UNITED STATES SECURITIES AND EXCHANGE COMMISSION
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, 2004
Commission File Number 1-3880
National Fuel Gas Company
New Jersey | 13-1086010 | |
(State or other jurisdiction of
incorporation or organization) |
(I.R.S. Employer
Identification No.) |
|
6363 Main Street
Williamsville, New York (Address of principal executive offices) |
14221
(Zip Code) |
(716) 857-7000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
|
|
|
Common Stock, $1 Par Value, and
Common Stock Purchase Rights |
New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
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 þ No o
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 registrants 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. o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,997,020,000 as of March 31, 2004.
Common Stock, $1 Par Value, outstanding as of November 30, 2004: 83,178,717 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 17, 2005 are incorporated by reference into Part III of this report.
For the Fiscal Year Ended September 30, 2004
CONTENTS
Page | ||||||
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PART I | ||||||
BUSINESS | 3 | |||||
THE COMPANY AND ITS SUBSIDIARIES | 3 | |||||
RATES AND REGULATION | 4 | |||||
THE UTILITY SEGMENT | 5 | |||||
THE PIPELINE AND STORAGE SEGMENT | 5 | |||||
THE EXPLORATION AND PRODUCTION SEGMENT | 6 | |||||
THE INTERNATIONAL SEGMENT | 6 | |||||
THE ENERGY MARKETING SEGMENT | 6 | |||||
THE TIMBER SEGMENT | 6 | |||||
ALL OTHER CATEGORY AND CORPORATE OPERATIONS | 7 | |||||
SOURCES AND AVAILABILITY OF RAW MATERIALS | 7 | |||||
COMPETITION | 8 | |||||
SEASONALITY | 9 | |||||
CAPITAL EXPENDITURES | 10 | |||||
ENVIRONMENTAL MATTERS | 10 | |||||
MISCELLANEOUS | 10 | |||||
EXECUTIVE OFFICERS OF THE COMPANY | 11 | |||||
PROPERTIES | 12 | |||||
GENERAL INFORMATION ON FACILITIES | 12 | |||||
EXPLORATION AND PRODUCTION ACTIVITIES | 12 | |||||
LEGAL PROCEEDINGS | 16 | |||||
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS | 17 | |||||
PART II | ||||||
MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS | 17 | |||||
SELECTED FINANCIAL DATA | 18 | |||||
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 19 | |||||
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 50 | |||||
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 51 | |||||
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | 100 | |||||
CONTROLS AND PROCEDURES | 100 | |||||
OTHER INFORMATION | 101 |
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PART III | ||||||||
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT | 101 | |||||||
EXECUTIVE COMPENSATION | 101 | |||||||
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | 101 | |||||||
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS | 102 | |||||||
PRINCIPAL ACCOUNTANT FEES AND SERVICES | 102 | |||||||
PART IV | ||||||||
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | 102 | |||||||
SIGNATURES | 108 | |||||||
EX-10.1 Executive Life Insurance Plan | ||||||||
EX-10.2 Executive Retirement Plan | ||||||||
EX-10.3 Administrative Rules | ||||||||
EX-10.4 Retirement and Consulting Agreement | ||||||||
EX-12 Computation of Ratio of Earnings | ||||||||
EX-23.1 Consent of Engineer | ||||||||
EX-23.2 Consent of Engineer | ||||||||
EX-23.3 Consent of Accounting Firm | ||||||||
EX-31.1 CEO Certification 302 | ||||||||
EX-31.2 CFO Certification 302 | ||||||||
EX-32 906 Certification | ||||||||
EX-99.1 Seneca Resources Corporation | ||||||||
EX-99.2 Seneca Energy Canada, Inc. | ||||||||
EX-99.3 Maps - Locations National Fuel |
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This 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 Form 10-K at Item 7, Managements 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 an asterisk (*) 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 Registrant), a holding company registered 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. Except as otherwise indicated below, the Registrant owns all of the outstanding securities of its subsidiaries. Reference to the Company in this report means the Registrant, the Registrant and its subsidiaries or the Registrants subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Companys fiscal year ended September 30 of that year unless otherwise noted.
The Company is a diversified energy company consisting of six reportable business segments.
1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 732,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire State Pipeline (Empire), a New York joint venture between two wholly-owned entities of the Company. 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) 28 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields operated jointly with various other interstate gas pipeline companies. Empire, an intrastate pipeline company, transports natural gas for Distribution Corporation and for other utilities, large industrial customers and power producers in New York State. Empire owns a 157-mile pipeline that extends from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York. The Company acquired Empire in February 2003.
3. The Exploration and Production segment operations are 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 California, in the Appalachian region of the United States, and in the Gulf Coast region of Texas, Louisiana, and Alabama. Also, Exploration and Production operations are conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada by Seneca Energy Canada, Inc. (SECI), formerly Player Resources Ltd. SECI is an Alberta, Canada corporation and a subsidiary of Seneca. At September 30, 2004, the Company had U.S. and Canadian reserves of 65,213 thousand barrels (Mbbl) and 224,784 million cubic feet (MMcf).
4. The International segment operations are carried out by Horizon Energy Development, Inc. (Horizon), a New York corporation. Horizon engages in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizons wholly-owned
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5. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, commercial, public authority and residential end-users in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management services for its customers.
6. The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a New York corporation, and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns two sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. At September 30, 2004, the Company owned and managed approximately 87,000 acres of timber property.
Financial information about each of the Companys business segments can be found in Item 7, MD&A and also in Item 8 at Note H Business Segment Information.
The Companys other direct wholly-owned subsidiaries are not included in any of the six reportable business segments and consist of the following:
| Horizon LFG, Inc. (Horizon LFG), a New York corporation engaged through subsidiaries in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Horizon LFG and one of its wholly owned subsidiaries own all of the partnership interests in Toro Partners, LP (Toro), a limited partnership which owns and operates short-distance landfill gas pipeline companies. Further information can be found in Item 8 at Note J Acquisitions; | |
| Leidy Hub, Inc. (Leidy), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States; | |
| Data-Track Account Services, Inc. (Data-Track), a New York corporation which provides collection services principally for the Companys subsidiaries; and | |
| Horizon Power, Inc. (Horizon Power), a New York corporation which is designated as an exempt wholesale generator under the Holding Company Act and is developing or operating mid-range independent power production facilities and landfill gas electric generation facilities. |
No single customer, or group of customers under common control, accounted for more than 10% of the Companys consolidated revenues in 2004.
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. In 2003, both houses of Congress passed comprehensive energy bills that included repeal of the Holding Company Act, but since November 2003 have been unable to reconcile their differences and pass any comprehensive energy legislation. The Company is unable to predict at this time what the ultimate outcome of legislative or regulatory changes will be and, therefore, whether the Holding Company Act will be repealed and what impact the repeal of the Holding Company Act might have on the Company.*
The Utility segments rates, services and other matters are regulated by the State of New York Public Service Commission (NYPSC) 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 segments rates and regulation, see Item 7, MD&A under the heading Rate Matters and Item 8 at Note B-Regulatory Matters.
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The Pipeline and Storage segments rates, services and other matters with respect to Supply Corporation are regulated by the Federal Energy Regulatory Commission (FERC) and by the NYPSC with respect to Empire. For additional discussion of the Pipeline and Storage segments rates and regulation, see Item 7, MD&A 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 Companys 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 Companys Consolidated Balance Sheets and such accounting treatment would be discontinued.
In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.
In addition, the Company and its subsidiaries are subject to the same federal, state and local (including foreign) regulations on various subjects, including environmental matters, to which other companies doing similar business in the same locations are subject.
The Utility Segment
The Utility segment contributed approximately 28.0% of the Companys 2004 net income available for common stock.
Additional discussion of the Utility segment appears below in this Item 1 under the headings Sources and Availability of Raw Materials, Competition and Seasonality, in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 28.6% of the Companys 2004 net income available for common stock.
Supply Corporation has service agreements for all of its firm storage capacity, which totals approximately 68,728 thousand dekatherms (MDth). The Utility segment has contracted for 27,865 MDth or 40.6% of the total storage capacity, and the Energy Marketing segment accounts for another 3,868 MDth or 5.6% of the total storage capacity. Nonaffiliated customers have contracted for the remaining 36,995 MDth or 53.8% of the firm storage capacity. Following an industry trend, most of Supply Corporations storage and transportation services are performed under contracts that allow Supply Corporation or the shipper to terminate the contract upon six or twelve months notice effective at the end of the contract term, and from time to time thereafter. At the beginning of 2005, approximately 88% of Supply Corporations firm storage capacity (including the 40.6% contracted for by affiliated shippers) was committed under contracts that could have expired or been terminated before the end of 2005. Based on contract expirations and termination notifications received before the deadline for termination effective within 2005, contracts representing approximately 3.3% of Supply Corporations firm storage capacity will be terminated during 2005.* Supply Corporation has been successful in marketing and obtaining executed contracts for storage service (at discounted rates) as it becomes available and expects to continue to do so.*
Supply Corporations firm transportation capacity is not a fixed quantity, due to the diverse weblike nature of its pipeline system, and is subject to change as different transportation paths and receipt/delivery point combinations are identified with the market. Supply Corporation currently has firm transportation service agreements for approximately 2,232 MDth per day (contracted capacity). The Utility segment accounts for approximately 1,122 MDth per day or 50.3% of contracted capacity, and the Energy Marketing segment represents another 78 MDth per day or 3.5% of contracted capacity. The remaining 1,032 MDth or 46.2% of contracted capacity are subject to firm contracts with nonaffiliated customers.
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At the beginning of 2005, 47% of Supply Corporations contracted capacity was committed under affiliate contracts that could have expired or been terminated effective before the end of 2005. Based on contract expirations and termination notices received before the deadline for termination effective within 2005, affiliate contracts representing only 0.3% of contracted capacity will actually expire or be terminated effective during 2005. Similarly, 28% of contracted capacity was committed under unaffiliated shipper contracts that could expire or be terminated effective before the end of 2005. Based on contract expirations and termination notices received before the deadline for termination within 2005, unaffiliated contracts representing 11% of contracted capacity will actually expire or be terminated effective during 2005. Supply Corporation has been successful in marketing and obtaining executed contracts for such transportation service previously (at discounted rates when necessary), and expects to continue to do so.*
Empire has service agreements for the 2004-2005 winter period for all of its firm transportation capacity, which totals approximately 562 MDth per day. Approximately 74% of Empires firm transportation capacity is contracted on a long-term basis. None of these transportation contracts could be terminated or will expire in 2005 or 2006. The Utility segment accounts for approximately 60 MDth per day or 10.7% of Empires total capacity, and the Energy Marketing segment accounts for approximately 10 MDth per day or 1.8% of Empires total capacity, with the remaining 87.5% of Empires capacity subject to firm contracts with nonaffiliated customers. Approximately 14% of Empires total capacity (including 5% of its total capacity contracted with affiliated shippers) is currently contracted under seasonal or annual contracts which will expire effective before the end of 2005.* Empire expects that all of this capacity will be re-contracted under seasonal and/or annual arrangements for future contracting periods.*
Additional discussion of the Pipeline and Storage segment appears below under the headings Sources and Availability of Raw Materials, Competition and Seasonality, in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 32.6% of the Companys 2004 net income available for common stock.
Additional discussion of the Exploration and Production segment appears below under the headings Sources and Availability of Raw Materials and Competition, in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The International Segment
The International segment contributed approximately 3.6% of the Companys 2004 net income available for common stock.
Additional discussion of the International segment appears below under the heading Sources and Availability of Raw Materials, Competition and Seasonality, in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Energy Marketing Segment
The Energy Marketing segment contributed approximately 3.3% of the Companys 2004 net income available for common stock.
Additional discussion of the Energy Marketing segment appears below under the headings Sources and Availability of Raw Materials, Competition and Seasonality, in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Timber Segment
The Timber segment contributed approximately 3.4% of the Companys 2004 net income available for common stock.
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Additional discussion of the Timber segment appears below under the headings Sources and Availability of Raw Materials, Competition and Seasonality, in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
All Other Category and Corporate Operations
The All Other category and Corporate operations contributed approximately 0.5% of the Companys 2004 net income available for common stock.
Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
Sources and Availability of Raw Materials
Natural gas is the principal raw material for the Utility segment. In 2004, the Utility segment purchased 105 billion cubic feet (Bcf) of gas, of which 85 Bcf served core market demand and 17 Bcf was used for off-system sales. The remaining 3 Bcf represents gas used in operations offset by storage withdrawals. Gas purchased from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 71% of the core market purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for the remaining 29% of the Utility segments 2004 core market purchases. Purchases from Conoco Phillips Company (16%), Cinergy Marketing & Trading, L.P. (13%), BP Energy Company (11%), Occidental Energy Marketing, Inc. (10%) and Anadarko Energy Services Company (9%) accounted for 59% of the Utilitys 2004 core market gas purchases. No other producer or supplier provided the Utility segment with more than 9% of its gas requirements in 2004.
Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern and Appalachian regions of the United States as well as in Canada. Empire transports gas owned by its customers, whose gas originates in the southwestern and mid-continent regions of the United States as well as in Canada. Additional discussion of proposed pipeline projects appears below under Competition and in Item 7, MD&A.
The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Notes H-Business Segment Information and N-Supplementary Information for Oil and Gas Producing Activities.
Coal is the principal raw material for the International segment, constituting 54% of the cost of raw materials needed in 2004 to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined accounted for the remaining 46% of such materials. Coal is purchased and delivered directly from the adjacent Mostecka Uhelna Spolecnost, a.s. mine in the Czech Republic for UEs largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. The Company has been informed that this mine is expected to have reserves through 2030, although the Company has not been provided with an independent reserve study to support this information.* Natural gas is imported into the Czech Republic from sources in Russia and the North Sea and is transported through the Transgas pipeline system, which is majority owned by RWE AG, a German multi-utility. The International segment purchases natural gas from one of the eight regional gas distribution companies in the Czech Republic. Oil is also imported into the Czech Republic. The International segment purchases oil from domestic and foreign refineries.
With respect to the Timber segment, Highland requires an adequate supply of timber to process in its sawmill and kiln operations. Approximately 50% of the timber processed during 2004 came from land owned by Seneca.
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2004, this segment purchased 44 Bcf of natural gas, of which 42 Bcf served core market demands. The remaining 2 Bcf largely represents gas used in operations.
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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 deregulation of the natural gas industry has enhanced the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, by removing some of the historical regulatory impediments to adding customers and responding to market forces. In addition, the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.
The electric industry has been 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 remains unclear what the impact will be on the Company of any further restructuring in response to legislation or other events.*
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 FERCs restructuring of the gas industry in Order No. 636, which was issued in 1992, continue to reshape the roles of the gas utility industry and the state regulatory commissions. Regulators in both New York and Pennsylvania have adopted retail competition programs for natural gas supply purchases. However, regulators in Pennsylvania have not pursued such programs recently, and there have been no significant new market entrants in New York. To date, the Utility segments traditional distribution function remains largely unchanged; however, the NYPSC continues to encourage customer choice at the retail residential level.
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 segments service territories (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.*
The Utility segment competes, 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 or new services, rates and contracts and (ii) emphasize and provide high quality service to its customers.
Competition: The Pipeline and Storage Segment
Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation 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 eastern United States and gas-producing regions of Canada and the southwestern, southern and other continental regions of the United States. This location offers the opportunity for increased transportation and storage services in the future.*
Empire competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is particularly well situated to provide transportation from Canadian sourced gas, and its facilities are readily expandable. These characteristics provide Empire the opportunity to compete for an increased share of the gas transportation markets.
As announced in February 2004, Empire is pursuing a project to expand its natural gas pipeline to serve new markets in New York and elsewhere in the Northeast.* For further discussion of this project, refer to Item 7, MD&A under the heading Investing Cash Flow.
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Competition: The Exploration and Production Segment
The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects.
To compete in this environment, Seneca and SECI each originate and act as operator on most prospects, minimize the risk of exploratory efforts through partnership-type arrangements, apply the latest technology for both exploratory studies and drilling operations, and focus on market niches that suit their size, operating expertise and financial criteria.
Competition: The International Segment
Horizon competes with other entities seeking to develop or acquire foreign and domestic energy projects. Horizon, through UE, faces competition in the sale of thermal energy. Most customers can opt to install boilers to produce their thermal energy, rather than purchase thermal energy from the district heating system. In addition, UE, which sells electricity at the wholesale level, faces competition in the sale of electricity. UE must submit price bids on an annual basis for the sale of its electricity to the regional distribution company. A large percentage of the electricity purchased by the regional distribution companies is produced by the Czech Republics dominant state-owned energy producer.
Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy management services. Although the deregulation of natural gas utilities continues to progress, the competition in this area is well developed with regard to price and services from both local and regional marketers.
Competition: The Timber Segment
With respect to the Timber segment, Highland competes with other sawmill operations and with other suppliers of timber, logs and lumber. These competitors may be local, regional, national or international in scope. This competition, however, is primarily limited to those entities which either process or supply high quality hardwoods species such as cherry, oak and maple as veneer logs, saw logs, export logs or lumber ultimately used in the production of high-end furniture, cabinetry and flooring. The Timber segment sells its products both nationally and internationally.
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 that this has on Utility segment revenues 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.
Volumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its revenues. Supply Corporations allowed rates are based on a straight fixed-variable rate design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed only to recover the variable costs associated with actual transportation or storage of gas.
Volumes transported by Empire may vary materially depending on weather, and can have a moderate effect on its revenues. Empires allowed rates are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. Variable charges based on volumes are
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Variations in weather conditions can materially affect the volume of gas consumed by customers of the Energy Marketing segment and the amount of thermal energy consumed by the heating customers of the International segment. Volume variations can have a corresponding impact on revenues within these segments.
The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. Traditionally, the timber harvesting season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months typically focus on pulpwood and on thinning out lower-grade species from the timber stands to encourage the growth of higher-grade species. During 2004, several factors, including the sale of acreage in 2003, changes in market demands, and facility upgrades resulted in a change in our cutting schedule and a more level harvest each month.
Capital Expenditures
A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading Investing Cash Flow.
Environmental Matters
A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading Other Matters and in Item 8, Note G Commitments and Contingencies.
Miscellaneous
The Company and its wholly-owned or majority-owned subsidiaries had a total of 2,918 full-time employees at September 30, 2004, with 2,055 employees in all of its U.S. operations and 863 employees in its international operations. This is a decrease of 3.9% from the 3,037 total employed at September 30, 2003.
Agreements covering employees in collective bargaining units in New York were renegotiated, effective as of November 2003, and are scheduled to expire in February 2008. Certain agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 2003, and are scheduled to expire in April 2009. Other agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 2003, and are scheduled to expire in May 2009. An agreement covering employees in collective bargaining units in the Czech Republic is scheduled to expire on December 31, 2004. A new four-year contract is currently being negotiated.
The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.
The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on the Companys internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Companys internet website is not part of this Form 10-K or any other report filed with or furnished to the SEC.
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Executive Officers of the Company as of
November 15, 2004(1)
Name and Age (as of
Current Company Positions and Other Material
September 30, 2004)
Business Experience During Past Five Years
(60)
Chairman of the Board of Directors since January
2002; Chief Executive Officer since October 2001; President
since July 1999; and President of Horizon since September 1995.
Mr. Ackerman has served as a Director since March 1994, and
previously served as Senior Vice President from June 1989 to
July 1999 and President of Distribution Corporation from October
1995 to July 1999.
(51)
President of Distribution Corporation since July
1999; Senior Vice President of Supply Corporation since July
2000. Mr. Smith served as Senior Vice President of
Distribution Corporation from January 1993 to July 1999.
(61)
President of Supply Corporation since March 2000;
President of Empire since February 2003; Senior Vice President
of Distribution Corporation since February 1997. Mr. Seeley
served as Vice President of the Company from January 2000 to
April 2000.
(57)
President of Seneca since October 1996 and
President of Highland since March 1998.
(52)
Treasurer of the Company since April 2004;
Controller of the Company from February 2003 through March 2004;
Senior Vice President of Distribution Corporation since July
2001; Controller of Distribution Corporation from February 1997
through March 2004; Treasurer of Distribution Corporation since
April 2004; Treasurer and Secretary of Supply Corporation since
April 2004; Secretary and Treasurer of Horizon since February
1997; and Vice President of Distribution Corporation from April
1993 to July 2001.
(45)
Controller of the Company since April 2004;
Controller of Distribution Corporation and Supply Corporation
since April 2004; Chief Auditor of the Company from July 1994
through March 2004.
(51)
Secretary of the Company since October 1995;
Senior Vice President of Distribution Corporation since July
2001; and Vice President of Distribution Corporation from June
1994 to July 2001.
(55)
President of Horizon Power since March 2001; Vice
President of Horizon since September 1995. Mr. Hale
previously served as Senior Vice President of Supply Corporation
from February 1997 to March 2003.
(52)
Senior Vice President of Supply Corporation since
July 2001; and Vice President of Supply Corporation from April
1993 to July 2001.
(49)
Senior Vice President of Distribution Corporation
since July 2001; and Vice President of Distribution Corporation
from June 1994 to July 2001.
(1) | The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers have served or currently serve as officers or directors of other subsidiaries of the Company. |
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Item 2 | Properties |
General Information on Facilities
The investment of the Company in net property, plant and equipment was $3.0 billion at September 30, 2004. Approximately 58% of this investment was in the Utility and Pipeline and Storage segments, which are primarily located in western and central New York and northwestern Pennsylvania. The Exploration and Production segment, which has the next largest investment in net property, plant and equipment (31%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, in the Gulf Coast region of Texas, Louisiana, and Alabama and in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The remaining investment in net property, plant and equipment consisted primarily of the International segment (7%) which is located in the Czech Republic, the Timber segment (3%) which is located primarily in northwestern Pennsylvania, and All Other and Corporate operations (1%). During the past five years, the Company has made significant additions to property, plant and equipment in order to augment the reserve base of oil and gas in the United States and Canada, and to expand and improve transmission and distribution facilities for both retail and transportation customers. Net property, plant and equipment has increased $646 million, or 27%, since 1999.
The Utility segment had a net investment in property, plant and equipment of $1.0 billion at September 30, 2004. The net investment in its gas distribution network (including 14,781 miles of distribution pipeline) and its service connections to customers represent approximately 57% and 29%, respectively, of the Utility segments net investment in property, plant and equipment at September 30, 2004.
The Pipeline and Storage segment had a net investment of $696.5 million in property, plant and equipment at September 30, 2004. Transmission pipeline represents 37% of this segments total net investment and includes 2,575 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 32 storage fields, four of which are jointly operated with certain pipeline suppliers, and 439 miles of pipeline. Net investment in storage facilities includes $91.1 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 29 compressor stations with 75,306 installed compressor horsepower.
The Exploration and Production segment had a net investment in property, plant and equipment of $923.7 million at September 30, 2004. Of this amount, $780.9 million relates to properties located in the United States. The remaining net investment of $142.8 million relates to properties located in Canada.
The International segment had a net investment in property, plant and equipment of $227.9 million at September 30, 2004. This represents UEs net investment in district heating and electric generation facilities.
The Timber segment had a net investment in property, plant and equipment of $82.8 million at September 30, 2004. Located primarily in northwestern Pennsylvania, the net investment includes two sawmills and approximately 87,000 acres of land and timber.
The Utility and Pipeline and Storage segments facilities provided the capacity to meet the Companys 2004 peak day sendout, including transportation service, of 1,756.3 MMcf, which occurred on January 15, 2004. Withdrawals from storage of 736.2 MMcf provided approximately 41.9% of the requirements on that day.
Company maps are included in exhibit 99.3 of this Form 10-K and are incorporated herein by reference.
Exploration and Production Activities
The Company is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the Gulf Coast region of Texas, Louisiana, and Alabama. Also, Exploration and Production operations are conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Further discussion of oil and gas producing activities is included in Item 8, Note N-Supplementary Information for Oil and Gas Producing Activities.
12
Senecas oil and gas reserves reported in Note N as of September 30, 2004 were estimated by Senecas geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA), a statistical agency of the U.S. Department of Energy. The basis of reporting Senecas reserves to the EIA is identical to that reported in Note N.
The following is a summary of certain oil and gas
information taken from Senecas records. All monetary
amounts are expressed in U.S. dollars.
Production
For the Year Ended
September 30
2004
2003
2002
$
5.61
$
5.41
$
2.89
$
35.31
$
29.17
$
22.83
$
4.78
$
4.22
$
3.69
$
31.51
$
27.88
$
22.51
$
0.60
$
0.56
$
0.60
73
75
100
$
5.54
$
5.01
$
2.86
$
31.89
$
26.12
$
19.94
$
5.72
$
5.12
$
2.86
$
22.86
$
23.67
$
20.09
$
1.05
$
1.00
$
0.81
55
59
63
$
5.91
$
5.07
$
3.74
$
31.30
$
28.77
$
23.76
$
5.72
$
5.10
$
3.74
$
31.30
$
28.77
$
23.76
$
0.54
$
0.43
$
0.53
14
14
12
13
Productive Wells
Productive Wells
For the Year Ended
September 30
2004
2003
2002
$
5.66
$
5.28
$
2.99
$
33.13
$
27.16
$
21.03
$
5.11
$
4.52
$
3.58
$
26.06
$
25.11
$
21.01
$
0.76
$
0.72
$
0.67
142
148
175
$
4.87
$
4.67
$
2.29
$
30.94
$
26.41
$
19.94
$
4.87
$
4.20
$
3.59
$
30.94
$
15.85
$
18.11
$
1.00
$
1.65
$
1.29
22
55
64
$
5.51
$
5.18
$
2.88
$
32.98
$
26.90
$
20.63
$
5.06
$
4.47
$
3.58
$
26.40
$
21.84
$
19.94
$
0.80
$
0.97
$
0.84
164
203
239
United States
Gulf Coast
West Coast
Appalachian
Region
Region
Region
Total U.S.
At September 30, 2004
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
32
34
1,155
1,912
31
1,944
1,220
20
15
1,146
1,837
25
1,857
1,186
Canada
Total Company
At September 30, 2004
Gas
Oil
Gas
Oil
177
49
2,121
1,269
124
34
1,981
1,220
14
Developed and Undeveloped Acreage
United States
Gulf
West
Coast
Coast
Appalachian
Total
Total
At September 30, 2004
Region
Region
Region
U.S.
Canada
Company
Gross
102,270
9,839
508,466
620,575
109,194
729,769
76,549
9,469
481,732
567,750
74,302
642,052
Gross
206,619
464,525
671,144
421,690
1,092,834
115,909
440,004
555,913
316,820
872,733
As of September 30, 2004, the aggregate
amount of gross undeveloped acreage expiring in the next three
years and thereafter are as follows: 142,172 acres in 2005
(106,758 net acres), 98,660 acres in 2006
(91,148 net acres), 130,707 acres in 2007
(80,783 net acres), and 721,295 acres thereafter
(594,044 net acres).
Drilling Activity
Present Activities
Productive
Dry
For the Year Ended September 30
2004
2003
2002
2004
2003
2002
Exploratory
1.25
1.27
0.50
3.67
0.65
2.10
0.31
Exploratory
49.00
30.97
47.99
2.00
Exploratory
3.00
3.00
3.00
0.10
1.00
41.00
58.00
27.00
0.10
Exploratory
4.25
4.27
3.50
0.10
4.67
90.65
91.07
75.30
2.10
Exploratory
52.85
5.00
0.20
6.08
2.50
4.00
10.50
17.16
33.70
5.00
7.90
Exploratory
52.85
9.25
4.47
9.58
2.60
8.67
101.15
108.23
109.00
5.00
10.00
United States
Gulf
West
Coast
Coast
Appalachian
Total
Total
At September 30, 2004
Region
Region
Region
U.S.
Canada
Company
Gross
1.00
5.00
25.00
31.00
1.00
32.00
Net
0.67
5.00
24.05
29.72
1.00
30.72
(1)
Includes wells awaiting completion.
