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, 1996 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, and New York Stock Exchange Common Stock Purchase Rights 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 $1,559,340,000 as of November 30, 1996. Common Stock, $1 Par Value, outstanding as of November 30, 1996: 37,992,960 shares. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's Annual Report to Shareholders for 1996 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 20, 1997 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, 1996 Table of Contents Page ---- Part I - ------ Item 1. Business The Company and its Subsidiaries 15 Rates and Regulation 16 The Utility Segment 17 The Pipeline and Storage Segment 17 The Exploration and Production Segment 18 The Other Nonregulated Segment 18 Sources and Availability of Raw Materials 19 Competition 19 Seasonality 21 Capital Expenditures 21 Environmental Matters 21 Miscellaneous 21 Executive Officers of the Company 22 Item 2. Properties General Information on Facilities 23 Exploration and Production Activities 23 Item 3. Legal Proceedings 25 Item 4. Submission of Matters to a Vote of Security Holders 25 Part II - ------- Item 5. Market for the Registrant's Common Stock and Related Shareholder Matters 25 Item 6. Selected Financial Data 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 27 Item 8. Financial Statements and Supplementary Data 45 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 73 Part III - -------- Item 10. Directors and Executive Officers of the Registrant 73 Item 11. Executive Compensation 74 Item 12. Security Ownership of Certain Beneficial Owners and Management 74 Item 13. Certain Relationships and Related Transactions 74 Part IV - ------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 75 Signatures 78 - ----------
This combined Annual Report to Shareholders/Form 10-K contains "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements included in this combined Annual Report to Shareholders/Form 10-K at Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A), under the heading "Safe Harbor for Forward-Looking Statements." Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are designated with a "1" following the statement, as well as those statements that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," "projects," and similar expressions. 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 segment 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. The Other Nonregulated segment is 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 and midwestern 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. (Enerchange) (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 Beheer-en-Beleggingsmaatschappij Bruwabel B.V. (Bruwabel), a Dutch company whose principal assets are a power development group and a district heating plant located in the eastern part of the Czech Republic; * 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 business 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 1996. 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 in the Letter to Shareholders, which is included in the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K, is 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 legislation to repeal conditionally 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. 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. In addition, recent SEC rule changes, and proposed rule changes, if implemented, have reduced and could reduce further the number of applications filed under the Holding Company Act, exempt routine financings and expand diversification opportunities. The Company is unable to predict at this time what the ultimate outcome of legislative and/or regulatory changes will be, and therefore what the impact on the Company might be.1 The Utility segment'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 segment's rates and regulation, see Item 7 under the heading "Rate Matters," and Item 8 at Note B-Regulatory Matters. The discussion under Item 8 at Note B-Regulatory Matters, includes a description of the regulatory assets and liabilities reflected on the Company's consolidated balance sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company's consolidated balance sheets and such accounting treatment would be discontinued. The Company is not currently facing any requirement to discontinue such accounting standards.1
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 segment 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 segment as the Nonregulated Operations. The Utility Segment The Utility segment contributed approximately 51% of the Company's operating income before income taxes in 1996. Additional discussion of the Utility segment appears in the Letter to Shareholders contained in this combined Annual Report to Shareholders/Form 10-K, below under the headings "Sources and Availability of Raw Materials" and "Competition," in Item 7 "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 33% of the Company's operating income before income taxes in 1996. The Pipeline and Storage segment currently has service agreements for substantially all of its firm transportation capacity, which totals approximately 1,896 million cubic feet (MMcf) per day. The Utility segment has contracted for approximately 1,126 MMcf per day or 59% of that capacity until 2003 and continuing year-to-year thereafter. An additional 22% of that capacity is subject to firm contracts with nonaffiliated customers until 2003 or later. The Pipeline and Storage segment has available for sale to customers approximately 61.6 billion cubic feet (Bcf) of firm storage capacity. The Utility segment has contracted for 26.0 Bcf or 42% of that capacity, in service agreements with initial terms of approximately 7 to 10 years and continuing year-to-year thereafter, effective beginning in 1993 (23.3 Bcf - 10 years), 1996 (2.0 Bcf - 10 years) and 1997 (0.7 Bcf - 7 years). Nonaffiliated customers are contracted for the remaining firm storage capacity. The primary terms of current firm 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. Five of these customers terminated or reduced contracts effective March 31, 1996. The resulting 3.3 Bcf of storage capacity was marketed and is under firm contracts, at discounted rates, with new customers until at least March 31, 1999. Three additional customers terminated contracts effective March 31, 1997 resulting in 2.1 Bcf of available storage capacity. Approximately 1.0 Bcf of this capacity is under contract, at discounted rates, with a new customer until March 31, 2001. The Pipeline and Storage segment is actively marketing the remaining 1.1 Bcf of available capacity. Additional discussion of the Pipeline and Storage segment appears in the Letter to Shareholders contained in this combined Annual Report to Shareholders/Form 10-K, below under the headings "Sources and Availability of
Raw Materials" and "Competition," 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 21% of the Company's operating income before income taxes in 1996. Additional discussion of the Exploration and Production segment appears in the Letter to Shareholders contained in this combined Annual Report to Shareholders/Form 10-K, 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. The Other Nonregulated Segment The Other Nonregulated segment reduced the Company's operating income before income taxes by approximately 4% in 1996. Corporate operations also reduced the Company's operating income before income taxes by approximately 1%. Additional discussion of the Other Nonregulated segment appears in the Letter to Shareholders contained in this combined Annual Report to Shareholders/Form 10-K, below under the headings "Sources and Availability of Raw Materials" and "Competition," Item 7 "MD&A," and Item 8 at Notes F-Financial Instruments and I-Business Segment Information. Sources and Availability of Raw Materials Natural gas is the principal raw material for the Utility segment and some of the subsidiaries in the Other Nonregulated segment, 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. Highland and Seneca's timber operations rely to a large degree 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 Letter to Shareholders contained in this combined Annual Report to Shareholders/Form 10-K, Item 7 "MD&A" and Item 8 at Notes I-Business Segment Information and L Supplementary Information for Oil and Gas Producing Activities. In 1996, the Utility segment purchased 149.5 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 70% 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%, 24% and 3%, respectively, of the Utility segment's 1996 gas purchases. Gas purchases from Vastar Resources, Inc. and Natural Gas Clearinghouse (southwest gas under long-term contract) represented 13% and 11%, respectively, of total 1996 gas purchases by the Utility segment. No other producer or marketer provided the Utility segment with 10% or more of its gas requirements in 1996. A portion of the Utility segment's gas purchase agreements with nonaffiliated gas producers require payment of fixed monthly charges. These charges are tied to various indices. At September 30, 1996, the projected aggregate amount of such required future payments, based on current indices, is approximately $10.8 million annually for the next five years.1 To move its gas from the point of purchase to its distribution system in New York and Pennsylvania, the Utility segment purchases contracted firm transportation and storage services from various interstate pipeline companies including Supply Corporation. These contracts provide for payment of a demand or reservation charge for contracted capacity and storage. At September 30, 1996, the projected aggregate amounts of such required future payments to nonaffiliated companies, based on current FERC approved rates, where applicable, are approximately $98.1 million and $2.4 million annually for the next five years, for pipeline capacity and storage service, respectively.1
The Other Nonregulated segment needs natural gas for NFR's marketing and Leidy's hub services, but is relatively indifferent as to the source. Competition Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy. The continuing deregulation of the natural gas industry should 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.1 In addition, the environmental advantages of natural gas compared with other fuels should increase the role of natural gas as an energy source.1 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 various states. It is unclear at this point what impact this restructuring will have on the Company.1 The Company competes on the basis of price, service 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 Segment 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. The PSC issued an order in 1995 providing for the Utility segment to implement unbundling of its services. The Utility segment has implemented most of the provisions contained in the PSC's 1995 order, and now offers unbundled, flexible services to its residential, commercial and industrial customers. At present, these provisions are not advantageous to the residential customers because of high cost and the resulting lack of interest by gas marketers in offering residential gas sales. In large part, the high cost is due to the significant customer protections required of utilities which are then passed along in rates. Such protections include sufficient contracts to purchase, transport and store natural gas in the event that it is needed by residential customers. Competition for large-volume customers continues, with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment's service territories (i.e., bypass). In addition, competition continues with fuel oil suppliers, and may increase with electric utilities making retail energy sales.1 Responding to those developments, the Utility segment is now better able to compete, through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets). The Utility segment 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.1
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, by competitive bidding and otherwise, 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: The Other Nonregulated Segment In the Other Nonregulated segment, 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 segment, as virtually all of its residential and commercial customers use gas for space heating. The effect on the Utility segment in New York is mitigated 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 A discussion of material environmental matters involving the Company is included in Item 8, Note H-Commitments and Contingencies. Miscellaneous The Company had 2,843 full-time employees at September 30, 1996, a decrease of 2.8% from the 2,925 employed at September 30, 1995. 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, effective April and May 1996, and are scheduled to expire in April and May 1999. 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.1
Executive Officers of the Company* Age as of Current Company Date Elected To Name 9/30/96 Positions Current Positions ---- --------- --------------- ----------------- Bernard J. Kennedy 65 Chairman of the Board of Directors. March 21, 1989 Chief Executive Officer. August 1, 1988 President. January 1, 1987 Director. March 29, 1978 Philip C. Ackerman 52 Director. March 16, 1994 Senior Vice President. June 1, 1989 President of Distribution Corporation. October 1, 1995 President of Seneca until October 1, 1996. June 1, 1989 Executive Vice President of Supply Corporation. October 1, 1994 President of Horizon. September 13, 1995 President of certain other subsidiaries of the Company from prior to 1991. Richard Hare 58 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 James A. Beck 49 President of Seneca. October 1, 1996** Joseph P. Pawlowski 55 Treasurer. December 11, 1980 Senior Vice President of Distribution Corporation. February 20, 1992 Treasurer of Distribution Corporation. January 1, 1981 Treasurer of Supply Corporation. June 1, 1985 Secretary of Supply Corporation. October 1, 1995 Officer of certain other subsidiaries of the Company from prior to 1991. Gerald T. Wehrlin 58 Controller. December 11, 1980 Senior Vice President of Distribution Corporation. April 1, 1991 Controller of Distribution Corporation. January 1, 1981 Controller of Seneca. September 1, 1981 Secretary and Treasurer of Leidy. September 1, 1993 Secretary and Treasurer of Horizon. September 13, 1995 Officer of certain other subsidiaries of the Company from prior to 1991. Walter E. DeForest 55 Senior Vice President of Distribution Corporation. August 1, 1993 President of Leidy. September 1, 1993
Age as of Current Company Date Elected To Name 9/30/96 Positions Current Positions ---- --------- --------------- ----------------- Bruce H. Hale 47 Senior Vice President of Distribution Corporation. April 1, 1991 through February 20, 1992, and again on January 1, 1993*** Vice President of Horizon. September 13, 1995 Dennis J. Seeley 53 Senior Vice President of Supply Corporation. January 1, 1993 David F. Smith 43 Senior Vice President of Distribution Corporation. January 1, 1993 Secretary of Distribution Corporation. June 20, 1986 Officer of certain other subsidiaries of the Company from prior to 1991. * 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. ** Vice President of Seneca from January 1, 1994 through April 30, 1995, Executive Vice President of Seneca from May 1, 1995 through September 30, 1996. *** Senior Vice President of Supply Corporation from February 21, 1992 through December 31, 1992. ITEM 2 PROPERTIES General Information on Facilities The investment of the Company in net property, plant and equipment was $1,709.6 million at September 30, 1996. Approximately 76% of this investment is in the Utility 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. 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 $395.9 million, or 30%, since 1991. The Utility segment 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 14,764 miles of distribution pipeline) and its services represent approximately 58% and 27%, respectively, of the Utility segment's net investment of $855.2 million. The Pipeline and Storage segment represents a net investment of $452.3 million in transmission and storage facilities at September 30, 1996. Transmission pipeline, with a net cost of $143.9 million, represents 32% of this segment's total net investment and includes 2,747 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 494 miles of pipeline. Included in the storage facilities net investment is $85.3 million of gas stored underground-
