the NYMEX prices indicated that the unusually warm winter was an aberration and that with the return of more normal weather, gas prices would rise. That has clearly been the case so far in fiscal 1996. We view our reserves as "money in the bank" and seek to maximize the benefit of that asset to our shareholders by producing at the most favorable price. By postponing the drilling of new gas wells, we were unable to counteract the natural depletion rates of both gas and oil condensate production from existing wells. Our 1995 gas production declined 2.3 Bcf, or 10%, from the prior year. The weighted average price received for natural gas in fiscal 1995 decreased $.51 per Mcf. Oil and condensate production decreased by 291,000 barrels, or 28%. A price increase of $1.30 per barrel was not sufficient to offset the lower level of oil production. West Cameron 552, our significant discovery offshore in the Gulf of Mexico in 1994, was the largest single field we shut-in this year. Effective October 5, 1995 it was back on production and, on December 1, it was producing 61,000 Mcf of gas per day and 870 barrels of oil condensate per day. We own 100% of the working interest in the block. Importantly, since we did not engage in much of our planned drilling activity, we concentrated on acquisitions, thereby positioning ourselves for the return of more normal weather and prices. Moreover we replaced 154% of our production in 1995, a good part of it through those acquisitions. In addition, we maintained our emphasis on cost control. A good indication of this is the decrease in Seneca's lifting cost over time. Lifting cost is the unit of production cost (including production and franchise taxes) incurred to raise gas and oil from a producing formation. Since 1991, our lifting cost has decreased from $.59 per Mcf equivalent to $.44 per Mcf equivalent. A significant portion of recent savings was achieved in our Appalachian operations, and reflects the wisdom of the 1994 merger of those operations into Seneca. Major Discoveries, Acquisitions in Offshore Gulf Coast Our focus continues to be centered in the Gulf Coast region. In April we announced a significant oil discovery at Vermilion 252. We have booked 24.2 Bcf equivalent to reserves for the discovery and plan on drilling two more wells in 1996. We made an offshore oil acquisition in West Delta Blocks 31 and 32 with several co-participants. Our interest in the production is 1,100 Mcf of gas per day and 800 barrels of oil condensate per day. We are in the process of evaluating three-dimensional (3-D) seismic data acquired with the purchase to identify additional drilling opportunities. Also, we obtained ten of the fourteen drilling leases on which we bid in the May 1995 Central Gulf of Mexico Federal Lease Sale. In the Western Gulf Federal Lease Sale in September 1995, we were high bidder on the one lease for which we bid. That lease has not yet been awarded. These additional prospects, along with existing prospects, provide us with a 23 block drilling base to continue a steady program offshore for the next three years. This year we completed three wells located at West Cameron Block 552 in the Federal waters offshore Louisiana. One of these is shown on the cover of this report, as is a slice of the seismic data used to make the find. Two dimensional and 3-D seismic technology, which enables us to record data and actually create an image of what is under the ground, is the most notable element of our successful offshore drilling program. Our skill in using it has resulted in an 82% drilling success ratio in our offshore program since its inception. Onshore Gulf Program - Horizontal Drilling Maintains Perfect Success Rate Because of the delays in activity, we drilled only three horizontal wells in 1995, all of which were successful. This continues our 100% success rate for a total of 25 wells in this part of our onshore program. Appalachian Activity This year we focused on cost cutting in our East program. We reduced our lifting cost in Appalachia from $.55 per Mcf equivalent last year to $.50 per Mcf equivalent. In addition, general and administrative expenses were cut by 50% from $1,406,000 to $698,000. Our cost savings were achieved through a variety of innovations and efficiencies, including staff reductions and the judicious use of outside contractors. West Coast Activity On our Temescal acreage we drilled three successful wells, all of which were on proved, but undeveloped sites (meaning that the reserves had been booked in previous years). Also this year, we made a $3.5 million acquisition of a 240-acre lease located in the Silverthread Field of California. Since assuming operation, Seneca has improved total production over 25%, without adding additional personnel. It is an example of the type of acquisition we pursue. Exciting recent news is the lifting of the export ban on Alaskan oil. The influx of Alaskan oil has depressed the California oil market for years. The elimination of the ban should improve the price of California oil. Hedging Activity We continue to eliminate a portion of the market risk associated with fluctuations in the price of natural gas and crude oil through hedging. Our