15
Item 3 | Legal Proceedings |
In an action instituted in the New York State Supreme Court, Chautauqua County on January 31, 2000 against Seneca, NFR and National Fuel Gas Corporation, Donald J. and Margaret Ortel and Brian and Judith Rapp, individually and on behalf of all those similarly situated, allege, in an amended complaint which adds National Fuel Gas Company as a party defendant that (a) Seneca underpaid royalties due under leases operated by it, and (b) Senecas co-defendants (i) fraudulently participated in and concealed such alleged underpayment, and (ii) induced Senecas alleged breach of such leases. Plaintiffs seek an accounting, declaratory and related injunctive relief, and compensatory and exemplary damages. Defendants have denied each of plaintiffs material substantive allegations and set up twenty-five affirmative defenses in separate verified answers.
A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc). On December 23, 2002, the court granted certification of the proposed class, as modified to exclude those leaseholders whose leases provide for calculation of royalties based upon a flat fee, or flat fee per cubic foot of gas produced. The courts order states that there are approximately 749 potential class members. Discovery has begun on the merits of the claims.
In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporations denial of natural gas service in November 2000 to the plaintiffs decedent, Velma Arlene Fordham, caused decedents death in February 2001. The plaintiff seeks damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation has denied plaintiffs material allegations, set up seven affirmative defenses in separate verified answers and filed a cross-claim against the co-defendant. Distribution Corporation believes and will vigorously assert that plaintiffs allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. The litigation is in the early stages of discovery. For a discussion of a related matter before the NYPSC, refer to Item 7 MD&A of this report under the heading Regulatory Matters.
On December 22, 2003, the Pennsylvania Department of Environmental Protection (DEP) issued an order to Seneca to halt its timber harvesting operations on 21,000 acres in Cameron, Elk and McKean counties in Pennsylvania. The order asserts certain violations of DEP regulations concerning erosion, sedimentation and stream crossings. The order requires Seneca to apply for certain permits, control erosion, submit plans for removal of water encroachments not included in permit applications, notify the DEP of additional current or planned timber harvesting operations, and grant the DEP access to timber acreage. On January 9, 2004, Seneca filed with the Pennsylvania Environmental Hearing Board (Hearing Board) a notice of appeal, objecting to each finding and order contained in the order, and asserting that the DEPs findings are factually incorrect, an arbitrary exercise of the DEPs functions and duties, and contrary to law. Also on January 9, 2004, Seneca filed with the Hearing Board a petition requesting a stay of operation of portions of the order. On January 16, 2004, the parties settled Senecas request for a stay. Seneca has resumed its timber harvesting operations pursuant to the terms of the settlement. The settlement preserves various issues raised by the DEPs order for a hearing on the merits of Senecas notice of appeal. The most substantial question involves whether Seneca is required to apply for a permit under Section 102.5(b) of Title 25 of the Pennsylvania Code, governing earth disturbance activities of greater than 25 acres. The DEP takes the position that Seneca must aggregate the acreage of all of its logging sites across its entire 21,000 acre tract for purposes of determining whether its earth disturbing activities meet the 25 acres threshold. Seneca maintains that no permit is required, because the law does not require aggregation and each of its individual logging sites disturbs less than 25 acres. Seneca is engaged in negotiations to resolve this dispute on acceptable terms, and litigation deadlines have been extended to accommodate those discussions.
The Company believes, based on the information presently known, that the ultimate resolution of these matters, individually or in the aggregate, will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcomes
16
For a discussion of various environmental and other matters, refer to Item 7, MD&A and Item 8 at Note G Commitments and Contingencies.
The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Companys present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
Item 4 | Submission of Matters to a Vote of Security Holders |
No matter was submitted to a vote of security holders during the quarter ended September 30, 2004.
PART II
Item 5 | Market for the Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Information regarding the market for the Companys common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 8 at Note D-Capitalization and Short-Term Borrowings and Note M-Market for Common Stock and Related Shareholder Matters (unaudited).
On July 1, 2004, the Company issued a total
of 1,800 unregistered shares of Company common stock to the
six non-employee directors of the Company then serving on the
Board of Directors, 300 shares to each such director. All
of these unregistered shares were issued as partial
consideration for such directors services during the
quarter ended September 30, 2004, pursuant to the
Companys Retainer Policy for Non-Employee Directors. These
transactions were exempt from registration under
Section 4(2) of the Securities Act of 1933, as transactions
not involving a public offering.
Issuer Purchases of Equity
Securities
Total Number of
Shares Purchased
Maximum Number of
as Part of Publicly
Shares that May Yet
Total Number of
Announced Share
Be Purchased Under
Shares
Average Price
Repurchase Plans
Share Repurchase
Period
Purchased(a)
Paid per Share
or Programs
Plans or Programs
59,546
$
26.04
35,616
$
26.49
216,163
$
27.97
311,325
$
27.43
(a) | Represents (i) shares of common stock of the Company purchased on the open market with Company matching contributions for the accounts of participants in the Companys 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices and/or applicable withholding taxes. |
17
Item 6 | Selected Financial Data(1) |
Year Ended September 30 | |||||||||||||||||||||
|
|||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||
|
|
|
|
|
|||||||||||||||||
(Thousands) | |||||||||||||||||||||
Summary of Operations
|
|||||||||||||||||||||
Operating Revenues
|
$ | 2,031,393 | $ | 2,035,471 | $ | 1,464,496 | $ | 2,059,836 | $ | 1,412,416 | |||||||||||
|
|
|
|
|
|||||||||||||||||
Operating Expenses:
|
|||||||||||||||||||||
Purchased Gas
|
949,452 | 963,567 | 462,857 | 1,002,466 | 488,383 | ||||||||||||||||
Fuel Used in Heat and Electric Generation
|
65,722 | 61,029 | 50,635 | 54,968 | 54,893 | ||||||||||||||||
Operation and Maintenance
|
413,593 | 386,270 | 394,157 | 364,318 | 350,383 | ||||||||||||||||
Property, Franchise and Other Taxes
|
72,111 | 82,504 | 72,155 | 83,730 | 78,878 | ||||||||||||||||
Depreciation, Depletion and Amortization
|
189,538 | 195,226 | 180,668 | 174,914 | 142,170 | ||||||||||||||||
Impairment of Oil and Gas Producing Properties
|
| 42,774 | | 180,781 | | ||||||||||||||||
|
|
|
|
|
|||||||||||||||||
1,690,416 | 1,731,370 | 1,160,472 | 1,861,177 | 1,114,707 | |||||||||||||||||
Gain (Loss) on Sale of Timber Properties
|
(1,252 | ) | 168,787 | | | | |||||||||||||||
Gain (Loss) on Sale of Oil and Gas Producing
Properties
|
4,645 | (58,472 | ) | | | | |||||||||||||||
|
|
|
|
|
|||||||||||||||||
Operating Income
|
344,370 | 414,416 | 304,024 | 198,659 | 297,709 | ||||||||||||||||
Other Income (Expense):
|
|||||||||||||||||||||
Income from Unconsolidated Subsidiaries
|
805 | 535 | 224 | 1,794 | 1,669 | ||||||||||||||||
Impairment of Investment in Partnership
|
| | (15,167 | ) | | | |||||||||||||||
Other Income
|
6,671 | 6,887 | 7,017 | 10,639 | 6,366 | ||||||||||||||||
Interest Expense on Long-Term Debt
|
(83,827 | ) | (92,766 | ) | (90,543 | ) | (81,851 | ) | (67,195 | ) | |||||||||||
Other Interest Expense
|
(6,763 | ) | (12,290 | ) | (15,109 | ) | (25,294 | ) | (32,890 | ) | |||||||||||
|
|
|
|
|
|||||||||||||||||
Income Before Income Taxes and Minority Interest
in Foreign Subsidiaries
|
261,256 | 316,782 | 190,446 | 103,947 | 205,659 | ||||||||||||||||
Income Tax Expense
|
92,737 | 128,161 | 72,034 | 37,106 | 77,068 | ||||||||||||||||
Minority Interest in Foreign Subsidiaries
|
(1,933 | ) | (785 | ) | (730 | ) | (1,342 | ) | (1,384 | ) | |||||||||||
|
|
|
|
|
|||||||||||||||||
Income Before Cumulative Effect of Changes in
Accounting
|
166,586 | 187,836 | 117,682 | 65,499 | 127,207 | ||||||||||||||||
Cumulative Effect of Changes in Accounting
|
| (8,892 | ) | | | | |||||||||||||||
|
|
|
|
|
|||||||||||||||||
Net Income Available for Common Stock
|
$ | 166,586 | $ | 178,944 | $ | 117,682 | $ | 65,499 | $ | 127,207 | |||||||||||
|
|
|
|
|
18
Year Ended September 30
2004
2003
2002
2001
2000
(Thousands)
$
2.03
$
2.21
(2)
$
1.47
$
0.83
$
1.63
$
2.01
$
2.20
(2)
$
1.46
$
0.82
$
1.61
$
1.10
$
1.06
$
1.03
$
0.99
$
0.95
$
1.09
$
1.05
$
1.02
$
0.97
$
0.94
$
1.12
$
1.08
$
1.04
$
1.01
$
0.96
19,063
19,217
20,004
20,345
21,164
$
1,048,428
$
1,028,393
$
960,015
$
945,693
$
939,753
696,487
705,927
487,793
483,222
474,972
923,730
925,833
1,072,200
1,081,622
998,852
227,905
219,199
207,191
178,250
172,602
80
171
125
262
360
82,838
87,600
110,624
90,453
95,607
21,172
22,042
6,797
1,209
1,241
6,124
1,883
2
4
$
3,006,764
$
2,991,048
$
2,844,745
$
2,780,713
$
2,683,391
$
3,711,798
$
3,719,060
$
3,401,309
$
3,445,231
$
3,251,031
$
1,253,701
$
1,137,390
$
1,006,858
$
1,002,655
$
987,437
1,133,317
1,147,779
1,145,341
1,046,694
953,622
$
2,387,018
$
2,285,169
$
2,152,199
$
2,049,349
$
1,941,059
(1) | Certain prior year amounts have been reclassified to conform with current year presentation. |
(2) | Includes cumulative effect of changes in accounting of ($0.11) basic and diluted. |
Item 7 | Managements Discussion and Analysis of Financial Condition and Results of Operations |
OVERVIEW
The Company is a diversified energy company consisting of six reportable business segments. Refer to Item I, Business, for a more detailed description of each of the segments. This Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations (MD&A), provides information concerning:
1. | The critical accounting policies of the Company; | |
2. | Changes in revenues and earnings of the Company under the heading, Results of Operations; | |
3. | Operating, investing and financing cash flows under the heading Capital Resources and Liquidity; | |
4. | Off-Balance Sheet Arrangements; |
19
5. | Contractual Obligations; and | |
6. | Other Matters, including: a.) disclosures and tables concerning market risk sensitive instruments, b.) rate matters in the Companys New York, Pennsylvania and FERC regulated jurisdictions, c.) environmental matters, and d.) new accounting pronouncements. |
The information in MD&A should be read in conjunction with the Companys financial statements in Item 8 of this report.
Throughout MD&A, a few events will stand out that impact the results of operations and capital resources and liquidity of the Company for 2004 and 2003. First, the Company, in its Exploration and Production segment, sold its Southeast Saskatchewan oil and gas properties in 2003 after a thorough review of the economics of its non-regulated business. These properties were sold given their overall marginal contribution to earnings. Second, the Companys Exploration and Production segment benefited from higher commodity prices in 2004. Third, the Company, in its Pipeline and Storage segment, purchased Empire State Pipeline (Empire) from Duke Energy Corporation on February 6, 2003. Empire was acquired because the Company believes that the pipeline better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases.* In furtherance of that objective, in February 2004, the Company announced that it is pursuing an extension of the Empire State Pipeline as an upstream supply link for Phase I of the Millennium Pipeline. Fourth, the Company, in its Timber segment, sold approximately 70,000 acres of timber properties in August 2003 as a means of financing its acquisition of Empire. The Company recognized the concerns about its debt to capital ratio after the Empire acquisition and therefore sold these timber properties to reduce the short-term debt used to initially finance the acquisition.
Another event, which occurred in 2003 and is discussed more fully in Item 8 at Note J Acquisitions, is the acquisition of all of the partnership interests in Toro Partners, L.P. (Toro). The Company has been successful in operating landfill gas projects, where the gas is used to generate electricity, and this acquisition allows the Company to operate short-distance landfill gas pipelines that purchase, transport and resell landfill gas to customers.
Overall, the Company emphasized debt reduction in 2004 and, to that end, has reduced its debt to capitalization ratio from .57 at September 30, 2003 to .51 at September 30, 2004.
CRITICAL ACCOUNTING POLICIES
The Company has prepared its consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. The preparation of these financial statements 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. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Companys most critical accounting policies, which are defined as those policies whereby judgments or uncertainties could affect the application of those policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Companys significant accounting policies, refer to Item 8 at Note A Summary of Significant Accounting Policies.
Oil and Gas Exploration and Development Costs. In the Companys Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities.
20
The Company believes that determining the amount of the Companys proved reserves is a critical accounting estimate. Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves 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. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full-cost method of accounting (on a units-of-production basis). Unevaluated properties are excluded from the depletion calculation until they are evaluated. Once they are evaluated, costs associated with these properties are transferred to the pool of costs being depleted.
In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed on a country-by-country basis and determines a limit, or ceiling, to the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net revenues using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income taxes. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions or subtractions to proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write-down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. The Company recorded non-cash impairments relating to its Canadian properties in 2003 which amounted to $28.9 million (after tax) and resulted from downward revisions to crude oil reserves (related to the Canadian properties sold) as well as a decline in crude oil prices subsequent to the March 31, 2003 ceiling test calculation. At September 30, 2003, the capitalized costs of Canadian oil and gas properties less accumulated depletion and related deferred taxes were nearly equal to the ceiling for Canadian oil and gas properties. During 2004, the Canadian oil and gas properties passed the quarterly ceiling tests but capitalized costs less accumulated depletion and related deferred taxes were still nearly equal to the ceiling at September 30, 2004. A downward revision to reserves or prices could result in an impairment of the Canadian oil and gas properties in the future.
It is difficult to predict what factors could lead to future impairments under the SECs full cost ceiling test. As discussed above, fluctuations or subtractions to proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to Statement of Financial Accounting Standards No. 71, Accounting for the Effect of Certain Types of Regulation and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows the Company to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in the income statement 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. Managements assessment of the probability of recovery or pass through of regulatory assets
21
Accounting for Derivative Financial Instruments. The Company, in its Exploration and Production segment, Energy Marketing segment, Pipeline and Storage segment and All Other Category, uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments are categorized as price swap agreements, no cost collars, options and futures contracts. The Company, in its Pipeline and Storage segment, uses an interest rate collar to limit interest rate fluctuations on certain variable rate debt. In accordance with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, the Company accounts for these instruments as effective cash flow hedges or fair value hedges. As such, gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective, gains or losses from the derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction.
The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The fair value of the non exchange-traded derivative financial instruments are based on valuations determined by the counterparties. Refer to the Market Risk Sensitive Instruments section in Item 7, MD&A, for further discussion of the Companys derivative financial instruments.
Pension and Other Post-Retirement
Benefits.
The amounts reported in the
Companys financial statements related to its pension and
other post-retirement benefits are determined on an actuarial
basis, which uses many assumptions in the calculation of such
amounts. These assumptions include the discount rate, the
expected return on plan assets, the rate of compensation
increase and, for other post-retirement benefits, the expected
annual rate of increase in per capita cost of covered medical
and prescription benefits. Changes in actuarial assumptions and
actuarial experience could have a material impact on the amount
of pension and post-retirement benefit costs and funding
requirements experienced by the Company.* However, the Company
expects to recover substantially all of its net periodic pension
and other post-retirement benefit costs attributable to
employees in its Utility and Pipeline and Storage segments in
accordance with the applicable regulatory commission
authorization.* For financial reporting purposes, the difference
between the amounts of pension cost and post-retirement benefit
cost recoverable in rates and the amounts of such costs as
determined under applicable accounting principles is recorded as
either a regulatory asset or liability, as appropriate, as
discussed above under Regulation.
RESULTS OF OPERATIONS
EARNINGS
2004 Compared with 2003
The Companys earnings were
$166.6 million in 2004 compared with earnings of
$178.9 million in 2003. The decrease in earnings is
primarily the result of lower earnings in the Timber and Utility
segments partially offset by higher earnings in the Exploration
and Production, International, and Pipeline and Storage
22
For a more complete discussion of the cumulative
effect of changes in accounting, refer to
Note A Summary of Significant Accounting
Policies in Item 8 of this report. Additional discussion of
earnings in each of the business segments can be found in the
business segment information that follows.
2003 Compared with 2002
The Companys earnings were
$178.9 million in 2003 compared with earnings of
$117.7 million in 2002. The increase in earnings of
$61.2 million was primarily the result of higher earnings
in the Timber, Utility, and Pipeline and Storage segments
partially offset by lower earnings in the Energy Marketing
segment and losses in the Exploration and Production and
International segments, as shown in the table below. This
earnings fluctuation was impacted by the 2003 events listed
above. Also, in 2002, earnings included a non-cash impairment of
the Companys investment in the Independence Pipeline
project in the Pipeline and Storage segment in the amount of
$9.9 million (after tax). Additional discussion of earnings
in each of the business segments can be found in the business
segment information that follows.
23
Earnings (Loss) by Segment
UTILITY
Revenues
Utility Operating Revenues
Utility Throughput million cubic
feet (MMcf)
24
Degree Days
2004 Compared with 2003
Operating revenues for the Utility segment
decreased $10.3 million in 2004 compared with 2003. This
resulted largely from a decrease in transportation revenues of
$5.8 million and a decrease in other revenues of
$4.3 million. Transportation revenues decreased because of
lower volumes being transported as a result of fuel switching, a
general economic downturn in the Utility segments service
territory and warmer weather, as shown in the degree day table
above. Retail revenues did not change significantly from the
prior year as the impact to revenues of lower retail sales
volumes was largely offset by the recovery of higher gas costs
(gas costs are recovered dollar for dollar in revenues) and a
base rate increase in the Utility segments Pennsylvania
jurisdiction. The recovery of higher gas costs resulted from a
much higher cost of purchased gas. See further discussion of
purchased gas below under the heading Purchased Gas.
Warmer weather and lower customer usage per account were the
major factors in the decrease in retail sales volumes. The
decrease in retail industrial sales volumes can be attributed to
fuel switching and a general economic downturn in the Utility
segments service territory.
The decrease in other operating revenues is
largely related to the three-year rate settlement approved by
the NYPSC which ended on September 30, 2003. As part of the
three-year rate settlement, Distribution Corporation was allowed
to utilize certain refunds from upstream pipeline companies and
certain other credits (referred to as the cost mitigation
reserve) to offset certain specific expense items. In
2003, Distribution Corporation utilized $7.6 million of the
cost mitigation reserve by recording $7.6 million of other
operating revenues. While the three-year rate settlement was
extended for an additional year, the provisions of the
settlement which gave rise to the other operating revenues in
2003 did not continue in 2004, causing other operating revenues
to decrease by $7.6 million in 2004. The impact of
utilizing a portion of the cost mitigation reserve in revenues
in 2003 was offset by an equal amount of operation and
maintenance expense and interest expense (thus there is no
earnings impact). Partially offsetting this decrease in
revenues, in accordance with the three-year rate settlement
which ended on September 30, 2003, Distribution Corporation
recorded a refund provision of $4.0 million as a reduction
of other operating revenues. While the provisions of the
settlement were extended for a one-year period, as previously
discussed, this refund provision did not recur in 2004 because
the New York rate jurisdictions earnings did not exceed
the sharing threshold. The refund provision relates to a 50%
sharing with customers of earnings over a predetermined amount.
Effective September 22, 2004, Distribution
Corporation stopped making off-system sales as a result of the
FERCs Order 2004, Standards of Conduct for
Transmission Providers, as discussed more fully in the
Rate Matters section below. As a result of this decision,
Distribution Corporation most likely will not have any
off-system sales in 2005.* However, due to profit sharing with
retail customers, the margins resulting from off-system sales
have been minimal and there should be no material impact to
margins in 2005.*
2003 Compared with 2002
Operating revenues for the Utility segment
increased $368.8 million in 2003 compared with 2002. This
resulted from an increase in retail and off-system gas sales
revenues of $319.5 million and $38.6 million,
respectively. Transportation and other revenues also increased
by $3.1 million and $7.5 million, respectively.
25
The increase in retail gas sales revenues for the
Utility segment was largely a function of the recovery of higher
gas costs, coupled with an increase in retail sales volumes, as
shown above. The increase in retail sales volumes was primarily
the result of colder weather, as shown in the degree day table
above. Off-system sales revenues increased because of higher gas
prices, which more than offset lower volumes. However, due to
profit sharing with retail customers, the margins resulting from
off-system sales were minimal. Colder weather also caused
transportation revenues and volumes to increase.
The increase in other operating revenues is
largely related to the three-year rate settlement which ended on
September 30, 2003, as discussed above. In 2003,
Distribution Corporation utilized $7.6 million of the cost
mitigation reserve by recording $7.6 million of other
operating revenues, compared to $2.2 million in 2002. In
both years, the impact of reversing a portion of the cost
mitigation reserve was offset by an equal amount of operation
and maintenance expense and interest expense (thus there is no
earnings impact). The increase in other operating revenues also
reflects a $1.3 million decrease in refund provisions. In
accordance with the three-year rate settlement discussed above,
Distribution Corporation recorded refund provisions related to a
50% sharing with customers of earnings over a predetermined
amount. The refund provisions associated with this earnings
sharing mechanism were $4.0 million and $5.3 million
in 2003 and 2002, respectively.
Earnings
2004 Compared with 2003
The Utility segments earnings in 2004 were
$46.7 million, a decrease of $10.1 million when
compared with earnings of $56.8 million in 2003. The major
factors driving this decrease were an increase in pension and
other post-retirement expenses of $9.9 million after tax,
higher bad debt expenses of $3.8 million after tax, warmer
weather in the Pennsylvania jurisdiction ($2.5 million
after tax), and lower usage per customer account in the New York
jurisdiction ($2.2 million after tax). These negative
factors were partially offset by the absence of a refund
provision in the New York jurisdiction in 2004 related to an
earnings sharing mechanism in the New York jurisdiction
($2.6 million after tax), as discussed above. Other
offsetting factors included a base rate increase in the
Pennsylvania jurisdiction of $1.5 million after tax and
lower interest expense of $4.7 million after tax.
The increase in pension and other post-retirement
expenses referred to above can be attributed largely to three
factors. First, in accordance with the one-year settlement
extension commencing on October 1, 2003 in the New York
rate jurisdiction (referred to above), the Company was required
to record an additional $8.0 million before tax
($5.2 million after tax) of pension and other
post-retirement expense for the year ended September 30,
2004 without a corresponding increase in revenues. Second, the
Utility segment recorded $2.2 million of expense after tax
associated with the settlement of a pension obligation. Third,
pension and other post-retirement expenses in the Pennsylvania
rate jurisdiction increased by $2.5 million after tax as
the rate settlement in that jurisdiction reflected higher
pension funding amounts and the amortization of previous other
post-retirement deferrals.
The impact of weather on the Utility
segments New York rate jurisdiction is tempered by a
weather normalization clause (WNC). The WNC, which covers
the eight month period from October through May, has had a
stabilizing effect on earnings for the New York rate
jurisdiction. In addition, in periods of colder than normal
weather, the WNC benefits the Utility segments New York
customers. In 2004, the WNC preserved $1.0 million of
earnings since the weather was warmer than normal in the New
York service territory. For 2003, the WNC reduced earnings by
approximately $3.8 million because it was colder than
normal in the New York service territory.
2003 Compared with 2002
The Utility segments earnings in 2003 were
$56.8 million, an increase of $7.3 million when
compared with earnings of $49.5 million in 2002. The major
factor driving this increase was the impact of colder weather in
the Utility segments Pennsylvania jurisdiction, which
contributed approximately $5.6 million to
26
In 2003, the WNC reduced earnings by
approximately $3.8 million because it was colder than
normal in the New York service territory. For 2002, the WNC
preserved earnings of approximately $9.9 million because it
was warmer than normal in the New York service territory.
Purchased Gas
The cost of purchased gas is the Companys
single largest operating expense. Annual variations in purchased
gas costs are 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 six 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 satisfies 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
Corporations average cost of purchased gas, including the
cost of transportation and storage, was $7.30 per thousand
cubic feet (Mcf) in 2004, an increase of 5% from the average
cost of $6.94 per Mcf in 2003. The average cost of
purchased gas in 2003 was 48% higher than the average cost of
$4.68 per Mcf in 2002. Additional discussion of the Utility
segments gas purchases appears under the heading
Sources and Availability of Raw Materials in
Item 1.
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating
Revenues
Pipeline and Storage Throughput
(MMcf)
27
2004 Compared with 2003
Operating revenues for the Pipeline and Storage
segment increased $8.3 million in 2004 as compared with
2003. The acquisition of Empire from Duke Energy Corporation on
February 6, 2003 was a significant factor contributing to
the revenue increase. For 2004, Empire recorded operating
revenues of $33.4 million ($32.3 million in firm
transportation revenues, $0.3 million in interruptible
transportation revenues and $0.8 million in other
revenues). For the period of February 6, 2003 to
September 30, 2003, Empire recorded operating revenues of
$20.9 million ($19.8 million in firm transportation
revenues, $0.8 million in interruptible transportation
revenues and $0.3 million in other revenues). Another
factor contributing to the increase in operating revenues in the
Pipeline and Storage segment was a $5.0 million increase in
revenues from unbundled pipeline sales included in other
revenues in the table above due to higher natural gas commodity
prices and higher volumes. These increases to operating revenues
were partially offset by lower intercompany rental income of
approximately $6.5 million and lower cashout revenues of
$1.3 million, both of which are included in other revenues
in the table above. Cashout revenues represent a cash resolution
of a gas imbalance whereby a customer pays Supply Corporation
for gas the customer receives in excess of amounts delivered
into Supply Corporations system by the customers
shipper. Cashout revenues are completely offset by purchased gas
expense. While transportation volumes increased during the year,
volume fluctuations generally do not have a significant impact
on revenues as a result of Supply Corporations straight
fixed-variable rate design.
2003 Compared with 2002
Operating revenues for the Pipeline and Storage
segment increased $34.0 million in 2003 as compared with
2002. For 2003, the acquisition of Empire was a significant
factor contributing to the revenue increase. For the period of
February 6, 2003 to September 30, 2003, Empire
recorded operating revenues of $20.9 million. Another
factor contributing to the increase in operating revenues in the
Pipeline and Storage segment was a $6.5 million increase in
revenues from unbundled pipeline sales included in other
revenues in the table above due primarily to higher natural gas
commodity prices and volumes. While transportation volumes
increased during the year, volume fluctuations generally do not
have a significant impact on revenues as a result of Supply
Corporations straight fixed-variable rate design.
Earnings
2004 Compared with 2003
The Pipeline and Storage segments earnings
in 2004 were $47.7 million, an increase of
$2.5 million when compared with earnings of
$45.2 million in 2003. The increase can be attributed
primarily to the earnings impact of the increase in revenues
from unbundled pipeline sales of $3.2 million after tax,
discussed above, as well as the increased earnings contribution
from Empire of $2.8 million. Also, Supply Corporation
interest expense decreased by $1.9 million after tax.
Offsetting these increases, Supply Corporation recorded
$1.8 million of expense after tax associated with the
settlement of a pension obligation in 2004. Supply Corporation
also experienced an earnings impact associated with higher
operation and maintenance expense of $1.5 million after tax.
2003 Compared with 2002
The Pipeline and Storage segments earnings
in 2003 were $45.2 million, an increase of
$15.5 million when compared with earnings of
$29.7 million in 2002. A major factor in the earnings
increase was the fact that 2002 included an after tax impairment
charge of $9.9 million ($15.2 million pre tax) related
to the Companys investment in Independence Pipeline
Company (a partnership discontinued in 2002 that had proposed to
construct and operate a 400-mile pipeline to transport natural
gas from Defiance, Ohio to Leidy, Pennsylvania). Higher revenues
from unbundled pipeline sales ($4.2 million after tax) were
also a contributor to the earnings increase. The Empire
acquisition in February 2003 contributed $3.0 million to
2003 earnings.