noncurrent, representing the cost of the gas required to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. 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 $376.0 million at September 30, 1996. Of this amount, Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast regions was $319.0 million, and Seneca's net investment in oil and gas properties in the Appalachian region aggregated $57.0 million. The Regulated Operations' facilities provided the capacity to meet its 1996 peak day sendout, including transportation service, of 1,982 MMcf, which occurred on February 4, 1996. Withdrawals from storage provided approximately 42% of the requirements on that day. Company maps, which are included on the inside fold out cover of the paper copy of the 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. A further discussion of oil and gas producing activities is included in Item 8, Note L-Supplementary Information for Oil and Gas Producing Activities. Note L sets forth proved developed and undeveloped reserve information for Seneca. Supply Corporation holds reserves related to held for future use storage wells. Information on such reserves is included on Supply Corporation's Form 2 "Annual Report of Natural Gas Companies" and Form 15 "Annual Report of Gas Supply" filed with the FERC. 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, 1996, 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 1996 1995 1994 - ------------------------------- ---- ---- ---- Average Sales Price per Mcf of Gas $ 2.35 $ 1.67 $ 2.18 Average Sales Price per Barrel of Oil $19.50 $16.16 $14.86 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 0.31 $ 0.44 $ 0.45 Productive Wells At September 30, 1996 Gas Oil - --------------------- --- --- Productive Wells - gross 2,054 285 - net 1,931 215 Developed and Undeveloped Acreage At September 30, 1996 - --------------------- Developed Acreage - gross 602,684 - net 533,535 Undeveloped Acreage - gross 602,706 - net 563,827
Drilling Activity Productive Dry ------------------ ------------------ For the Year Ended September 30 1996 1995 1994 1996 1995 1994 ---- ---- ---- ---- ---- ---- Net Wells Completed - Exploratory 3 5 5 7 0 4 - Development 7 6 8 0 0 0 Present Activities At September 30, 1996 Wells in Process of Drilling - gross 4 - net 2 There are currently no waterflood projects or pressure maintenance operations of material importance. ITEM 3 Legal Proceedings None 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 1996. 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 <TABLE> <CAPTION> Year Ended September 30: 1996 1995 1994 1993 1992 - ----------------------- ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> Summary of Operations (Thousands) Operating Revenues $1,208,017 $975,496 $1,141,324 $1,020,382 $920,450 ---------- -------- ---------- ---------- -------- Operating Expenses: Purchased Gas 477,357 351,094 497,687 409,005 363,690 Operation and Maintenance 309,206 292,505 291,390 283,230 263,084 Property, Franchise and Other Taxes 99,456 91,837 103,788 95,393 89,158 Depreciation, Depletion and Amortization 98,231 71,782 74,764 69,425 55,726 Income Taxes - Net 66,321 43,879 47,792 41,046 35,231 --------- -------- ---------- ---------- -------- 1,050,571 851,097 1,015,421 898,099 806,889 --------- -------- ---------- ---------- -------- Operating Income 157,446 124,399 125,903 122,283 113,561 Other Income 3,869 5,378 3,656 4,833 5,790 --------- -------- ---------- ---------- -------- Income Before Interest Charges 161,315 129,777 129,559 127,116 119,351 Interest Charges 56,644 53,883 47,124 51,899 59,041 --------- -------- ---------- ---------- -------- Income Before Cumulative Effect 104,671 75,894 82,435 75,217 60,310 Cumulative Effect of Changes in Accounting - - 3,237 - - --------- -------- ---------- ---------- -------- Net Income Available for Common Stock $104,671 $ 75,894 $ 85,672 $ 75,217 $ 60,310 ======== ======== ========== ========== ======== Per Common Share Data Earnings $2.78 $2.03 $2.32* $2.15 $1.94 Dividends Declared $1.65 $1.60 $1.56 $1.52 $1.48 Dividends Paid $1.64 $1.59 $1.55 $1.51 $1.47 Dividend Rate at Year-End $1.68 $1.62 $1.58 $1.54 $1.50 At September 30: Number of Common Shareholders 21,640 21,429 22,465 22,893 23,218 ====== ======== ========== ========== ======== Net Property, Plant and Equipment (Thousands) Regulated: Utility $ 855,161 $ 822,764 $ 787,794 $ 754,466 $ 719,755 Pipeline and Storage 452,305 463,647 443,622 436,547 423,383 ---------- ---------- ---------- ---------- ---------- 1,307,466 1,286,411 1,231,416 1,191,013 1,143,138 ---------- ---------- ---------- ---------- ---------- Nonregulated: Exploration and Production 375,958 339,950 295,418 273,470 261,446 Other 26,167 22,690 18,579 16,209 11,670 ---------- ---------- ---------- ---------- ---------- 402,125 362,640 313,997 289,679 273,116 ---------- ---------- ---------- ---------- ---------- Corporate 15 131 137 122 128 ---------- ---------- ---------- ---------- ---------- Total Net Plant $1,709,606 $1,649,182 $1,545,550 $1,480,814 $1,416,382 ========== ========== ========== ========== ========== Total Assets (Thousands) $2,149,772 $2,036,823 $1,980,806 $1,801,540 $1,760,830 ========== ========== ========== ========== ========== Capitalization (Thousands) Common Stock Equity $ 855,998 $ 800,588 $ 780,288 $ 736,245 $ 632,333 Long-Term Debt, Net of Current Portion 574,000 474,000 462,500 478,417 479,500 ---------- ---------- ---------- ---------- ---------- Total Capitalization $1,429,998 $1,274,588 $1,242,788 $1,214,662 $1,111,833 ========== ========== ========== ========== ========== </TABLE> * 1994 includes Cumulative Effect of Changes in Accounting of $0.09. 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 1996 Compared with 1995 National Fuel's earnings were $104.7 million, or $2.78 per common share, in 1996. This compares with earnings of $75.9 million, or $2.03 per common share, in 1995.
The earnings increase in 1996 was attributable to higher earnings of the Company's Exploration and Production, Utility, and Pipeline and Storage segments, partly offset by lower earnings of the Other Nonregulated segment. Exploration and Production earnings increased because of significant increases in natural gas and oil production combined with higher gas and oil prices. The earnings increase of the Utility segment reflects the positive impact of colder weather, new rates that became effective in September 1995 in both the New York and Pennsylvania jurisdictions, and the results of management's emphasis on controlling operation and maintenance expense. Also, purchased gas expense adjustments in the Utility segment's New York jurisdiction increased 1996 earnings. The Pipeline and Storage segment's earnings increase was attributable to the February 1996 Federal Energy Regulatory Commission (FERC) approval of Supply Corporation's rate case, which became effective on April 1, 1996 retroactive to June 1, 1995. In addition, 1995 Pipeline and Storage earnings included a reserve for previously deferred preliminary survey and investigation charges for the Laurel Fields Storage Project. Partly offsetting the increased earnings of the Pipeline and Storage segment were lower revenues related to unbundled pipeline sales and open access transportation. A special early retirement offer (SERO) to certain salaried, non-union hourly and union employees of both the Utility and Pipeline and Storage segments resulted in a reduction to 1996 earnings for both segments. The decrease in earnings of the Other Nonregulated segment was mainly attributable to withdrawing from an international energy project, which resulted in the expensing of certain pre-operating costs, as well as discontinuance of operations at the Company's pipeline construction subsidiary in 1995. 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 and Utility segments, partly offset by higher earnings of the Pipeline and Storage segment, Other Nonregulated segment, 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 segment's earnings suffered from the warm weather and the impact of lower normalized usage per residential and commercial account. Additionally, the Utility segment's New York jurisdiction recorded additional purchased gas expense associated with lost and unaccounted-for gas. The Pipeline and Storage segment earnings reflect increased revenues associated with unbundled pipeline sales and open access transportation. This increase in earnings 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. Increased earnings of the Company's Other Nonregulated segment 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.
Operating Revenues Year Ended September 30 (Thousands) 1996 1995 1994 - ----------------------------------------------------------------------------- Utility Retail Revenues: Residential $ 678,395 $569,603 $ 677,068 Commercial 165,824 137,869 177,249 Industrial 25,648 18,269 31,096 - ----------------------------------------------------------------------------- 869,867 725,741 885,413 Off-System Sales 30,907 18,255 6,930 Transportation 49,180 37,183 34,419 Other 4,372 4,885 4,911 - ----------------------------------------------------------------------------- 954,326 786,064 931,673 - ----------------------------------------------------------------------------- Pipeline and Storage Storage Service 67,975 59,826 58,971 Transportation 92,401 88,766 90,416 Other 16,177 15,995 3,734 - ----------------------------------------------------------------------------- 176,553 164,587 153,121 - ----------------------------------------------------------------------------- Exploration and Production 114,462 56,232 70,261 Other Nonregulated 68,930 57,075 72,036 - ----------------------------------------------------------------------------- 183,392 113,307 142,297 - ----------------------------------------------------------------------------- Less: Intersegment Revenues 106,254 88,462 85,767 - ----------------------------------------------------------------------------- Total Operating Revenues $1,208,017 $975,496 $1,141,324 ============================================================================= Operating Income (Loss) Before Income Taxes Year Ended September 30 (Thousands) 1996 1995 1994 - ----------------------------------------------------------------------------- Utility $115,257 $ 83,774 $ 90,584 Pipeline and Storage 72,914 67,884 62,302 Exploration and Production 46,408 16,404 21,767 Other Nonregulated (8,581) 3,021 2,505 Corporate (2,231) (2,805) (3,463) - ----------------------------------------------------------------------------- Total Operating Income Before Income Taxes $223,767 $168,278 $173,695 ============================================================================= System Natural Gas Volumes Year Ended September 30 (billion cubic feet) 1996 1995 1994 - ------------------------------------------------------------------------- Regulated Gas Sales Residential 90.7 79.9 90.6 Commercial 24.9 22.2 26.9 Industrial 6.0 4.8 6.5 Off-System 11.1 9.4 3.3 - ------------------------------------------------------------------------- 132.7 116.3 127.3 - ------------------------------------------------------------------------- Nonregulated Gas Sales Gas Sales for Resale - 0.4 0.3 Production (equivalent billion cubic feet) 49.2 25.4 29.5 - ------------------------------------------------------------------------- 49.2 25.8 29.8 - ------------------------------------------------------------------------- Total Gas Sales 181.9 142.1 157.1 - ------------------------------------------------------------------------- Transportation Utility 58.2 52.8 52.2 Pipeline and Storage 325.0 290.8 296.6 Nonregulated 0.6 2.5 1.4 - ------------------------------------------------------------------------- 383.8 346.1 350.2 - ------------------------------------------------------------------------- Marketing Volumes 20.5 18.8 18.2 - ------------------------------------------------------------------------- Less Intersegment Volumes: Transportation 156.7 154.2 164.8 Production 4.8 5.0 2.5 Gas Sales 0.8 - 0.1 Marketing 0.1 - - - ------------------------------------------------------------------------- 162.4 159.2 167.4 - ------------------------------------------------------------------------- Total System Natural Gas Volumes 423.8 347.8 358.1 =========================================================================
Utility Operating Revenues 1996 Compared with 1995 Operating revenues increased $168.3 million in 1996 compared with 1995. This increase reflects general rate increases of $14.2 million and $6.0 million, respectively, in the New York and Pennsylvania rate jurisdictions, effective in September 1995. The increase also reflects the recovery of increased gas costs mainly because of higher gas sales of 16.4 billion cubic feet (Bcf) as well as a 25% increase in the average cost of purchased gas (see discussion of purchased gas below under the heading "Purchased Gas"). In addition, higher transportation volumes of 5.4 Bcf contributed to the increase in operating revenues. The increase in gas sales and transportation volumes can be attributed mainly to weather in Distribution Corporation's service territory that was, on average, 16.7% colder than the prior year. Transportation volumes also increased as a result of new customers and increased production at various manufacturing facilities in Distribution Corporation's service territory which more than offset lower transportation volumes to a cogeneration customer. The increase in off-system sales reflects the continued utilization of available capacity on the upstream pipelines serving Distribution Corporation and other customers from the southwestern to northeastern regions of the United States. Distribution Corporation, in each of its jurisdictions, has a mechanism whereby it retains a portion of the margin on these off-system sales. 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 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 1994. 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. Operating Income 1996 Compared with 1995 Operating income before income taxes increased $31.5 million in 1996 compared with 1995. The increase reflects higher gas revenue, as discussed above. It also reflects certain purchased gas cost adjustments associated with lost and unaccounted-for gas in Distribution Corporation's New York jurisdiction. In the New York jurisdiction, an annual reconciliation of purchased gas costs is performed in August of each year. Based on this reconciliation, an amount is determined that is either over or under the amount that is allowed to be recovered by the Public Service Commission of the State of New York (PSC). Any amount over the recoverable amount increases purchased gas expense and any amount under the recoverable amount decreases purchased gas expense. In 1995, this reconciliation resulted in an additional $4.3 million of purchased gas expense. However, based upon a recently completed thorough review by the Company, it was determined that the estimated additional purchased gas expense recognized in 1995 was overstated by $6.5 million. Therefore, purchased gas expense for 1996 was reduced to reflect this adjustment. In 1996, the annual reconciliation of purchased gas costs also resulted in the recognition of purchased gas expense for excess lost and unaccounted-for gas. The amount charged to purchased gas expense in 1996 based on the 1996 reconciliation was $2.3 million. The net impact of these purchased gas cost adjustments was to reduce 1996 purchased gas expense by $4.2 million. Offsetting the net increases discussed above was the impact of the SERO offered to certain salaried, non-union hourly and union employees of Distribution Corporation. The SERO resulted in additional operating expenses in the Utility segment of $6.4 million in 1996. The SERO was undertaken as a means to reduce future costs.