intent is to lock in prices on approximately 60-75% of expected production, if we can do so at prices acceptable to us. In 1995, a year of low gas prices, hedging preserved $7.0 million of pre-tax revenues, or $.12 per share after tax. Future Plans Our current plans for fiscal 1996 are to drill up to eight wells offshore in the Gulf, four to six horizontal wells onshore in Texas, and two wells in California. In addition, we are seeking to apply successful technologies, like the use of 3-D seismic data and horizontal drilling, to new areas. As a result, we will drill up to two wells in the West Texas Permian Basin, where Seneca is participating in a regional 3-D seismic program, and four to six wells in Ohio utilizing a unique regional evaluation to identify potential oil plays. As in the past, we will also evaluate other opportunities and prospects. Other Nonregulated Activities National Fuel Resources' Profits Increase National Fuel Resources (NFR), our nonregulated full service gas marketing company, increased pre-tax operating income by 46% to $2.4 million. Many state regulatory commissions are requiring local utilities to allow customers to purchase gas supplies in the competitive markets. NFR has capitalized on these changes. In 1995, we expanded our services by opening an office near Newark, New Jersey. Moreover, NFR also acquired Integrated Gas Marketing, which marketed to retail commercial and industrial markets, principally in New York. In September 1995, NFR received approval from the FERC to become a wholesale electric power marketer, and is pursuing other necessary approvals. We expect to begin marketing wholesale electric power within the next year. Leidy Hub, Inc. Joins New Business Entity In 1995 Leidy Hub, Inc. formed, with affiliates of NGC Corporation, Nicor Inc. and Pacific Enterprises, an entity known as Enerchange, L.L.C. (Enerchange). Enerchange will develop, manage and operate interests in natural gas hubs located throughout North America. In addition to the Ellisburg-Leidy Hub, we now have an interest in the Chicago Hub and the California Energy (Los Angeles) Hub. Leidy Hub is a 14.5% owner of Enerchange. Enerchange is a 50% participant in another entity formed to develop and promote an electronic trading system. As more and more local gas utilities unbundle their sales and transportation services, we anticipate that Enerchange's three market centers will become a vital link for parties buying and selling gas. Timber Division Earnings were down slightly this year in our timber operation, reflecting a decline in the price received for lumber. Nonetheless, this business contributes positively to earnings. Pipeline Construction Subsidiary Discontinued In 1995 we elected to discontinue Utility Constructors, Inc. (UCI), our nonregulated pipeline construction subsidiary, because of few pipeline construction projects. The sale of that subsidiary's equipment, net of accrued expenses, amounted to a gain of $.03 per share to earnings. New Subsidiary Pursues International and Domestic Energy Projects Horizon Energy Development, Inc. is a newly formed subsidiary created to engage in the development, financing and acquisition of international and domestic electric generation projects and in foreign utility companies. To facilitate our foreign electric generation initiative, Horizon has succeeded to the interest of two former partners in a partnership known as Sceptre Power Company. Our partners in Sceptre have developed a number of domestic power projects, and they have engaged in the development of foreign and domestic steam and electric power generation projects since 1993. With the experienced team we now have in place, we are actively pursuing opportunities in South America, Eastern Europe and Asia. UTILITY OPERATION Efforts in the Utility Operation continue to focus on providing high quality service at the lowest possible cost to customers, while pursuing an appropriate rate of return for shareholders. While our customer service and cost containment performance remain strong, the financial results for the Utility Operation declined this year, with operating income before income taxes of $83.8 million, down 8% from $90.6 million in 1994. Extremely warm weather and lower than expected residential and commercial usage took their toll on this segment in fiscal 1995. Temperatures were 7% warmer than normal and 12% warmer than last year. Consequently, total utility throughput declined by 10.3 Bcf. As designed, a weather normalization feature in New York rates tempered the impact of the weather on earnings. We do not have a similar adjustment mechanism in our Pennsylvania service area and, therefore, weather negatively affected earnings in this jurisdiction. Also impacting 1995 results was the annual reconciliation of gas costs in New York that resulted in $4.3 million of lost and unaccounted for gas that was in excess of that recoverable in rates. Even with significantly warmer than normal weather, we were able to take advantage of recently introduced incentive mechanisms in both New York and Pennsylvania which allow us to retain a portion of the revenues derived from the sale of gas outside our service territory. We