28
EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating
Revenues
Production Volumes
29
Average Prices
2004 Compared with 2003
Operating revenues for the Exploration and
Production segment decreased $11.6 million in 2004 as
compared with 2003. Oil production revenue after hedging
decreased $27.5 million due to a 2,209 Mbbl decline in
production offset partly by higher weighted average prices after
hedging ($4.56 per barrel). Most of the decrease in oil
production occurred in Canada (a 2,058 Mbbl decrease) as a
result of the September 2003 sale of the Companys
Southeast Saskatchewan properties, which is discussed below. Gas
production revenue after hedging increased $16.1 million.
Increases in the weighted average price of gas after hedging
($0.59 per Mcf) more than offset an overall decrease in gas
production. Most of the decrease in gas production occurred in
the Gulf Coast (an 845 MMcf decline), which is consistent
with the expected decline rates in the region. Lower West Coast
production (a 410 MMcf decline), down mainly due to a
decline in this segments South Lost Hills wells, was more
than offset by a 454 MMcf increase in Canadian gas
production. The increase in Canadian gas production is
attributable to additional drilling in East Central Alberta. The
decline in the South Lost Hills wells was attributable to the
maturing of the wells.
Refer to further discussion of derivative
financial instruments in the Market Risk Sensitive
Instruments section that follows. Refer to the tables
above for production and price information.
2003 Compared with 2002
Operating revenues for the Exploration and
Production segment decreased $5.7 million in 2003 as
compared with 2002. Oil production revenue after hedging
decreased $5.6 million due to a 925,000 barrel decline
in production offset partly by higher weighted average prices
after hedging ($1.90 per barrel). Gas production revenue
after hedging increased $2.5 million. Increases in the
weighted average price of gas after hedging ($0.89 per Mcf)
more than offset an overall decrease in gas production. Most of
the decrease in gas production occurred in the Gulf Coast (a
7,335 MMcf decline). The Company had anticipated some of
this decline in gas and oil production due to reduced activity
in the Gulf Coast region. Other factors in the overall
production decrease included an outside-operated offshore
pipeline leak that required four key producing blocks to be
shut-in for ten days, and a decline in drilling activity in
Canada related to a decision to sell the
30
Earnings
2004 Compared with 2003
The Exploration and Production segments
earnings in 2004 were $54.3 million, an increase of
$86.2 million when compared with a loss of
$31.9 million in 2003. Earnings were impacted by a few
events. In 2003, the Company sold its Southeast Saskatchewan
properties, recording an after tax loss of $39.6 million.
In 2004, the Company recorded an adjustment to the sale of its
Southeast Saskatchewan properties which increased 2004 earnings
by $4.6 million. When the transaction closed in September
2003, the initial proceeds received were subject to an
adjustment based on actual working capital and the resolution of
certain income tax matters. Those items were resolved with the
buyer in 2004 and, as a result, the Company received an
additional $4.6 million of sales proceeds. The Company
recorded impairment charges of $28.9 million after tax in
2003 related to its Canadian oil and gas properties. Also
contributing to the increase was the fact that the loss in 2003
included a charge of $0.6 million representing the
cumulative effect of a change in accounting for plugging and
abandonment costs. These events sum up to $73.7 million of
the overall earnings increase of $86.2 million. The
remaining increase can be attributed to decreases in depletion,
lease operating, and interest expense of $6.2 million after
tax, $15.9 million after tax, and $1.7 million after
tax, respectively, which more than offset the earnings impact of
a $7.4 million decrease in oil and gas revenues, discussed
above, and a $3.2 million increase in income tax expense
due to a higher effective tax rate. The decrease in depletion
and lease operating expenses primarily reflects the absence of
the Companys former Southeast Saskatchewan properties from
results of operations in 2004. The decrease in interest expense
was the result of lower debt balances. The higher effective tax
rate resulted from the elimination of cross-border intercompany
loans in September 2003 as a result of the sale of the Southeast
Saskatchewan properties.
2003 Compared with 2002
The Exploration and Production segment
experienced a loss of $31.9 million in 2003, a decrease of
$58.8 million when compared with earnings of
$26.9 million in 2002. The main reason for this decrease
was the loss of $39.6 million recorded upon the sale of the
Companys Southeast Saskatchewan oil and gas properties.
During 2003, the Company reviewed the economics of its
non-regulated business including certain oil and gas properties.
The Southeast Saskatchewan properties were identified as a
candidate for sale given their overall marginal contribution to
earnings. Impairment charges of $28.9 million after tax
recorded in 2003 related to the Companys Canadian oil and
gas assets also contributed to the decrease. Lower oil and gas
revenues, as discussed above, decreased earnings by
approximately $2.0 million. As an offset, the Exploration
and Production segment experienced lower depletion expense of
$2.9 million after tax (attributable to the production
decline) and lower general and administrative expenses of
$2.1 million after tax (attributable to cost-cutting
efforts in Canada). Another offsetting factor was a lower
effective income tax rate, which benefitted earnings by
approximately $3.4 million.
31
INTERNATIONAL
Revenues
International Operating Revenues
International Heating and Electric
Volumes
2004 Compared with 2003
Operating revenues for the International segment
increased $9.4 million in 2004 as compared with 2003.
Substantially all of this increase can be attributed to an
increase in the value of the Czech koruna compared to the
U.S. dollar.
2003 Compared with 2002
Operating revenues for the International segment
increased $18.8 million in 2003 as compared with 2002.
Substantially all of this increase can be attributed to an
increase in the value of the Czech koruna compared to the
U.S. dollar.
Earnings
2004 Compared with 2003
The International segments earnings in 2004
were $6.0 million, an increase of $15.6 million when
compared with a loss of $9.6 million in 2003. Earnings were
impacted by two events. During 2004, the government in the Czech
Republic enacted legislation that gradually reduces the
corporate statutory income tax rate from 31% to 24% over a
three-year period commencing January 1, 2004. In accordance
with accounting principles generally accepted in the United
States of America (GAAP), the Company recorded the full benefit
resulting from the change in the income tax rate
($5.2 million) as a reduction to deferred income tax
expense during 2004. During 2003, the Company recorded a
$8.3 million impairment charge resulting from the
Companys change in accounting for goodwill, as discussed
below. These two events account for $13.5 million of the
earnings increase in the International segment. An increase in
the value of the Czech koruna compared to the U.S. dollar
improved earnings by approximately $1.1 million.
2003 Compared with 2002
The International segment experienced a loss of
$9.6 million in 2003 compared with a loss of
$4.4 million in 2002. This decrease can be attributed
primarily to an $8.3 million impairment charge, resulting
from the Companys change in accounting for goodwill. The
Companys goodwill balance as of October 1, 2002
totaled $8.3 million and was related to the Companys
investments in the Czech Republic,
32
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues
Energy Marketing Volumes
2004 Compared with 2003
Operating revenues for the Energy Marketing
segment decreased $20.3 million in 2004 as compared with
2003. This decrease primarily reflects lower gas sales revenue
due to lower throughput, which was the result of warmer weather
and the loss of several large volume but low margin customers to
other marketers.
2003 Compared with 2002
Operating revenues for the Energy Marketing
segment increased $153.4 million in 2003 as compared with
2002. This increase primarily reflects higher gas sales revenue
due to higher natural gas commodity prices. Higher volumes,
which were principally the result of the addition of several
high volume but low margin customers and colder weather, also
contributed to the increase in operating revenues.
Earnings
2004 Compared with 2003
The Energy Marketing segment earnings in 2004
were $5.5 million, a decrease of $0.4 million when
compared with earnings of $5.9 million in 2003. While
margins on gas sales improved slightly, this increase was offset
by expenses associated with the settlement of a pension
obligation and a higher effective tax rate.
2003 Compared with 2002
The Energy Marketing segment earnings in 2003
were $5.9 million, a decrease of $2.7 million when
compared with earnings of $8.6 million in 2002. This
decrease primarily reflects lower margins on gas sales,
33
TIMBER
Revenues
Timber Operating Revenues
Timber Board Feet
2004 Compared with 2003
Operating revenues for the Timber segment did not
change significantly in 2004 as compared with 2003. The decrease
in log sales of $5.6 million was principally due to the
Companys August 2003 sale of approximately
70,000 acres of timber properties discussed below. However,
kiln dry lumber sales increased $5.6 million due to an
increase in activity at the Companys mill operations. As a
result of the sale of the timber properties, a larger percentage
of timber processed in the Companys mills is now purchased
from third parties.
2003 Compared with 2002
Operating revenues for the Timber segment
increased $8.8 million in 2003, as compared with 2002. The
increase can largely be attributed to higher sales of cherry
veneer logs that command higher than average prices. Higher kiln
dry lumber sales also contributed to the increase. Partially
offsetting the increase in log sales and kiln dry lumber sales,
other revenues decreased $2.5 million primarily because
2002 included a $2.4 million gain on the sale of standing
timber.
Earnings
2004 Compared with 2003
The Timber segment earnings in 2004 were
$5.6 million, a decrease of $106.9 million when
compared with earnings of $112.5 million in 2003. This
earnings fluctuation is largely a reflection of the sale of
timber properties discussed below. In 2003, the Company recorded
a gain of $102.2 million after tax on that sale. In 2004,
the Company received final timber cruise information of the
properties it sold and, based on that information, determined
that property records pertaining to $1.3 million
($0.8 million after tax) of timber property were not
properly shown as having been transferred to the purchaser. As a
result, the Company
34
2003 Compared with 2002
The Timber segment earnings in 2003 were
$112.5 million, an increase of $102.8 million when
compared with earnings of $9.7 million in 2002. The
increase was primarily due to the sale of approximately
70,000 acres of timber properties on August 1, 2003
for approximately $186.0 million. As a result of the sale,
the Company recorded a gain of approximately $102.2 million
after tax. After the August sale, the Company had approximately
87,000 acres of timber property remaining.
OPERATIONS OF UNCONSOLIDATED
SUBSIDIARIES
The Companys unconsolidated subsidiaries
consist of equity method investments in Seneca Energy II,
LLC (Seneca Energy), Model City Energy, LLC (Model City) and
Energy Systems North East, LLC (ESNE). The Company has a 50%
ownership interest in each of these entities. Seneca Energy and
Model City generate and sell electricity using methane gas
obtained from landfills owned by outside parties. ESNE generates
electricity from an 80-megawatt, combined-cycle, natural
gas-fired power plant in North East, Pennsylvania. ESNE sells
its electricity into the New York power grid. In 2002, the
Company wrote off its 33 1/3% equity method
investment in Independence Pipeline Company. The write-off
amounted to $15.2 million ($9.9 million after tax) and
is recorded on the Consolidated Statement of Income as
Impairment of Investment in Partnership. Aside from this
impairment, income from unconsolidated subsidiaries has been
relatively small, amounting to $0.8 million,
$0.5 million and $0.2 million in 2004, 2003 and 2002,
respectively.
INTEREST CHARGES
Although most of the variances in Interest
Charges are discussed in the earnings discussion by segment
above, following is a summary on a consolidated basis:
Interest on long-term debt was $8.9 million
lower in 2004 compared to 2003; however, interest on long-term
debt was $2.2 million higher in 2003 compared to 2002. The
decrease in 2004 resulted mainly from a lower average amount of
long-term debt outstanding and lower weighted average interest
rates. The increase in 2003 resulted mainly from a higher
average amount of long-term debt outstanding which more than
offset lower weighted average interest rates.
Other interest charges decreased
$5.5 million in 2004 and $2.8 million in 2003. The
decrease in both years was primarily the result of lower
weighted average interest rates on short-term debt combined with
a lower average amount of short-term debt outstanding.
35
Table of Contents
2004 Events
A $5.2 million reduction to deferred income
tax expense in the International segment resulting from a change
in the statutory income tax rate in the Czech Republic;
Settlement of a pension obligation which resulted
in the recording of additional expense amounting to
$6.4 million after tax, allocated among the segments as
follows: $2.2 million to the Utility segment
($1.2 million in the New York jurisdiction and
$1.0 million in the Pennsylvania jurisdiction),
$2.0 million to the Pipeline and Storage segment
($1.8 million to Supply Corporation and $0.2 million
to Empire State Pipeline), $0.9 million to the Exploration
and Production segment, $0.4 million to the International
segment, $0.3 million to the Energy Marketing segment and
$0.6 million to the Corporate and All Other categories;
An adjustment to the 2003 sale of the
Companys Southeast Saskatchewan oil and gas properties in
the Exploration and Production segment which increased 2004
earnings by $4.6 million; and
An adjustment to the Companys 2003 sale of
its timber properties in the Timber segment, which reduced 2004
earnings by $0.8 million after tax.
2003 Events
The Companys Timber segment completed the
sale of approximately 70,000 acres of its timber property,
recording an after tax gain of $102.2 million;
The Companys Exploration and Production
segment completed the sale of its Southeast Saskatchewan oil and
gas properties in Canada, recording an after tax loss of
$39.6 million;
The Companys Exploration and Production
segment recorded after tax impairment charges of
$28.9 million related to its Canadian oil and gas assets;
An impairment in the amount of $8.3 million,
representing the cumulative effect of a change in accounting for
goodwill in the Companys International segment; and
A reduction in the amount of $0.6 million,
representing the cumulative effect of a change in accounting for
plugging and abandonment costs in the Companys Exploration
and Production segment.
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
$
46,718
$
56,808
$
49,505
47,726
45,230
29,715
54,344
(31,930
)
26,851
5,982
(9,623
)
(4,443
)
5,535
5,868
8,642
5,637
112,450
9,689
165,942
178,803
119,959
1,530
193
(885
)
(886
)
(52
)
(1,392
)
$
166,586
$
178,944
$
117,682
Year Ended September 30
2004
2003
2002
(Thousands)
$
808,740
$
801,984
$
538,345
137,092
137,905
86,963
17,454
23,263
18,332
963,286
963,152
643,640
106,841
107,220
68,606
80,563
86,374
83,267
1,951
6,237
(1,292
)
$
1,152,641
$
1,162,983
$
794,221
Year Ended September 30
2004
2003
2002
70,109
76,449
64,639
12,752
14,177
11,549
2,261
3,537
3,715
85,122
94,163
79,903
16,839
17,999
21,541
60,565
64,232
61,909
162,526
176,394
163,353
Table of Contents
Percent (Warmer)
Colder Than
Year Ended September 30
Normal
Actual
Normal
Prior Year
Buffalo
6,729
6,572
(2.3
)%
(7.9
)%
Erie
6,277
6,086
(3.0
)%
(10.1
)%
Buffalo
6,815
7,137
4.7
%
22.9
%
Erie
6,135
6,769
10.3
%
26.9
%
Buffalo
6,847
5,808
(15.2
)%
(12.6
)%
Erie
6,146
5,334
(13.2
)%
(16.0
)%
Table of Contents
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
$
120,443
$
109,508
$
88,082
3,084
3,944
3,315
123,527
113,452
91,397
63,962
63,223
62,733
20
36
7
63,982
63,259
62,740
22,198
24,709
13,247
$
209,707
$
201,420
$
167,384
Year Ended September 30
2004
2003
2002
338,991
340,925
290,507
12,692
10,004
7,315
351,683
350,929
297,822
Table of Contents
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
$
167,127
$
150,982
$
148,467
119,564
147,101
152,746
28,614
28,879
16,995
1,815
1,308
6,627
(23,422
)
(22,956
)
(13,855
)
$
293,698
$
305,314
$
310,980
(1)
Represents the elimination of certain West Coast
gas production revenue included in Gas (after
Hedging) in the table above that is sold to the gas
processing plant shown in the table above. An elimination for
the same dollar amount is made to reduce the gas processing
plants purchased gas expense.
Year Ended September 30
2004
2003
2002
17,596
18,441
25,776
4,057
4,467
4,889
5,132
5,123
4,402
6,228
5,774
6,387
33,013
33,805
41,454
1,534
1,473
1,815
2,650
2,872
3,004
20
10
9
324
2,382
2,834
4,528
6,737
7,662
Table of Contents
Year Ended September 30
2004
2003
2002
$
5.61
$
5.41
$
2.89
$
5.54
$
5.01
$
2.86
$
5.91
$
5.07
$
3.74
$
4.87
$
4.67
$
2.29
$
5.51
$
5.18
$
2.88
$
5.06
$
4.47
$
3.58
$
35.31
$
29.17
$
22.83
$
31.89
$
26.12
$
19.94
$
31.30
$
28.77
$
23.76
$
30.94
$
26.41
$
19.94
$
32.98
$
26.90
$
20.63
$
26.40
$
21.84
$
19.94
(1)
Refer to further discussion of hedging activities
below under Market Risk Sensitive Instruments and in
Note E Financial Instruments in Item 8 of
this report.
(2)
Includes low gravity oil which generally sells
for a lower price.
Table of Contents
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
$
88,395
$
80,752
$
65,386
30,949
29,386
26,960
4,081
3,932
2,969
$
123,425
$
114,070
$
95,315
Year Ended September 30
2004
2003
2002
8,538,554
8,766,567
8,689,887
936,877
973,968
972,832
(1)
Gigajoules = one billion joules. A joule is
a unit of energy.
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
$
283,747
$
304,390
$
151,219
602
270
38
$
284,349
$
304,660
$
151,257
Year Ended September 30
2004
2003
2002
41,651
45,135
33,042
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
$
21,790
$
27,341
$
21,528
5,923
6,200
6,567
27,416
21,814
15,976
841
871
3,336
$
55,970
$
56,226
$
47,407
Year Ended September 30
2004
2003
2002
(Thousands)
6,848
8,764
8,174
9,552
11,913
12,878
15,020
13,300
10,794
31,420
33,977
31,846
Table of Contents
Table of Contents
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
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, impairment of oil and
gas producing properties (in 2003), deferred income taxes,
impairment of investment in partnership (in 2002), income or
loss from unconsolidated subsidiaries net of cash distributions,
minority interest in foreign subsidiaries, gain or loss on sale
of timber properties, gain or loss on sale of oil and gas
producing properties and cumulative effect of changes in
accounting.
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 impact of weather on cash flow is tempered in the
Utility segments New York rate jurisdiction by its WNC and
in the Pipeline and Storage segment by Supply Corporations
straight fixed-variable rate design.
Cash provided by operating activities in the
Exploration and Production segment may vary from period to
period as a result of changes in the commodity prices of natural
gas and crude oil. The Company uses various derivative financial
instruments, including price swap agreements, no cost collars,
options and futures contracts in an attempt to manage this
energy commodity price risk.
Net cash provided by operating activities totaled
$444.3 million in 2004, an increase of $117.5 million
compared with the $326.8 million provided by operating
activities in 2003. Most of this increase occurred in the
Utility segment, largely attributable to gas cost recovery
timing differences.
36
INVESTING CASH FLOW
Expenditures for Long-Lived Assets
Expenditures for long-lived assets include
additions to property, plant and equipment (capital
expenditures) and investments in corporations (stock
acquisitions) or partnerships, net of any cash acquired.
The Companys expenditures for long-lived
assets totaled $172.3 million in 2004. The table below
presents these expenditures:
Utility
The majority of the Utility capital expenditures
were made for replacement of mains and main extensions, as well
as for the replacement of service lines.
Pipeline and Storage
The majority of the Pipeline and Storage
segments capital expenditures were made for additions,
improvements and replacements to this segments
transmission and gas storage systems.
Exploration and Production
The Exploration and Production segments
capital expenditures were primarily well drilling and completion
expenditures and included approximately $31.4 million for
the Canadian region, $19.4 million for the Gulf Coast
region, $17.4 million for the West Coast region and
$9.5 million for the Appalachian region. These amounts
included approximately $12.1 million spent to develop
proved undeveloped reserves.
International
The majority of the International segments
capital expenditures were concentrated in improvements and
replacements within the district heating and power generation
plants in the Czech Republic.
Timber
The majority of the Timber segments capital
expenditures were for equipment for this segments sawmill
and kiln operations.
All Other and Corporate
The majority of the All Other and Corporate
capital expenditures were for capital improvements to the
Companys new corporate headquarters.
37
Estimated Capital Expenditures
The Companys estimated capital expenditures
for the next three years are:*
Estimated capital expenditures for the Utility
segment in 2005 will be concentrated in the areas of main and
service line improvements and replacements and, to a minor
extent, the installation of new services.*
Estimated capital expenditures for the Pipeline
and Storage segment in 2005 will be concentrated in the
reconditioning of storage wells and the replacement of storage
and transmission lines.*
The Company also continues to explore various
opportunities to expand its capabilities to transport gas to the
East Coast, either through the Supply Corporation or Empire
systems or in partnership with others. As announced in February
2004, the Company is pursuing a project to expand its natural
gas pipeline operations to serve new markets in New York and
elsewhere in the Northeast by extending the Empire State
Pipeline.* This proposed extension project would provide an
upstream supply link for Phase I of the Millennium Pipeline
and will transport Canadian and other natural gas supplies to
downstream customers, including KeySpan Gas East Corporation,
which has entered into a precedent agreement to be a major
shipper, subject to the satisfaction of various conditions.* The
pipeline extension will be designed to move at least
250 MMcf of natural gas per day.* The preliminary estimate
of the cost for developing the Empire extension project is
$140 million and the targeted in-service date is late in
calendar 2006.* The estimated capital expenditures do not
include any expenditures for the Empire extension project. As of
September 30, 2004, the Company had incurred approximately
$0.6 million in costs (all of which have been reserved)
related to this project.
Estimated capital expenditures in 2005 for the
Exploration and Production segment include approximately
$32.0 million for Canada, $29.0 million for the Gulf
Coast region ($28.0 million on the off-shore program in the
Gulf of Mexico), $20.0 million for the West Coast region
and $12.0 million for the Appalachian region.*
The estimated capital expenditures for the
International segment in 2005 will be concentrated on
improvements and replacements within the district heating and
power generation plants in the Czech Republic.* The estimated
capital expenditures do not include any expenditures for the
Companys European power development projects. Currently,
any costs incurred on these power development projects are
expensed. The Companys European power development projects
currently include one project in Italy and one project in
Bulgaria. In Italy, the Company has signed a joint development
agreement with an Italian utility for the construction of a
400-megawatt combined-cycle natural gas fired electric
generating plant. The estimated cost of this project is
$200.0 million to $210.0 million. In Bulgaria, the
Company is pursuing the opportunity to construct, own and
operate two new 100-megawatt gas-fired combined-cycle plants.
The estimated cost of this project is $200.0 million to
$220.0 million. Whether the Company moves forward to
construct these projects will depend on successful negotiation
of various operating agreements as well as the availability of
funds from banks or other financial institutions to cover a
significant amount of the construction costs.* The respective
projects would serve as collateral for such financing
arrangements.*
38
Estimated capital expenditures in the Timber
segment will be concentrated on the construction or purchase of
new facilities and equipment for this segments sawmill and
kiln operations.*
Estimated capital expenditures in the All Other
and Corporate category will be concentrated on the purchase of
equipment for a 55-megawatt electric generation facility in
Buffalo, New York combined with capital improvements to the
Companys corporate headquarters.
The Company continuously evaluates capital
expenditures and investments in corporations and partnerships.
The amounts are subject to modification for opportunities such
as the acquisition of attractive oil and gas properties, timber
or natural gas storage facilities and the expansion of natural
gas 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 or
other investments in the Companys other business segments
depends, to a large degree, upon market conditions.*
FINANCING CASH FLOW
In February 2004 and August 2004, the Company
repaid $125.0 million of maturing 7.75% debentures at
par and $100.0 million of maturing 6.82% medium-term notes
at par, respectively. The Company used available cash and
short-term borrowings to repay this debt.
Consolidated short-term debt increased
$38.6 million during 2004. Although a certain amount of
short-term borrowings were initially used to repay the maturing
debt discussed above, the Company was able to use cash flow from
operations to repay most of this additional short-term debt. The
Company continues to consider short-term debt (consisting of
short-term notes payable to banks and commercial paper) an
important source of cash for temporarily financing capital
expenditures and investments in corporations and/or
partnerships, gas-in-storage inventory, unrecovered purchased
gas costs, exploration and development expenditures and other
working capital needs. Fluctuations in these items can have a
significant impact on the amount and timing of short-term debt.
At September 30, 2004, the Company had outstanding
short-term notes payable to banks and commercial paper of
$26.5 million and $130.3 million, respectively. The
Company has SEC authorization under the Holding Company Act to
borrow and have outstanding as much as $750.0 million of
short-term debt at any time through December 31, 2005. As
for bank loans, the Company maintains a number of individual
(bi-lateral) uncommitted or discretionary lines of credit with
certain financial institutions for general corporate purposes.
Borrowings under these lines of credit are made at competitive
market rates. Each of these credit lines, which aggregate to
$400.0 million, are revocable at the option of the
financial institutions and are reviewed on an annual basis. The
Company anticipates that these lines of credit will continue to
be renewed.* The total amount available to be issued under the
Companys commercial paper program is $200.0 million.
The commercial paper program is backed by a syndicated committed
credit facility totaling $220.0 million. Of that amount,
$110.0 million is committed to the Company through
September 25, 2005 and $110.0 million is committed to
the Company through September 30, 2005. The Company
anticipates that it will be able to replace this facility at or
before its maturity.*
Under the Companys committed credit
facility, the Company has agreed that its debt to capitalization
ratio will not at the last day of any fiscal quarter, exceed
.625 from October 1, 2003 through September 30, 2004
and .60 from October 1, 2004 and thereafter. At
September 30, 2004, the Companys debt to
capitalization ratio (as calculated under the facility) was .51.
The constraints specified in the committed credit facility would
permit an additional $576.0 million in short-term and/or
long-term debt to be outstanding before the Companys debt
to capitalization ratio would exceed .60. If a downgrade in any
of the Companys credit ratings were to occur, access to
the commercial paper markets might not be possible.* However,
the Company expects that it could borrow under its uncommitted
bank lines of credit or rely upon other liquidity sources,
including cash provided by operations.*
Under the Companys existing indenture
covenants, at September 30, 2004, the Company would have
been permitted to issue up to a maximum of $713.0 million
in additional long-term unsecured indebtedness at then current
market interest rates (further limited by the debt to
capitalization ratio constraints noted in
39
The Companys 1974 indenture pursuant to
which $399.0 million (or 35%) of the Companys
long-term debt (as of September 30, 2004) was issued
contains a cross-default provision whereby the failure by the
Company to perform certain obligations under other borrowing
arrangements could trigger an obligation to repay the debt
outstanding under the indenture. In particular, a repayment
obligation could be triggered if the Company fails (i) to
pay any scheduled principal or interest on any debt under any
other indenture or agreement or (ii) to perform any other
term in any other such indenture or agreement, and the effect of
the failure causes, or would permit the holders of the debt to
cause, the debt under such indenture or agreement to become due
prior to its stated maturity, unless cured or waived.
The Companys $220.0 million, committed
credit facility also contains a cross-default provision whereby
the failure by the Company or its significant subsidiaries to
make payments under other borrowing arrangements, or the
occurrence of certain events affecting those other borrowing
arrangements, could trigger an obligation to repay any amounts
outstanding under the committed credit facility. In particular,
a repayment obligation could be triggered if (i) the
Company or any of its significant subsidiaries fails to make a
payment when due of any principal or interest on any other
indebtedness aggregating $20.0 million or more or
(ii) an event occurs that causes, or would permit the
holders of any other indebtedness aggregating $20.0 million
or more to cause, such indebtedness to become due prior to its
stated maturity. As of September 30, 2004, the Company had
no debt outstanding under the committed credit facility.
The Companys embedded cost of long-term
debt was 6.4% at September 30, 2004 and 6.5% at
September 30, 2003. Refer to Interest Rate Risk
in this Item for a more detailed break-down of the
Companys embedded cost of long-term debt.