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 addition, in periods of colder than normal weather, the WNC benefits Distribution Corporation's New York customers. In 1996, the WNC in New York resulted in a benefit to customers of $10.6 million as weather, overall, was colder than normal for the period of October 1995 through May 1996. 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 17.1% colder than last year and 8.1% colder than normal. The colder weather in 1996 compared with 1995 had a positive impact on the Pennsylvania rate jurisdiction's pretax operating income of approximately $7.6 million, of which approximately $3.9 million relates to colder than normal weather in 1996 and approximately $3.7 million is because 1995 was warmer than normal. 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 purchased 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 segment recognized an additional $4.3 million of purchased gas expense as a result of this reconciliation. 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. In the Pennsylvania service territory, weather was 14.2% warmer than 1994 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. Degree Days Percent Colder (Warmer) Than ------------------- Year Ended September 30 Normal Actual Normal Last Year - ------------------------------------------------------------------------------ 1996: Buffalo 6,728 7,203 7.1% 16.5% Erie 6,258 6,764 8.1% 17.1% - ------------------------------------------------------------------------------ 1995: Buffalo 6,693 6,181 (7.6%) (11.4%) Erie 6,128 5,774 (5.8%) (14.2%) - ------------------------------------------------------------------------------ 1994: Buffalo 6,710 6,975 3.9% 3.6% Erie 6,202 6,726 8.4% 9.6% - ------------------------------------------------------------------------------ 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 other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation can satisfy a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation's average cost of purchased gas, including the cost of transportation and storage, was $3.98 per thousand cubic feet (Mcf) in 1996, an increase of 25% from the average cost of $3.19 per Mcf in 1995. The average cost of purchased gas in 1995 was 15% lower than the $3.74 per Mcf in 1994.
Pipeline and Storage Operating Revenues 1996 Compared with 1995 Operating revenues increased $12.0 million in 1996 compared with 1995. Higher transportation and storage revenues reflect the impact of a $6.0 million rate increase effective on April 1, 1996 retroactive to June 1, 1995. The retroactive rates added approximately $2.0 million to revenues in 1996 that relate to 1995. Higher volumes of gas transported as well as certain surcharge adjustments also increased revenues in 1996. Other operating revenues increased only slightly, but include an increase of approximately $4.6 million related to cashouts (a cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas it receives in excess of amounts delivered into Supply Corporation's system by the customer's shipper). Cashout revenues are offset by purchased gas expense. A decrease of approximately $4.4 million related to unbundled pipeline sales and open access transportation reduced other operating revenue for the year. 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 addressed and clarified financial reporting aspects for unbundled pipeline sales and open access transportation. Operating Income 1996 Compared with 1995 Operating income before income taxes increased $5.0 million in 1996 compared with 1995. This increase reflects the revenue increase discussed above as well as the recording of a $3.7 million reserve in the fourth quarter of 1995 for previously deferred preliminary survey and investigation charges for the Laurel Fields Storage Project, as discussed below. Partly offsetting the increase was the impact of higher operating expenses, including the SERO offered to certain salaried, non-union hourly and union employees of Supply Corporation. The SERO resulted in additional operating expenses in the Pipeline and Storage segment of $1.8 million in 1996. The SERO was undertaken as a means to reduce future costs. 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 expenses 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. This project was delayed as there was not sufficient interest to proceed with the project at the time. Exploration and Production Operating Revenues 1996 Compared with 1995 Operating revenues increased $58.2 million in 1996 compared with 1995. This increase reflects higher natural gas and oil production coupled with increased prices for both. As indicated in the tables below, natural gas production rose to a level of 38.8 Bcf, an 85% increase over the prior year. Oil production of 1,742,000 barrels (bbls) was more than twice the prior year production. Last year, natural gas and oil production was delayed when prices were low in order to preserve the value received for reserves. Increased production continues to be driven by this segment's Gulf Coast program. Offshore finds at West Cameron 552 and Vermilion 252 and the acquisition of West Delta Block 30 in September 1995 are the major contributors to production increases for the year. In the West Coast program, the production increases are primarily a result of the 1995 Hamp Lease acquisition in California. Weighted average prices received for this segment's natural gas production increased by $0.68 per Mcf to $2.35 per Mcf and the weighted average prices received for oil production increased $3.34
per bbl to $19.50 per bbl. These prices do not reflect gains and losses from hedging activities. For 1996, this segment recognized a pre-tax loss on hedging of approximately $11.8 million compared with a pre-tax gain of $6.9 million in 1995. Gains or losses on hedging activities are offset by lower or higher prices received for actual natural gas and crude oil production. The Company utilizes its hedging program to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil thereby providing more stability to the operating results of this business segment. 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 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 1995 increased 9%, this was not enough to offset the lower production level. The fluctuations in prices noted above do not include the impact of hedging activities. A pre-tax gain of approximately $6.9 million was recognized from hedging activities in 1995. Production Volumes Year Ended September 30 1996 1995 1994 - ----------------------------------------------------------- Gas Production (million cubic feet) Gulf Coast 32,355 14,294 16,296 West Coast 990 840 706 Appalachia 5,422 5,808 6,271 - ----------------------------------------------------------- 38,767 20,942 23,273 =========================================================== Oil Production (thousands of barrels) Gulf Coast 1,195 287 615 West Coast 533 433 404 Appalachia 14 19 11 - ----------------------------------------------------------- 1,742 739 1,030 =========================================================== Weighted Average Prices Year Ended September 30 1996 1995 1994 - ---------------------------------------------------------- Weighted Average Gas Price/Mcf Gulf Coast $2.33 $1.56 $2.03 West Coast $1.25 $1.33 $1.58 Appalachia $2.65 $2.01 $2.65 Weighted Average Price $2.35 $1.67 $2.18 - ------------------------------------------------------------ Weighted Average Oil Price/bbl Gulf Coast $20.45 $16.94 $15.54 West Coast $17.41 $15.66 $13.79 Appalachia $18.43 $15.72 $15.92 Weighted Average Price $19.50 $16.16 $14.86 Operating Income 1996 Compared with 1995 Operating income before income taxes increased $30.0 million in 1996 compared with 1995. This increase reflects the higher operating revenues discussed above, partly offset by higher depletion expense, which is directly related to higher revenues. Higher other operating expense (lease operating expenses and production taxes) due to increased production also partly offset the increase in revenues.
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. Lower other operating expense (lease operating expenses and production taxes) also partly offset the decrease in revenues. Other Nonregulated Operating Revenues 1996 Compared with 1995 Operating revenues increased $11.9 million in 1996 compared with 1995. The increase primarily reflects higher operating revenues from NFR, the Company's gas marketing subsidiary, largely because of an increase in marketing volumes and higher natural gas prices. Offsetting this increase was a decrease in operating revenues from UCI, the Company's discontinued pipeline construction subsidiary. 1995 Compared with 1994 Operating revenues decreased $15.0 million in 1995 compared with 1994. This decrease reflects lower operating revenues from UCI as a result of management's decision to discontinue its pipeline construction operations. The decrease also reflects lower revenues from NFR largely because of lower natural gas prices in 1995 compared with 1994. Operating Income 1996 Compared with 1995 The Other Nonregulated segment experienced an operating loss before income taxes of $8.6 million in 1996 compared with operating income before income taxes of $3.0 million in 1995. Horizon, the Company's foreign and domestic energy projects subsidiary, was the main factor in this decrease. In August 1996, Horizon withdrew from participation in the development of a 151 megawatt power plant near Kabirwala, Punjab Province, in east-central Pakistan (Kabirwala Project). As a result of this withdrawal, certain pre-operating costs were charged to earnings. Total pre-tax charges in 1996 associated with the Kabirwala Project were approximately $9.0 million. UCI also experienced a significant decrease in operating income before income taxes as a result of discontinuing its pipeline construction operations late in 1995. NFR experienced an increase in operating income before income taxes based primarily on increased volumes marketed. 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. Income Taxes, Other Income and Interest Charges Income Taxes Income taxes increased $22.4 million in 1996 mainly because of an increase in pretax income. The opposite was true in 1995 as income taxes decreased because of a decrease in pretax income. Income taxes in 1996 and 1995 reflect lower Section 29 nonconventional fuel tax credits. These credits, which relate to production from qualified gas wells drilled by December 31, 1992, decreased to $0.5 million in 1996 from $0.9 million in 1995 and $1.7 million in 1994. These credits are a direct reduction of income tax expense. Other Income Other income decreased $1.5 million in 1996, primarily because other income in 1995 reflected 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.
Interest Charges Interest on long-term debt did not change significantly in 1996 and increased $4.2 million in 1995. Although there was a higher average amount of long-term debt outstanding in 1996 compared with 1995, this was offset by a lower average interest rate. The increase in 1995 can be attributed to a higher average amount of long-term debt in 1995 compared with 1994. Other interest charges increased $2.8 million and $2.6 million, respectively, in 1996 and 1995. The increase in 1996 resulted primarily from a higher average balance of outstanding short-term borrowings offset partly by a lower weighted average interest rate on such borrowings. 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. Additionally, both 1996 and 1995 experienced an increase in interest expense as a result of interest on Amounts Payable to Customers. 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) 1996 1995 1994 - ------------------------------------------------------------------- Provided by Operating Activities $168.5 $174.4 $199.8 Capital Expenditures (171.6) (182.8) (135.1) Short-Term Debt, Net Change 52.1 35.1 (84.3) Long-Term Debt, Net Change 11.2 3.1 79.5 Issuance of Common Stock 9.0 2.5 9.1 Common Dividends (61.2) (59.2) (57.2) Other Investing Activities (1.4) 10.6 3.6 - ------------------------------------------------------------------- Net Increase (Decrease) in Cash and Temporary Cash Investments $6.6 $(16.3) $ 15.4 =================================================================== 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 and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather also significantly impact cash flow. The Company considers supplier refunds and over-recovered purchased gas costs as a substitute for short-term borrowings. The impact of weather on cash flow is tempered in the Utility segment's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's straight fixed-variable (SFV) rate design. Net cash provided by operating activities totalled $168.5 million in 1996, a decrease of $5.9 million compared with the $174.4 million provided by operating activities in 1995. This decrease reflects higher receivable balances, mainly in the Utility and Exploration and Production segments, and a decrease in amounts owed to customers in the Utility segment. These are offset partly by higher net income and higher payable balances in the Utility and Exploration and Production segments.