also have an incentive mechanism in New York under which we retain a portion of the savings realized from the release to third parties of upstream pipeline capacity when that capacity is not needed to serve our customers. In 1995, these incentives combined to add approximately $830,000 to revenues. Competitive and Customer-Driven Rate Structures Regulatory changes will continue to impact how we provide service to customers and generate earnings for the company. Utilities have historically received most of their revenue from retail sales of gas to homes and businesses. This is referred to in our industry as "bundled sales" because the customer pays a single price for a package of services including the cost of gas and the associated transportation, balancing and storage costs necessary to deliver it. Recent regulatory actions have now given the company the opportunity to truly engage in a new competitive era. Of particular note, the Public Service Commission of the State of New York (PSC) approved a rate design settlement as part of our most recent rate case under which we became the first New York utility to "unbundle" gas sales and transportation services pursuant to a December 1994 PSC order known as the Generic Restructuring Order. The Generic Restructuring Order instructed all New York gas utilities to unbundle their services and to offer market-based rates, if appropriate. Pursuant to that order, our utility negotiated a settlement agreement providing for transportation service with, among others, groups representing our large industrial customers. The PSC approved the settlement and, as of September 20, 1995, New York customers who use 5,000 Mcf or more of gas per year may now choose from a menu of unbundled services including transportation, customized sales services, and daily or monthly-metered options. Rates for these new services may be "flexed" at the company's discretion, in order to better respond to growing competition. On November 9, 1995, we submitted a filing to the PSC which proposes to eliminate the 5,000 Mcf per year minimum volume requirement for transportation service, thereby creating an opportunity for all customers, including residential, to choose their gas supplier. We anticipate that this proposal will be approved in some form in the Spring of 1996. Because of the complexity involved in nominating and managing gas supply, it is not likely that customers who use less than 2,500 Mcf of gas a year will initially take advantage of the new unbundled services. However, we are committed to eventually making this concept work for all customers, including the private homeowner. A service innovation of this kind is nothing new to us. In fact, we view the Generic Restructuring Order as a regulatory endorsement of many of the decisions the company had already implemented. We were the first utility to unbundle services to our customers when we introduced a transportation rate in 1983 in New York. During the past five years alone we have increased the number of transportation customers to 1,528 from 752, with nearly all industrial customers that qualify electing to receive transportation service. We have also been an innovator in Pennsylvania by offering many unbundled services in that state to allow customers greater flexibility and lower prices. National Fuel is, and will continue to be, an industry leader in offering flexible rate and service options to meet customer needs in an ever-changing and more price sensitive environment. Company Efforts Result in Competitive Utility Prices One of our proudest accomplishments over the past decade has been the competitiveness of our retail rates. We continue to be one of the lowest priced gas utilities in the states in which we operate. However, several factors that remain beyond our control have a direct and substantial impact on our cost of providing service. Taxes currently represent some 17.4% of a residential customer's gas bill in New York and 10% in Pennsylvania. Included in New York is the Gross Receipts Tax, which represents as much as 8.4% of an average residential customer's bill and, in effect, is concealed, since by law we are unable to itemize it. Also significant is the subsidization of uncollectible account expense by those customers who unfailingly pay their gas bills. We are aggressively addressing these concerns in an effort to keep natural gas rates as reasonable as possible for our customers. At the same time, we are taking steps to reduce costs for customers who simply cannot make ends meet. We currently have pilot "low income" rates in effect in New York and Pennsylvania. These programs enable customers to have continued gas service while reducing their usage and remaining current in their payments. Also, we are working to establish a pilot transportation program for the Erie County, New York Department of Social Services that, if approved by the PSC, would enable the direct purchase of gas supplies for delivery to the Department's low income clients. This should reduce expenses for the Department and our customers alike. At the federal level, we are working to preserve funding for the Low Income Home Energy Assistance Program (LIHEAP) which is