The Company also has authorization from the SEC,
in an order under the Holding Company Act, to issue long-term
debt securities and equity securities in an aggregate amount of
up to $1.5 billion during the orders authorization
period, which commenced in November 2002 and extends to
December 31, 2005. The Company has an effective
registration statement on file with the SEC under which it has
available capacity to issue an additional $550.0 million of
debt and equity securities under the Securities Act of 1933, and
within the authorization granted by the SEC under the Holding
Company Act. The Company may sell all or a portion of the
remaining registered securities if warranted by market
conditions and the Companys capital requirements. Any
offer and sale of the above mentioned $550.0 million of
debt and equity securities will be made only by means of a
prospectus meeting the requirements of the Securities Act of
1933 and the rules and regulations thereunder.
The amounts and timing of the issuance and sale
of debt or equity securities will depend on market conditions,
indenture requirements, regulatory authorizations and the
capital requirements of the Company.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has entered into certain off-balance
sheet financing arrangements. These financing arrangements are
primarily operating and capital leases. The Companys
consolidated subsidiaries have operating leases, the majority of
which are with the Utility and the Pipeline and Storage
segments, having a remaining lease commitment of approximately
$34.3 million. These leases have been entered into for the
use of buildings, vehicles, construction tools, meters, computer
equipment and other items and are accounted for as operating
leases. The Companys unconsolidated subsidiaries, which
are accounted for under the equity method, have capital leases
of electric generating equipment having a remaining lease
commitment of approximately $10.0 million. The Company has
guaranteed 50%, or $5.0 million, of these capital lease
commitments.
40
CONTRACTUAL OBLIGATIONS
The following table summarizes the Companys
expected future contractual cash obligations as of
September 30, 2004, and the twelve-month periods over which
they occur:
The Company has made certain other guarantees on
behalf of its subsidiaries. The guarantees relate primarily to:
(i) obligations under derivative financial instruments,
which are included on the consolidated balance sheet in
accordance with the Financial Accounting Standards Boards
Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities (see Item 7,
MD&A under the heading Critical Accounting
Policies Accounting for Derivative Financial
Instruments); (ii) NFR obligations to purchase gas or
to purchase gas transportation/storage services where the
amounts due on those obligations each month are included on the
consolidated balance sheet as a current liability; and
(iii) other obligations which are reflected on the
consolidated balance sheet. The Company believes that the
likelihood it would be required to make payments under the
guarantees is remote, and therefore has not included them on the
table above.*
OTHER MATTERS
The Company is involved in litigation arising in
the normal course of business. Also in the normal course of
business, the Company is involved in tax, regulatory and other
governmental audits, inspections, investigations and other
proceedings that involve state and federal taxes, safety,
compliance with regulations, rate base, cost of service and
purchased gas cost issues, among other things. While the
resolution of such litigation or regulatory matters could have a
material effect on earnings and cash flows in the period of
resolution, none of this litigation, and none of these
regulatory matters, are expected to change materially the
Companys present liquidity position, nor have a material
adverse effect on the financial condition of the Company.*
The Company has a tax-qualified, noncontributory
defined-benefit retirement plan (Retirement Plan) that covers
substantially all domestic employees of the Company. The Company
has been making contributions to the Retirement Plan over the
last several years and anticipates that it will continue making
contributions to the Retirement Plan.* During 2004, the Company
contributed $37.1 million to the Retirement Plan. The
Company anticipates that the annual contribution to the
Retirement Plan in 2005 will be in the range of
$25.0 million to $35.0 million.* The Company expects
that all subsidiaries having domestic employees covered by the
Retirement Plan will make contributions to the Retirement Plan.*
The funding of such contributions will come from amounts
collected in rates in the Utility and Pipeline and Storage
segments or through short-term borrowings or through cash from
operations.*
The Company provides health care and life
insurance benefits for substantially all domestic retired
employees under a post-retirement benefit plan (Post-Retirement
Plan). The Company has been making contributions to the
Post-Retirement Plan over the last several years and anticipates
that it will continue making contributions to the
Post-Retirement Plan.* During 2004, the Company contributed
$39.7 million to
41
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodity Price Risk
The Company, in its Exploration and Production
segment, Energy Marketing segment, Pipeline and Storage segment,
and All Other category, uses various derivative financial
instruments (derivatives), including price swap agreements, no
cost collars, options and futures contracts, as part of the
Companys overall energy commodity price risk management
strategy. Under this strategy, the Company manages a portion of
the market risk associated with fluctuations in the price of
natural gas and crude oil, thereby attempting to provide more
stability to operating results. The Company has operating
procedures in place that are administered by experienced
management to monitor compliance with the Companys risk
management policies. The derivatives are not held for trading
purposes. The fair value of these derivatives, as shown below,
represents the amount that the Company would receive from or pay
to the respective counterparties at September 30, 2004 to
terminate the derivatives. However, the tables below and the
fair value that is disclosed do not consider the physical side
of the natural gas and crude oil transactions that are related
to the financial instruments.
The following tables disclose natural gas and
crude oil price swap information by expected maturity dates for
agreements in which the Company receives a fixed price in
exchange for paying a variable price as quoted in Inside
FERC or on the New York Mercantile Exchange. Notional
amounts (quantities) are used to calculate the contractual
payments to be exchanged under the contract. The weighted
average variable prices represent the weighted average
settlement prices by expected maturity date as of
September 30, 2004. At September 30, 2004, the Company
had not entered into any natural gas or crude oil price swap
agreements extending beyond 2009.
At September 30, 2004, the Company would
have had to pay its respective counterparties an aggregate of
approximately $25.0 million to terminate the natural gas
price swap agreements outstanding at that date. The Company
would have had to pay an aggregate of approximately
$57.2 million to its counterparties to terminate the crude
oil price swap agreements outstanding at September 30, 2004.
42
At September 30, 2003, the Company had
natural gas price swap agreements covering 13.1 Bcf at a
weighted average fixed rate of $4.24 per Mcf. The Company
also had crude oil price swap agreements covering 2,184,000 bbls
at a weighted average fixed rate of $25.44 per bbl. The
increase in price swap agreements from September 2003 to
September 2004 is largely a result of managements decision
to hedge farther into the future in the Exploration and
Production segment given the high commodity prices available. It
is also a reflection of managements decision to use crude
oil price swap agreements instead of crude oil no cost collars
in the Exploration and Production segment, as discussed below.
The following table discloses the notional
quantities, the weighted average ceiling price and the weighted
average floor price for the no cost collars used by the Company
to manage natural gas and crude oil price risk. The no cost
collars provide for the Company to receive monthly payments from
(or make payments to) other parties when a variable price falls
below an established floor price (the Company receives payment
from the counterparty) or exceeds an established ceiling price
(the Company pays the counterparty). At September 30, 2004,
the Company had not entered into any natural gas or crude oil no
cost collars extending beyond 2006.
At September 30, 2004, the Company would
have had to pay an aggregate of approximately $1.6 million
to terminate the natural gas no cost collars outstanding at that
date. The Company would have had to pay an aggregate of
approximately $2.1 million to terminate the crude oil no
cost collars outstanding at that date.
At September 30, 2003, the Company had
natural gas no cost collars covering 3.7 Bcf at a weighted
average floor price of $3.46 per Mcf and a weighted average
ceiling price of $7.21 per Mcf. The Company also had crude
oil no cost collars covering 1,290,000 bbls at a weighted
average floor price of $23.91 per bbl and a weighted
average ceiling price of $28.00 per bbl. The increase in
natural gas no cost collars from September 2003 to September
2004 is a result of managements decision to hedge farther
out into the future in the Exploration and Production segment
given the high commodity prices available. The decrease in crude
oil no cost collars from September 2003 to September 2004 is a
result of managements decision to use crude oil price swap
agreements instead of crude oil no cost collars to hedge future
crude oil production in the Exploration and Production segment.
With the current commodity price environment, management
determined that it could better meet its commodity price
objectives through the use of price swap agreements.
43
The following table discloses the notional
quantities and weighted average strike prices by expected
maturity dates for options used by the Exploration and
Production segment to manage natural gas price risk. The put
options provide for the Company to receive monthly payments from
other parties when a variable price falls below an established
floor or strike price. The call options provide for
the Company to pay monthly payments to other parties when a
variable price rises above an established ceiling or
strike price. At September 30, 2004, the
Company held no options with maturity dates extending beyond
2006.
At September 30, 2004, the Company would
have received from the respective counterparties an aggregate of
approximately $0.2 million to terminate the put options
outstanding at that date. The Company would have had to pay an
aggregate of approximately $1.0 million to terminate the
call options outstanding at that date. The Company did not have
any options outstanding at September 30, 2003.
The following table discloses the net contract
volumes purchased (sold), weighted average contract prices and
weighted average settlement prices by expected maturity date for
futures contracts used to manage natural gas price risk. At
September 30, 2004, the Company held no futures contracts
with maturity dates extending beyond 2007.
At September 30, 2004, the Company would
have had to pay $6.2 million to terminate these futures
contracts.
At September 30, 2003, the Company had
futures contracts covering 3.6 Bcf (net long position) at a
weighted average contract price of $5.60 per Mcf. The
change from a net long position at September 30, 2003 to a
net short position at September 30, 2004 can largely be
explained by the high commodity price environment experienced by
the Energy Marketing segment in 2004. With high commodity
prices, customers have been reluctant to enter into fixed price
sales commitments. With fewer fixed price sales commitments, the
Energy Marketing segment has purchased fewer contracts since it
no longer faces as great a risk of commodity price increases.
The Company may be exposed to credit risk on some
of the derivatives disclosed above. 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. To mitigate such credit risk,
management performs a credit check and then, on an ongoing
basis, monitors counterparty credit exposure. Management has
obtained guarantees from the parent companies of the respective
counterparties to its derivatives. At September 30, 2004,
the Company used seven counterparties for its over the counter
derivatives. At September 30, 2004, no individual
counterparty represented greater than 20% of total credit risk
(measured as volumes hedged by an individual counterparty as a
percentage of the Companys total volumes hedged).
44
Exchange Rate Risk
The International segments investment in
the Czech Republic is valued in Czech korunas, and, as such,
this investment is subject to currency exchange risk when the
Czech korunas are translated into U.S. dollars. The
Exploration and Production segments investment in Canada
is valued in Canadian dollars, and, as such, this investment is
subject to currency exchange risk when the Canadian dollars are
translated into U.S. dollars. This exchange rate risk to
the Companys investments in the Czech Republic and Canada
results in increases or decreases to the Cumulative Foreign
Currency Translation Adjustment (CTA), a component of
Accumulated Other Comprehensive Income/ Loss on the Consolidated
Balance Sheets. When the foreign currency increases in value in
relation to the U.S. dollar, there is a positive adjustment
to CTA. When the foreign currency decreases in value in relation
to the U.S. dollar, there is a negative adjustment to CTA.
Interest Rate Risk
The Companys exposure to interest rate risk
arises primarily from its borrowing under short-term debt
instruments. At September 30, 2004, these instruments
consisted of domestic short-term bank loans and commercial paper
totaling $156.8 million. The interest rate on these
short-term bank loans and commercial paper approximated 1.8% at
September 30, 2004.
The following table presents the principal cash
repayments and related weighted average interest rates by
expected maturity date for the Companys long-term fixed
rate debt as well as the other long-term debt of certain of the
Companys subsidiaries. The interest rates for the variable
rate debt are based on those in effect at September 30,
2004:
The Company uses an interest rate collar to limit
interest rate fluctuations on $41.4 million of variable
rate debt included in Other Notes in the table above. Under the
interest rate collar the Company makes quarterly payments to (or
receives payments from) another party when a variable rate falls
below an established floor rate (the Company pays the
counterparty) or exceeds an established ceiling rate (the
Company receives payment from the counterparty). Under the terms
of the collar, which extends until 2009, the variable rate is
based on London InterBank Offered Rate. The floor rate of the
collar is 5.15% and the ceiling rate is 9.375%. The Company
would have had to pay $2.2 million to terminate the
interest rate collar at September 30, 2004.
45
RATE MATTERS
Utility Operation
Base rate adjustments 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 of the appropriate
regulatory authorities.
New York Jurisdiction
On October 11, 2000, the NYPSC approved a
settlement agreement (Agreement) between Distribution
Corporation, Staff of the Department of Public Service, the New
York State Consumer Protection Board and Multiple Intervenors
(an advocate for large commercial and industrial customers)
(collectively, Parties) that established rates for
the three-year period ending September 30, 2003. On
July 25, 2003, the Parties and other interests executed a
settlement agreement (Settlement) to extend the terms of the
Agreement and Distribution Corporations restructuring plan
one year commencing October 1, 2003. The Settlement was
approved by the NYPSC in an order issued on September 18,
2003. As approved, the Settlement continued existing base rates,
but reduced the level above which earnings are shared 50/50 with
customers from the previous 11.5% return on equity to 11.0%. In
addition, the Settlement increased the combined pension and
other post-retirement benefit expense by $8.0 million,
without a corresponding increase in revenues. Most other
features of Distribution Corporations service remained
largely unchanged. In April 2004, Distribution Corporation
commenced confidential settlement negotiations with the NYPSC
and other parties concerning, among other things, its revenue
requirement for the year ending September 30, 2005. Those
settlement discussions failed to produce an agreement prior to
the expiration of the Settlement. On August 27, 2004,
Distribution Corporation filed proposed tariff amendments and
supporting testimony designed to increase its annual revenues by
$41.3 million beginning October 1, 2004. The rate
request was filed to address throughput reductions and increased
operating costs such as uncollectibles and personnel expenses.
In accordance with standard rate case procedure, the NYPSC
suspended Distribution Corporations filing as provided by
law in order to allow time for an investigation and hearings.
Following hearings and further proceedings, the Commission will
issue an order approving, rejecting or modifying Distribution
Corporations rate request for an anticipated effective
date of late July, 2005. Distribution Corporation is unable to
ascertain the outcome of the rate proceeding at this time. The
existing base rates and other provisions of the Settlement that
expired on September 30, 2004 will continue to be in effect
until the Commission issues an order concerning Distribution
Corporations rate request.
On June 1, 2004, Distribution Corporation
submitted a filing to the NYPSC supporting the removal of a
$5 million annual bill credit originally established under
the terms of the Agreement. The filing requested removal of the
bill credit effective October 1, 2004. On
September 28, 2004, the NYPSC issued an order rejecting
Distribution Corporations request for the stated reason
that Distribution Corporations earnings were adequate, in
the NYPSCs opinion, without removal of the bill credit.
Distribution Corporation is contemplating further action on the
NYPSCs order.
In another order issued on September 28,
2004, the NYPSC directed the continuation, with modification, of
four programs under the Settlement that were scheduled to expire
on September 30, 2004. The effect of the NYPSCs order
was to unilaterally extend the terms of the Settlement without
Distribution Corporations consent. Although the
NYPSCs order stated that it provided for funding of the
programs, Distribution Corporation petitioned Supreme Court,
Albany County for an injunction to allow the programs to expire
on their own terms. Distribution Corporations petition was
partially successful, and the proceeding remains pending.
On September 20, 2001, the NYPSC issued an
order under which Distribution Corporation was directed to show
cause why an action for penalties of $19.0 million should
not be commenced against it for alleged violations of consumer
protection requirements. On December 3, 2001, Distribution
Corporation filed its response which vigorously asserted that
the allegations lacked merit. Distribution Corporation continues
to so believe. On July 28, 2004, the NYPSC concluded the
investigation of issues raised in the order without
46
Pennsylvania Jurisdiction
On April 16, 2003, Distribution Corporation
filed a request with the PaPUC to increase annual operating
revenues by $16.5 million to cover increases in the cost of
providing service, to be effective June 15, 2003. The PaPUC
suspended the effective date to January 15, 2004.
Distribution Corporation filed this request for several reasons
including increases in the costs associated with Distribution
Corporations ongoing construction program as well as
increases in uncollectible accounts and personnel expenses. On
October 16, 2003, the parties reached a settlement of all
issues. The settlement was submitted to the Administrative Law
Judge, who, on November 17, 2003, issued a decision
recommending adoption of the settlement. The settlement provides
for a base rate increase of $3.5 million and authorizes
deferral accounting for pension and other post-retirement
benefit expenses. The settlement was approved by the PaPUC on
December 18, 2003, and rates became effective
January 15, 2004.
On September 15, 2004, Distribution
Corporation filed revised tariffs with the PaPUC to increase
annual revenues by $22.8 million to cover increases in the
cost of service to be effective November 14, 2004. The rate
request was filed to address throughput reductions and increased
operating costs such as uncollectibles and personnel expenses.
Applying standard procedure, the PaPUC suspended Distribution
Corporations tariff filing to perform an investigation and
hold hearings. With this suspension, the effective date was
changed to June 14, 2005 and the proceeding remains pending.
Pipeline and Storage
Supply Corporation currently does not have a rate
case on file with the FERC. Management will continue to monitor
Supply Corporations financial position to determine the
necessity of filing a rate case in the future.
On November 25, 2003, the FERC issued
Order 2004 Standards of Conduct for Transmission
Providers (Order 2004). Order 2004
was clarified in Order 2004-A on April 16, 2004 and
Order 2004-B on August 2, 2004. Order 2004, which
went into effect September 22, 2004, regulates the conduct
of transmission providers (such as Supply Corporation) with
their energy affiliates. The FERC broadened the
definition of energy affiliates to include any
affiliate of a transmission provider if that affiliate engages
in or is involved in transmission (gas or electric)
transactions, or manages or controls transmission capacity, or
buys, sells, trades or administers natural gas or electric
energy or engages in financial transactions relating to the sale
or transmission of natural gas or electricity. Supply
Corporations principal energy affiliates will be Seneca,
NFR and, possibly, Distribution Corporation.* Order 2004
provides that companies may request waivers, which the Company
has done with respect to Distribution Corporation and is
awaiting rulings. Order 2004 also provides an exemption for
local distribution companies that are affiliated with interstate
pipelines (such as Distribution Corporation), but the exemption
is limited, with very minor exceptions, to local distribution
corporations that do not make any off-system sales and do not
purchase gas in ways FERC considers to be financial or
futures transactions or hedging. While Distribution
Corporation stopped making such off-system sales effective
September 22, 2004, some of its gas purchase arrangements
might be considered by FERC to be financial or futures
transactions or hedging. Supply Corporation and
Distribution Corporation would like to continue operating as
they do, whether by waiver, amendment or further clarification
of the new rules, or by complying with the requirements
applicable if Distribution Corporation were an energy affiliate.
Treating Distribution Corporation as an energy affiliate,
without any waivers, would require changes in the way Supply
Corporation and Distribution Corporation operate which would
decrease efficiency, but probably would not increase capital or
operating expenses to an extent that would be material to the
financial condition of the Company.* Until there is further
clarification from the FERC on the scope of these
47
Empire currently does not have a rate case on
file with the NYPSC. Management will continue to monitor its
financial position in the New York jurisdiction to
determine the necessity of filing a rate case in the future.
ENVIRONMENTAL MATTERS
It is the Companys policy to accrue
estimated environmental clean-up costs (investigation and
remediation) when such amounts can reasonably be estimated and
it is probable that the Company will be required to incur such
costs. The Company has estimated its clean-up costs related to
former manufactured gas plant sites and third party waste
disposal sites will be $14.0 million.* This liability has
been recorded on the Consolidated Balance Sheet at
September 30, 2004. Other than discussed in Note G
(referred to below), 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.* The Company is subject to
various federal, state and local laws and regulations (including
those of the Czech Republic and Canada) relating to the
protection of the environment. The Company has established
procedures for the ongoing evaluation of its operations to
identify potential environmental exposures and comply with
regulatory policies and procedures.
For further discussion refer to Item 8 at
Note G Commitments and Contingencies under the
heading Environmental Matters.
NEW ACCOUNTING PRONOUNCEMENTS
In September 2004, the SEC issued Staff
Accounting Bulletin No. 106 (SAB 106). SAB 106
addresses the application of SFAS No. 143,
Accounting for Asset Retirement Obligations
(SFAS 143) to companies that follow the full-cost method of
accounting for oil and gas property acquisition, exploration and
development costs. For a discussion of SAB 106 and its
impact on the Company, refer to Item 8 at
Note A Summary of Significant Accounting
Policies.
EFFECTS OF INFLATION
Although the rate of inflation has been
relatively low over the past few years, the Companys
operations remain sensitive to increases in the rate of
inflation because of its capital spending and the regulated
nature of a significant portion of its business.
SAFE HARBOR FOR FORWARD-LOOKING
STATEMENTS
The Company is including the following cautionary
statement in this 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, projections, 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 in this report, including, without limitation, those
which are designated with an asterisk (*) and those
which are identified by the use of the words
anticipates, estimates,
expects, intends, plans,
predicts, projects, and similar
expressions, are forward-looking statements as
defined in the Private Securities
48
49
The Company disclaims any obligation to update
any forward-looking statements to reflect events or
circumstances after the date hereof.
Refer to the Market Risk Sensitive
Instruments section in Item 7, MD&A.
50
Year Ended September 30
2004
2003
2002
(Millions)
$
444.3
$
326.8
$
345.6
(172.3
)
(152.2
)
(232.4
)
(228.8
)
(0.4
)
(0.5
)
186.0
7.1
78.5
22.1
2.0
12.1
5.0
38.6
(147.6
)
(224.8
)
(243.1
)
20.7
139.6
23.8
17.0
10.9
(89.1
)
(84.5
)
(81.0
)
3.4
1.6
1.5
$
14.7
$
29.2
$
(14.0
)
Table of Contents
Year Ended
September 30, 2004
Total Expenditures
For Long-Lived
Assets
(Millions)
$
55.4
23.2
77.7
7.5
2.8
5.7
$
172.3
Table of Contents
Year Ended September 30,
2005
2006
2007
(Millions)
$
54.0
$
52.0
$
51.0
22.0
22.0
22.0
93.0
91.0
89.0
15.0
26.0
29.0
2.0
1.0
1.0
5.0
$
191.0
$
192.0
$
192.0
(1)
Includes estimated expenditures for the years
ended September 30, 2005, 2006 and 2007 of approximately
$14 million, $27 million and $29 million,
respectively, to develop proved undeveloped reserves.
Table of Contents
Table of Contents
Table of Contents
Payments by Expected Maturity Dates
2005
2006
2007
2008
2009
Thereafter
Total
(Millions)
$
14.3
$
14.3
$
9.3
$
209.3
$
104.1
$
796.3
$
1,147.6
$
26.5
$
$
$
$
$
$
26.5
$
130.3
$
$
$
$
$
$
130.3
$
8.7
$
7.1
$
6.1
$
5.2
$
4.8
$
2.4
$
34.3
$
0.8
$
1.1
$
0.9
$
0.8
$
0.4
$
1.0
$
5.0
$
589.5
$
87.0
$
11.1
$
5.8
$
5.7
$
68.4
$
767.5
$
134.4
$
135.4
$
133.0
$
125.9
$
69.5
$
12.4
$
610.6
$
2.4
$
0.8
$
0.4
$
0.4
$
0.4
$
$
4.4
(1)
Gas prices are variable based on the NYMEX prices
adjusted for basis.
Table of Contents
Natural Gas Price Swap
Agreements
Expected Maturity Dates
2005
2006
2007
2008
2009
Total
11.3
8.4
1.8
1.2
0.3
23.0
$
5.47
$
5.68
$
5.02
$
4.80
$
4.81
$
5.47
$
7.12
$
6.74
$
6.13
$
5.58
$
5.50
$
6.81
Crude Oil Price Swap
Agreements
Expected Maturity Dates
2005
2006
2007
Total
2,743,000
1,755,000
540,000
5,038,000
$30.51
$33.27
$35.55
$32.01
$46.74
$41.31
$38.41
$43.95
Table of Contents
No Cost Collars
Expected Maturity Dates
2005
2006
Total
5.1
0.4
5.5
$8.31
$
7.88
$8.28
$4.94
$
4.77
$4.93
105,000
105,000
$28.56
$28.56
$25.00
$25.00
Table of Contents
Options
Expected Maturity Dates
2005
2006
Total
0.8
0.3
1.1
$
6.05
$
5.83
$
5.99
0.8
0.3
1.1
$
7.84
$
8.69
$
8.06
Futures Contracts
Expected Maturity Dates
2005
2006
2007
Total
(3.5
)
(0.4
)
0.1
(3.8
)
$
6.16
$
6.29
$
5.88
$
6.17
$
7.74
$
6.96
$
6.33
$
7.69
Table of Contents
Principal Amounts by Expected Maturity Dates
2005
2006
2007
2008
2009
Thereafter
Total
(Dollars in Millions)
$
$
$
$
200
$
100
$
796.3
$
1,096.3
0
%
0
%
0
%
6.3
%
6.0
%
6.5
%
6.4
%
$
14.3
$
14.3
$
9.3
$
9.3
$
4.1
$
$
51.3
4.1
%
4.1
%
2.8
%
2.8
%
2.8
%
3.5
%
(1)
$41.4 million is variable rate debt;
$9.9 million is fixed rate debt.
(2)
Weighted average interest rate excludes the
impact of an interest rate collar on $41.4 million of
variable rate debt.
Table of Contents
Table of Contents
Table of Contents
Table of Contents
1.
Changes in economic conditions, including
economic disruptions caused by terrorist activities or acts of
war;
2.
Changes in demographic patterns and weather
conditions, including the occurrence of severe weather;
3.
Changes in the availability and/or price of
natural gas, oil and coal;
4.
Inability to obtain new customers or retain
existing ones;
5.
Significant changes in competitive factors
affecting the Company;
6.
Governmental/regulatory actions, initiatives and
proceedings, including those affecting acquisitions, financings,
allowed rates of return, industry and rate structure,
franchises, permits, and environmental/safety requirements;
7.
Unanticipated impacts of restructuring
initiatives in the natural gas and electric industries;
8.
Significant changes from expectations in actual
capital expenditures and operating expenses and unanticipated
project delays or changes in project costs;
9.
The nature and projected profitability of pending
and potential projects and other investments;
10.
Occurrences affecting the Companys ability
to obtain funds from operations, debt or equity to finance
needed capital expenditures and other investments;
11.
Uncertainty of oil and gas reserve estimates;
12.
Ability to successfully identify and finance
acquisitions and ability to operate and integrate existing and
any subsequently acquired business or properties;
13.
Ability to successfully identify, drill for and
produce economically viable natural gas and oil reserves;
14.
Significant changes from expectations in the
Companys actual production levels for natural gas or oil;
15.
Changes in the availability and/or price of
derivative financial instruments;
16.
Changes in the price of natural gas or oil and
the effect of such changes on the accounting treatment or
valuation of financial instruments for the Companys
natural gas and oil reserves;
17.
Inability of the various counterparties to meet
their obligations with respect to the Companys financial
instruments;
18.
Regarding foreign operations, changes in trade
and monetary policies, inflation and exchange rates, taxes,
operating conditions, laws and regulations related to foreign
operations, and political and governmental changes;
19.
Significant changes in tax rates or policies or
in rates of inflation or interest;
20.
Significant changes in the Companys
relationship with its employees or contractors and the potential
adverse effects if labor disputes, grievances or shortages were
to occur;
Table of Contents
21.
Changes in accounting principles or the
application of such principles to the Company;
22.
Changes in laws and regulations to which the
Company is subject, including tax, environmental and employment
laws and regulations;
23.
The cost and effects of legal and administrative
claims against the Company;
24.
Changes in actuarial assumptions and the return
on assets with respect to the Companys retirement plan and
post-retirement benefit plans;
25.
Increasing health care costs and the resulting
effect on health insurance premiums and on the obligation to
provide post-retirement benefits; or
26.
Increasing costs of insurance, changes in
coverage and the ability to obtain insurance.
Item 7A
Quantitative and Qualitative Disclosures
About Market Risk
Table of Contents
Item 8 | Financial Statements and Supplementary Data |
Index to Financial Statements |
Page | |||||
|
|||||
Financial Statements:
|
|||||
52 | |||||
53 | |||||
54 | |||||
55 | |||||
56 | |||||
57 | |||||
Financial Statement Schedules:
|
|||||
For the three years ended September 30, 2004
|
|||||
100 |
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 L Quarterly Financial Data (unaudited) and Note N Supplementary Information for Oil and Gas Producing Activities, appears under this Item, and reference is made thereto.