Investing Cash Flow Capital Expenditures Capital expenditures totalled $171.6 million in 1996. The table below presents these expenditures by business segment: Year Ended September 30 (in millions) 1996 - ------------------------------------------------- Utility $ 63.7 Pipeline and Storage 22.3 Exploration and Production 83.6 Other Nonregulated 3.2 - ------------------------------------------------- 172.8 - ------------------------------------------------- Intersegment Elimination (1.2) - ------------------------------------------------- $171.6 ================================================= Most of the Utility segment'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. The bulk of the Pipeline and Storage segment's capital expenditures were made for additions, improvements and replacements to this segment's transmission and storage systems. The Exploration and Production segment spent approximately $60.2 million on its offshore program in the Gulf of Mexico, including offshore lease acquisitions and drilling and construction expenditures. Lease acquisitions included the acquisition of Galveston Block 225, Vermilion 309, and Viosca Knoll 432 through federal lease sales. Approximately $23.4 million was spent on the Exploration and Production segment's onshore program, including horizontal drilling in central Texas and recompletion activity in California. Finding and development costs, which exclude the effect of property purchases and sales and provides an indicator of the efficiency and performance of a company's drilling program, were $1.25 per Mcf equivalent in 1996. Going back to 1991, the inception of Seneca's offshore program, the six-year average of finding and development costs is $0.98 per Mcf equivalent. Other Nonregulated capital expenditures consisted primarily of timberland purchases. The Company's estimated capital expenditures for the next three years are:1 Year Ended September 30 (in millions) 1997 1998 1999 - -------------------------------------------------------------------- Utility $61.9 $57.9 $56.9 Pipeline and Storage 31.6 28.0 20.5 Exploration and Production 116.2 116.0 115.9 Other Nonregulated 4.3 4.3 4.3 - -------------------------------------------------------------------- $214.0 $206.2 $197.6 ==================================================================== Estimated expenditures for the Utility segment 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.1 Estimated expenditures for the Pipeline and Storage segment in 1997 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines.1 Approximately $6.4 million is included in the 1997 budget for the proposed 1997 Niagara Expansion Project, which would provide approximately 47.3 million cubic feet (MMcf) per day of firm winter capacity and 21.0 MMcf per day of firm non-winter capacity from the Niagara Falls, New York import point to interconnections at Leidy and Wharton, Pennsylvania.1 An additional $4.9 million is included in the 1998 budget for this proposed project.1 An open season was recently completed to ascertain
customer interest in the proposed 1998/1999 Niagara Expansion Project, which would expand transportation capacity from the Canadian border at Niagara Falls, New York, to Leidy, Pennsylvania, by 250 - 500 MMcf per day.1 The preliminary interest indicated the Company is substantially oversubscribed for such a project. At an expansion level of 500 MMcf per day, the total project cost is estimated to be approximately $240 million over a two-year period.1 However, no amount has been included in the budget for this proposed project as the timing of the "go-ahead" will depend on several factors, the major one being the number of signed precedent agreements received as a result of the open season.1 Estimated capital expenditures in 1997 for the Exploration and Production segment are approximately 39% higher than capital spending in 1996 as the Company sees significant opportunities for growth in this segment.1 These expenditures will be directed mainly toward developing Seneca's Gulf Coast offshore prospects, reserve acquisitions and significantly expanding exploration activities.1 In late September 1996, Seneca was the high bidder on five of twelve bids placed at the federal Western Gulf of Mexico Sale 161. Two of those leases have been awarded. In October 1996, Seneca was the successful bidder on five state tracts in Texas state waters. At the State of Louisiana lease sale held in October 1996, Seneca's bid on 1,229.55 acres in the Eugene Island area was accepted. The Company's capital expenditure program is under continuous review. The amounts are subject to modification for opportunities 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 segment 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.1 Other Investing Activities Other cash provided by or used in investing activities reflects cash received on the sale of the Company's investment in property, plant and equipment and cash used for other investments. The Company is continuing to pursue investment opportunities in the international arena.1 On June 25, 1996, Horizon purchased Beheer-en-Beleggingsmaatschappij Bruwabel B.V. (Bruwabel). Bruwabel is a Dutch company that in turn directly or indirectly owns three Czech corporations. Bruwabel's principal assets are a power development group, which is involved in development initiatives for the conversion of district heating plants into cogeneration facilities, and a district heating plant located in the eastern part of the Czech Republic. Horizon plans to convert the heating plant to a combined-cycle cogeneration facility, with electrical output of up to 50 Megawatts.1 In November 1996, Supply Corporation entered into a Memorandum of Understanding (the MOU) with Green Canyon Gathering Company, a subsidiary of Tenneco Energy, regarding a project to develop, construct, own and operate natural gas gathering and processing facilities offshore and onshore Louisiana (the Project). The total cost of the Project is estimated at approximately $200 million.1 The MOU provides for the parties to (i) share past and future development costs for the Project through January 1, 1997, and thereafter as agreed by the parties, (ii) negotiate toward definitive agreements to be signed about January 1, 1997, to form one or more 50-50 partnerships, and (iii) negotiate toward definitive agreements to finance, develop, build, own and operate the Project. If the definitive agreements are not executed, or if the Project is not constructed, Supply Corporation's share of the development costs through January 1, 1997 is estimated not to exceed $2 million, for which it is unlikely Supply Corporation would be reimbursed.1 Supply Corporation intends to use short-term borrowings to finance construction of the Project.1 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.1 The Company retired $88.5 million of maturing medium-term notes during 1996. In December 1995, the Company retired $38.5 million of 8.90% medium-term notes and $20.0 million of 8.875% medium-term notes. In September 1996, the Company retired $30.0 million of 4.53% medium-term notes. Short-term borrowings were used to retire these notes. In March 1996, the Company issued $100.0 million of 5.58% medium-term notes due in March 1999. After reflecting underwriting discounts and commissions, the net proceeds to the Company amounted to $99.7 million. The Company's embedded cost of long-term debt was 7.0% and 7.3% at September 30, 1996 and 1995, respectively. Consolidated short-term debt increased $52.1 million during 1996. 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. In addition, the Company considers supplier refunds and over-recovered purchased gas costs as a substitute for short-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. The Company's present liquidity position is believed to be adequate to satisfy known demands.1 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 $689.0 million in additional long-term unsecured indebtedness at September 30, 1996, in light of then current long-term interest rates. In addition, at September 30, 1996, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $400.3 million of short-term debt. The Company currently has authorization from the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended, to issue and sell up to $150.0 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.1 The Company expects that it will issue new debentures and/or medium-term notes late in calendar 1997 to retire $50.0 million of 6.42% medium-term notes maturing in November 1997.1 The Company, through Seneca, has entered into certain price swap agreements to manage 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 1996, Seneca utilized natural gas and crude oil price swap agreements with notional amounts of 23.0 equivalent Bcf and 1,071,000 equivalent bbl, respectively. These hedging activities resulted in the recognition of a pre-tax loss of approximately $11.8 million. This loss was offset by higher prices received for actual natural gas and crude oil production. At September 30, 1996, Seneca had natural gas price swap agreements outstanding with a notional amount of approximately 35.7 equivalent Bcf at prices ranging from $1.71 per Mcf to $2.10 per Mcf. The weighted average fixed price of these swap agreements is approximately $1.93 per Mcf. Seneca also had crude oil price swap agreements outstanding at September 30, 1996 with a notional amount of 1,818,000 equivalent bbl at prices ranging from $17.40 per bbl to $18.71 per bbl. The weighted average fixed price of these swap agreements is approximately $17.96 per bbl. In addition, the Company has SEC authority to enter into certain interest rate swap agreements. For further discussion of the Company's derivative financial instruments, see disclosure in Note F - Financial Instruments under the heading "Derivative Financial Instruments" in Item 8 of this report.
The Company's credit risk is the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations related to investments, such as temporary cash investments and cash surrender values of insurance contracts, and derivative financial instruments. 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.1 See further discussion in Note F-Financial Instruments under the heading "Credit Risk" 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 nor have a material adverse effect on the financial condition of the Company at this time.1 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%. A two-year settlement with the parties in this rate proceeding has been approved by the PSC. The settlement calls for annual base rate increases of $7.2 million in each of fiscal years beginning October 1, 1996 and 1997 with no specified rate of return on equity. Generally, earnings above a 12% return on equity (excluding certain items and determined on a cumulative basis over the three years ending September 30, 1998) will be shared equally between shareholders and ratepayers. However, the settlement includes a number of incentives which would impact return on equity. Distribution Corporation may earn a maximum of 25 basis points or incur a maximum penalty of 50 basis points on common equity based on its customer service. The incentives relate to customer satisfaction, customer complaints, appointments, new service installations, telephone response, adjusted bills and estimated meter readings. In addition, there is a gas cost incentive mechanism designed to compare Distribution's spot gas purchases to monthly gas cost targets. Certain costs above the targets and savings below the targets will be shared equally between Distribution Corporation and its customers. 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. The order included certain incentive mechanisms that allowed the PSC to administer penalties determined by Distribution Corporation's ability to maintain required performance levels. The incentives related to: response time to customer inquiries and complaints; billing accuracy; keeping appointments for service; and efficiency in the installation of new service lines. Distribution Corporation did not incur any penalties as a result of these incentive mechanisms. Pennsylvania Jurisdiction Distribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission (PaPUC). Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future. 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 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.
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 The New York and Pennsylvania regulatory commissions have instituted several generic proceedings related to, among other things, 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. On March 28, 1996, the PSC issued an order directing the state's LDC's, including Distribution Corporation, to file additional tariff amendments regarding this proceeding. On April 30, 1996, Distribution Corporation submitted a filing, effective May 1, 1996 on a temporary basis, proposing to amend its services to provide a framework for small customer aggregation in compliance with the PSC's March 28, 1996 Order (Distribution Corporation already offers unbundled, flexible service to its commercial and industrial customers). The changes provide the option for all customers to choose from whom they want to buy gas, which could be Distribution Corporation, another utility, or a non-utility supplier or marketer. If a customer purchases gas from a supplier other than Distribution Corporation, the supplier would obtain and transport the gas to Distribution Corporation's pipeline system and Distribution Corporation would then deliver the gas to the customer. Distribution Corporation would continue to be responsible for maintaining its pipelines and responding to safety calls, but billing and other traditional services would be assumed by the alternate supplier. On September 12, 1996, the PSC issued an order approving the April 30, 1996 filing, subject to additional changes. Further revisions were filed as directed for an effective date of October 1, 1996. Additional changes in retail services are anticipated as this proceeding continues.1 Generic Affordability/Gas Cost Incentive Proceeding. This proceeding was established to investigate the development of guidelines for "affordable" natural gas utility service and, on a separate track, an appropriate gas cost incentive mechanism. However, guidelines on affordability and gas cost incentive mechanisms are currently being addressed by the PSC on a case-by-case basis. 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.1 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%. In
February 1996, the FERC approved a settlement authorizing an annual rate increase of approximately $6.0 million with a return on equity of 11.3%. The new rates were put into effect on April 1, 1996, retroactive to June 1, 1995. With this settlement, Supply Corporation agreed not to seek recovery for increased cost of service until April 1, 1998. As part of the settlement discussed above, Supply Corporation also agreed not to seek recovery of revenues related to certain terminated service from other storage customers until April 1, 2000, as long as the terminations were not greater than approximately 30% of the terminable service. Supply Corporation did receive notification of the termination of 3.3 Bcf of such service, effective March 31, 1996. However, Supply Corporation has successfully obtained executed contracts for all 3.3 Bcf at discounted prices. Such discounts will not have a material impact on the results of operations for Supply Corporation.1 An open season was recently completed concerning an additional 2.1 Bcf of such storage service, which will become available on April 1, 1997. Supply Corporation obtained executed contracts for 1.0 Bcf of this storage service at discounted prices and will continue to market the remaining 1.1 Bcf. Management does not anticipate a problem in marketing the remaining 1.1 Bcf.1 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 $8.7 million to $10.1 million.1 At September 30, 1996, Distribution Corporation has recorded the minimum liability of $8.7 million. 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 potentially responsible parties at each site and the portion, if any, attributed to Distribution Corporation.1 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 and Pennsylvania, Distribution Corporation is recovering site investigation and remediation costs in rates. For further discussion, see disclosure in Note H - Commitments and Contingencies under the heading "Environmental Matters" 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 its capital spending and the regulated nature of two 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.1 Safe Harbor for Forward-Looking Statements The Company is including the following cautionary statement in this combined Annual Report to Shareholders/Form 10-K to make applicable and take advantage