being reduced and is in jeopardy of being eliminated entirely for the winter of 1997. LIHEAP has been a safety net program for many of our customers for 17 years. Our gas acquisition is focused on maintaining our competitive price position by taking advantage of opportunities to refine our current contracts and explore new gas supply alternatives. An example of these efforts is Distribution Corporation's recent notice to terminate a transportation agreement with Tennessee Gas Pipeline Company effective August 1996, which covers 30,750 Decatherms per day. Our intent is to replace this transportation service with competitively priced winter-only service from storage service operators. This should produce a savings of about $5 million per year. In addition, we signed a gas storage agreement with Avoca Natural Gas Storage to commence in October 1998. Use of this storage service will replace other upstream capacity and result in an estimated future savings of over $5 million dollars per year. Customer Service Emphasized Our customer satisfaction level remains high at 86.9 percent. We measure how satisfied our customers are with recent contacts with the company, whether it be over the telephone, in person at a Consumer Assistance Center, or at their homes. The results are used to identify training needs, as a guide for the modification of policies or procedures and as part of the PSC customer service performance incentive plan. The plan establishes minimum customer service levels for the company's telephone response time, percentage of field appointments kept, timeliness of new service line installations, frequency of billing adjustments and estimated meter readings, customer satisfaction levels and number of complaints to the PSC. Our excellent customer service is due to the expertise of our employee group. With an average tenure of 22 years, our experienced employees work diligently to provide the low cost, dependable service upon which our customers have come to rely. Their unwavering commitment is demonstrated by our ability to maintain strong customer satisfaction levels even while aggressively containing costs. Rate Developments In order to recover the capital investments and operating expenditures required to provide a safe and reliable utility system for our customers, we have been on a schedule of filing annual rate increase requests. In December 1994, the Pennsylvania Public Utility Commission (PaPUC) approved a $4.8 million rate increase with a rate of return on equity of 11.0%. Rates took effect that same month. In a subsequent case filed in March 1995, a settlement was approved by the PaPUC in September 1995. The rate change amounted to an increase of $6.0 million in annual revenues with no specified rate of return on equity. New rates were effective as of September 27, 1995. In September 1995, the PSC issued an order authorizing a base rate increase of $14.2 million with a rate of return on equity of 10.4%. Subsequently, the company filed a rate request with the PSC in November 1995, in which it is seeking an increase of $28.9 million to be effective in October 1996. PIPELINE AND STORAGE The year 1995 was dominated by the need to address major regulatory and Company initiatives, specifically the continuing restructuring of our industry, compliance with the Clean Air Act Amendments of 1990 and the placement of the final touches on the merger into Supply Corporation of its former sister company, Penn-York. A series of strategies with respect to these issues converged toward fulfillment this year. As a result, our Pipeline and Storage segment is well-positioned for the rapidly approaching competitive world. Moreover, we were able to accomplish our goals while at the same time increasing earnings. Financial Performance In spite of higher operating costs, and the recording of a reserve in the amount of $3.7 million for previously deferred preliminary survey and investigation charges for the Laurel Fields Storage Project, operating income before income taxes increased 9% to $67.9 million in fiscal 1995 compared to $62.3 million last year. This result reflects the application of a final rule issued by the Federal Energy Regulatory Commission (FERC) which addresses and clarifies financial reporting aspects of the current practices for unbundled pipeline sales and open access transportation. Positioning Ourselves In 1995 over 80% of our transportation and storage revenues were attributable to long-term contracts. Nonetheless, our pipeline and storage business is moving closer to a truly competitive market. States are beginning to open utility markets to competition. Some utilities, in turn, have pipeline capacity they no longer require because certain customers are not purchasing gas from them. In the short-term the capacity is being sold to others. As existing contracts expire, utilities will not fully renew current contracts. Hence, pipeline capacity has become a commodity. We believe that the ultimate conclusion of this evolution will be a fully competitive marketplace. Companies like Supply Corporation will be competing against each other to provide transportation and storage service to those who require it. It also appears