51
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 our opinion.
As discussed in Note A to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, and No. 143, Accounting for Asset Retirement Obligations, on October 1, 2002.
PRICEWATERHOUSECOOPERS LLP |
Buffalo, New York
52
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
See Notes to Consolidated Financial Statements
53
NATIONAL FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
At September 30, | ||||||||||
|
||||||||||
2004 | 2003 | |||||||||
|
|
|||||||||
(Thousands of dollars) | ||||||||||
ASSETS | ||||||||||
Property, Plant and Equipment
|
$ | 4,602,779 | $ | 4,657,343 | ||||||
Less Accumulated Depreciation,
Depletion and Amortization
|
1,596,015 | 1,666,295 | ||||||||
|
|
|||||||||
3,006,764 | 2,991,048 | |||||||||
|
|
|||||||||
Current Assets
|
||||||||||
Cash and Temporary Cash Investments
|
66,153 | 51,421 | ||||||||
Receivables Net of Allowance for
Uncollectible Accounts of $17,440 and $17,943, Respectively
|
129,825 | 136,604 | ||||||||
Unbilled Utility Revenue
|
18,574 | 20,155 | ||||||||
Gas Stored Underground
|
68,511 | 89,640 | ||||||||
Materials and Supplies at average cost
|
43,922 | 32,311 | ||||||||
Unrecovered Purchased Gas Costs
|
7,532 | 28,692 | ||||||||
Prepayments
|
38,760 | 46,860 | ||||||||
Fair Value of Derivative Financial Instruments
|
23 | 1,698 | ||||||||
|
|
|||||||||
373,300 | 407,381 | |||||||||
|
|
|||||||||
Other Assets
|
||||||||||
Recoverable Future Taxes
|
83,847 | 84,818 | ||||||||
Unamortized Debt Expense
|
19,573 | 22,119 | ||||||||
Other Regulatory Assets
|
66,862 | 52,381 | ||||||||
Deferred Charges
|
3,411 | 7,528 | ||||||||
Other Investments
|
72,556 | 64,025 | ||||||||
Investments in Unconsolidated Subsidiaries
|
16,444 | 16,425 | ||||||||
Goodwill
|
5,476 | 5,476 | ||||||||
Intangible Assets
|
45,994 | 49,664 | ||||||||
Other
|
17,571 | 18,195 | ||||||||
|
|
|||||||||
331,734 | 320,631 | |||||||||
|
|
|||||||||
Total Assets
|
$ | 3,711,798 | $ | 3,719,060 | ||||||
|
|
|||||||||
CAPITALIZATION AND LIABILITIES | ||||||||||
Capitalization:
|
||||||||||
Comprehensive Shareholders
Equity
|
||||||||||
Common Stock, $1 Par Value
Authorized 200,000,000 Shares; Issued and
Outstanding 82,990,340 Shares and
81,438,290 Shares, Respectively
|
$ | 82,990 | $ | 81,438 | ||||||
Paid In Capital
|
506,560 | 478,799 | ||||||||
Earnings Reinvested in the Business
|
718,926 | 642,690 | ||||||||
|
|
|||||||||
Total Common Shareholder Equity Before Items
|
||||||||||
Of Other Comprehensive Loss
|
1,308,476 | 1,202,927 | ||||||||
Accumulated Other Comprehensive Loss
|
(54,775 | ) | (65,537 | ) | ||||||
|
|
|||||||||
Total Comprehensive Shareholders
Equity
|
1,253,701 | 1,137,390 | ||||||||
Long-Term Debt, Net of Current
Portion
|
1,133,317 | 1,147,779 | ||||||||
|
|
|||||||||
Total Capitalization
|
2,387,018 | 2,285,169 | ||||||||
|
|
|||||||||
Minority Interest in Foreign
Subsidiaries
|
37,048 | 33,281 | ||||||||
|
|
|||||||||
Current and Accrued Liabilities
|
||||||||||
Notes Payable to Banks and Commercial Paper
|
156,800 | 118,200 | ||||||||
Current Portion of Long-Term Debt
|
14,260 | 241,731 | ||||||||
Accounts Payable
|
115,979 | 118,563 | ||||||||
Amounts Payable to Customers
|
3,154 | 692 | ||||||||
Other Accruals and Current Liabilities
|
91,164 | 52,851 | ||||||||
Fair Value of Derivative Financial Instruments
|
95,099 | 17,928 | ||||||||
|
|
|||||||||
476,456 | 549,965 | |||||||||
|
|
|||||||||
Deferred Credits
|
||||||||||
Accumulated Deferred Income Taxes
|
458,095 | 423,282 | ||||||||
Taxes Refundable to Customers
|
11,065 | 13,519 | ||||||||
Unamortized Investment Tax Credit
|
7,498 | 8,199 | ||||||||
Cost of Removal Regulatory Liability
|
82,020 | 76,782 | ||||||||
Other Regulatory Liabilities
|
67,669 | 72,632 | ||||||||
Pension Liability
|
91,587 | 153,240 | ||||||||
Asset Retirement Obligation
|
32,292 | 27,493 | ||||||||
Other Deferred Credits
|
61,050 | 75,498 | ||||||||
|
|
|||||||||
811,276 | 850,645 | |||||||||
|
|
|||||||||
Commitments and Contingencies
|
| | ||||||||
|
|
|||||||||
Total Capitalization and Liabilities
|
$ | 3,711,798 | $ | 3,719,060 | ||||||
|
|
See Notes to Consolidated Financial Statements
54
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended September 30 | |||||||||||||||
|
|||||||||||||||
2004 | 2003 | 2002 | |||||||||||||
|
|
|
|||||||||||||
(Thousands of dollars) | |||||||||||||||
Operating Activities
|
|||||||||||||||
Net Income Available for Common Stock
|
$ | 166,586 | $ | 178,944 | $ | 117,682 | |||||||||
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
|
|||||||||||||||
(Gain) Loss on Sale of Timber Properties
|
1,252 | (168,787 | ) | | |||||||||||
(Gain) Loss on Sale of Oil and Gas Producing
Properties
|
(4,645 | ) | 58,472 | | |||||||||||
Impairment of Oil and Gas Producing Properties
|
| 42,774 | | ||||||||||||
Depreciation, Depletion and Amortization
|
189,538 | 195,226 | 180,668 | ||||||||||||
Deferred Income Taxes
|
40,329 | 78,369 | 62,013 | ||||||||||||
Impairment of Investment in Partnership
|
| | 15,167 | ||||||||||||
Cumulative Effect of Changes in Accounting
|
| 8,892 | | ||||||||||||
(Income) Loss from Unconsolidated Subsidiaries,
Net of Cash Distributions
|
(19 | ) | 703 | 361 | |||||||||||
Minority Interest in Foreign Subsidiaries
|
1,933 | 785 | 730 | ||||||||||||
Other
|
9,839 | 11,289 | 9,842 | ||||||||||||
Change in:
|
|||||||||||||||
Receivables and Unbilled Utility Revenue
|
4,840 | (28,382 | ) | 40,786 | |||||||||||
Gas Stored Underground and Materials and Supplies
|
9,860 | (12,421 | ) | 8,717 | |||||||||||
Unrecovered Purchased Gas Costs
|
21,160 | (16,261 | ) | (8,318 | ) | ||||||||||
Prepayments
|
8,146 | (2,773 | ) | (1,737 | ) | ||||||||||
Accounts Payable
|
(5,134 | ) | 13,699 | (24,025 | ) | ||||||||||
Amounts Payable to Customers
|
2,462 | 692 | (51,223 | ) | |||||||||||
Other Accruals and Current Liabilities
|
38,718 | 8,595 | (27,332 | ) | |||||||||||
Other Assets
|
(10,693 | ) | (32,681 | ) | 11,869 | ||||||||||
Other Liabilities
|
(29,872 | ) | (10,298 | ) | 10,350 | ||||||||||
|
|
|
|||||||||||||
Net Cash Provided by Operating
Activities
|
444,300 | 326,837 | 345,550 | ||||||||||||
|
|
|
|||||||||||||
Investing Activities
|
|||||||||||||||
Capital Expenditures
|
(172,341 | ) | (152,251 | ) | (232,368 | ) | |||||||||
Investment in Subsidiaries, Net of Cash Acquired
|
| (228,814 | ) | | |||||||||||
Investment in Partnerships
|
| (375 | ) | (536 | ) | ||||||||||
Net Proceeds from Sale of Timber Properties
|
| 186,014 | | ||||||||||||
Net Proceeds from Sale of Oil and Gas Producing
Properties
|
7,162 | 78,531 | 22,068 | ||||||||||||
Other
|
1,974 | 12,065 | 5,012 | ||||||||||||
|
|
|
|||||||||||||
Net Cash Used in Investing
Activities
|
(163,205 | ) | (104,830 | ) | (205,824 | ) | |||||||||
|
|
|
|||||||||||||
Financing Activities
|
|||||||||||||||
Change in Notes Payable to Banks and Commercial
Paper
|
38,600 | (147,622 | ) | (224,845 | ) | ||||||||||
Net Proceeds from Issuance of Long-Term Debt
|
| 248,513 | 243,844 | ||||||||||||
Reduction of Long-Term Debt
|
(243,085 | ) | (227,826 | ) | (104,212 | ) | |||||||||
Proceeds from Issuance of Common Stock
|
23,763 | 17,019 | 10,915 | ||||||||||||
Dividends Paid on Common Stock
|
(89,092 | ) | (84,530 | ) | (80,974 | ) | |||||||||
|
|
|
|||||||||||||
Net Cash Used in Financing
Activities
|
(269,814 | ) | (194,446 | ) | (155,272 | ) | |||||||||
|
|
|
|||||||||||||
Effect of Exchange Rates on Cash
|
3,451 | 1,644 | 1,535 | ||||||||||||
|
|
|
|||||||||||||
Net Increase (Decrease) in Cash and Temporary
Cash Investments
|
14,732 | 29,205 | (14,011 | ) | |||||||||||
Cash and Temporary Cash Investments At
Beginning of Year
|
51,421 | 22,216 | 36,227 | ||||||||||||
|
|
|
|||||||||||||
Cash and Temporary Cash Investments At End of
Year
|
$ | 66,153 | $ | 51,421 | $ | 22,216 | |||||||||
|
|
|
|||||||||||||
Supplemental Disclosure of Cash Flow
Information
|
|||||||||||||||
Cash Paid For:
|
|||||||||||||||
Interest
|
$ | 90,705 | $ | 104,452 | $ | 100,397 | |||||||||
Income Taxes
|
$ | 30,214 | $ | 56,146 | $ | 29,985 | |||||||||
|
|
|
See Notes to Consolidated Financial Statements
55
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Year Ended September 30 | ||||||||||||
|
||||||||||||
2004 | 2003 | 2002 | ||||||||||
|
|
|
||||||||||
(Thousands of dollars) | ||||||||||||
Net Income Available for Common Stock
|
$ | 166,586 | $ | 178,944 | $ | 117,682 | ||||||
|
|
|
||||||||||
Other Comprehensive Income (Loss), Before Tax:
|
||||||||||||
Minimum Pension Liability Adjustment
|
56,612 | (86,170 | ) | (52,977 | ) | |||||||
Foreign Currency Translation Adjustment
|
21,466 | 54,472 | 24,278 | |||||||||
Reclassification Adjustment for Realized Foreign
Currency Translation Gain in Net Income
|
| (9,607 | ) | | ||||||||
Unrealized Gain (Loss) on Securities Available
for Sale Arising During the Period
|
3,629 | 2,419 | (2,086 | ) | ||||||||
Unrealized Loss on Derivative Financial
Instruments Arising During the Period
|
(129,934 | ) | (47,777 | ) | (42,584 | ) | ||||||
Reclassification Adjustment for Realized (Gain)
Loss on Derivative Financial Instruments in Net Income
|
49,142 | 69,809 | (20,063 | ) | ||||||||
|
|
|
||||||||||
Other Comprehensive Income (Loss), Before Tax
|
915 | (16,854 | ) | (93,432 | ) | |||||||
|
|
|
||||||||||
Income Tax Expense (Benefit) Related to Minimum
Pension Liability Adjustment
|
19,814 | (30,159 | ) | (18,542 | ) | |||||||
Income Tax Expense (Benefit) Related to
Unrealized Gain (Loss) on Securities Available for Sale Arising
During the Period
|
1,270 | 847 | (730 | ) | ||||||||
Income Tax Benefit Related to Unrealized Loss on
Derivative Financial Instruments Arising During the Period
|
(49,113 | ) | (18,594 | ) | (17,341 | ) | ||||||
Reclassification Adjustment for Income Tax
(Expense) Benefit on Realized (Gain) Loss on Derivative
Financial Instruments in Net Income
|
18,182 | 26,953 | (8,040 | ) | ||||||||
|
|
|
||||||||||
Income Taxes Net
|
(9,847 | ) | (20,953 | ) | (44,653 | ) | ||||||
|
|
|
||||||||||
Other Comprehensive Income (Loss)
|
10,762 | 4,099 | (48,779 | ) | ||||||||
|
|
|
||||||||||
Comprehensive Income
|
$ | 177,348 | $ | 183,043 | $ | 68,903 | ||||||
|
|
|
See Notes to Consolidated Financial Statements
56
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
Note A Summary of Significant
Accounting Policies
The Company consolidates its majority owned
subsidiaries. The equity method is used to account for minority
owned entities. All significant intercompany balances and
transactions are eliminated.
The preparation of the consolidated financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Certain prior year amounts have been reclassified
to conform with current year presentation.
The Company is subject to regulation by certain
state and federal authorities. The Company has accounting
policies which conform to accounting principles generally
accepted in the United States of America, 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
Regulatory Matters for further discussion.
In the International segment, rates charged for
the sale of thermal energy and electric energy at the retail
level are subject to regulation and audit in the Czech Republic
by the Czech Ministry of Finance. The regulation of electric
energy rates at the retail level indirectly impacts the rates
charged by the International segment for its electric energy
sales at the wholesale level.
The Companys Utility segment records
revenue 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. The Companys Pipeline and Storage,
International and Energy Marketing segments record revenue as
bills are rendered for service supplied on a calendar month
basis. The International segment also records monthly revenue on
an estimated basis for certain heating customers. The customers
make estimated payments on a monthly basis and a final true-up
and bill is rendered at the end of the calendar year. The
Companys Timber segment records revenue on lumber and log
sales as products are shipped.
The Companys Exploration and Production
segment records revenue based on entitlement, which means that
revenue is recorded based on the actual amount of gas or oil
that is delivered to a pipeline and the Companys ownership
interest in the producing well. If a production imbalance occurs
between what was supposed to be delivered to a pipeline and what
was actually produced and delivered, the Company accrues the
difference as an imbalance.
The Companys rate schedules in the Utility
segment 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. Such amounts are generally
recovered from (or passed back to) customers during the
following fiscal year.
57
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Estimated refund liabilities to ratepayers
represent managements current estimate of such refunds.
Reference is made to Note B Regulatory Matters
for further discussion.
The impact of weather on revenues in the Utility
segments New York rate jurisdiction is tempered by a
weather normalization clause (WNC), which covers the eight-month
period from October through May. The WNC 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. Since the Utility segments
Pennsylvania rate jurisdiction does not have a WNC, weather
variations have a direct impact on the Pennsylvania rate
jurisdictions revenues.
In the Pipeline and Storage segment, the allowed
rates that Supply Corporation bills its customers are based on a
straight fixed-variable rate design, which allows recovery of
all fixed costs in fixed monthly reservation charges. The
allowed rates that Empire bills its customers are based on a
modified-fixed variable rate design, which allows recovery of
most fixed costs in fixed monthly reservation charges. To
distinguish between the two rate designs, the modified
fixed-variable rate design recovers return on equity and income
taxes through variable charges whereas straight fixed-variable
recovers all fixed costs, including return on equity and income
taxes, through its monthly reservation charge. Because of the
difference in rate design, changes in throughput due to weather
variations do not have a significant impact on Supply
Corporations revenues but may have a significant impact on
Empires revenues.
The principal assets of the Utility and Pipeline
and Storage segments, 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.
Oil and gas property acquisition, exploration and
development costs are capitalized under the full cost method of
accounting. All costs directly associated with property
acquisition, exploration and development activities are
capitalized, up to certain specified limits. If capitalized
costs exceed these limits at the end of any quarter, a permanent
impairment is required to be charged to earnings in that
quarter. The Companys capitalized costs exceeded the full
cost ceiling for the Companys Canadian properties at
June 30, 2003 and September 30, 2003. The Company
recognized impairments of $31.8 million and
$11.0 million at June 30, 2003 and September 30,
2003, respectively.
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.
58
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For oil and gas properties, depreciation,
depletion and amortization is computed based on quantities
produced in relation to proved reserves using the units of
production method. The cost of unevaluated oil and gas
properties is excluded from this computation. For timber
properties, depletion, determined on a property by property
basis, is charged to operations based on the actual amount of
timber cut in relation to the total amount of recoverable
timber. For all other property, plant and equipment,
depreciation, depletion and amortization is computed using the
straight-line method in amounts sufficient to recover costs over
the estimated service lives of property in service. The
following is a summary of depreciable plant by segment:
Average depreciation, depletion and amortization
rates are as follows:
59
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Effective October 1, 2002, the Company
adopted SFAS 143. SFAS 143 requires entities to record
the fair value of a liability for an asset retirement obligation
in the period in which it is incurred. When the liability is
initially recorded, the entity capitalizes the estimated cost of
retiring the asset as part of the carrying amount of the related
long-lived asset. Over time, the liability is adjusted to its
present value each period and the capitalized cost is
depreciated over the useful life of the related asset. In the
Companys case, SFAS 143 changed the accounting for
plugging and abandonment costs associated with the Exploration
and Production segments crude oil and natural gas wells.
In prior fiscal years, the Company accounted for plugging and
abandonment costs using the Securities and Exchange
Commissions full cost accounting rules. SFAS 143 was
calculated retroactively to determine the cumulative effect
through October 1, 2002. This cumulative effect reduced
earnings $0.6 million, net of income tax. If the new method
of accounting for plugging and abandonment costs had been
effective for 2002, there would not have been a material change
to net income available for common stock. A reconciliation of
the Companys asset retirement obligation calculated in
accordance with SFAS 143 is shown below ($000s):
In the Companys Utility and Pipeline and
Storage segment, costs of removal are collected from customers
through depreciation expense. These removal costs are not a
legal retirement obligation in accordance with SFAS 143.
Rather, they represent a regulatory liability. However,
SFAS 143 requires that such costs of removal be
reclassified from accumulated depreciation to other regulatory
liabilities. At September 30, 2004 and 2003, the costs of
removal reclassified to other regulatory liabilities amounted to
$82.0 million and $76.8 million, respectively.
Effective October 1, 2002, the Company
adopted SFAS No. 142, Goodwill and Other
Intangible Assets (SFAS 142). In accordance with
SFAS 142, the Company stopped amortization of goodwill and
tested it for impairment as of October 1, 2002. The
Companys goodwill balance as of October 1, 2002
totaled $8.3 million and was related to the Companys
investments in the Czech Republic, which are included in the
International segment. As a result of the impairment test, the
Company recognized an impairment of $8.3 million. The
Company used discounted cash flows to estimate the fair value of
its goodwill and determined that the goodwill had no remaining
value. Based on projected restructuring in the Czech electricity
market, the Company could not be assured that the level of
future cash flows from the Companys investments in the
Czech Republic would attain the level that was originally
forecasted. In accordance with SFAS 142, this impairment
was reported as a cumulative effect of change in accounting.
Goodwill amortization amounted to $0.6 million in 2002.
Unrealized gains or losses from the
Companys investments in an equity mutual fund and the
stock of an insurance company (securities available for sale)
are recorded as a component of accumulated other comprehensive
income (loss). Reference is made to Note E
Financial Instruments for further discussion.
60
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company uses a variety of derivative
financial instruments to manage a portion of the market risk
associated with fluctuations in the price of natural gas and
crude oil. These instruments include price swap agreements, no
cost collars, options and futures contracts. The Company
accounts for these instruments as either cash flow hedges or
fair value hedges. In both cases, the fair value of the
instrument is recognized on the Consolidated Balance Sheets as
either an asset or a liability labeled fair value of derivative
financial instruments. Fair value represents the amount the
Company would receive or pay to terminate these instruments.
For effective cash flow hedges, the offset to the
asset or liability that is recorded is a gain or loss recorded
in accumulated other comprehensive income (loss) on the
Consolidated Balance Sheets. Any ineffectiveness associated with
the cash flow hedges is recorded in the Consolidated Statements
of Income. The Company did not experience any material
ineffectiveness with regard to its cash flow hedges during 2004,
2003 or 2002. The gain or loss recorded in accumulated other
comprehensive income (loss) remains there until the hedged
transaction occurs, at which point the gains or losses are
reclassified to operating revenues or interest expense on the
Consolidated Statements of Income. For fair value hedges, the
offset to the asset or liability that is recorded is a gain or
loss recorded to operating revenues or purchased gas expense on
the Consolidated Statements of Income. However, in the case of
fair value hedges, the Company also records an asset or
liability on the Consolidated Balance Sheets representing the
change in fair value of the asset or firm commitment that is
being hedged. The offset to this asset or liability is a gain or
loss recorded to operating revenues or purchased gas expense on
the Consolidated Statements of Income as well. If the fair value
hedge is effective, the gain or loss from the derivative
financial instrument is offset by the gain or loss that arises
from the change in fair value of the asset or firm commitment
that is being hedged. The Company did not experience any
material ineffectiveness with regard to its fair value hedges
during 2004, 2003 or 2002.
The components of Accumulated Other Comprehensive
Income (Loss) are as follows:
At September 30, 2004, it is estimated that
$45.4 million of the net unrealized loss on derivative
financial instruments shown in the table above will be
reclassified into the Consolidated Statement of Income during
2005. As disclosed in Note E Financial
Instruments, the Companys derivative financial instruments
extend out to 2009.
In the Utility segment, gas stored
underground current in the amount of
$46.6 million is carried at lower of cost or market, on a
last-in, first-out (LIFO) method. Based upon the average price
of spot market gas purchased in September 2004, including
transportation costs, the current cost of replacing this
inventory of gas stored underground-current exceeded the amount
stated on a LIFO basis by approximately $113.3 million at
September 30, 2004. All other gas stored
underground current is carried at lower of cost or
market on an average cost method.
61
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Costs associated with the issuance of debt by the
Company are deferred and amortized over the lives of the related
debt. 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.
The functional currency for the Companys
foreign operations is the local currency of the country where
the operations are located. Asset and liability accounts are
translated at the rate of exchange on the balance sheet date.
Revenues and expenses are translated at the average exchange
rate during the period. Foreign currency translation adjustments
are recorded as a component of accumulated other comprehensive
income (loss).
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. No
provision has been made for domestic income taxes applicable to
certain undistributed earnings of foreign subsidiaries as these
amounts are considered to be permanently reinvested outside the
United States.
For purposes of the Consolidated Statement of
Cash Flows, the Company considers all highly liquid debt
instruments purchased with a maturity of three months or less to
be cash equivalents. Cash and temporary cash investments
includes cash held in margin accounts to serve as collateral for
open positions on exchange-traded futures contracts and
exchange-traded options. The amounts held in margin accounts
amounted to $8.6 million and $1.5 million at
September 30, 2004 and 2003, respectively.
Basic earnings per common share is computed by
dividing income available for common stock by the weighted
average number of common shares outstanding for the period.
Diluted earnings per common share reflects the potential
dilution that could occur if securities or other contracts to
issue common stock were exercised or converted into common
stock. The only potentially dilutive securities the Company has
outstanding are stock options. The diluted weighted average
shares outstanding shown on the Consolidated Statement of Income
reflects the potential dilution as a result of these stock
options as determined using the Treasury Stock Method. Stock
options that are antidilutive are excluded from the calculation
of diluted earnings per common share. For 2004, 2003 and 2002,
2,296,828, 7,789,688 and 5,260,633 stock options, respectively,
were excluded as being antidilutive.
62
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company accounts for stock-based compensation
using the intrinsic value method specified by Accounting
Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees and related interpretations. Under
that method, no compensation expense was recognized for options
granted under the plans for the years ended September 30,
2004, 2003 and 2002. Had compensation expense been determined
based on fair value at the grant dates, which is the accounting
treatment specified by SFAS 123, Accounting for
Stock-Based Compensation, the Companys net income
and earnings per share would have been reduced to the pro forma
amounts below:
The weighted average fair value per share of
options granted in 2004, 2003 and 2002 was $4.66, $4.17 and
$4.32, respectively. These weighted average fair values were
estimated on the date of grant using a binomial option pricing
model with the following weighted average assumptions:
In September 2004, the SEC issued SAB 106.
SAB 106 addresses the application of SFAS 143 to
companies that follow the full cost method of accounting for oil
and gas property acquisition, exploration and development costs.
SAB 106 states that after adoption of SFAS 143,
the future cash outflows associated with settling asset
retirement obligations that have been accrued on the balance
sheet should be excluded from the computation of the present
value of estimated future net revenues for purposes of the full
cost ceiling calculation. The Company adopted SAB 106 for
purposes of the full cost ceiling calculation at
September 30, 2004. The adoption of SAB 106 did not
have any impact on the Companys financial statements and
did not have a material effect on the results of the ceiling
test calculation.
63
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note B Regulatory
Matters
The Company has recorded the following regulatory
assets and liabilities:
If for any reason the Company ceases to meet the
criteria for application of regulatory accounting treatment for
all or part of its 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
regulatory accounting treatment occurs. Such amounts would be
classified as an extraordinary item.
With respect to utility services provided in New
York, the Company has entered into rate settlements approved by
the State of New York Public Service Commission (NYPSC). The
rate settlements provide for a sharing mechanism, whereby
earnings above an 11.5% (11.0%, effective October 1, 2003)
return on equity are to be shared equally between shareholders
and customers. As a result of this sharing mechanism, the
Company had liabilities of $12.0 million and
$11.4 million at September 30, 2004 and 2003,
respectively. Other aspects of the settlements include a special
reserve of $3.5 million and $5.4 million at
September 30, 2004 and 2003, respectively, to be applied
against the Companys incremental costs resulting from the
64
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
NYPSCs gas restructuring effort and a
cost mitigation reserve of $5.6 million and
$8.2 million at September 30, 2004 and 2003,
respectively. The cost mitigation reserve is an accumulation of
certain refunds from upstream pipeline companies and certain
credits which can be used to offset certain specific expense
items. Various other regulatory liabilities have also been
created through the New York rate settlements and amounted to
$4.9 million and $5.9 million at September 30,
2004 and 2003, respectively.
Note C Income Taxes
The components of federal, state and foreign
income taxes included in the Consolidated Statement of Income
are as follows:
The U.S. and foreign components of income (loss)
before income taxes are as follows:
65
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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:
Legislation was enacted in the Czech Republic
which reduces the corporate statutory income tax rate from 31%
to 24% over a three-year period. The foreign tax rate reduction
amount shown above reflects a reduction in deferred income taxes
that were provided in prior years when a higher statutory tax
rate was in effect.
Significant components of the Companys
deferred tax liabilities and assets are as follows:
Regulatory liabilities representing the reduction
of previously recorded deferred income taxes associated with
rate-regulated activities that are expected to be refundable to
customers amounted to $11.1 million and $13.5 million
at September 30, 2004 and 2003, respectively. Also,
regulatory assets representing future amounts collectible from
customers, corresponding to additional deferred income taxes not
previously recorded because of prior ratemaking practices,
amounted to $83.8 million and $84.8 million at
September 30, 2004 and 2003, respectively.
66
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has undistributed earnings of foreign
subsidiaries that relate to its operations in the Czech
Republic. These earnings are considered to be permanently
reinvested outside the United States and, accordingly, no
U.S. income taxes have been provided thereon. In the event
such earnings are distributed, the Company may be subject to
U.S. income taxes and foreign withholding taxes, net of
allowable foreign tax credits or deductions. At
September 30, 2004, such undistributed earnings totaled
$49.6 million. In addition, there was a $35.8 million
positive cumulative translation adjustment attributable to this
investment, and similarly, no U.S. income taxes have been
provided thereon.