of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained herein, including those which are designated with a "1", are forward-looking statements and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that management's expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statement: 1. Changes in economic conditions, demographic patterns and weather conditions 2. Changes in the availability and/or price of natural gas and oil 3. Inability to obtain new customers or retain existing ones 4. Significant changes in competitive factors affecting the Company 5. Governmental/regulatory actions and initiatives, including those affecting financings, allowed rates of return, industry and rate structure, franchise renewal, and environmental/safety requirements 6. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries 7. Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays 8. Occurrences affecting the Company's ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments 9. Ability to successfully identify and finance oil and gas property acquisitions and ability to operate existing and any subsequently acquired properties 10. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves 11. Inability of the various counterparties to meet their obligations with respect to the Company's financial instruments 12. Regarding foreign operations - changes in foreign trade and monetary policies, laws and regulations related to foreign operations, political and governmental changes, inflation and exchange rates, taxes and operating conditions 13. Significant changes in tax rates or policies or in rates of inflation or interest 14. Significant changes in the Company's relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur
15. Changes in accounting principles and/or the application of such principles to the Company The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof. ITEM 8 Financial Statements and Supplementary Data Index to Financial Statements - ----------------------------- Page ---- Financial Statements: Report of Independent Accountants 46 Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 1996 47 Consolidated Balance Sheets at September 30, 1996 and 1995 48 - 49 Consolidated Statement of Cash Flows, three years ended September 30, 1996 50 Notes to Consolidated Financial Statements 51 - 72 Financial Statement Schedules: For the three years ended September 30, 1996 II-Valuation and Qualifying Accounts 73 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1996, 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 30, 1996, except as to Note H, which is as of November 8, 1996
National Fuel Gas Company ------------------------- Consolidated Statements of Income and Earnings ---------------------------------------------- Reinvested in the Business -------------------------- Year Ended September 30 (Thousands of Dollars, Except Per Common Share Amounts) 1996 1995 1994 ---- ---- ---- Income Operating Revenues $1,208,017 $ 975,496 $1,141,324 ---------- ---------- ---------- Operating Expenses Purchased Gas 477,357 351,094 497,687 Operation 283,844 266,786 260,411 Maintenance 25,362 25,719 30,979 Property, Franchise and Other Taxes 99,456 91,837 103,788 Depreciation, Depletion and Amortization 98,231 71,782 74,764 Income Taxes - Net 66,321 43,879 47,792 ---------- ---------- ---------- 1,050,571 851,097 1,015,421 ---------- ---------- ---------- Operating Income 157,446 124,399 125,903 Other Income 3,869 5,378 3,656 ---------- ---------- ---------- Income Before Interest Charges 161,315 129,777 129,559 ---------- ---------- ---------- Interest Charges Interest on Long-Term Debt 40,872 40,896 36,699 Other Interest 15,772 12,987 10,425 ---------- ---------- ---------- 56,644 53,883 47,124 ---------- ---------- ---------- Income Before Cumulative Effect 104,671 75,894 82,435 Cumulative Effect of Changes in Accounting - - 3,237 ---------- ---------- ---------- Net Income Available for Common Stock 104,671 75,894 85,672 Earnings Reinvested in the Business Balance at Beginning of Year 380,123 363,854 335,907 ---------- ---------- ---------- 484,794 439,748 421,579 Dividends on Common Stock 61,920 59,625 57,725 ---------- ---------- ---------- Balance at End of Year $ 422,874 $ 380,123 $ 363,854 ========== ========== ========== Earnings Per Common Share Income Before Cumulative Effect $2.78 $2.03 $2.23 Cumulative Effect of Changes in Accounting - - .09 ---------- ---------- ---------- Net Income Available for Common Stock $2.78 $2.03 $2.32 ========== ========== ========== Weighted Average Common Shares Outstanding 37,613,305 37,396,875 37,046,249 ========== ========== ========== See Notes to Consolidated Financial Statements
National Fuel Gas Company ------------------------- Consolidated Balance Sheets --------------------------- At September 30 (Thousands of Dollars) 1996 1995 ---- ---- Assets Property, Plant and Equipment $2,471,063 $2,322,335 Less - Accumulated Depreciation, Depletion and Amortization 761,457 673,153 ---------- ---------- 1,709,606 1,649,182 ---------- ---------- Current Assets Cash and Temporary Cash Investments 19,320 12,757 Receivables - Net 96,740 75,933 Unbilled Utility Revenue 20,778 20,838 Gas Stored Underground 34,727 25,589 Materials and Supplies - at average cost 21,544 24,374 Prepayments 27,872 29,753 ---------- ---------- 220,981 189,244 ---------- ---------- Other Assets Recoverable Future Taxes 88,832 92,574 Unamortized Debt Expense 25,193 26,976 Other Regulatory Assets 57,086 37,040 Deferred Charges 7,377 8,653 Other 40,697 33,154 ---------- ---------- 219,185 198,397 ---------- ---------- $2,149,772 $2,036,823 ========== ========== See Notes to Consolidated Financial Statements
National Fuel Gas Company ------------------------- Consolidated Balance Sheets --------------------------- At September 30 (Thousands of Dollars) 1996 1995 ---- ---- Capitalization and Liabilities Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 100,000,000 Shares; Issued and Outstanding - 37,851,655 Shares and 37,434,363 Shares, Respectively $ 37,852 $ 37,434 Paid In Capital 395,272 383,031 Earnings Reinvested in the Business 422,874 380,123 ---------- ---------- Total Common Stock Equity 855,998 800,588 Long-Term Debt, Net of Current Portion 574,000 474,000 ---------- ---------- Total Capitalization 1,429,998 1,274,588 ---------- ---------- Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 199,700 147,600 Current Portion of Long-Term Debt - 88,500 Accounts Payable 64,610 53,842 Amounts Payable to Customers 4,618 51,001 Other Accruals and Current Liabilities 82,520 60,440 ---------- ---------- 351,448 401,383 ---------- ---------- Deferred Credits Accumulated Deferred Income Taxes 281,207 280,441 Taxes Refundable to Customers 21,005 21,601 Unamortized Investment Tax Credit 12,711 13,380 Other Deferred Credits 53,403 45,430 ---------- ---------- 368,326 360,852 ---------- ---------- Commitments and Contingencies - - ---------- ---------- $2,149,772 $2,036,823 ========== ========== See Notes to Consolidated Financial Statements
National Fuel Gas Company ------------------------- Consolidated Statement of Cash Flows ------------------------------------ <TABLE> <CAPTION> Year Ended September 30 (Thousands of Dollars) 1996 1995 1994 <S> <C> <C> <C> ---- ---- ---- Operating Activities Net Income Available for Common Stock $104,671 $ 75,894 $ 85,672 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities Cumulative Effect of Changes in Accounting - - (3,237) Depreciation, Depletion and Amortization 98,231 71,782 74,764 Deferred Income Taxes 3,907 8,452 4,853 Other 4,540 275 5,780 Change in: Receivables and Unbilled Utility Revenue (20,747) 16,034 863 Gas Stored Underground and Materials and Supplies (6,308) 5,733 (15,539) Unrecovered Purchased Gas Costs - - 20,772 Prepayments 1,881 (9,144) (3,017) Accounts Payable 10,768 (14,451) 23,774 Amounts Payable to Customers (46,383) 12,287 (2,062) Other Accruals and Current Liabilities 18,200 (1,305) 3,072 Other Assets and Liabilities - Net (291) 8,804 4,119 -------- -------- -------- Net Cash Provided by Operating Activities 168,469 174,361 199,814 -------- -------- -------- Investing Activities Capital Expenditures (171,567) (182,826) (135,084) Other (1,366) 10,646 3,586 -------- -------- -------- Net Cash Used in Investing Activities (172,933) (172,180) (131,498) -------- -------- -------- Financing Activities Change in Notes Payable to Banks and Commercial Paper 52,100 35,100 (84,300) Net Proceeds from Issuance of Long-Term Debt 99,650 99,099 99,415 Reduction of Long-Term Debt (88,500) (96,000) (19,917) Proceeds from Issuance of Common Stock 8,956 2,555 9,064 Dividends Paid on Common Stock (61,179) (59,194) (57,157) -------- -------- -------- Net Cash Provided by (Used in) Financing Activities 11,027 (18,440) (52,895) -------- -------- -------- Net Increase (Decrease) in Cash and Temporary Cash Investments 6,563 (16,259) 15,421 Cash and Temporary Cash Investments at Beginning of Year 12,757 29,016 13,595 -------- -------- -------- Cash and Temporary Cash Investments at End of Year $ 19,320 $ 12,757 $ 29,016 ======== ======== ======== </TABLE> 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. 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 and other 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 full-cost ceiling). The present value of estimated future net revenues is computed based on end-of-year prices adjusted for contracted price changes. At September 30, 1996, Seneca's capitalized costs under the full-cost method of accounting were well below the full-cost ceiling. There are certain factors, including price declines, which could lower the full-cost ceiling and 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 $98.4 million in 1996, $73.1 million in 1995 and $75.7 million in 1994, and were equivalent to 4.4% in 1996, 3.5% in 1995 and 3.9% in 1994 of average depreciable property, plant and equipment for those years. Gas Stored Underground - Current Gas stored underground - current is carried at lower of cost or market, on a last-in, first-out (LIFO) method. 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 1996, 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 $19.0 million at September 30, 1996. 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. Foreign Currency Translation The functional currency for the Company's foreign operations is the applicable local currency. The translation from the applicable foreign currency to U. S. dollars is performed for balance sheet accounts using current exchange ratios in effect at the balance sheet date and for revenue and expense accounts using an average exchange rate during the period. The gain which resulted from foreign currency translation during 1996 was immaterial. Income Taxes The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment Tax Credit, prior to its repeal in 1986, was deferred and is being amortized 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 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 to manage 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 1996, 1995 and 1994 was $54.8 million, $53.5 million and $46.2 million, respectively. Net income taxes paid in 1996, 1995 and 1994 were $60.8 million, $34.6 million and $37.6 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. 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 (Thousands) 1996 1995 ---- ---- Regulatory Assets: Recoverable Future Taxes (Note C) $ 88,832 $ 92,574 Unamortized Debt Expense (Note A) 20,319 22,035 Pension and Post-Retirement Benefit Costs (Note G) 22,259 18,412 Order 636 Transition Costs* 14,256 12,358 Gathering Plant 9,868 - Environmental Clean-up (Note H) 8,144 7,475 Other 2,559 (1,205) -------- -------- Total Regulatory Assets 166,237 151,649 -------- -------- Regulatory Liabilities: Amounts Payable to Customers (Note A) 4,618 51,001 Taxes Refundable to Customers (Note C) 21,005 21,601 Other 6,881 8,628 -------- -------- Total Regulatory Liabilities 32,504 81,230 -------- -------- Net Regulatory Position $133,733 $ 70,419 ======== ======== * 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 Federal Energy Regulatory Commission's (FERC) Order 636, Distribution Corporation is incurring transition costs billed by Supply Corporation and other upstream pipeline companies. As of September 30, 1996, Distribution Corporation's estimate of its exposure to outstanding transition cost claims to nonaffiliated companies is in the range of $9.6 million to $26.6 million. The estimated maximum exposure has been significantly reduced as a result of a preliminary settlement by one of Distribution Corporation's upstream pipeline companies. In addition, estimated maximum exposure continues to decline as transition costs are incurred and paid. At September 30, 1996, Distribution Corporation has recorded the minimum liability and corresponding regulatory asset of $9.6 million. In addition, Distribution Corporation's estimated share of Supply Corporation's $9.9 million of gathering plant at September 30, 1996 is approximately $9.2 million. See further discussion under "Gathering Rates" below. Distribution Corporation is currently recovering transition costs from its sales and transportation customers in New York and Pennsylvania. Gathering Rates 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 under its restructuring orders was filed by Supply Corporation and was approved by the FERC in February 1996. As approved, the Stipulation and Agreement permits Supply Corporation to fully recover its net investment in production and gathering plant, as well as its production and gathering cost of service. A portion of Supply Corporation's net investment in production and gathering plant is being recovered over a five-year period. The unamortized portion amounts to approximately $9.9 million at September 30, 1996 and is included in Other Regulatory Assets on the Consolidated Balance Sheets. 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 (Thousands) 1996 1995 1994 ---- ---- ---- Operating Expenses: Current Income Taxes - Federal $55,148 $30,522 $36,630 State 7,266 4,905 6,309 Deferred Income Taxes 3,907 8,452 4,853 ------- ------- ------ 66,321 43,879 47,792 Other Income: Deferred Investment Tax Credit (665) (672) (682) Cumulative Effect of Changes in Accounting: Adoption of SFAS 109 - - (3,826) Tax Effect of Adoption of SFAS 112 - - (425) ------- ------- ------ Total Income Taxes $65,656 $43,207 $42,859 ======= ======= =======
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 (Thousands) 1996 1995 1994 ---- ---- ---- Net Income Available for Common Stock $104,671 $ 75,894 $ 85,672 Total Income Taxes 65,656 43,207 42,859 -------- -------- -------- Income Before Income Taxes $170,327 $119,101 $128,531 ======== ======== ======== Income Tax Expense, Computed at Federal Statutory Rate of 35% $59,614 $41,685 $44,986 Increase (Reduction) in Taxes Resulting from: Current State Income Taxes, Net of Federal Income Tax Benefit 4,723 3,188 4,101 Depreciation 2,499 2,397 2,174 Adoption of SFAS 109 - - (3,826) Miscellaneous (1,180) (4,063) (4,576) ------- ------- ------- Total Income Taxes $65,656 $43,207 $42,859 ======= ======= ======= Significant components of the Company's deferred tax liabilities and assets were as follows: At September 30 (Thousands) 1996 1995 ---- ---- Deferred Tax Liabilities: Excess of Tax Over Book Depreciation $182,271 $185,595 Exploration and Intangible Well Drilling Costs 98,293 84,380 Other 67,030 67,831 -------- -------- Total Deferred Tax Liabilities 347,594 337,806 ======== ======== Deferred Tax Assets: Overheads Capitalized for Tax Purposes (16,289) (11,766) Other (50,098) (45,599) -------- -------- Total Deferred Tax Assets (66,387) (57,365) ======== ======== Total Net Deferred Income Taxes $281,207 $280,441 ======== ======== 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 $21.0 million and $21.6 million at September 30, 1996 and 1995, 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 $88.8 million and $92.6 million at September 30, 1996 and 1995, respectively.
Note D - Capitalization Summary of Changes in Common Stock Equity Earnings Paid Reinvested Common Stock In in the (Thousands, Except Per Share Amounts) Shares Amount Capital Business ------ ------ ------- ---------- 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 Option 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 Option 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 Net Income Available for Common Stock 104,671 Dividends Declared on Common Stock ($1.65 Per Share) (61,920) Common Stock Issued: Stock Option and Stock Award Plans 126 126 2,490 Dividend Reinvestment and Stock Purchase Plan 134 134 4,460 401(k) Plans 124 124 4,128 Customer Stock Purchase Plan 34 34 1,163 ------ ------- -------- --------- Balance at September 30, 1996 37,852 $37,852 $395,272 $422,874* ====== ======= ======== ======== * 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, 1996, $348.5 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. Shareholder Rights Plan On March 19, 1996, the Company's Board of Directors adopted a shareholder rights plan, the adoption of which was subsequently approved by the SEC, pursuant to the Public Utility Holding Company Act of 1935, as amended (the Holding Company Act). On June 13, 1996, the Company's Board of Directors declared a dividend of one right (Right) for each share of common stock held by the shareholders of record on July 31, 1996.