that long-term contracts will generally be a thing of the past, as customers will want flexibility to respond to further market changes. To position ourselves for the new era we have concentrated on putting regulatory issues behind us so that we can focus on what is important in a competitive market: providing the most reliable and economical service to our customers. Rate Activity On November 6, 1995, an administrative law judge certified a settlement in principle to the FERC in Supply Corporation's October 1994 rate case filing, which would increase our revenue by $6.4 million annually. The services and facilities of Penn-York, an affiliate merged into Supply Corporation effective July 1, 1994, will be rolled-in to the latter company's rates. The result will be a more efficient structure. Competition already exists for us with respect to approximately two-thirds of the storage capacity we dedicate to nonaffiliated customers. That capacity is now subject to year-to-year contracts. In the pending settlement, Supply Corporation has agreed not to seek recovery from existing customers of lost revenues related to terminated storage service for five years, as long as the terminations are not greater than approximately 7 Bcf. We feel confident that we will be able to remarket such volumes. We also agreed not to file a new rate case based on increased cost of service for three years. These actions are taken in recognition of the fact that we are now part of the competitive world. Gathering Rates Supply Corporation has approximately $20 million of production and gathering facilities used, in part, to gather natural gas of local producers in the Appalachian region. The FERC has directed Supply Corporation to fully unbundle its production and gathering cost of service from its transportation cost of service, and to establish a separate gathering rate. An administrative law judge certified a new settlement in principle on this matter to the FERC in October 1995. As a consequence, the company believes that it will earn on and fully recover its investment in production and gathering facilities. Environmental Compliance As a result of the requirements of the Clean Air Act Amendments of 1990, Supply Corporation spent $5.1 million in fiscal 1995 to retrofit 16 compressor stations with "clean burn" equipment. The refitted units reduce emissions of nitrogen oxides by about 90 percent, realize fuel savings of three to five percent, and require less maintenance. Importantly, we successfully completed this extraordinary and expensive project within the period necessary for recovery in our latest rate case. Because we do not expect to file a case for at least three years, this action ensured that our shareholders earn a reasonable return on their investment for that period. Laurel Fields Storage Project Postponed We withdrew our application from the FERC to construct facilities associated with our Laurel Fields Storage Project. While we believe that the project is solid, there was not sufficient customer interest at this time due to the restructuring of the natural gas industry. In particular, many potential customers are tied to long-term transportation contracts through the year 2000 and beyond. We continue to believe that it makes sound business sense for customers to store gas near ultimate markets. Because of that belief, we plan on remarketing our storage proposals in 1997 or 1998, to leave sufficient construction time to bring the projects to fruition by the year 2000, when many contracts for pipeline transportation expire giving customers the option to switch to storage service. Future Plans After the final settlement of our current rate case, Supply Corporation's maximum rates should be fixed for at least three years and possibly longer. By running a tight ship and keeping capital expenditures within the depreciation allowance, Supply Corporation has the opportunity to generate appropriate earnings for the benefit of our shareholders. Moreover, our affiliates continue to develop the market area hub in the vicinity of Ellisburg and Leidy, Pennsylvania. Within this area, Supply Corporation enjoys the unique position of interconnecting with all of the major pipelines bringing Canadian and southwest gas to the northeast. It is our intent to foster increases in activity at the hub with the goal of also increasing volumes transported and revenue for Supply Corporation. Finally, we will continue to pursue acquisition opportunities as they present themselves. APPENDIX TO EXHIBIT 13 - This appendix contains a narrative description of image and graphic information as contained in the discussion of the Company's business segments included in the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K. I. Exploration and Production and Other Nonregulated Activities a) Graph - Oil and Gas Prices A bar graph detailing weighted average oil and gas prices (in dollars) for the years 1991 through 1995, as follows: 1991 1992 1993 1994 1995 ---- ---- ---- ---- ---- Gas $2.00 $1.97 $2.20 $2.18 $1.67 Oil $20.62 $17.11 $16.78 $14.86 $16.16 b) Graph - Lifting Costs A bar graph detailing lift costs (in dollars per equivalent thousand cubic feet (Mcf)) for the years 