The American Jobs Creation Act of 2004 was signed
into law on October 22, 2004. The Company is reviewing the
aspects of this legislation which affect, or will affect, the
Companys various segments, including the provision
providing a substantially reduced tax rate of 5.25% on certain
dividends received from foreign affiliates. This provision is
effective, at the election of the Company, for foreign dividends
received in either 2005 or 2006.
A capital loss carryover of $36 million
exists at September 30, 2004, which expires if not utilized
by September 30, 2008. Although realization is not assured,
management estimates that a portion of the deferred tax asset
associated with this carryover will be realized during the
carryover period, and a valuation allowance is recorded for the
remaining portion. Adjustments to the valuation allowance may be
necessary in the future if estimates of capital gain income are
revised.
67
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note D Capitalization and
Short-Term Borrowings
The Company has various plans which allow
shareholders, employees and others to purchase shares of the
Company common stock. The National Fuel Gas Company Direct Stock
Purchase and Dividend Reinvestment Plan allows shareholders to
reinvest cash dividends and make cash investments in the
Companys common stock and provides investors the
opportunity to acquire shares of the Company common stock
without the payment of any brokerage commissions in connection
with such acquisitions. The 401(k) Plans allow employees the
opportunity to invest in the Company common stock, in addition
to a variety of other investment alternatives. Generally, 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 independent
agent.
68
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company also has a Director Stock Program
under which it issues shares of the Company common stock to its
non-employee directors as partial consideration for their
services as directors.
In 1996, the Companys Board of Directors
adopted a shareholder rights plan (Plan). Effective
April 30, 1999, the Plan was amended and is now embodied in
an Amended and Restated Rights Agreement, under which the Board
of Directors made adjustments in connection with the two-for-one
stock split of September 7, 2001.
The holders of the Companys common stock
have one right (Right) for each of their shares. Each Right,
which will initially be evidenced by the Companys common
stock certificates representing the outstanding shares of common
stock, entitles the holder to purchase one-half of one share of
common stock at a purchase price of $65.00 per share, being
$32.50 per half share, subject to adjustment (Purchase
Price).
The Rights become exercisable upon the occurrence
of a distribution date. At any time following a distribution
date, each holder of a Right may exercise its right to receive
common stock (or, under certain circumstances, other property of
the Company) having a value equal to two times the Purchase
Price of the Right then in effect. However, the Rights are
subject to redemption or exchange by the Company prior to their
exercise as described below.
A distribution date would occur upon the earlier
of (i) ten days after the public announcement that a person
or group has acquired, or obtained the right to acquire,
beneficial ownership of the Companys common stock or other
voting stock having 10% or more of the total voting power of the
Companys common stock and other voting stock and
(ii) ten days after the commencement or announcement by a
person or group of an intention to make a tender or exchange
offer that would result in that person acquiring, or obtaining
the right to acquire, beneficial ownership of the Companys
common stock or other voting stock having 10% or more of the
total voting power of the Companys common stock and other
voting stock.
In certain situations after a person or group has
acquired beneficial ownership of 10% or more of the total voting
power of the Companys stock as described above, each
holder of a Right will have the right to exercise its Rights to
receive common stock of the acquiring company having a value
equal to two times the Purchase Price of the Right then in
effect. These situations would arise if the Company is acquired
in a merger or other business combination or if 50% or more of
the Companys assets or earning power are sold or
transferred.
At any time prior to the end of the business day
on the tenth day following the announcement that a person or
group has acquired, or obtained the right to acquire, beneficial
ownership of 10% or more of the total voting power of the
Company, the Company may redeem the Rights in whole, but not in
part, at a price of $0.005 per Right, payable in cash or
stock. A decision to redeem the Rights requires the vote of 75%
of the Companys full Board of Directors. Also, at any time
following the announcement that a person or group has acquired,
or obtained the right to acquire, beneficial ownership of 10% or
more of the total voting power of the Company, 75% of the
Companys full Board of Directors may vote to exchange the
Rights, in whole or in part, at an exchange rate of one share of
common stock, or other property deemed to have the same value,
per Right, subject to certain adjustments.
After a distribution date, Rights that are owned
by an acquiring person will be null and void. Upon exercise of
the Rights, the Company may need additional regulatory approvals
to satisfy the requirements of the Rights Agreement. The Rights
will expire on July 31, 2008, unless they are exchanged or
redeemed earlier than that date.
The Rights have anti-takeover effects because
they will cause substantial dilution of the common stock if a
person attempts to acquire the Company on terms not approved by
the Board of Directors.
69
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has various stock option and stock
award plans which provide or provided for the issuance of one or
more of the following to key employees: incentive stock options,
nonqualified stock options, restricted stock, performance units
or performance shares. Stock options under all 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.
Transactions involving option shares for all
plans are summarized as follows:
The following table summarizes information about
options outstanding at September 30, 2004:
70
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 recorded
as compensation expense over the periods during which the
vesting restrictions exist. Certificates for shares of
restricted stock awarded under the Companys stock option
and stock award 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:
As of September 30, 2004, 98,528 shares
of non-vested restricted stock were outstanding. Vesting
restrictions will lapse as follows: 2005
33,600 shares; 2006 34,600 shares;
2007 29,000 shares; and 2010
1,328 shares.
Compensation expense related to restricted stock
under the Companys stock plans was $0.7 million,
$1.0 million and $0.7 million for the years ended
September 30, 2004, 2003 and 2002, respectively.
As of September 30, 2004, there were
10,000,000 shares of $1 par value Preferred Stock
authorized but unissued.
The outstanding long-term debt is as follows:
71
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of September 30, 2004, the aggregate
principal amounts of long-term debt maturing during the next
five years and thereafter are as follows: $14.3 million in
2005, $14.3 million in 2006, $9.3 million in 2007,
$209.3 million in 2008, $104.1 million in 2009 and
$796.3 million thereafter.
The Company historically has obtained short-term
funds either through bank loans or the issuance of commercial
paper. As for the former, the Company maintains a number of
individual (bi-lateral) uncommitted or discretionary lines of
credit with certain financial institutions for general corporate
purposes. Borrowings under these lines of credit are made at
competitive market rates. Each of these credit lines, which
aggregate to $400.0 million, are revocable at the option of
the financial institutions and are reviewed on an annual basis.
The Company anticipates that these lines of credit will continue
to be renewed. The total amount available to be issued under the
Companys commercial paper program is $200.0 million.
The commercial paper program is backed by a syndicated committed
credit facility totaling $220.0 million. Of that amount,
$110.0 million is committed to the Company through
September 25, 2005, and $110.0 million is committed to
the Company through September 30, 2005.
At September 30, 2004, the Company had
outstanding short-term notes payable to banks and commercial
paper of $26.5 million and $130.3 million,
respectively. All of this debt was domestic. At
September 30, 2003, the Company had outstanding notes
payable to banks and commercial paper of $55.2 million and
$63.0 million, respectively.
The weighted average interest rate on notes
payable to banks was 1.82% and 1.27% at September 30, 2004
and 2003, respectively. The weighted average interest rate on
commercial paper was 1.85% and 1.18% at September 30, 2004
and 2003, respectively.
Under the Companys committed credit
facility, the Company has agreed that its debt to capitalization
ratio (as calculated under that facility) will not at the last
day of any fiscal quarter exceed .625 from October 1, 2003
through September 30, 2004 and .60 from October 1,
2004 and thereafter. At September 30, 2004, the
Companys debt to capitalization ratio (as calculated under
the facility) was .51. The constraints specified in the
committed credit facility would permit an additional
$576.0 million in short-term and/or long-term debt to be
outstanding before the Companys debt to capitalization
ratio would exceed .60. If a downgrade in any of the
Companys credit ratings were to occur, access to the
commercial paper markets might not be possible. However, the
Company expects that it could borrow under its committed and
uncommitted bank lines of credit or rely upon other liquidity
sources, including cash provided by operations.
Under the Companys existing indenture
covenants, at September 30, 2004, the Company would have
been permitted to issue up to a maximum of $713.0 million
in additional long-term unsecured indebtedness at then current
market interest rates (further limited by the debt to
capitalization ratio constraints noted in the previous
paragraph) in addition to being able to issue new indebtedness
to replace maturing debt.
The Companys 1974 indenture pursuant to
which $399.0 million (or 35%) of the Companys
long-term debt (as of September 30, 2004) was issued
contains a cross-default provision whereby the failure by the
Company to perform certain obligations under other borrowing
arrangements could trigger an obligation to repay the debt
outstanding under the indenture. In particular, a repayment
obligation could be triggered if the
72
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Company fails (i) to pay any scheduled
principal or interest or any debt under any other indenture or
agreement or (ii) to perform any other term in any other
such indenture or agreement, and the effect of the failure
causes, or would permit the holders of the debt to cause, the
debt under such indenture or agreement to become due prior to
its stated maturity, unless cured or waived.
The Companys $220.0 million, committed
credit facility also contains a cross-default provision whereby
the failure by the Company or its significant subsidiaries to
make payments under other borrowing arrangements, or the
occurrence of certain events affecting those other borrowing
arrangements, could trigger an obligation to repay any amounts
outstanding under the committed credit facility. In particular,
a repayment obligation could be triggered if (i) the
Company or any of its significant subsidiaries fails to make a
payment when due of any principal or interest on any other
indebtedness aggregating $20.0 million or more or
(ii) an event occurs that causes, or would permit the
holders of any other indebtedness aggregating $20.0 million
or more to cause, such indebtedness to become due prior to its
stated maturity. As of September 30, 2004, the Company had
no debt outstanding under the committed credit facility.
Note E Financial
Instruments
The fair market value of the Companys
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:
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 cost, which
approximates 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 in an equity mutual fund and the stock of an
insurance company (marketable equity securities), as discussed
below, are stated at fair value based on quoted market prices.
Other investments includes cash surrender values
of insurance contracts and marketable equity securities. The
cash surrender values of the insurance contracts amounted to
$56.1 million and $53.5 million at September 30,
2004 and 2003, respectively. The fair value of the equity mutual
fund was $7.8 million and $4.8 million at
September 30, 2004 and 2003, respectively. The gross
unrealized gain on the equity mutual fund was $0.1 million
at September 30, 2004, as compared with a gross unrealized
loss of $0.6 million at September 30, 2003. The fair
value of the stock of an insurance company was $8.7 million
and $5.7 million at September 30, 2004 and 2003,
respectively. The gross unrealized gain on this stock was
$6.2 million and $3.2 million at September 30,
2004 and 2003, respectively. The insurance contracts and
marketable equity securities are primarily informal funding
mechanisms for various benefit obligations the Company has to
certain employees.
73
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company uses a variety of derivative
financial instruments to manage a portion of the market risk
associated with the fluctuations in the price of natural gas and
crude oil. These instruments include price swap agreements, no
cost collars, options and futures contracts.
Under the price swap agreements, the Company
receives monthly payments from (or makes payments to) other
parties based upon the difference between a fixed price 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 (NYMEX) or a quoted natural gas price in Inside
FERC. The majority of these derivative financial
instruments are accounted for as cash flow hedges and are used
to lock in a price for the anticipated sale of natural gas and
crude oil production in the Exploration and Production segment
and the All Other category. The Energy Marketing segment
accounts for these derivative financial instruments as fair
value hedges and uses them to hedge against falling prices, a
risk to which they are exposed on their fixed price gas purchase
commitments. The Energy Marketing segment also uses these
derivative financial instruments to hedge against rising prices,
a risk to which they are exposed on their fixed price sales
commitments. At September 30, 2004, the Company had natural
gas price swap agreements covering a notional amount of
23.0 Bcf extending through 2009 at a weighted average fixed
rate of $5.47 per Mcf. Of this amount, 3.3 Bcf is
accounted for as fair value hedges at a weighted average fixed
rate of $5.51 per Mcf. The remaining 19.7 Bcf are
accounted for as cash flow hedges at a weighted average fixed
rate of $5.47 per Mcf. The Company also had crude oil price
swap agreements covering a notional amount of
5,038,000 bbls extending through 2007 at a weighted average
fixed rate of $32.01 per bbl. At September 30, 2004,
the Company would have had to pay a net $82.2 million to
terminate the price swap agreements.
Under the no cost collars, the Company receives
monthly payments from (or makes payments to) other parties when
a variable price falls below an established floor price (the
Company receives payment from the counterparty) or exceeds an
established ceiling price (the Company pays the counterparty).
The variable price is either a crude oil price quoted on the
NYMEX or a quoted natural gas price in Inside FERC.
These derivative financial instruments are accounted for as cash
flow hedges and are used to lock in a price range for the
anticipated sale of natural gas and crude oil production in the
Exploration and Production segment. At September 30, 2004,
the Company had no cost collars on natural gas covering a
notional amount of 5.5 Bcf extending through 2006 with a
weighted average floor price of $4.93 per Mcf and a
weighted average ceiling price of $8.28 per Mcf. The
Company also had no cost collars on crude oil covering a
notional amount of 105,000 bbls extending through 2005 with a
weighted average floor price of $25.00 per bbl and a
weighted average ceiling price of $28.56 per bbl. At
September 30, 2004, the Company would have had to pay
$3.7 million to terminate the no cost collars.
At September 30, 2004, the Company, in the
Exploration and Production segment, had purchased natural gas
put options and sold natural gas call options extending through
2006. The call options sold by the Company cover a notional
amount of 1.1 Bcf at a weighted average strike price of
$8.06 per Mcf. The put options purchased by the Company
cover a notional amount of 1.1 Bcf at a weighted average
strike price of $5.99 per Mcf. These derivative financial
instruments are accounted for as cash flow hedges. The call
options are used to establish a ceiling price (the Company makes
payments to the counterparty when a variable price rises above
the ceiling price) for the anticipated sale of natural gas in
the Exploration and Production segment. At September 30,
2004, the Company would have had to pay $1.0 million to
terminate these call options. The put options are used to
establish a floor price (the Company receives payment from the
counterparty when a variable price falls below the floor price)
for the anticipated sale of natural gas in the Exploration and
Production segment. At September 30, 2004, the Company
would have received $0.2 million to terminate these put
options.
At September 30, 2004, the Company had long
(purchased) futures contracts covering 3.5 Bcf of gas
extending through 2007 at a weighted average contract price of
$6.13 per Mcf. Of this amount, 3.1 Bcf is
74
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
accounted for as fair value hedges. They are used
by the Companys Energy Marketing segment to hedge against
rising prices, a risk to which this segment is exposed due to
the fixed price gas sales commitments that it enters into with
commercial and industrial customers. The remaining 0.4 Bcf
is accounted for as cash flow hedges. The Company would have
received $5.1 million to terminate these futures contracts
at September 30, 2004.
At September 30, 2004, the Company had short
(sold) futures contracts covering 7.3 Bcf of gas
extending through 2006 at a weighted average contract price of
$6.19 per Mcf. Of this amount, 5.9 Bcf is accounted
for as cash flow hedges as these contracts relate to the
anticipated sale of natural gas by the Energy Marketing segment,
the Exploration and Production segment and the All Other
category. The remaining 1.4 Bcf is accounted for as fair
value hedges, since these contracts hedge against falling
prices, a risk to which the Energy Marketing segment is exposed
on its gas storage inventory and fixed price gas purchase
commitments. The Company would have had to pay
$11.3 million to terminate these futures contracts at
September 30, 2004.
The Company may be exposed to credit risk on some
of the derivative financial instruments discussed above. 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. To mitigate such credit
risk, management performs a credit check, and then on an ongoing
basis monitors counterparty credit exposure. Management has
obtained guarantees from the parent companies of the respective
counterparties to its derivative financial instruments. At
September 30, 2004, the Company used seven counterparties
for its over the counter derivative financial instruments. At
September 30, 2004, no individual counterparty represented
greater than 20% of total credit risk (measured as volumes
hedged by an individual counterparty as a percentage of the
Companys total volumes hedged).
The Company uses an interest rate collar to limit
interest rate fluctuations on certain variable rate debt in the
Pipeline and Storage segment. Under the interest rate collar the
Company makes quarterly payments (or receives payments from)
another party when a variable rate falls below an established
floor rate (the Company pays the counterparty) or exceeds an
established ceiling rate (the Company receives payment from the
counterparty). Under the terms of the collar, which extends
until 2009, the variable rate is based on London InterBank
Offered Rate. The floor rate of the collar is 5.15% and the
ceiling rate is 9.375%. At September 30, 2004 the notional
amount on the collar was $44.3 million. The Company would
have had to pay $2.2 million to terminate the interest rate
collar at September 30, 2004.
Note F Retirement Plan and
Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory,
defined-benefit retirement plan (Retirement Plan) that covers
substantially all domestic employees of the Company. The Company
provides health care and life insurance benefits for
substantially all domestic retired employees under a
post-retirement benefit plan (Post-Retirement Plan).
The Companys policy is to fund the
Retirement Plan with 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. The Company has established Voluntary
Employees Beneficiary Association (VEBA) trusts for
its Post-Retirement Plan. Contributions to the VEBA trusts are
tax deductible, subject to limitations contained in the Internal
Revenue Code and regulations and are made to fund
employees post-retirement health care and life insurance
benefits, as well as benefits as they are paid to current
retirees. In addition, the Company has established
401(h) accounts for its Post-Retirement Plan. They are
separate accounts in the Retirement Plan used to pay retiree
medical benefits for the associated participants in the
Retirement Plan. Contributions are tax-deductible when made and
investments accumulate tax-free. Retirement Plan and
Post-Retirement Plan assets primarily consist of equity and
fixed income investments or units in commingled funds or money
market funds.
75
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company recovers certain of its net periodic
pension and post-retirement benefit costs in its Utility and
Pipeline and Storage segments in accordance with the applicable
regulatory commission authorization. For financial reporting
purposes, to the extent there is recovery in rates, the
difference between the amounts of pension cost and
post-retirement benefit cost recoverable in rates and the
amounts of such costs as determined under applicable accounting
principles is recorded as either a regulatory asset or
liability, as appropriate. The regulatory treatment of a
substantial amount of these regulatory assets and liabilities is
governed by policy statements issued by the regulatory
commissions having jurisdiction over the Utility and Pipeline
and Storage segments. Pension and post-retirement benefit costs
reflect the amount recovered from customers in rates during the
year. Under the NYPSCs policies, the Company segregates
the amount of such costs collected in rates, but not yet
contributed to the Retirement and Post-Retirement Plans, into a
regulatory liability account. This liability accrues interest at
the NYPSC-mandated interest rate, and this interest cost is
included in pension and post-retirement benefit costs. For
purposes of disclosure, the liability also remains in the
disclosed pension and post-retirement benefit liability amount
because it has not yet been contributed.
The expected returns on plan assets of the
Retirement Plan and Post-Retirement Plan are applied to the
market-related value of plan assets of the respective plans. For
the Retirement Plan, the market-related value of assets
recognizes the performance of its portfolio over five years and
reduces the effects of short-term market fluctuations. The
market-related value of Post-Retirement Plan assets is set equal
to market value.
76
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Reconciliations of the Benefit Obligations, Plan
Assets and Funded Status, as well as the components of Net
Periodic Benefit Cost and the Weighted Average Assumptions of
the Retirement Plan and Post-Retirement Plan are as follows:
77
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In accordance with the provisions of
SFAS No. 87, Employers Accounting for
Pensions, the Company recorded an additional minimum
liability at September 30, 2004, 2003 and 2002 representing
the excess of the accumulated benefit obligation over the fair
value of plan assets plus accrued amounts previously recorded.
An intangible asset, as shown in the table above, has offset the
additional liability to the extent of previously Unrecognized
Prior Service Cost. The amount in excess of Unrecognized Prior
Service Cost is recorded net of the related tax benefit as
accumulated other comprehensive loss. The pre-tax amount of the
accumulated other comprehensive loss is shown in the table
above. The projected benefit obligation, accumulated benefit
obligation and fair value of assets for the retirement plan were
as follows:
The effect of the discount rate change for the
Retirement Plan in 2004, was to decrease the benefit obligation
by $20.2 million. The effects of the discount rate changes
in 2003 and 2002 were to increase the Benefit Obligation of the
Retirement Plan by $57.4 million and $34.0 million as
of the end of each period, respectively.
The Company made cash contributions totaling
$37.1 million to the Retirement Plan during the year ended
September 30, 2004. The Company expects that the annual
contribution to the Retirement Plan in 2005 will be in the range
of $25.0 million to $35.0 million. The following
benefit payments, which reflect expected future service, are
expected to be paid during the next five years and the five
years thereafter:
78
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$40.5 million in 2005; $42.3 million in
2006; $44.3 million in 2007; $46.2 million in 2008;
$48.6 million in 2009; and $279.3 million in the five
years thereafter.
In addition to the Retirement Plan discussed
above, the Company also has a nonqualified benefit plan that
covers a group of management employees designated by the Chief
Executive Officer of the Company. This plan provides for defined
benefit payments upon retirement of the management employee, or
to the spouse upon death of the management employee. The net
periodic benefit cost associated with this plan was
$13.7 million, $5.1 million and $8.5 million in
2004, 2003 and 2002, respectively. The accumulated benefit
obligation for this plan was $18.2 million and
$40.0 million at September 30, 2004 and 2003,
respectively. The projected benefit obligation for the plan was
$35.7 million and $48.3 million at September 30,
2004 and 2003, respectively. The actuarial valuations for this
plan were determined based on a discount rate of 6.25%, 6.0% and
6.75% as of September 30, 2004, 2003 and 2002 respectively;
a weighted rate of compensation increase of 10.0% as of
September 30, 2004, and 8.11% as of September 30, 2003
and 2002; and an expected long-term rate of return on plan
assets of 8.25%, at September 30, 2004 and 2003, and 8.5%
at September 30, 2002. In January 2004, a participant
of the plan received a $23.0 million lump sum payment under
a provision of an agreement previously entered into between the
Company and the participant. Under GAAP, this payment was
considered a partial settlement of the projected benefit
obligation of the plan. Accordingly, GAAP required that a pro
rata portion of this plans unrecognized actuarial losses
resulting from experience different from that assumed and from
changes in assumptions be currently recognized. Therefore,
$9.9 million before tax ($6.4 million, after tax) was
recognized as a settlement expense (included in Operation and
Maintenance Expense) on the income statement.
On December 8, 2003, the Medicare
Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law. This Act introduces a
prescription drug benefit under Medicare (Medicare Part D),
as well as a federal subsidy to sponsors of retiree health care
benefit plans that provide a benefit that is at least
actuarially equivalent to Medicare Part D. In accordance
with FASB Staff Position FAS 106-2, Accounting and
Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003, since the
Company is assumed to continue to provide a prescription drug
benefit to retirees in the point of service and indemnity plans
that is at least actuarially equivalent to Medicare Part D,
the impact of the Act was reflected as of December 8, 2003.
The discount rate was changed from 6.0% to 6.25% per annum
as of the remeasurement date, which resulted in a decrease in
the benefit obligation of $15.9 million. The accumulated
post-retirement benefit obligation decreased by
$42.9 million and the Net Periodic Post-Retirement Benefit
Cost decreased by $4.2 million as a result of the Act. The
effect of the subsidy by Net Periodic Post-Retirement Benefit
Cost component is shown below and is reflected within Components
of Net Periodic Benefit Cost shown in the table above.
The estimated gross amount of subsidy receipts is
as follows:
79
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Effective July 1, 2004, the Medicare
Part B Reimbursement trend assumption was changed. The
effect of this change was to decrease the Accumulated
Post-Retirement Benefit Obligation by $3.5 million for 2004.
The effects of the discount rate changes in 2003
and 2002 were to increase the Other Post-Retirement Benefit
Obligation by $45.1 million and $21.7 million as of
the end of each period, respectively. The prescription drug
aging assumptions and related factors were changed in 2003 to
better reflect anticipated future experience. The effect of the
changed prescription drug assumptions was to decrease the
Accumulated Post-Retirement Benefit Obligation by
$22.6 million. Other actuarial experience increased the
Accumulated Post-Retirement Benefit Obligation in 2003 by
$35.1 million. In 2002, the impact of changes in health
care trend assumptions to better reflect anticipated future
experiences was an increase in the Accumulated Post-Retirement
Benefit Obligation of $57.9 million.
The annual rate of increase in the per capita
cost of covered medical care benefits was assumed to be 12.0%
for 2002, 11.0% for 2003, 10.0% for 2004 and gradually decline
to 5.5% by the year 2010 and remain level thereafter. The annual
rate of increase for medical care benefits provided by
healthcare maintenance organizations was assumed to be 12.0% in
2002, 11.0% in 2003, 10.0% in 2004 and gradually decline to 5.5%
by the year 2010 and remain level thereafter. The annual rate of
increase in the per capita cost of covered prescription drug
benefits was assumed to be 15.0% for 2002, 13.5% for 2003 and
12.0% for 2004, and gradually decline to 5.5% by the year 2010
and remain level thereafter. The annual rate of increase in the
per capita Medicare Part B Reimbursement was assumed to be
8.0% for 2002, 7.0% for 2003, 9.25% for 2004 and gradually
decline to 5.0% by the year 2013 and remain level thereafter.
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 Benefit Obligation as of October 1, 2004 would be
increased by $57.4 million. This 1% change would also have
increased the aggregate of the service and interest cost
components of net periodic post-retirement benefit cost for 2004
by $5.8 million. If the health care cost trend rates were
decreased by 1% in each year, the Benefit Obligation as of
October 1, 2004 would be decreased by $47.4 million.
This 1% change would also have decreased the aggregate of the
service and interest cost components of net periodic
post-retirement benefit cost for 2004 by $4.7 million.
The Company made cash contributions totaling
$39.7 million to the Other Post-Retirement Benefit Plan
during the year ended September 30, 2004. The Company
expects that the annual contribution to the Other
Post-Retirement Benefit Plan in 2005 will be in the range of
$30.0 million to $40.0 million.
The Companys retirement plan weighted
average asset allocations at September 30, 2004, 2003 and
2002 by asset category are as follows:
80
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys post-retirement plan weighted
average asset allocations at September 30, 2004, 2003 and
2002 by asset category are as follows:
The Companys assumption regarding the
expected long-term rate of return on plan assets is 8.25%. The
return assumption reflects the anticipated long-term rate of
return on the plans current and future assets. The Company
utilizes historical investment data, projected capital market
conditions, and the plans target asset class and
investment manager allocations to set the assumption regarding
the expected return on plan assets.
The long-term investment objective of the pension
trust is to achieve the target total return in accordance with
the Companys risk tolerance. Assets are diversified
utilizing a mix of equities, fixed income and other securities
(including real estate). Risk tolerance is established through
consideration of plan liabilities, plan funded status and
corporate financial condition.
Investment managers are retained to manage
separate pools of assets. Comparative market and peer group
performance of individual managers and the total fund are
monitored on a regular basis, and reviewed by the Companys
Retirement Committee on at least a quarterly basis.
Note G Commitments and
Contingencies
The Company is subject to various federal, state
and local laws and regulations (including those of the Czech
Republic and Canada) relating to the protection of the
environment. The Company has established procedures for the
ongoing evaluation of its operations, to identify potential
environmental exposures and to comply with regulatory policies
and procedures.
It is the Companys policy to accrue
estimated environmental clean-up costs (investigation and
remediation) when such amounts can reasonably be estimated and
it is probable that the Company will be required to incur such
costs. The Company has estimated its remaining clean-up costs
related to the sites described below in paragraphs (i) and
(ii) will be $14.0 million. This liability has been
recorded on the Consolidated Balance Sheet at September 30,
2004. Other than as discussed below, the Company is currently
not aware of any material exposure to environmental liabilities.
However, adverse changes in environmental regulations, new
information or other factors could impact the Company.
The Company has incurred or is incurring clean-up
costs at five former manufactured gas plant sites in New York
and Pennsylvania. Remediation is substantially complete at a
site where the Company has been designated by the New York
Department of Environmental Conservation (DEC) as a potentially
responsible party (PRP). The Company is engaged in litigation
regarding that site with the DEC and the party who bought the
site from the Companys predecessor. At a second site,
remediation is complete. At a third site, the Company is
negotiating with the DEC for clean-up under a voluntary program.