The Rights become exercisable ten days after an acquirer (a) announces it has acquired or has the right to acquire 10% or more of the Company's voting stock, or (b) announces a tender offer which would result in it owning 10% or more of the Company's voting stock. If the Rights become exercisable, each Company stockholder, except an acquirer, will be able to exercise a Right and receive common stock (or, in certain cases, cash, property or other securities) of the Company, or common stock of the acquirer, having a market value equal to twice the Right's then current purchase price. If a Right were currently exercisable, it would entitle a Company stockholder, other than an acquirer, to purchase $130 worth of Company common stock (or the common stock of the acquirer) for $65. All Rights expire on July 31, 2006. The Board of Directors is able to exchange the Rights at an exchange ratio of one share of common stock per Right. It also is able to redeem, in whole but not in part, the Rights at a price of $0.01 per Right anytime until ten days after an acquirer announces that it has acquired or has the right to acquire 10% or more of the Company's voting stock. Stock Option 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. 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. In October 1995, the Financial Accounting Standards Board issued SFAS 123, "Accounting for Stock-Based Compensation," (SFAS 123). In 1996, the Company adopted the disclosure provision of SFAS 123 but opted to remain under the expense recognition provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for its stock option and stock award plans. For the fiscal years ended September 30, 1996, 1995 and 1994, no compensation expense was recognized for options granted under these plans. Compensation expense related to stock appreciation rights and restricted stock under these stock plans was $6.7 million, $1.4 million and $(0.3) million for the fiscal years ended September 30, 1996, 1995 and 1994, respectively. Had compensation expense for stock options granted under the Company's stock plans been determined based on fair value at the grant dates consistent with the method of SFAS 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts below: 1996 - ------------------------------------------------------------------------------- Net Income: As reported $104,671,000 Pro Forma $104,322,000 Earnings per Common Share: As reported $2.78 Pro Forma $2.77 The above pro forma amounts relate only to options granted since the beginning of 1996. Had SFAS 123 been effective prior to 1996, the fair value of options granted in 1995 but vesting in 1996 would have further reduced 1996 pro forma net income and earnings per share by $1,039,000 and $0.03, respectively.
Transactions involving option shares for all three plans are summarized as follows: Number of Shares Subject Weighted Average to Option Exercise Price - ---------------------------------------------------------------------------- Outstanding at September 30, 1993 955,846 $25.10 Granted in 1994 272,000 $31.63 Exercised in 1994* (60,509) $21.61 - ---------------------------------------------------------------------------- Outstanding at September 30, 1994 1,167,337 $26.80 Granted in 1995 362,100 $27.94 Exercised in 1995* (17,615) $19.46 Forfeited in 1995 (11,532) $31.00 - ---------------------------------------------------------------------------- Outstanding at September 30, 1995 1,500,290 $27.13 Granted in 1996 487,750 $34.44 Exercised in 1996* (195,321) $22.72 Forfeited in 1996 (19,468) $27.90 - ---------------------------------------------------------------------------- Outstanding at September 30, 1996 1,773,251 $29.62 - ---------------------------------------------------------------------------- Shares exercisable at September 30, 1996 1,285,501 $27.79 Shares available for future grant at September 30, 1996** 314,377 Weighted average fair value of options granted during 1996 $5.58 - ---------------------------------------------------------------------------- * In connection with exercising these options, 77,679; 3,192; and 18,088 shares were surrendered and canceled during 1996, 1995 and 1994, respectively. ** Including shares available for restricted stock grants. The weighted average fair value of options granted in 1996 was estimated on the date of grant using a binomial option pricing model which is a modification of the Black-Scholes option pricing model, with the following weighted average assumptions: quarterly dividend yield of 1.22%, annual expected return of 12.83%, annual standard deviation (volatility) of 15.62%, risk free rate of 6.28%, and expected term of 5.5 years. The following table summarizes information about options outstanding at September 30, 1996: <TABLE> <CAPTION> Options Outstanding Options Exercisable - -------------------------------------------------------------- ----------------------------- Number Weighted Average Weighted Number Range of Outstanding Remaining Average Exercisable Weighted Average Exercise Prices at 9/30/96 Contractual Life Exercise Price at 9/30/96 Exercise Price - --------------- ----------- ---------------- -------------- ----------- ---------------- <C> <C> <C> <C> <C> <C> $18.00 - $25.19 460,516 4.7 years $23.82 460,516 $23.82 $27.94 - $36.81 1,312,735 8.6 years $31.66 824,985 $30.01 - --------------------------------------------------------------------------------------------- </TABLE> On October 11, 1996, an additional 280,000 stock options were granted at an exercise price per share of $36.75. The Company's Board of Directors is expected to adopt the 1997 Award and Option Plan (1997 Plan) at its December 13, 1996 meeting. The 1997 Plan will have the same basic provisions as the 1993 Plan. The total number of shares available for grant under the 1997 Plan will be 1.8 million. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is being recorded as compensation expense over the periods during which the vesting restrictions exist. Certificates for shares of restricted stock awarded under the Company's 1984 and 1993 Plans are held by the Company during the periods in which the restrictions on vesting are effective. The following table summarizes the awards of restricted stock over the past three years: 1996 1995 1994 - ------------------------------------------------------------------------------- Shares of Restricted Stock Awarded 8,000 8,000 121,494 Weighted Average Market Price of Stock on Award Date $36.81 $26.00 $34.15 - -------------------------------------------------------------------------------
As of September 30, 1996, 134,578 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse on 126,578 of these shares on January 2 of each year as follows: 1997 - 18,916 shares; 1998 - 18,916 shares; 1999 - 20,916 shares; 2000 - 22,916 shares; 2001 - 24,914 shares; 2002 - 8,000 shares; 2003 - 6,000 shares; 2004 - 4,000 shares; and 2005 - 2,000 shares. For restricted stock awarded before 1996, the restrictions on transferability do not lapse until the earliest of (a) six years from the date the vesting restrictions lapse; (b) the recipient's attainment of age 65; or (c) the recipient's death. For restricted stock awarded in 1996, all restrictions will lapse respecting one-fourth of such shares on each September 26, 2003 through 2006. Redeemable Preferred Stock As of September 30, 1996, 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 (Thousands) 1996 1995 ---- ---- Debentures: 7-3/4% due February 2004 $125,000 $125,000 Medium-Term Notes: 8.875% due December 1995 - 20,000 8.90% due December 1995 - 38,500 4.53% due September 1996 - 30,000 6.42% due November 1997 50,000 50,000 6.08% due July 1998 50,000 50,000 5.58% due March 1999 100,000 - 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 50,000 -------- -------- 574,000 562,500 Less Current Portion - 88,500 -------- -------- $574,000 $474,000 ======== ======== * Callable beginning July 1999. The aggregate principal amounts of long-term debt maturing for the next five years are: none in 1997, $100.0 million in 1998, $150.0 million in 1999, $50.0 million in 2000 and none in 2001. The Company currently has authorization from the SEC under the Holding Company Act to issue and sell up to $150.0 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 $600.0 million thereunder. These credit lines, which are callable at the option of the financial institutions, are reviewed on an annual basis. The Company also has authorization to issue as much as $300.0 million of commercial paper from time to time, but is not likely to exceed $105.0 million. In no event may its borrowings under its discretionary lines of credit, or through the issuance of commercial paper, exceed $600.0 million in the aggregate.
Additionally, the Company has entered into an agreement that establishes a 364-day committed revolving credit arrangement with five commercial banks, under which it may borrow as much as $105.0 million. This arrangement may be utilized for general corporate purposes, primarily 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 $600.0 million available for borrowing under the discretionary lines of credit is correspondingly reduced. No borrowings under this arrangement were outstanding at September 30, 1996. At September 30, 1996, the Company had outstanding notes payable to banks and commercial paper of $109.7 million and $90.0 million, respectively. At September 30, 1995, the Company had outstanding notes payable to banks and commercial paper of $52.6 million and $95.0 million, respectively. The weighted average interest rate on notes payable to banks was 5.63% and 6.15% at September 30, 1996 and 1995, respectively. The weighted average interest rate on commercial paper was 5.56% and 5.85% at September 30, 1996 and 1995, 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 (Thousands) 1996 1995 ------------------- ------------------- Carrying Fair Carrying Fair Amount Value Amount Value -------- ----- -------- ----- Long-Term Debt $574,000 $572,001 $562,500 $570,236 ======== ======== ======== ======== 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 $31.6 million and $28.2 million at September 30, 1996 and 1995, 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 segment, has entered into certain price swap agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil thereby providing more stability to the operating results of that business segment. 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." These variable prices are highly correlated with the market prices received by the Company for its natural gas and crude oil production.
The following summarizes the Company's activity under price swap agreements during 1996, 1995 and 1994: <TABLE> <CAPTION> Year Ended September 30 1996 1995 1994 --------------- --------------- --------------- <S> <C> <C> <C> Natural Gas Swap Agreements: Notional Amount - Equivalent Billion Cubic Feet (Bcf) 23.0 16.3 8.0 Range of Fixed Prices per Thousand Cubic Feet (Mcf) $1.71 - $3.05 $1.74 - $2.39 $2.17 - $2.39 Weighted Average Fixed Price per Mcf $1.91 $2.03 $2.30 Range of Variable Prices per Mcf $1.67 - $3.43 $1.36 - $1.77 $1.44 - $2.44 Weighted Average Variable Price per Mcf $2.31 $1.59 $2.05 Gain (Loss) $(9,231,000) $7,157,000 $1,986,000 Crude Oil Swap Agreements: Notional Amount - Equivalent Barrels (bbl) 1,071,000 686,000 - Range of Fixed Prices per bbl $17.40 - $19.25 $16.68 - $19.60 - Weighted Average Fixed Price per bbl $18.22 $18.01 - Range of Variable Prices per bbl $17.40 - $23.93 $17.16 - $19.89 - Weighted Average Variable Price per bbl $20.72 $18.35 - Loss $(2,606,000) $(221,000) - </TABLE> The Company had the following swap agreements outstanding at September 30, 1996: Natural Gas Swap Agreements: Notional Amount Range of Fixed Weighted Average Fixed Fiscal Year (Equivalent Bcf) Prices per Mcf Price per Mcf ----------- ---------------- -------------- ---------------------- 1997 24.9 $1.71 - $2.10 $1.92 1998 9.7 $1.77 - $2.06 $1.94 1999 1.1 $2.00 $2.00 ---- 35.7 ==== Crude Oil Swap Agreements: Notional Amount Range of Fixed Weighted Average Fixed Fiscal Year (Equivalent bbl) Prices per bbl Price per bbl ---------- ---------------- -------------- ---------------------- 1997 1,371,000 $17.40 - $18.71 $18.00 1998 447,000 $17.50 - $18.71 $17.81 --------- 1,818,000 ========= 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. At September 30, 1996, the Company had unrecognized losses of approximately $10.2 million related to price swap agreements which are offset by corresponding unrecognized gains from the Company's anticipated natural gas and crude oil production over the terms of the price swap agreements. The Company has SEC authority to enter into interest rate swaps and other derivative instruments associated with long-term borrowings up to a notional amount of $350.0 million at any one time outstanding. All such interest rate swaps and other derivative instruments must be directly related to then outstanding long or short-term debt, at the time they are entered into. The Company also has SEC authority to enter into interest rate and currency exchange agreements associated with short-term borrowings covering a total principal amount of $300.0 million. No such agreements were entered into during the year ended September 30, 1996 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 covering its natural gas and crude oil derivative financial instruments in those instances where the Company is not dealing directly with the majority affiliate of the counterparty group. 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. For financial reporting purposes, the regulated subsidiaries record the difference between the amounts of pension cost recoverable in rates and the amounts of pension cost determined by the actuary under SFAS 87, "Employers' Accounting for Pensions," as deferred pension assets. The amounts deferred are expected to be recovered in rates as contributions are made to the Plan. Pension cost in 1996 reflects the amount recovered from customers in rates during the year. In September 1996, the Company completed its special early retirement offer (SERO) for certain salaried, non-union hourly and union employees of Distribution Corporation and Supply Corporation. As a result, the Company recorded SERO expense in 1996 of $8.2 million ($5.2 million after-tax), comprised of special termination benefits and severance pay. The special termination benefits portion of SERO expense is included in pension cost. The components of pension cost were as follows: Year Ended September 30 (Thousands) 1996 1995 1994 ---- ---- ---- Service Cost $11,049 $ 9,680 $10,441 Interest Cost 31,422 28,338 26,532 Actual Return on Plan Assets (48,022) (47,591) (16,212) Net Amortization and Deferral 10,414 9,722 (20,623) Special Termination Benefits 6,986 - - ------- ------- ------- Pension Cost $11,849 $ 149 $ 138 ======= ======= ======= The projected benefit obligation was determined using an assumed discount rate of 8% for 1996 and 1995, and 8.5% for 1994. 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.