1991 through 1995, as follows: 1991 1992 1993 1994 1995 ---- ---- ---- ---- ---- $.59 $.62 $.54 $.45 $.44 Dotted line crossing horizontally across the 5 bars indicates the 5-year average of $.51. c) Graph - Oil and Gas Proved Reserves A bar graph detailing oil and gas proved reserves (in million of barrels (MMbbl) and billion cubic feet (Bcf), respectively) for the years 1993 through 1995, as follows: 1993 1994 1995 ---- ---- ---- Gas (in Bcf) 175.1 247.4 221.5 Oil (in MMbbl) 18.5 17.5 22.9 d) Image - Picture of offshore drilling platform in West Delta 30 field with the following caption: West Delta 30 Field covers 11 blocks and is one of the largest fields in the Gulf of Mexico. The field was discovered in the late 1950s and one of the blocks in the field was purchased by Seneca Resources in September 1995. The field has produced half a billion barrels of oil and seven-tenths of a trillion cubic feet of gas. e) Image - Map of Gulf Coast of Texas and Louisiana, including offshore, indicating areas where Seneca Resources Corporation has prospects, successful discoveries and wells on-production. f) Image - Picture of drilling rig in Temescal 9-5 field with the following caption: Temescal 9-5, located near Lake Piru, California in Ventura County, has proven to be a successful well with production at 210 Mcf of natural gas per day and 193 barrels of oil per day. This field found by Seneca was the first new discovery in Ventura County in more than ten years. g) Image - Map of the United States identifying the location of the Ellisburg-Leidy Hub, California Hub (Los Angeles) and Chicago Hub. II. Utility Operation a) Image - Picture of employee conferring with realtor/contractor in Erie, Pennsylvania with the following caption: The New Services Department expedites new service requests by giving the customer one contact who coordinates the application process through completion. The company's goal is to install new services within 10 days. Wanda Bender, Supervisor of New Services, confers with Realtor/Contractor John Schaefer who is developing a residential subdivision in Millcreek Township, Erie, Pennsylvania. b) Image - Picture of airplane de-icing with the following caption: Process Technologies Inc. (PTI) developed the Infratek system, a revolutionary natural gas-driven radiant heat process to improve airplane de-icing and make it more environmentally friendly. National Fuel supported PTI's demonstration at the Greater Buffalo International Airport. Natural gas was used to power the testing. c) Graph - Two bar graphs detailing the Utility Operation's transportation revenues (in millions of dollars) and transportation volumes (in Bcf) for every other year, beginning in 1985 through 1995, as follows: 1985 1987 1989 1991 1993 1995 ---- ---- ---- ---- ---- ---- Revenues (millions of dollars) $5.4 $10.4 $17.8 $22.4 $30.2 $37.2 Volumes (Bcf) 7.0 16.5 31.4 39.8 48.9 52.8 d) Graph - Bar graph detailing National Fuel's utility rates as being lower than the state average in both New York and Pennsylvania, based on an average annual cost for the three years ended September 30, 1995, as follows: National Fuel State Average New York $904 $997 Pennsylvania $860 $882 e) Image - Picture of production at Abbott Laboratories' Cheektowaga, New York plant with the following caption: Abbott Laboratories' Cheektowaga, New York plant manufactures plastic medical components for customers around the world. It is National Fuel's seventh cogeneration customer. The gas-fired, 2 megawatt cogeneration system will allow Abbott to reduce its energy costs resulting in a payback period of less than four years and will add 180 MMcf per year to National Fuel's annual throughput. Plant Manager William P. Bobo, Jr. and National Fuel's Senior Energy Consultant Carol Tuzzolino observe Production Specialist Sandy Conners producing a sight chamber at a plastic injection molding machine. f) Graph - A pie graph detailing the use of the New York revenue dollar (in percents), broken down as follows: Gas Purchases 45.5% Other Operating Costs 29.2 Taxes 17.4 Interest Charges 4.1 Earnings 3.8 ------ 100.0% III. Pipeline and Storage a) Graph - A pie graph of the Pipeline and Storage segment's transportation and storage service revenues by contract length (in percents) for 1995, broken down as follows: Less than One Year 3% One to Five Years 16 Greater than Five Years 81 ---- 100% b) Image - Picture of Company's gas dispatch operations with the following caption: Gas Dispatch operations have been consolidated to a new Gas Control Operations Center. Monitoring system operations are Gas Dispatch personnel John O'Brien, Timothy Duggan, David Fridmann and Timothy Cody. c) Image - Picture of employee monitoring compression equipment at the Company's Independence Compressor Station, Andover, New York, with the following caption: New, state-of-the-art emission reduction equipment, as well as fire and gas detection equipment has been installed on a number of compressor stations. These devices will result in 90% cleaner air emission and improved safety protection. Guy Milligan, Station Engineer at the Independence Compressor Station, Andover, New York, regularly monitors compression