A fourth site, which allegedly contains, among other things,
manufactured gas plant waste, is in the investigation stage.
Remediation has been completed at a fifth site; however,
post-remedial construction care and maintenance is ongoing.
81
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has been identified by the DEC or the
United States Environmental Protection Agency as one of a number
of companies considered to be PRPs with respect to two 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 the Company
with respect to the remediation of these sites will depend on
such factors as the remediation plan selected, the extent of
site contamination, the number of additional PRPs at each site
and the portion of responsibility, if any, attributed to the
Company. The remediation has been completed at one site, with
final payments pending. At a second waste disposal site,
settlement was reached in the amount of $9.3 million to be
allocated among five PRPs. The allocation process is currently
being determined. Further negotiations remain in process for
additional settlements related to this site.
The Company received, in 1998 and again in
October 1999, notice that the DEC believes the Company is
responsible for contamination discovered at an additional former
manufactured gas plant site in New York. The Company,
however, has not been named as a PRP. The Company responded to
these notices that other companies operated that site before its
predecessor did, that liability could be imposed upon it only if
hazardous substances were disposed at the site during a period
when the site was operated by its predecessor, and that it was
unaware of any such disposal. The Company has not incurred any
clean-up costs at this site nor has it been able to reasonably
estimate the probability or extent of potential liability.
The Company, in its Utility segment, has entered
into contractual commitments in the ordinary course of business,
including commitments to purchase capacity on nonaffiliated
pipelines to meet customer gas supply needs. Substantially all
of these contracts (representing 88% of contracted demand
capacity) expire within the next five years. Costs incurred
under these contracts are purchased gas costs, subject to state
commission review, and are being recovered in customer rates.
Management believes that, to the extent any stranded pipeline
costs are generated by the unbundling of services in the Utility
segments service territory, such costs will be recoverable
from customers.
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 currently expected to have a material
adverse effect on the financial condition of the Company.
Note H Business Segment
Information
The Company has six reportable segments: Utility,
Pipeline and Storage, Exploration and Production, International,
Energy Marketing and Timber. The breakdown of the Companys
reportable segments is based upon a combination of factors
including differences in products and services, regulatory
environment and geographic factors.
The Utility segment operations are regulated by
the NYPSC and the PaPUC and are carried out by Distribution
Corporation. Distribution Corporation sells natural gas to
retail customers and provides natural gas transportation
services in western New York and northwestern Pennsylvania.
The Pipeline and Storage segment operations are
regulated. The FERC regulates the operations of Supply
Corporation and the NYPSC regulates the operations of Empire, an
intrastate pipeline which was acquired on
82
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
February 6, 2003 (see
Note J Acquisitions). Supply Corporation
transports and stores natural gas for utilities (including
Distribution Corporation), natural gas marketers (including NFR)
and pipeline companies in the northeastern United States
markets. Empire transports natural gas from the United
States/Canadian border near Buffalo, New York into Central
New York just north of Syracuse, New York. Empire
transports gas to major industrial companies, utilities
(including Distribution Corporation) and power producers. In
June 2002, the Company wrote off its 33 1/3% equity
method investment in Independence Pipeline Company, a
partnership that had proposed to construct and operate a
400-mile pipeline to transport natural gas from Defiance, Ohio
to Leidy, Pennsylvania. As shown in the table below, this
impairment amounted to $15.2 million.
The Exploration and Production segment, through
Seneca, is engaged in exploration for, and development and
purchase of, natural gas and oil reserves in California, in the
Appalachian region of the United States, in the Gulf Coast
region of Texas, Louisiana and Alabama and in the provinces of
Alberta, Saskatchewan and British Columbia in Canada.
Senecas production is, for the most part, sold to
purchasers located in the vicinity of its wells. On
September 30, 2003, Seneca sold its southeast Saskatchewan
oil and gas properties for a loss of $58.5 million, as
shown in the table below for the year ended September 30,
2003. Proved reserves associated with the properties sold were
19.4 million barrels of oil and 0.3 Bcf of natural
gas. When the transaction closed, the initial proceeds received
were subject to an adjustment based on working capital and the
resolution of certain income tax matters. In 2004, those items
were resolved with the buyer and, as a result, the Company
received an additional $4.6 million of sales proceeds.
The International segments operations are
carried out by Horizon. Horizon engages in foreign energy
projects through the investment of its indirect subsidiaries as
the sole or partial owner of various business entities.
Horizons current emphasis is the Czech Republic, where,
through its subsidiaries, it owns majority interests in
companies having district heating and power generation plants in
the northern Bohemia region.
The Energy Marketing segment is comprised of
NFRs operations. NFR markets natural gas to industrial,
commercial, public authority and residential end-users in
western and central New York and northwestern Pennsylvania,
offering competitively priced energy and energy management
services for its customers.
The Timber segments operations are carried
out by the Northeast division of Seneca and by Highland. This
segment has timber holdings (primarily high quality hardwoods)
in the northeastern United States and several sawmills and kilns
in Pennsylvania. On August 1, 2003, the Company sold
approximately 70,000 acres of timber property in
Pennsylvania and New York. A gain of $168.8 million
was recognized on the sale of this timber property, as shown in
the table below for the year ended September 30, 2003.
During 2004, the Company received final timber cruise
information of the properties it sold and, based on that
information, determined that property records pertaining to
$1.3 million of timber property were not properly shown as
having been transferred to the purchaser. As a result, the
Company removed those assets from its property records and
adjusted the previously recognized gain downward by recognizing
a pretax loss of $1.3 million.
The data presented in the tables below reflect
the reportable segments and reconciliations to consolidated
amounts. The accounting policies of the segments are the same as
those described in Note A Summary of
Significant Accounting Policies. Sales of products or services
between segments are billed at regulated rates or at market
rates, as applicable. Expenditures for long-lived assets include
additions to property, plant and equipment and equity
investments in corporations (stock acquisitions) or
partnerships, net of any cash acquired. The Company evaluates
segment performance based on income before discontinued
operations, extraordinary items and cumulative effects of
changes in accounting (when applicable). When these items are
not applicable, the Company evaluates performance based on net
income.
83
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
84
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
85
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
86
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note I Investments in
Unconsolidated Subsidiaries
The Companys unconsolidated subsidiaries
consist of equity method investments in Seneca Energy II,
LLC (Seneca Energy), Model City Energy, LLC (Model City) and
Energy Systems North East, LLC (ESNE). The Company has 50%
interests in each of these entities. Seneca Energy and Model
City generate and sell electricity using methane gas obtained
from landfills owned by outside parties. ESNE generates
electricity from an 80-megawatt, combined cycle, natural
gas-fired power plant in North East, Pennsylvania. ESNE sells
its electricity into the New York power grid.
A summary of the Companys investments in
unconsolidated subsidiaries at September 30, 2004 and 2003
is as follows:
Note J Acquisitions
On February 6, 2003, the Company acquired
Empire from a subsidiary of Duke Energy Corporation for
$189.2 million in cash (including cash acquired) plus
$57.8 million of project debt. Empires results of
operations were incorporated into the Companys
consolidated financial statements for the period subsequent to
the completion of the acquisition on February 6, 2003.
Empire is a 157-mile, 24-inch pipeline that begins at the United
States/ Canadian border at the Niagara River near Buffalo, New
York, which is within the Companys service territory, and
terminates in Central New York just north of Syracuse, New York.
Empire has almost all of its capacity under contract, with a
substantial portion being long-term contracts. Empire
87
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
delivers natural gas supplies to major industrial
companies, utilities (including the Companys Utility
segment), and power producers. The Company believes that the
acquisition of Empire better positions the Company to bring
Canadian gas supplies into the East Coast markets of the United
States as demand for natural gas along the East Coast increases.
Details of the acquisition are as follows (all figures in
thousands):
On June 3, 2003, the Company acquired for
approximately $47.8 million in cash (including cash
acquired) all of the partnership interests in Toro, which owns
and operates short-distance landfill gas pipeline companies that
purchase, transport and resell landfill gas to customers in six
states located primarily in the Midwestern United States.
Toros results of operations were incorporated into the
Companys consolidated financial statements for the period
subsequent to the completion of the acquisition on June 3,
2003. The existing landfill gas purchase and sale agreements at
these facilities remained in place. The Company believes there
are opportunities for expansion at many of these locations. The
acquisition consisted of approximately $15.3 million in
property, plant and equipment, $31.9 million in intangible
assets (as discussed in Note K), $1.1 million of
current assets and $0.5 million of current liabilities.
Details of the acquisition are as follows (all figures in
thousands):
Note K Intangible
Assets
As a result of the Empire and Toro acquisitions
discussed in Note J Acquisitions, the Company
acquired certain intangible assets during 2003. In the case of
the Empire acquisition, the intangible assets represent the fair
value of various long-term transportation contracts with
Empires customers. In the case of
88
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the Toro acquisition, the intangible assets
represent the fair value of various long-term gas purchase
contracts with the various landfills. These intangible assets
are being amortized over the lives of the transportation and gas
purchase contracts with no residual value at the end of the
amortization period. The weighted-average amortization period
for the gross carrying amount of the transportation contracts is
8 years. The weighted-average amortization period for the
gross carrying amount of the gas purchase contracts is
20 years. Details of these intangible assets are as follows:
Amortization expense for the transportation
contracts is estimated to be $1.1 million annually for
2005, 2006, 2007 and 2008. Amortization is estimated to be
$0.5 million for 2009. Amortization expense for the gas
purchase contracts is estimated to be $1.6 million annually
for 2005, 2006, 2007, 2008 and 2009.
Note L 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.
Per common share amounts are calculated using the weighted
average number of shares outstanding during each quarter. The
total of all quarters may differ from the per common share
amounts shown on the Consolidated Statement of Income. Those per
common share amounts are based on the weighted average number of
shares outstanding for the entire fiscal
89
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
year. Because of the seasonal nature of the
Companys heating business, there are substantial
variations in operations reported on a quarterly basis.
Note M Market for Common
Stock and Related Shareholder Matters (unaudited)
At September 30, 2004, there were 19,063
holders of Company common stock. The common stock is listed and
traded on the New York Stock Exchange. Information related to
restrictions on the payment of dividends can be found in
Note D Capitalization and Short-Term
Borrowings. The quarterly price ranges
90
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(based on intra-day prices) and quarterly
dividends declared for the fiscal years ended September 30,
2004 and 2003, are shown below:
Note N Supplementary Information
for Oil and Gas Producing Activities
The following supplementary information is
presented in accordance with SFAS No. 69,
Disclosures about Oil and Gas Producing Activities,
and related SEC accounting rules. All monetary amounts are
expressed in U.S. dollars.
Costs related to unproved properties are excluded
from amortization as they represent unevaluated properties that
require additional drilling to determine the existence of oil
and gas reserves. Following is a summary of such costs excluded
from amortization at September 30, 2004:
91
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
92
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For the years ended September 30, 2004, 2003
and 2002, the Company spent $12.1 million,
$1.7 million and $18.2 million, respectively,
developing proved undeveloped reserves.
93
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys proved oil and gas reserves
are located in the United States and Canada. 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.
94
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
95
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys 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 widely
fluctuating political and economic conditions.
The standardized measure is intended instead to
provide a means for comparing the value of the Companys
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.
96
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
97
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The principal sources of change in the
standardized measure of discounted future net cash flows were as
follows:
98
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
99
Principles of Consolidation
Reclassification
Regulation
Revenues
Regulatory Mechanisms
Table of Contents
Property, Plant and Equipment
Table of Contents
Depreciation, Depletion and
Amortization
As of September 30
2004
2003
(Thousands)
$
1,426,540
$
1,380,278
946,866
854,923
1,517,856
1,673,827
379,356
349,132
1,169
1,159
97,290
96,315
28,442
20,541
$
4,397,519
$
4,376,175
Year Ended September 30
2004
2003
2002
2.8
%
2.8
%
2.8
%
4.1
%
4.4
%
3.6
%
$
1.49
$
1.34
$
1.19
4.2
%
4.2
%
4.2
%
8.7
%
10.9
%
16.4
%
6.5
%
7.0
%
3.2
%
6.2
%
1.7
%
2.7
%
(1)
Amounts include depletion of oil and gas
producing properties as well as depreciation of fixed assets. As
disclosed in Note N Supplementary Information for
Oil and Gas Producing Properties, depletion of oil and gas
producing properties amounted to $1.47, $1.30 and $1.16 per
Mcfe of production in 2004, 2003 and 2002, respectively.
Table of Contents
Cumulative Effect of Changes in
Accounting
Year Ended
September 30
2004
2003
(Thousands)
$
27,493
$
36,090
3,510
242
(831
)
(13,227
)
1,933
2,602
187
1,786
$
32,292
$
27,493
Financial Instruments
Table of Contents
Accumulated Other Comprehensive Income
(Loss)
Year Ended
September 30
2004
2003
(Thousands)
$
(53,648
)
$
(90,446
)
51,516
30,050
(56,733
)
(6,872
)
4,090
1,731
$
(54,775
)
$
(65,537
)
Gas Stored Underground
Current
Table of Contents
Unamortized Debt Expense
Foreign Currency Translation
Income Taxes
Consolidated Statement of Cash
Flows
Earnings Per Common Share
Table of Contents
Stock-Based Compensation
Year Ended September 30
2004
2003
2002
(Thousands, except per share amounts)
$
166,586
$
178,944
$
117,682
1,318
3,105
4,641
$
165,268
$
175,839
$
113,041
$
2.03
$
2.21
$
1.47
$
2.01
$
2.18
$
1.42
$
2.01
$
2.20
$
1.46
$
1.99
$
2.16
$
1.40
Year Ended September 30
2004
2003
2002
1.12
%
1.10
%
1.07
%
21.77
%
22.24
%
21.83
%
4.61
%
3.33
%
4.88
%
7.0
6.5
5.5
New Accounting Pronouncements
Table of Contents
Regulatory Assets and
Liabilities
At September 30
2004
2003
(Thousands)
$
83,847
$
84,818
7,532
28,692
9,882
11,364
62,664
47,750
4,198
4,631
168,123
177,255
82,020
76,782
3,154
692
26,048
30,900
11,065
13,519
13,232
23,719
28,389
18,013
163,908
163,625
$
4,215
$
13,630
(1)
The Company recovers the cost of its regulatory
assets but, with the exception of Unrecovered Purchased Gas
Costs, does not earn a return on them.
(2)
Included in Other Regulatory Assets on the
Consolidated Balance Sheets.
(3)
Included in Other Regulatory Liabilities on the
Consolidated Balance Sheets.
New York Rate Settlements
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
Federal
$
42,502
$
37,335
$
7,743
7,871
11,990
1,384
2,035
467
894
Federal
29,559
53,311
50,205
9,620
12,983
9,968
1,150
12,075
1,840
92,737
128,161
72,034
(697
)
(693
)
(697
)
374
(566
)
(277
)
(354
)
$
92,414
$
126,548
$
71,060
Year Ended September 30
2004
2003
2002
(Thousands)
$
232,928
$
383,695
$
180,349
26,072
(78,202
)
8,394
$
259,000
$
305,493
$
188,743
Table of Contents
Year Ended September 30
2004
2003
2002
(Thousands)
$
90,650
$
106,923
$
66,060
11,369
16,232
7,379
(1,166
)
3,318
(481
)
(5,174
)
(3,265
)
75
(1,898
)
$
92,414
$
126,548
$
71,060
At September 30
2004
2003
(Thousands)
$
568,114
$
519,578
37,051
21,532
605,165
541,110
(28,887
)
(48,701
)
(12,546
)
(18,607
)
(33,890
)
(4,509
)
(74,624
)
(52,368
)
(149,947
)
(124,185
)
2,877
6,357
(147,070
)
(117,828
)
$
458,095
$
423,282
Table of Contents
Table of Contents
Summary of Changes in Common Stock
Equity
Earnings
Accumulated
Common Stock
Reinvested
Other
Paid In
in the
Comprehensive
Shares
Amount
Capital
Business
Income (Loss)
(Thousands, except per share amounts)
79,406
$
79,406
$
430,618
$
513,488
$
(20,857
)
117,682
(81,773
)
(48,779
)
859
859
16,214
80,265
80,265
446,832
549,397
(69,636
)
178,944
(85,651
)
4,099
(3
)
(3
)
(63
)
1,176
1,176
32,030
81,438
81,438
478,799
642,690
(65,537
)
166,586
(90,350
)
10,762
1,552
1,552
27,761
82,990
$
82,990
$
506,560
$
718,926
(1)
$
(54,775
)
(1)
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, 2004, $644.5 million of accumulated
earnings was free of such limitations.
Common Stock
Table of Contents
Shareholder Rights Plan
Table of Contents
Stock Option and Stock Award
Plans
Number of
Shares Subject
Weighted Average
to Option
Exercise Price
9,372,686
$
21.92
5,673,172
$
22.26
(247,910
)
$
15.76
(168,444
)
$
25.56
14,629,504
$
22.12
233,500
$
24.61
(673,866
)
$
16.56
(123,800
)
$
23.55
14,065,338
$
22.41
87,000
$
24.95
(1,571,794
)
$
18.29
(84,105
)
$
25.40
12,496,439
$
22.93
11,594,368
$
22.83
919,537
(1)
In connection with exercising these options,
557,410, 200,708 and 43,834 shares were surrendered and
canceled during 2004, 2003 and 2002, respectively.
(2)
Including 3,097,172 non-qualified stock
options issued in November 2001. The Company canceled
3,097,172 stock appreciation rights (SARs) in November 2001
and issued 3,097,172 non-qualified stock options. The
Company eliminated all future awards of SARs.
(3)
Including shares available for restricted stock
grants.
Options Outstanding
Options Exercisable
Weighted
Number
Average
Weighted
Number
Weighted
Outstanding
Remaining
Average
Exercisable
Average
Range of Exercise Price
at 9/30/04
Contractual Life
Exercise Price
at 9/30/04
Exercise Price
441,060
1.0
$
14.23
441,060
$
14.23
1,139,558
2.0
$
18.38
1,139,558
$
18.38
2,545,696
5.0
$
21.26
2,432,296
$
21.25
6,073,297
5.3
$
23.34
5,354,957
$
23.19
2,296,828
6.3
$
27.63
2,226,497
$
27.68
Table of Contents
Year Ended September 30
2004
2003
2002
100,000
$
24.50
Redeemable Preferred Stock
Long-Term Debt
At September 30
2004
2003
(Thousands)
$
$
125,000
749,000
849,000
347,272
347,400
1,096,272
1,321,400
41,433
50,767
9,872
17,343
1,147,577
1,389,510
14,260
241,731
$
1,133,317
$
1,147,779
(1)
These debentures, medium-term notes and notes are
unsecured.
(2)
At September 30, 2004 and 2003, $97,272,000
and $97,400,000, respectively, of these notes were callable at
par at any time after September 15, 2006. The change in the
amount outstanding from year to year is
Table of Contents
attributable to the estates of individual note
holders exercising put options due to the death of an individual
note holder.
(3)
These notes constitute project
financing and are secured by the various project
documentation and natural gas transportation contracts related
to the Empire State Pipeline.
Short-Term Borrowings
Debt Restrictions
Table of Contents
Fair Values
At September 30
2004
2004
2003
2003
Carrying
Fair
Carrying
Fair
Amount
Value
Amount
Value
(Thousands)
$
1,147,577
$
1,199,189
$
1,389,510
$
1,520,606
Other Investments
Table of Contents
Derivative Financial
Instruments
Table of Contents
Table of Contents
Table of Contents
Retirement Plan
Other Post-Retirement Benefits
Year Ended September 30
Year Ended September 30
2004
2003
2002
2004
2003
2002
(Thousands)
$
694,960
$
625,470
$
580,046
$
467,418
$
393,851
$
304,548
14,598
13,043
11,639
6,027
5,844
4,658
40,565
40,967
40,720
26,393
26,124
21,617
627
682
610
420
(19,593
)
51,302
28,880
(62,146
)
57,983
76,972
(36,998
)
(35,822
)
(36,235
)
(16,316
)
(17,066
)
(14,554
)
$
693,532
$
694,960
$
625,470
$
422,003
$
467,418
$
393,851
$
491,333
$
485,927
$
536,625
$
166,494
$
150,293
$
161,959
81,946
6,145
(29,898
)
38,960
390
(18,181
)
37,085
35,083
15,435
39,720
32,195
20,459
627
682
610
(36,998
)
(35,822
)
(36,235
)
(16,316
)
(17,066
)
(14,554
)
$
573,366
$
491,333
$
485,927
$
229,485
$
166,494
$
150,293
$
(120,166
)
$
(203,627
)
$
(139,543
)
$
(192,518
)
$
(300,924
)
$
(243,558
)
159,554
222,250
132,064
108,943
212,242
157,247
(3,716
)
64,144
71,272
78,399
9,171
10,274
11,451
20
26
30
$
48,559
$
28,897
$
256
$
(19,411
)
$
(17,384
)
$
(7,882
)
$
(91,587
)
$
(153,240
)
$
(75,116
)
$
(27,263
)*
$
(23,163
)*
$
(20,375
)*
14,536
10,782
10,944
7,852
5,779
12,493
33,904
21,934
9,171
10,274
11,451
82,535
139,147
52,977
$
48,559
$
28,897
$
256
$
(19,411
)
$
(17,384
)
$
(7,882
)
6.25
%
6.00
%
6.75
%
6.25
%**
6.00
%
6.75
%
8.25
%
8.25
%
8.50
%
8.25
%
8.25
%
8.50
%
6.11
%
6.11
%
6.11
%
6.11
%
6.11
%
6.11
%
*
Amounts are included in Other Accruals and
Current Liabilities on the Consolidated Balance Sheets.
**
The weighted average discount rate was 6.0%
through 12/8/2003. Subsequent to 12/8/2003, the discount rate
used was 6.25%.
Table of Contents
Retirement Plan
Other Post-Retirement Benefits
Year Ended September 30
Year Ended September 30
2004
2003
2002
2004
2003
2002
(Thousands)
$
14,598
$
13,043
$
11,639
$
6,027
$
5,844
$
4,658
40,565
40,967
40,720
26,393
26,124
21,617
(48,281
)
(47,260
)
(48,454
)
(14,898
)
(12,268
)
(13,551
)
1,103
1,176
1,205
4
4
4
(3,716
)
(3,716
)
7,127
7,127
7,127
9,438
2,231
(1,061
)
17,092
14,866
4,289
722
3,781
7,379
(9,731
)
(15,423
)
(729
)
$
18,145
$
10,222
$
7,712
$
32,014
$
26,274
$
23,415
$
(56,612
)
$
86,170
$
52,977
$
$
$
6.00
%
6.75
%
7.25
%
6.25
%*
6.75
%
7.25
%
8.25
%
8.50
%
8.50
%
8.25
%
8.50
%
8.50
%
6.11
%
6.11
%
6.11
%
6.11
%
6.11
%
6.11
%
*
The weighted average discount rate was 6.0%
through 12/8/2003. Subsequent to 12/8/2003, the discount rate
used was 6.25%.
2004
2003
2002
$
693,532
$
694,960
$
625,470
$
616,513
$
611,858
$
550,099
$
573,366
$
491,333
$
485,927
Table of Contents
Effect of Subsidy
$
(286,527
)
(1,500,001
)
(2,372,270
)
$
(4,158,798
)
$
$
(649,599
)
$
(1,475,809
)
$
(1,672,331
)
$
(1,861,515
)
$
(11,935,959
)
Table of Contents
Percentage of Plan
Assets at
September 30
Target Allocation
Asset Category
2005
2004
2003
2002
60-65%
61
%
53
%
55
%
25-30%
28
%
32
%
29
%
10-15%
11
%
15
%
16
%
100
%
100
%
100
%
Table of Contents
Percentage of Plan
Assets at
September 30
Target Allocation
Asset Category
2005
2004
2003
2002
93%
91
%
85
%
90
%
3%
1
%
1
%
0
%
4%
8
%
14
%
10
%
100
%
100
%
100
%
Environmental Matters
(i) Former Manufactured Gas Plant
Sites
Table of Contents
(ii) Third Party Waste Disposal
Sites
(iii) Other
Other
Table of Contents
Table of Contents
Year Ended September 30, 2004
Pipeline
Exploration
Total
Corporate and
and
and
Energy
Reportable
Intersegment
Total
Utility
Storage
Production
International
Marketing
Timber
Segments
All Other
Eliminations
Consolidated
(Thousands)
$
1,137,288
$
122,970
$
293,698
$
123,425
$
284,349
$
55,968
$
2,017,698
$
13,695
$
$
2,031,393
$
15,353
$
86,737
$
$
$
$
2
$
102,092
$
$
(102,092
)
$
$
21,945
$
10,933
$
50,642
$
7,080
$
33
$
2,218
$
92,851
$
919
$
(3,180
)
$
90,590
$
39,101
$
37,345
$
89,943
$
15,257
$
102
$
6,277
$
188,025
$
1,071
$
442
$
189,538
$
31,393
$
30,968
$
28,899
$
(6,137)
$
3,964
$
3,320
$
92,407
$
829
$
(499
)
$
92,737
$
$
$
$
$
$
1,252
$
1,252
$
$
$
1,252
$
$
$
4,645
$
$
$
$
4,645
$
$
$
4,645
$
46,718
$
47,726
$
54,344
$
5,982
$
5,535
$
5,637
$
165,942
$
1,530
$
(886
)
$
166,586
$
55,449
$
23,196
$
77,654
$
7,498
$
10
$
2,823
$
166,630
$
200
$
5,511
$
172,341
At September 30, 2004
(Thousands)
$
1,390,361
$
777,800
$
1,039,524
$
268,119
$
65,971
$
143,101
$
3,684,876
$
73,583
$
(46,661
)
$
3,711,798
Table of Contents
Year Ended September 30, 2003
Pipeline
Exploration
Total
Corporate and
and
and
Energy
Reportable
Intersegment
Total
Utility
Storage
Production
International
Marketing
Timber
Segments
All Other
Eliminations
Consolidated
(Thousands)
$
1,145,336
$
106,499
$
305,314
$
114,070
$
304,660
$
56,226
$
2,032,105
$
3,366
$
$
2,035,471
$
17,647
$
94,921
$
$
$
$
$
112,568
$
$
(112,568
)
$
$
29,122
$
14,000
$
53,326
$
8,700
$
33
$
2,507
$
107,688
$
521
$
(3,153
)
$
105,056
$
38,186
$
35,940
$
99,292
$
13,910
$
117
$
7,543
$
194,988
$
238
$
$
195,226
$
36,857
$
30,863
$
(17,537
)
$
876
$
3,350
$
72,692
$
127,101
$
279
$
781
$
128,161
$
$
$
$
$
$
168,787
$
168,787
$
$
$
168,787
$
$
$
58,472
$
$
$
$
58,472
$
$
$
58,472
$
$
$
42,774
$
$
$
$
42,774
$
$
$
42,774
$
56,808
$
45,230
$
(31,293
)
$
(1,368
)
$
5,868
$
112,450
$
187,695
$
193
$
(52
)
$
187,836
$
49,944
$
199,327
$
75,837
$
2,499
$
164
$
3,493
$
331,264
$
48,293
(1)
$
1,883
$
381,440
At September 30, 2003
(Thousands)
$
1,411,808
$
812,846
$
969,512
$
247,721
$
54,134
$
125,915
$
3,621,936
$
77,195
$
19,929
$
3,719,060
(1)
Amount includes the acquisition of all of the
partnership interests in Toro Partners, L.P. and is disclosed in
Note J Acquisitions.