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 (Thousands) 1996 1995 ---- ---- Actuarial Present Value of: Vested Benefit Obligation $317,049 $287,470 ======== ======== Accumulated Benefit Obligation $367,612 $333,597 ======== ======== Projected Benefit Obligation $432,753 $404,157 Plan Assets at Fair Value 431,828 399,608 -------- -------- Funded Status (925) (4,549) Unrecognized Net Asset (26,278) (33,335) Unrecognized Prior Service Cost 11,947 12,446 Unrecognized Net Loss (Gain) (15,111) 5,419 -------- -------- Pension Liability $(30,367) $(20,019) ======== ======== 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 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. 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 Public Service Commission of the State of New York (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 under SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," are deferred in each jurisdiction as either a regulatory asset or liability, as appropriate. The Company has elected to amortize the initial accumulated liability at October 1, 1993 to post-retirement benefit cost on a straight-line basis over a 20-year period. The components of post-retirement benefit cost were as follows: Year Ended September 30 (Thousands) 1996 1995 1994 ---- ---- ---- Service Cost $ 3,926 $ 3,394 $ 3,974 Interest Cost 14,391 13,027 13,714 Actual Return on Post-Retirement Plan Assets (9,072) (4,613) (1,035) Net Amortization and Deferral 11,830 12,592 6,877 ------- ------- ------- Post-Retirement Benefit Cost $21,075 $24,400 $23,530 ======= ======= ======= The weighted average assumed discount rate used in determining the accumulated post-retirement benefit obligation was 8% for 1996 and 1995, and 8.5% for 1994. The average assumed annual rate of salary increase for the applicable life insurance plans was 5% for all three years. The expected long-term rate of return on Post-Retirement Plan assets was 8.5% for all three 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, 12% for 1995 and 11% for 1996; this rate was assumed to decrease gradually to 5.5% by the year 2003 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, and 6% for 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 and 1996. This rate was assumed to decrease gradually to 5.5% by the year 2003 and remain level thereafter. The annual rate increase in the per capita Medicare Part B Reimbursement was assumed to be 12.3% for 1994, 12.2% for 1995, 12% for 1996, 3.1% for 1997 and 5.5% for each year thereafter. 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 (Thousands) 1996 1995 ---- ---- Accumulated Post-Retirement Benefit Obligation: Inactives $111,970 $ 76,272 Actives Fully Eligible 25,363 36,223 Actives Not Yet Fully Eligible 74,715 70,620 -------- -------- 212,048 183,115 Fair Value of Post-Retirement Plan Assets 73,059 48,678 -------- -------- Funded Status (138,989) (134,437) Unrecognized Transition Obligation 132,055 141,561 Unrecognized Net Loss (Gain) 4,510 (8,930) -------- -------- Post-Retirement Liability $ (2,424) $ (1,806) ======== ======== 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 accumulated post-retirement benefit obligation as of October 1, 1995, would be increased by $27.6 million. This 1% change would also increase the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 1996 by $3.2 million. 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 $16.9 million in 1996, $16.3 million in 1995 and $17.2 million in 1994. At September 30, 1996, the future minimum payments under the Company's lease agreements for the next five years are: $13.4 million in 1997, $10.0 million in 1998, $6.8 million in 1999, $4.9 million in 2000 and $3.4 million in 2001. The aggregate future minimum lease payments attributable to later years is $10.1 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 average terms that range from three to five years. Additionally, Distribution Corporation has agreements with three nonaffiliated companies for gas storage services through 2006 that require payment of a demand charge, for contracted storage. At September 30, 1996, the projected aggregate amounts of such required future payments, based on current FERC-approved rates and current indices, where applicable, are approximately $98.1 million, $10.8 million, and $2.4 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, 1996, total gross costs incurred under these contracts, including commodity charges on actual quantities shipped, purchased and stored, amounted to $365.2 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 several former manufactured gas plant sites in New York and Pennsylvania. Distribution Corporation has been designated by the New York Department of Environmental Conservation (DEC) as a potentially responsible party (PRP) with respect to one of these sites in New York, and is also engaged in litigation with the DEC and the party who bought the site from Distribution Corporation's predecessor. 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. 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 the above noted sites are in the range of $8.7 million to $10.1 million. At September 30, 1996, Distribution Corporation has recorded the minimum liability of $8.7 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 and Pennsylvania, Distribution Corporation is recovering site investigation and remediation costs in rates. Accordingly, the Consolidated Balance Sheet at September 30, 1996, includes related regulatory assets in the amount of approximately $8.1 million. Memorandum of Understanding - Green Canyon Project In November 1996, Supply Corporation entered into a Memorandum of Understanding (the MOU) with Green Canyon Gathering Company, a subsidiary of
Tenneco Energy, regarding a project to develop, construct, own and operate natural gas gathering and processing facilities offshore and onshore Louisiana (the Project). The total cost of the Project is estimated at approximately $200 million. The MOU provides for the parties to (i) share past and future development costs for the Project through January 1, 1997, and thereafter as agreed by the parties, (ii) negotiate toward definitive agreements to be signed about January 1, 1997, to form one or more 50-50 partnerships, and (iii) negotiate toward definitive agreements to finance, develop, build, own and operate the Project. If the definitive agreements are not executed, or if the Project is not constructed, Supply Corporation's share of the development costs through January 1, 1997 is estimated not to exceed $2 million, for which it is unlikely Supply Corporation would be reimbursed. Supply Corporation intends to use short-term borrowings to finance construction of the Project. 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 and Pipeline and Storage. The nonregulated operations consist principally of the Exploration and Production business segment. The Other Nonregulated segment consists primarily of the Company's sawmill and dry kiln operations, natural gas marketing operations, natural gas hub operations, investment in foreign and domestic energy projects and pipeline construction operations (which were discontinued during 1995, the effect of which was immaterial to the Company). The Utility segment 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). The Pipeline and Storage segment is regulated by the FERC and is carried out by Supply Corporation. Supply Corporation transports and stores natural gas for utilities and pipeline companies in the northeastern United States markets. In 1996, 1995 and 1994, 51%, 48% and 52%, respectively, 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 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's activities center around its investment in 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 is engaged in the investigation and development of foreign and domestic energy projects and presently operates a district heating plant and a power development group in the Czech Republic. UCI was engaged in the Company's pipeline construction operations prior to the discontinuance of its business 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 three years ended September 30, 1996. 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 (Thousands) 1996 1995 1994 ---- ---- ---- Operating Revenues Regulated: Utility $ 954,326 $786,064 $ 931,673 Pipeline and Storage 176,553 164,587 153,121 ---------- -------- ---------- 1,130,879 950,651 1,084,794 ---------- -------- ---------- Nonregulated: Exploration and Production 114,462 56,232 70,261 Other 68,930 57,075 72,036 ---------- -------- ---------- 183,392 113,307 142,297 ---------- -------- ---------- Intersegment Revenues* (106,254) (88,462) (85,767) ---------- -------- ---------- $1,208,017 $975,496 $1,141,324 ========== ======== ========== * Represents primarily Pipeline and Storage revenue from the Utility segment. Operating Income (Loss) Before Income Taxes Regulated: Utility $115,257 $ 83,774 $ 90,584 Pipeline and Storage 72,914 67,884 62,302 -------- -------- -------- 188,171 151,658 152,886 -------- -------- -------- Nonregulated: Exploration and Production 46,408 16,404 21,767 Other (8,581) 3,021 2,505 -------- -------- -------- 37,827 19,425 24,272 -------- -------- -------- Corporate (2,231) (2,805) (3,463) -------- -------- -------- $223,767 $168,278 $173,695 ======== ======== ======== Identifiable Assets At September 30 (Thousands) Regulated: Utility $1,154,364 $1,098,757 $1,105,202 Pipeline and Storage 515,569 512,546 498,798 ---------- ---------- ---------- 1,669,933 1,611,303 1,604,000 ---------- ---------- ---------- Nonregulated: Exploration and Production 396,077 351,262 311,037 Other 38,955 33,734 33,357 ---------- ---------- ---------- 435,032 384,996 344,394 ---------- ---------- ---------- Corporate 44,807 40,524 32,412 ---------- ---------- ---------- $2,149,772 $2,036,823 $1,980,806 ========== ========== ==========
Year Ended September 30 (Thousands) 1996 1995 1994 ---- ---- ---- Depreciation, Depletion and Amortization Regulated: Utility $31,491 $30,052 $28,216 Pipeline and Storage 19,942 19,320 17,516 ------- ------- ------- 51,433 49,372 45,732 ------- ------- ------- Nonregulated: Exploration and Production 46,042 21,201 27,496 Other 752 1,203 1,530 ------- ------- ------- 46,794 22,404 29,026 ------- ------- ------- Corporate 4 6 6 ------- ------- ------- $98,231 $71,782 $74,764 ======= ======= ======= Capital Expenditures Regulated: Utility $ 63,730 $ 64,844 $ 61,715 Pipeline and Storage 22,260 38,678 20,472 -------- -------- -------- 85,990 103,522 82,187 -------- -------- -------- Nonregulated: Exploration and Production 83,554 69,741 52,458 Other 3,189 9,563 3,603 -------- -------- -------- 86,743 79,304 56,061 -------- -------- -------- Corporate - - 20 -------- -------- -------- Intersegment Elimination (1,166) - - -------- -------- -------- $171,567 $182,826 $138,268 ======== ======== ======== 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 quarter ended September 30, 1996 reflects the after-tax net benefit of gas cost reconciliation adjustments of $2.7 million or $0.07 per share, and the reversal of estimated lost and unaccounted-for gas accrued in prior quarters of 1996 of $4.6 million, after-tax, or $0.12 per share. These items were offset by an after-tax charge to earnings of $5.2 million, or $0.14 per share, related to a special early retirement offer to certain salaried, non-union hourly and union employees of Distribution Corporation and Supply Corporation. In addition, Horizon recognized a fourth quarter after-tax charge to earnings of $3.8 million, or $0.10 per share, related to its decision to withdraw from participation in the development of a 151 megawatt power plant near Kabirwala, Punjab Province, in east-central Pakistan. Financial data for the quarter ended September 30, 1995 reflects an after-tax charge of $2.8 million, or $0.07 per share, related to Distribution Corporation's recording of estimated gas costs for lost and unaccounted-for gas in excess of that allowed to be recovered in rates. In addition, the quarter ended September 30, 1995 includes an after-tax charge of $2.2 million recorded by Supply Corporation establishing a reserve for previously deferred preliminary survey and investigation charges related to a storage project.