equipment. EX-3 20 CERTIFICATE OF AMENDMENT OF RESTATED CERTIFICATE OF INCORPORATION (As Restated March 15, 1985) OF NATIONAL FUEL GAS COMPANY Pursuant to the provisions of Chapter 9 of Title 14A of the New Jersey Statutes and particularly Section 14A: 9-4 thereof, National Fuel Gas Company, a corporation organized under the laws of the State of New Jersey, hereby certifies: FIRST: The name of the Corporation is NATIONAL FUEL GAS COMPANY (the "Company"). SECOND: The Board of Directors of the Company ("the Board"), at a meeting duly called and held on December 10, 1987, adopted, inter alia, the following resolutions: RESOLVED: That the following Article NINTH be added to the Company's Restated Certificate of Incorporation, as amended ("Certificate"): "NINTH: No director or officer of this corporation shall be personally liable to the corporation or any of its shareholders for monetary damages for breach of any duty owed to the corporation or any of its shareholders, except to the extent that such exemption from liability is not permitted under the New Jersey Business Corporation Act, as the same exists or may hereafter be amended, or under any revision thereof or successor statute thereto"; and it is FURTHER RESOLVED: That the above proposed amendment and addition to the Company's Certificate, as hereby approved by the Board of Directors, be submitted to a vote of the Company's common stockholders at the Annual Meeting of Stockholders to be held on February 18, 1988, or any adjournment thereof, with the recommendation that they approve same; and it is FURTHER RESOLVED: That all actions heretofore taken, and which may hereafter be taken as the officers of the Company deem necessary or appropriate, in connection with the above proposed amendments to the Certificate, including, but not limited to, the filing of an Application- Declaration on Form U-1, and amendments thereto, with the Securities and Exchange Commission ("Commission"), receipt of an Order in connection therewith, and necessary filings with the Secretary of State of the State of New Jersey be, and they hereby are, in all respects authorized, approved, ratified and confirmed. THIRD: That said Annual Meeting of Common Stockholders of the Company was held on the 18th day of February, 1988, pursuant to written notice of the time, place and purposes of said meeting, including the taking of action upon the amendment to the Restated Certificate of Incorporation, as amended, of the Company approved by the Board as aforesaid. FOURTH: Said written notice of said Annual Meeting was mailed to each stockholder of record entitled to vote thereon in accordance with the Company's By-Laws and not less than ten (10) nor more than sixty (60) days before the date of said Annual Meeting. FIFTH: The number of shares of Common Stock of the Company entitled to vote as a class at said Annual Meeting was 25,871,234, and each such share entitled the registered holder thereof to abstain from voting or to vote one vote for or against the adoption of the amendment. SIXTH: At said Annual Meeting, the following votes were registered with respect to the amendment set out in paragraph SECOND above: For - 19,752,149 shares of Common Stock Against - 1,227,581 shares of Common Stock Abstain - 537,548 shares of Common Stock A quorum of the holders of Common Stock was present and voting at said Annual Meeting, and the amendment was duly adopted by the affirmative vote of a majority of the votes cast by holders of outstanding shares of Common Stock entitled to vote thereon. SEVENTH: The amendment shall become effective on the date of filing. Dated: February 18, 1988 NATIONAL FUEL GAS COMPANY By: /s/ Bernard J. Kennedy Name: Bernard J. Kennedy Title: president EX-27 21
UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS AND SCHEDULES 1,000 12-MOS SEP-30-1994 OCT-01-1993 SEP-30-1994 PER-BOOK 1,545,550 0 218,126 15,797 202,184 1,981,657 37,278 379,156 363,854 780,288 0 0 462,500 102,500 0 10,000 96,000 0 0 0 530,369 1,981,657 1,141,324 47,792 967,629 1,015,421 125,903 3,656 129,559 47,124 85,672 0 85,672 57,725 36,699 199,229 2.32 2.32
EX-27 22 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 03-MOS SEP-30-1995 OCT-01-1994 DEC-31-1994 PER-BOOK 1,582,207 0 252,579 14,140 200,477 2,049,403 37,366 381,426 379,723 798,515 0 0 404,000 154,600 0 0 154,500 0 0 0 537,788 2,049,403 279,332 18,507 217,537 236,044 43,288 844 44,132 13,561 30,571 0 30,571 14,702 0 10,188 .82 .82
EX-27 23 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 06-MOS SEP-30-1995 OCT-01-1994 MAR-31-1995 PER-BOOK 1,613,203 0 264,521 14,287 195,766 2,087,777 37,421 382,797 408,306 828,524 0 0 404,000 70,700 0 20,000 154,500 0 0 0 610,053 2,087,777 658,094 45,115 513,234 558,349 99,745 1,475 101,220 27,342 73,878 0 73,878 29,426 0 127,484 1.98 1.98
EX-27 24 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 09-MOS SEP-30-1995 OCT-01-1994 JUN-30-1995 PER-BOOK 1,630,124 0 196,330 11,699 192,529 2,030,682 37,422 382,816 402,190 822,428 0 0 504,000 73,200 0 0 58,500 0 0 0 572,554 2,030,682 851,555 51,353 681,470 732,823 118,732 4,685 123,417 40,558 82,859 0 82,859 44,523 0 186,892 2.22 2.22
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