Net Income Earnings Available for Per Quarter Operating Operating Common Common Ended Revenues Income Stock Share - ------- --------- --------- ------------- -------- 1996 (Thousands, except earnings per common share) - ------------------------------------------------------------------------ 12/31/95 $316,328 $46,344 $32,392 $ .87 3/31/96 $492,376 $69,631 $55,692 $1.48 6/30/96 $239,330 $29,687 $17,310 $ .46 9/30/96 $159,983 $11,784 $ (723) $(.02) 1995 (Thousands, except earnings per common share) - ------------------------------------------------------------------------ 12/31/94 $279,332 $43,288 $30,571 $ .82 3/31/95 $378,762 $56,457 $43,307 $1.16 6/30/95 $193,461 $18,987 $ 8,981 $ .24 9/30/95 $123,941 $ 5,667 $(6,965) $(.19) Note K - Market for Common Stock and Related Shareholder Matters (unaudited) At September 30, 1996, there were 21,640 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, 1996 and 1995, are shown below: Price Range Dividends Quarter Ended High Low Declared - ------------- ---- --- --------- 1996 ---- 12/31/95 $33-7/8 $28-1/2 $.405 3/31/96 $34-7/8 $31-3/8 $.405 6/30/96 $36-3/8 $33-3/4 $.42 9/30/96 $38 $33-3/8 $.42 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 (Thousands) 1996 1995 ---- ---- Capitalized Costs Subject to Amortization $570,815 $495,802 Capitalized Acquisition Costs Excluded from Amortization 35,627 28,565 -------- -------- 606,442 524,367 Less - Accumulated Depreciation, Depletion and Amortization 233,743 188,241 -------- -------- $372,699 $336,126 ======== ======== 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 1996, 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 (Thousands) 1996 1995 1994 ---- ---- ---- Property Acquisition Costs: Proved $ 4,632 $13,186 $ 5,109 Unproved 12,879 12,119 3,106 Exploration Costs 33,191 18,588 17,855 Development Costs 32,747 25,161 25,102 Other 230 559 259 ------- ------- ------- $83,679 $69,613 $51,431 ======= ======= ======= Results of Operations for Producing Activities Year Ended September 30 (Thousands) 1996 1995 1994 ---- ---- ---- Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $11,872, $8,650 and $5,456, respectively) $ 91,018 $34,849 $50,803 Oil, Condensate and Other Liquids 33,978 11,948 15,307 -------- ------- ------- Total Operating Revenues 124,996 46,797 66,110 Production/Lifting Costs 15,196 11,215 13,177 Depreciation, Depletion and Amortization ($0.36, $0.44 and $0.41, respectively, per dollar of operating revenues) 45,502 20,528 26,992 Income Tax Expense 22,069 4,301 7,907 -------- ------- ------- Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 42,229 $10,753 $18,034 ======== ======= ======= 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 1996 1995 1994 1996 1995 1994 ---- ---- ---- ---- ---- ---- Proved Developed and Undeveloped Reserves: Beginning of Year 221,459 247,447 175,051 22,865 17,495 18,519 Extensions and Discoveries 29,161 9,912 94,733 5,701 3,863 1,666 Revisions of Previous Estimates (3,442) (21,046) (2,075) (1,173) (60) (1,660) Production (38,767) (20,942) (23,273) (1,742) (739) (1,030) Sales of Minerals in Place (1,532) (4,685) (32) (27) (474) - Purchases of Minerals in Place and Other 203 10,773 3,043 125 2,780 - ------- ------- ------- ------ ------ ------ End of Year 207,082 221,459 247,447 25,749 22,865 17,495 ======= ======= ======= ====== ====== ====== Proved Developed Reserves: Beginning of Year 162,504 179,291 134,712 14,937 10,110 10,801 ======= ======= ======= ====== ====== ====== End of Year 163,537 162,504 179,291 14,043 14,937 10,110 ======= ======= ======= ====== ====== ====== 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 (Thousands) 1996 1995 1994 ---- ---- ---- Future Cash Inflows $1,003,280 $738,711 $705,874 Less: Future Production and Development Costs 294,778 272,268 252,901 Future Income Tax Expense at Applicable Statutory Rate 221,956 129,055 131,060 ---------- -------- -------- Future Net Cash Flows 486,546 337,388 321,913 Less: 10% Annual Discount for Estimated Timing of Cash Flows 157,302 92,120 106,647 ---------- -------- -------- Standardized Measure of Discounted Future Net Cash Flows $ 329,244 $245,268 $215,266 ========== ======== ========
The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 (Thousands) 1996 1995 1994 ---- ---- ---- Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $245,268 $215,266 $209,655 Sales, Net of Production Costs (109,801) (35,582) (52,933) Net Changes in Prices, Net of Production Costs 147,330 10,757 (48,149) Purchases of Minerals in Place 770 18,602 2,793 Sales of Minerals in Place (1,141) (5,688) (29) Extensions and Discoveries 93,864 47,236 96,134 Changes in Estimated Future Development Costs (53,630) (50,366) (36,466) Previously Estimated Development Costs Incurred 42,780 39,833 22,941 Net Change in Income Taxes at Applicable Statutory Rate (52,613) (6,838) 3,098 Revisions of Previous Quantity Estimates (15,491) (20,934) (11,042) Accretion of Discount and Other 31,908 32,982 29,264 -------- -------- -------- Standardized Measure of Discounted Future Net Cash Flows at End of Year $329,244 $245,268 $215,266 ======== ======== ========
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES Schedule II - Valuation and Qualifying Accounts (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, 1996 - ----------------------------- Reserve for Doubtful Accounts $5,924 $15,191 $ - $13,443 $7,672 ====== ======= ====== ======= ====== 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 ====== ======= ====== ======= ====== 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 20, 1997 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1996. 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 20, 1997 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1996. 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 20, 1997 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1996. The information provided in such definitive Proxy Statement is incorporated herein by reference.
ITEM 13 Certain Relationships and Related Transactions At September 30, 1996, 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) * Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated March 9, 1987 (Exhibit 3.1, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) * Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated February 22, 1988 (Exhibit 3.2, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) * 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) (See Exhibit 3.1 for amendment intended to become effective in January 1997) 3.1 Excerpts from Minutes from the National Fuel Gas Company Board of Directors Meeting of September 19, 1996 regarding compensation of non-employee directors and related amendments of By-Laws (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) * Third Supplemental Indenture dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No. 33-49401)
* 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) 4.1 Fifteenth Supplemental Indenture dated as of September 1, 1996 to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) * Rights Agreement between National Fuel Gas Company and Marine Midland Bank dated June 12, 1996 (Exhibit 99.1, Form 8-K dated June 13, 1996 in File No. 1-3880) (10) Material Contracts: (ii) (B) Contracts upon which Registrant's business is substantially dependent: 10.1 Service Agreement No. 830016 with Texas Eastern Transmission Corporation, under Rate Schedule FT-1, dated November 2, 1995 10.2 Service Agreement No. 830017 with Texas Eastern Transmission Corporation, under Rate Schedule FT-1, dated November 2, 1995 10.3 Service Agreement with Texas Eastern Transmission Corporation, under Rate Schedule CDS, dated November 2, 1995 10.4 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation, under Rate Schedule FSS, dated April 3, 1996 [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2]
10.5 Service Agreement with St. Clair Pipelines Ltd., dated January 29, 1996 [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2] * Service Agreement with Empire State Pipeline under Rate Schedule FT, dated December 15, 1994 [Portions of this agreement are subject to confidential treatment under Rule 24b-2] (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) * Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated August 1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) * Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated September 19, 1995 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) * Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) * 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 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) * Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated August 1, 1993 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) * Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated October 1, 1993 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) * 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 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) 10.6 Ninth Extension to Employment Agreement with Bernard J. Kennedy, dated September 19, 1996 * 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) 10.7 Amendment to the National Fuel Gas Company 1984 Stock Plan, dated December 11, 1996 * 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 December 11, 1996 * Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) 10.9 National Fuel Gas Company 1997 Award and Option Plan * 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)
* 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) 10.10 Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 * Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1995 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) 10.11 Amendment to April 1, 1991 Death Benefits Agreement, dated January 8, 1996, with Philip C. Ackerman * 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) 10.12 Amendment to April 1, 1991 Death Benefits Agreement, dated January 8, 1996, with Richard Hare * 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) * 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) * Amendment to Death Benefit Agreement of August 28, 1991, with Bernard J. Kennedy, dated March 15, 1994 (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) * National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) 10.13 National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II) dated May 10, 1996 * 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) 10.14 Administrative Rules with Respect to at Risk Awards under the 1993 Award and Option Plan 10.15 Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company as amended through December 11, 1996
* Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of December 5, 1991 regarding change in control agreements, non-employee director retirement plan, and restrictions on restricted stock (Exhibit 10-UU, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880) 10.16 Form of Change in Control Agreement, dated May 1, 1992, with Walter E. DeForest, Bruce H. Hale, Joseph P. Pawlowski, Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin, and dated March 16, 1995, with James A. Beck (12) Computation of Ratio of Earnings to Fixed Charges (13) Letter to Shareholders as contained in the 1996 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, 1996 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, 1996 ------------------- /s/ P. C. Ackerman Senior Vice President, Principal ------------------------ P. C. Ackerman Financial Officer and Director Date: December 13, 1996 ------------------- /s/ R. T. Brady Director ------------------------ R. T. Brady Date: December 13, 1996 ------------------- /s/ W. J. Hill Director ------------------------ W. J. Hill Date: December 13, 1996 ------------------- /s/ L. F. Kahl Director ------------------------ L. F. Kahl Date: December 13, 1996 ------------------- /s/ B. S. Lee Director ------------------------ B. S. Lee Date: December 13, 1996 ------------------- /s/ E. T. Mann Director ------------------------ E. T. Mann Date: December 13, 1996 -------------------
/s/ G. L. Mazanec Director ------------------------ G. L. Mazanec Date: December 13, 1996 ------------------- /s/ L. Rochwarger Director ------------------------ L. Rochwarger Date: December 13, 1996 ------------------- /s/ G. H. Schofield Director ------------------------ G. H. Schofield Date: December 13, 1996 ------------------- /s/ J. P. Pawlowski Treasurer and Principal ------------------------ J. P. Pawlowski Accounting Officer Date: December 13, 1996 ------------------- /s/ A. M. Cellino Secretary ------------------------ A. M. Cellino Date: December 13, 1996 ------------------- /s/ G. T. Wehrlin Controller ------------------------ G. T. Wehrlin Date: December 13, 1996 -------------------
APPENDIX TO ITEM 2 - PROPERTIES Four maps outlining the Company's operating areas at September 30, 1996 are included on the inside foldout cover of 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 Utility Operating area (i.e., Distribution Corporation's service area). The second map identifies the Company's Pipeline and Storage operating area (i.e., Supply Corporation's storage areas and pipelines). The third map identifies the Company's Exploration and Production operating area (i.e., Seneca Resources' operating area). The fourth map identifies the geographic location of the Company's Other Nonregulated operating areas (i.e., NFR's marketing office, Horizon's Czech Republic operations and Highland's sawmill operations). APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS A. The Revenue Dollar - 1996 Two pie graphs detailing the revenue dollar in 1996: where it came from and where it went to, broken down as follows: Where it came from: $ .560 Residential Sales .182 Commercial, Industrial and Off-System Sales .094 Oil and Gas Revenues .067 Transportation Revenues .049 Marketing Revenues .032 Storage Service Revenues .016 Other Revenues $1.000 Total Where it went to: $ .394 Gas Purchased .157 Wages, Including Benefits .136 Taxes .098 Other Materials and Services .081 Depreciation .051 Dividends - Common Stock .047 Interest .036 Reinvested in the Business $1.000 Total B. Capital Expenditures A bar graph detailing capital expenditures (millions of dollars) for the years 1992 through 1996, broken down as follows: 1992 1993 1994 1995 1996 ---- ---- ---- ---- ---- Other Nonregulated $ 7.2 $ 6.2 $ 3.6 $ 9.6 $ 3.2 Pipeline and Storage 58.7 27.4 20.5 38.7 22.2 Utility 65.7 61.8 61.7 64.8 62.6 Exploration and Production 26.3 36.5 52.5 69.7 83.6 ------ ------ ------ ------ ------ $157.9 $131.9 $138.3 $182.8 $171.6
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS (Concluded) C. Capitalization Ratios A bar graph detailing capitalization (percentage) for the years 1992 through 1996, broken down as follows: Debt (%) Equity (%) 1992 54.5 45.5 1993 47.8 52.2 1994 46.2 53.8 1995 47.0 53.0 1996 47.5 52.5 D. Book Value Per Common Share A bar graph detailing book value per common share (dollars) for the years 1992 through 1996, as follows: 1992 - $18.68 1993 - 20.08 1994 - 20.93 1995 - 21.39 1996 - 22.61
Exhibit Index 3.1 Excerpts from Minutes from the National Fuel Gas Company Board of Directors Meeting of September 19, 1996 regarding compensation of non-employee directors and related amendments of By-Laws 4.1 Fifteenth Supplemental Indenture dated as of September 1, 1996 to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) 10.1 Service Agreement No. 830016 with Texas Eastern Transmission Corporation, under Rate Schedule FT-1, dated November 2, 1995 10.2 Service Agreement No. 830017 with Texas Eastern Transmission Corporation, under Rate Schedule FT-1, dated November 2, 1995 10.3 Service Agreement with Texas Eastern Transmission Corporation, under Rate Schedule CDS, dated November 2, 1995 10.4 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation, under Rate Schedule FSS, dated April 3, 1996 [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2] 10.5 Service Agreement with St. Clair Pipelines Ltd., dated January 29, 1996 [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2] 10.6 Ninth Extension to Employment Agreement with Bernard J. Kennedy, dated September 19, 1996 10.7 Amendment to the National Fuel Gas Company 1984 Stock Plan, dated December 11, 1996. 10.8 Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 10.9 National Fuel Gas Company 1997 Award and Option Plan 10.10 Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 10.11 Amendment to April 1, 1991 Death Benefits Agreement, dated January 8, 1996, with Philip C. Ackerman 10.12 Amendment to April 1, 1991 Death Benefits Agreement, dated January 8, 1996, with Richard Hare 10.13 National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II) dated May 10, 1996 10.14 Administrative Rules with Respect to at Risk Awards under the 1993 Award and Option Plan 10.15 Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company as amended through December 11, 1996 10.16 Form of Change in Control Agreement, dated May 1, 1992, with Walter E. DeForest, Bruce H. Hale, Joseph P. Pawlowski, Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin, and dated March 16, 1995, with James A. Beck (12) Computation of Ratio of Earnings to Fixed Charges (13) Letter to Shareholders as contained in the 1996 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, 1996 27.2 Financial Data Schedule for 12 months ending September 30, 1995, Restated 27.3 Financial Data Schedule for 12 months ending September 30, 1994, Restated 99.1 Report of Ralph E. Davis Associates, Inc.