Table of Contents
Year Ended September 30, 2002
Pipeline
Exploration
Total
Corporate and
and
and
Energy
Reportable
Intersegment
Total
Utility
Storage
Production
International
Marketing
Timber
Segments
All Other
Eliminations
Consolidated
(Thousands)
$
776,577
$
80,165
$
310,980
$
95,315
$
151,257
$
47,407
$
1,461,701
$
2,795
$
$
1,464,496
$
17,644
$
87,219
$
$
$
$
$
104,863
$
7,340
$
(112,203
)
$
$
30,790
$
10,424
$
55,367
$
8,045
$
76
$
2,896
$
107,598
$
420
$
(2,366
)
$
105,652
$
37,412
$
23,626
$
103,946
$
11,977
$
161
$
3,429
$
180,551
$
115
$
2
$
180,668
$
31,657
$
18,148
$
15,108
$
(2,030
)
$
5,103
$
4,476
$
72,462
$
(473
)
$
45
$
72,034
$
$
15,167
$
$
$
$
$
15,167
$
$
$
15,167
$
49,505
$
29,715
$
26,851
$
(4,443
)
$
8,642
$
9,689
$
119,959
$
(885
)
$
(1,392
)
$
117,682
$
51,550
$
30,329
$
114,602
$
4,244
$
51
$
25,574
$
226,350
$
6,554
$
$
232,904
At September 30, 2002
(Thousands)
$
1,248,426
$
532,543
$
1,161,310
$
241,466
$
52,850
$
131,721
$
3,368,316
$
33,563
$
(570
)
$
3,401,309
Table of Contents
For the Year Ended September 30
Geographic Information
2004
2003
2002
(Thousands)
$
1,867,335
$
1,818,980
$
1,293,239
123,425
114,070
95,315
40,633
102,421
75,942
$
2,031,393
$
2,035,471
$
1,464,496
At September 30
(Thousands)
$
2,967,277
$
2,975,329
$
2,621,001
228,179
219,695
216,044
143,042
116,655
258,196
$
3,338,498
$
3,311,679
$
3,095,241
(1)
Revenue is based upon the country in which the
sale originates.
At September 30
2004
2003
(Thousands)
$
10,045
$
11,113
5,169
4,445
1,230
867
$
16,444
$
16,425
Table of Contents
$
257,397
(68,192
)
(8,053
)
$
181,152
Condensed Balance Sheet:
$
220,792
14,984
5,476
8,580
7,565
$
257,397
$
189,205
48,433
237,638
15,265
4,494
$
257,397
$
48,319
(497
)
(160
)
$
47,662
Table of Contents
At September 30, 2004
At September 30, 2003
Gross Carrying
Accumulated
Net Carrying
Amount
Amortization
Amount
Net Carrying Amount
$
8,580
$
(1,782
)
$
6,798
$
7,867
31,864
(1,839
)
30,025
31,522
9,171
9,171
10,275
$
49,615
$
(3,621
)
$
45,994
$
49,664
$
2,567
$
1,054
Table of Contents
Net
Income
Available
Earnings Per
for
Common Share
Operating
Operating
Common
Quarter Ended
Revenues
Income
Stock
Basic
Diluted
2004
(Thousands, except per common share amounts)
$
278,197
$
27,675
$
7,754
$
0.09
$
0.09
$
419,006
$
72,324
$
32,563
(1)
$
0.40
$
0.39
$
801,677
$
148,554
$
77,055
(2)
$
0.94
$
0.93
$
532,513
$
95,817
$
49,214
(3)
$
0.60
$
0.60
2003
$
297,170
$
122,674
$
58,146
(4)
$
0.71
$
0.71
$
449,530
$
35,411
$
2,219
(5)
$
0.03
$
0.03
$
809,065
$
156,703
$
80,538
$
1.00
$
0.99
$
479,706
$
99,628
$
38,041
(6)
$
0.47
$
0.47
(1)
Includes expense of $0.8 million related to
an adjustment to the gain on sale of timber properties
recognized in 2003.
(2)
Includes expense of $6.4 million due to the
recognition of a pension settlement loss and income of
$4.6 million due to an adjustment to the loss on sale of
oil and gas properties recognized in 2003.
(3)
Includes income of $5.2 million related to
tax rate changes in the Czech Republic.
(4)
Includes expense of $6.3 million related to
the impairment of oil and gas producing properties, loss of
$39.6 million related to the sale of oil and gas producing
properties, and a gain of $102.2 million from the sale of
timber properties.
(5)
Includes expense of $22.6 million related to
the impairment of oil and gas producing properties.
(6)
Includes expense of $8.3 million related to
the cumulative effect of change in accounting (SFAS 142)
and an expense of $0.6 million due to the cumulative effect
of change in accounting (SFAS 143).
Table of Contents
Price Range
Dividends
Quarter Ended
High
Low
Declared
$
28.43
$
24.84
$
.280
$
25.57
$
23.75
$
.280
$
26.48
$
24.26
$
.270
$
25.01
$
21.71
$
.270
$
27.51
$
22.51
$
.270
$
26.90
$
21.60
$
.270
$
22.25
$
18.97
$
.260
$
21.86
$
17.95
$
.260
Capitalized Costs Relating to Oil and Gas
Producing Activities
At September 30
2004
2003
(Thousands)
$
1,489,284
$
1,647,075
27,277
30,955
1,516,561
1,678,030
609,469
763,258
$
907,092
$
914,772
(1)
Includes asset retirement costs of
$22.2 million and $18.1 million at September 30,
2004 and 2003, respectively.
Year Costs Incurred
Total as of
September 30, 2004
2004
2003
2002
Prior
(Thousands)
$
27,277
$
7,650
$
6,748
$
2,884
$
9,995
Table of Contents
Costs Incurred in Oil and Gas Property
Acquisition, Exploration and Development
Activities
Year Ended September 30
2004
2003
2002
(Thousands)
$
(8
)
$
(13
)
$
9,316
3,529
1,920
698
10,503
17,947
25,583
31,881
23,649
51,792
2,292
242
48,197
43,745
87,389
29
181
(536
)
3,167
6,217
2,804
22,624
6,641
8,779
5,500
17,745
15,332
1,218
32,538
30,784
26,379
21
168
8,780
6,696
8,137
3,502
33,127
24,588
34,362
37,381
41,394
67,124
3,510
242
$
80,735
$
74,529
$
113,768
Table of Contents
Results of Operations for Producing
Activities
Year Ended September 30,
2004
2003
2002
(Thousands, except per Mcfe amounts)
$
151,570
$
148,104
$
104,954
139,301
118,277
101,549
290,871
266,381
206,503
39,677
39,162
42,956
1,756
1,800
73,396
70,127
80,142
65,337
62,672
30,253
110,705
92,620
53,152
30,359
26,992
14,621
10,018
62,908
56,511
40,377
89,900
71,132
8,176
33,038
30,109
177
802
14,922
26,165
21,707
42,774
5,235
(3,273
)
4,672
11,867
(9,606
)
14,644
Table of Contents
Year Ended September 30,
2004
2003
2002
(Thousands, except per Mcfe amounts)
181,929
175,096
119,575
149,319
181,185
158,060
331,248
356,281
277,635
47,853
72,200
73,065
1,933
2,602
88,318
96,292
101,849
42,774
70,572
59,399
34,925
$
122,572
$
83,014
$
67,796
(1)
Exclusive of hedging gains and losses. See
further discussion in Note E Financial
Instruments
(2)
See discussion of impairment in
Note A Summary of Significant Accounting
Policies
Reserve Quantity Information
(unaudited)
Gas MMcf
U.S.
Gulf Coast
West Coast
Appalachian
Total
Total
Region
Region
Region
U.S.
Canada
Company
89,858
98,498
78,457
266,813
55,567
322,380
6,530
5,770
4,242
16,542
20,263
36,805
1,613
(26,063
)
342
(24,108
)
(20,676
)
(44,784
)
(25,776
)
(4,889
)
(4,402
)
(35,067
)
(6,387
)
(41,454
)
(14,361
)
(365
)
(14,726
)
(14,726
)
57,864
73,316
78,274
209,454
48,767
258,221
10,538
5,844
16,382
11,641
28,023
(2,278
)
1,213
2,224
1,159
(2,211
)
(1,052
)
(18,441
)
(4,467
)
(5,123
)
(28,031
)
(5,774
)
(33,805
)
(270
)
(270
)
Table of Contents
Gas MMcf
U.S.
Gulf Coast
West Coast
Appalachian
Total
Total
Region
Region
Region
U.S.
Canada
Company
47,683
70,062
81,219
198,964
52,153
251,117
2,632
3,784
6,416
15,925
22,341
(4,984
)
1,831
(1,111
)
(4,264
)
(11,004
)
(15,268
)
(17,596
)
(4,057
)
(5,132
)
(26,785
)
(6,228
)
(33,013
)
(1
)
(392
)
(393
)
(393
)
27,734
67,444
78,760
173,938
50,846
224,784
87,893
47,442
78,457
213,792
53,463
267,255
57,274
57,286
78,273
192,833
39,253
232,086
45,402
54,180
81,218
180,800
42,745
223,545
25,827
53,035
78,760
157,622
46,223
203,845
Oil Mbbl
U.S.
Gulf Coast
West Coast
Appalachian
Total
Total
Region
Region
Region
U.S.
Canada
Company
6,294
68,424
77
74,795
40,533
115,328
57
1,360
20
1,437
586
2,023
781
129
6
916
(10,278
)
(9,362
)
(1,815
)
(3,004
)
(9
)
(4,828
)
(2,834
)
(7,662
)
(200
)
(200
)
(410
)
(610
)
5,117
66,909
94
72,120
27,597
99,717
104
46
150
729
879
(365
)
(185
)
8
(542
)
(4,119
)
(4,661
)
(1,473
)
(2,872
)
(10
)
(4,355
)
(2,382
)
(6,737
)
(19,434
)
(19,434
)
3,383
63,852
138
67,373
2,391
69,764
19
18
37
181
218
213
(17
)
11
207
(144
)
63
(1,534
)
(2,650
)
(20
)
(4,204
)
(324
)
(4,528
)
(1
)
(303
)
(304
)
(304
)
2,080
60,882
147
63,109
2,104
65,213
6,259
44,304
77
50,640
33,676
84,316
5,111
41,735
94
46,940
24,100
71,040
2,533
40,079
139
42,751
2,391
45,142
2,061
38,631
148
40,840
2,104
42,944
Table of Contents
Standardized Measure of Discounted Future
Net Cash Flows Relating to Proved Oil and Gas Reserves
(unaudited)
Year Ended September 30,
2004
2003
2002
(Thousands)
$
3,728,168
$
2,684,286
$
2,764,556
676,361
579,321
546,182
124,298
116,639
117,999
995,327
613,893
653,347
1,932,182
1,374,433
1,447,028
996,813
641,185
665,941
935,369
733,248
781,087
Table of Contents
Year Ended September 30,
2004
2003
2002
(Thousands)
343,026
279,772
888,515
111,519
85,817
413,006
13,222
9,787
25,398
60,610
58,436
101,919
157,675
125,732
348,192
46,945
40,575
103,097
110,730
85,157
245,095
4,071,194
2,964,058
3,653,071
787,880
665,138
959,188
137,520
126,426
143,397
1,055,937
672,329
755,266
2,089,857
1,500,165
1,795,220
1,043,758
681,760
769,038
$
1,046,099
$
818,405
$
1,026,182
Table of Contents
Year Ended September 30,
2004
2003
2002
(Thousands)
$
733,248
$
781,087
$
605,350
(251,194
)
(227,219
)
(163,548
)
592,326
11,130
441,085
(5,554
)
(27,197
)
16,638
29,266
42,970
(40,042
)
(35,062
)
(42,069
)
32,653
36,423
45,310
(166,055
)
24,796
(126,263
)
(5,107
)
(3,572
)
(32,646
)
28,456
116,399
38,095
935,369
733,248
781,087
85,157
245,095
181,439
(32,201
)
(56,862
)
(41,023
)
29,230
8,167
111,148
(120,960
)
(3,084
)
36,986
28,241
29,813
(8,491
)
(14,045
)
18,151
5,055
29,657
12,361
(2,640
)
(6,280
)
(6,910
)
(19,369
)
(41,205
)
(88,571
)
17,003
13,349
31,771
110,730
85,157
245,095
Table of Contents
Year Ended September 30,
2004
2003
2002
(Thousands)
818,405
1,026,182
786,789
(283,395
)
(284,081
)
(204,571
)
621,556
19,297
552,233
(5,554
)
(120,960
)
(30,281
)
53,624
57,507
72,783
(48,533
)
(49,107
)
(23,918
)
37,708
66,080
57,671
(168,695
)
18,516
(133,173
)
(24,476
)
(44,777
)
(121,217
)
45,459
129,748
69,866
$
1,046,099
$
818,405
$
1,026,182
Table of Contents
Schedule II Valuation and Qualifying Accounts
Additions | Additions | |||||||||||||||||||
Balance at | Charged to | Charged to | Balance at | |||||||||||||||||
Beginning | Costs and | Other | End of | |||||||||||||||||
Description | of Period | Expenses | Accounts(1) | Deductions(2) | Period | |||||||||||||||
|
|
|
|
|
|
|||||||||||||||
(Thousands) | ||||||||||||||||||||
Year Ended September 30, 2004
|
||||||||||||||||||||
Reserve for Doubtful Accounts
|
$ | 17,943 | $ | 20,328 | $ | | $ | 20,831 | $ | 17,440 | ||||||||||
Deferred Tax Valuation Allowance
|
$ | 6,357 | $ | (3,480 | ) | $ | | $ | | $ | 2,877 | |||||||||
|
|
|
|
|
||||||||||||||||
Year Ended September 30, 2003
|
||||||||||||||||||||
Reserve for Doubtful Accounts
|
$ | 17,299 | $ | 17,275 | $ | | $ | 16,631 | $ | 17,943 | ||||||||||
Deferred Tax Valuation Allowance
|
$ | | $ | 6,357 | $ | | $ | | $ | 6,357 | ||||||||||
|
|
|
|
|
||||||||||||||||
Year Ended September 30, 2002
|
||||||||||||||||||||
Reserve for Doubtful Accounts
|
$ | 18,521 | $ | 16,082 | $ | 2,834 | $ | 20,138 | $ | 17,299 | ||||||||||
|
|
|
|
|
(1) | Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate settlements. |
(2) | Amounts represent net accounts receivable written-off. |
Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None
Item 9A | Controls and Procedures |
The following information includes the evaluation of disclosure controls and procedures by the Companys Chief Executive Officer and Treasurer, along with any significant changes in internal controls of the Company.
Evaluation of Disclosure Controls and Procedures
The term disclosure controls and procedures is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act). These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Companys management, including the Chief Executive Officer and Treasurer, evaluated the effectiveness of the Companys disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Companys Chief Executive Officer and Treasurer concluded that the Companys disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Controls Over Financial Reporting
The Company maintains a system of internal control over financial reporting that is designed to provide reasonable assurance that the Companys transactions are properly authorized, the Companys assets are safeguarded against unauthorized or improper use, and the Companys transactions are properly recorded and reported to permit preparation of the Companys financial statements in conformity with GAAP. There were no changes in the Companys internal control over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Companys internal control over financial reporting.
100
Item 9B | Other Information |
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 Companys definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning directors is set forth in the definitive Proxy Statement under the captions entitled Nominees for Election as Directors for Three-Year Terms to Expire in 2008, Directors Whose Terms Expire in 2007, Directors Whose Terms Expire in 2006, and Compliance with Section 16(a) of the Securities Exchange Act of 1934 and is incorporated herein by reference. Information concerning the Companys executive officers can be found in Part I, Item 1, of this report.
The Company has adopted a Code of Business Conduct and Ethics that applies to the Companys directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Companys website, www.nationalfuelgas.com , together with certain other corporate governance documents. Copies of the Companys Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
Item 11 | Executive Compensation |
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Companys definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning executive compensation is set forth in the definitive Proxy Statement under the captions Executive Compensation and Compensation Committee Interlocks and Insider Participation and, excepting the Report of the Compensation Committee and the Corporate Performance Graph, is incorporated herein by reference.
Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Equity Compensation Plan Information
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Companys definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The equity compensation plan information is set forth in the definitive Proxy Statement under the caption Equity Compensation Plan Information and is incorporated herein by reference.
Security Ownership and Changes in Control
(a) | Security Ownership of Certain Beneficial Owners |
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Companys definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning security ownership of certain beneficial owners is set forth in the definitive Proxy Statement under the caption Security Ownership of Certain Beneficial Owners and Management and is incorporated herein by reference.
101
(b) | Security Ownership of Management |
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Companys definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning security ownership of management is set forth in the definitive Proxy Statement under the caption Security Ownership of Certain Beneficial Owners and Management and is incorporated herein by reference.
(c) | Changes in Control |
None
Item 13 | Certain Relationships and Related Transactions |
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Companys definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the caption Compensation Committee Interlocks and Insider Participation and is incorporated herein by reference.
Item 14 | Principal Accountant Fees and Services |
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Companys definitive Proxy Statement for its February 17, 2005 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004. The information concerning principal accountant fees and services is set forth in the definitive Proxy Statement under the caption Audit Fees and is incorporated herein by reference.
PART IV
Item 15 | Exhibits and Financial Statement Schedules |
(a)1. Financial Statements
Financial statements filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.
(a)2. Financial Statement Schedules
Financial statement schedules filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.
(a)3. Exhibits
Exhibit | ||||
Number | Description of Exhibits | |||
|
|
|||
3(i) | Articles of Incorporation: | |||
| Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1, Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880) | |||
3(ii) | By-Laws: | |||
| National Fuel Gas Company By-Laws as amended on December 9, 2004 (Exhibit 3(ii), Form 8-K dated December 9, 2004 in File No. 1-3880) | |||
(4) | Instruments Defining the Rights of Security Holders, Including Indentures: | |||
| Indenture, dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796) |
102
Exhibit
Number
Description of Exhibits
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)
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)
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) (Exhibit 4.1, Form
10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
Indenture dated as of October 1, 1999,
between the Company and The Bank of New York
(Exhibit 4.1, Form 10-K for fiscal year ended
September 30, 1999 in File No. 1-3880)
Officers Certificate Establishing Medium-Term
Notes, dated October 14, 1999 (Exhibit 4.2,
Form 10-K for fiscal year ended September 30, 1999 in
File No. 1-3880)
Amended and Restated Rights Agreement, dated as
of April 30, 1999, between the Company and HSBC Bank USA
(Exhibit 10.2, Form 10-Q for the quarterly period
ended March 31, 1999 in File No. 1-3880)
Certificate of Adjustment, dated
September 7, 2001, to the Amended and Restated Rights
Agreement dated as of April 30, 1999, between the Company
and HSBC Bank USA (Exhibit 4, Form 8-K dated
September 7, 2001 in File No. 1-3880)
Officers Certificate establishing
6.50% Notes due 2022, dated September 18, 2002
(Exhibit 4, Form 8-K dated October 3, 2002 in
File No. 1-3880)
Officers Certificate establishing
5.25% Notes due 2013, dated February 18, 2003
(Exhibit 4, Form 10-Q for the quarterly period ended
March 31, 2003 in File No. 1-3880)
(10)
Material Contracts:
(ii)
Contracts upon which the Companys business
is substantially dependent:
Credit Agreement, dated as of September 30,
2002, among the Company, the Lenders and JPMorgan Chase Bank
(Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 2002 in File No. 1-3880)
First Amendment to Credit Agreement, among the
Company, the Lenders and JPMorgan Chase Bank, dated
September 29, 2003 (Exhibit 10.1, Form 10-K for fiscal
year ended September 30, 2003 in File No. 1-3880)
Second Amendment to Credit Agreement, among the
Company, the Lenders and JPMorgan Chase Bank, dated
September 26, 2004 (Exhibit 99, Form 8-K dated
September 30, 2004 in File No. 1-3880)
(iii)
Compensatory plans for officers:
Retirement Benefit Agreement, dated
September 22, 2003, between the Company and David F. Smith
(Exhibit 10.2, Form 10-K for fiscal year ended
September 30, 2003 in File No. 1-3880)
Form of Employment Continuation and
Noncompetition Agreement, dated as of December 11, 1998,
among the Company, National Fuel Gas Distribution Corporation
and each of Philip C. Ackerman, Anna Marie Cellino, Joseph P.
Pawlowski, James D. Ramsdell, Dennis J. Seeley, David F. Smith
and Ronald J. Tanski (Exhibit 10.1, Form 10-Q for the
quarterly period ended June 30, 1999 in File
No. 1-3880)
103
Exhibit
Number
Description of Exhibits
Form of Employment Continuation and
Noncompetition Agreement, dated as of December 11, 1998,
among the Company, National Fuel Gas Supply Corporation and each
of Bruce H. Hale and John R. Pustulka (Exhibit 10.2, Form
10-Q for the quarterly period ended June 30, 1999 in File
No. 1-3880)
Form of Employment Continuation and
Noncompetition Agreement, dated as of December 11, 1998,
among the Company, Seneca Resources Corporation and James A.
Beck (Exhibit 10.3, Form 10-Q for the quarterly period
ended June 30, 1999 in File No. 1-3880)
National Fuel Gas Company 1993 Award and Option
Plan, dated February 18, 1993 (Exhibit 10.1, Form 10-Q
for the quarterly period ended March 31, 1993 in File
No. 1-3880)
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)
Amendment to National Fuel Gas Company 1993 Award
and Option Plan, dated December 11, 1996
(Exhibit 10.8, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
Amendment to National Fuel Gas Company 1993 Award
and Option Plan, dated December 18, 1996 (Exhibit 10,
Form 10-Q for the quarterly period ended December 31, 1996
in File No. 1-3880)
National Fuel Gas Company 1993 Award and Option
Plan, amended through June 14, 2001 (Exhibit 10.1,
Form 10-K for fiscal year ended September 30, 2001 in File
No. 1-3880)
National Fuel Gas Company 1997 Award and Option
Plan, amended through June 14, 2001 (Exhibit 10.2,
Form 10-K for fiscal year ended September 30, 2001 in File
No. 1-3880)
Amendment to National Fuel Gas Company Deferred
Compensation Plan, dated June 15, 2001 (Exhibit 10.3,
Form 10-K for fiscal year ended September 30, 2001 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)
Amendment to National Fuel Gas Company Deferred
Compensation Plan, dated September 19, 1996
(Exhibit 10.10, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
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)
National Fuel Gas Company Deferred Compensation
Plan, as amended and restated through March 20, 1997
(Exhibit 10.3, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
Amendment to National Fuel Gas Company Deferred
Compensation Plan, dated June 16, 1997 (Exhibit 10.4,
Form 10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
Amendment No. 2 to the National Fuel Gas
Company Deferred Compensation Plan, dated March 13, 1998
(Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1998 in File No. 1-3880)
Amendment to the National Fuel Gas Company
Deferred Compensation Plan, dated February 18, 1999
(Exhibit 10.1, Form 10-Q for the quarterly period ended
March 31, 1999 in File No. 1-3880)
National Fuel Gas Company Tophat Plan, effective
March 20, 1997 (Exhibit 10, Form 10-Q for the
quarterly period ended June 30, 1997 in File
No. 1-3880)
Amendment No. 1 to National Fuel Gas Company
Tophat Plan, dated April 6, 1998 (Exhibit 10.2, Form
10-K for fiscal year ended September 30, 1998 in File
No. 1-3880)
Amendment No. 2 to National Fuel Gas Company
Tophat Plan, dated December 10, 1998 (Exhibit 10.1,
Form 10-Q for the quarterly period ended December 31, 1998
in File No. 1-3880)
Amended Restated Split Dollar Insurance
Agreement, effective June 15, 2000, among the Company,
Bernard J. Kennedy, and Joseph B. Kennedy, as Trustee of the
Trust under the Agreement dated January 9, 1998
(Exhibit 10.1, Form 10-Q for the quarterly period
ended June 30, 2000 in File No. 1-3880)
Contingent Benefit Agreement effective
June 15, 2000, between the Company and Bernard J. Kennedy
(Exhibit 10.2, Form 10-Q for the quarterly period
ended June 30, 2000 in File No. 1-3880
104
Exhibit
Number
Description of Exhibits
Amended and Restated Split Dollar Insurance and
Death Benefit Agreement, dated September 17, 1997 between
the Company and Philip C. Ackerman (Exhibit 10.5, Form 10-K
for fiscal year ended September 30, 1997 in File
No. 1-3880)
Amendment Number 1 to Amended and Restated
Split Dollar Insurance and Death Benefit Agreement by and
between the Company and Philip C. Ackerman, dated March 23,
1999 (Exhibit 10.3, Form 10-K for fiscal year ended
September 30, 1999 in File No. 1-3880)
Amended and Restated Split Dollar Insurance and
Death Benefit Agreement, dated September 15, 1997, between
the Company and Joseph P. Pawlowski (Exhibit 10.7, Form
10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
Amendment Number 1 to Amended and Restated
Split Dollar Insurance and Death Benefit Agreement by and
between the Company and Joseph P. Pawlowski, dated
March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal
year ended September 30, 1999 in File No. 1-3880)
Amended and Restated Split Dollar Insurance and
Death Benefit Agreement, dated September 15, 1997, between
the Company and Dennis J. Seeley (Exhibit 10.9, Form 10-K
for fiscal year ended September 30, 1999 in File
No. 1-3880)
Amendment Number 1 to Amended and Restated
Split Dollar Insurance and Death Benefit Agreement by and
between the Company and Dennis J. Seeley, dated March 29,
1999 (Exhibit 10.10, Form 10-K for fiscal year ended
September 30, 1999 in File No. 1-3880)
Split Dollar Insurance and Death Benefit
Agreement dated September 15, 1997, between the Company and
Bruce H. Hale (Exhibit 10.11, Form 10-K for fiscal year
ended September 30, 1999 in File No. 1-3880)
Amendment Number 1 to Split Dollar Insurance
and Death Benefit Agreement by and between the Company and Bruce
H. Hale, dated March 29, 1999 (Exhibit 10.12, Form
10-K for fiscal year ended September 30, 1999 in File
No. 1-3880)
Split Dollar Insurance and Death Benefit
Agreement, dated September 15, 1997, between the Company
and David F. Smith (Exhibit 10.13, Form 10-K for fiscal
year ended September 30, 1999 in File No. 1-3880)
Amendment Number 1 to Split Dollar Insurance
and Death Benefit Agreement by and between the Company and David
F. Smith, dated March 29, 1999 (Exhibit 10.14, Form
10-K for fiscal year ended September 30, 1999 in File
No. 1-3880)
10
.1
National Fuel Gas Company Parameters for
Executive Life Insurance Plan
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
.2
National Fuel Gas Company Participating
Subsidiaries Executive Retirement Plan 2003 Trust
Agreement (I), dated September 1, 2003
National Fuel Gas Company and Participating
Subsidiaries 1996 Executive Retirement Plan Trust
Agreement (II), dated May 10, 1996
(Exhibit 10.13, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
Amendments to National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan, dated
September 18, 1997 (Exhibit 10.9, Form 10-K for
fiscal year ended September 30, 1997 in File
No. 1-3880)
Amendments to National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan, dated
December 10, 1998 (Exhibit 10.2, Form 10-Q for the
quarterly period ended December 31, 1998 in File
No. 1-3880)
Amendments to National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan, effective
September 16, 1999 (Exhibit 10.15, Form 10-K for
fiscal year ended September 30, 1999 in File
No. 1-3880)
105
Exhibit
Number
Description of Exhibits
Amendment to National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan, effective
September 5, 2001 (Exhibit 10.4, Form 10-K/A for
fiscal year ended September 30, 2001, in File
No. 1-3880)
Retirement Supplement Agreement, dated
January 11, 2002, between the Company and Joseph P.
Pawlowski (Exhibit 10.6, Form 10-K/A for fiscal year ended
September 30, 2001 in File No. 1-3880)
Amendment No. 1 to Retirement Supplement
Agreement, dated March 11, 2004, between the Company and
Joseph P. Pawlowski (Exhibit 10(iii), Form 10-Q for the
quarterly period ended March 31, 2004 in File
No. 1-3880)
Administrative Rules with Respect to At Risk
Awards under the 1993 Award and Option Plan (Exhibit 10.14,
Form 10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
Administrative Rules with Respect to At Risk
Awards under the 1997 Award and Option Plan (Exhibit A,
Definitive Proxy Statement, Schedule 14(A) filed
January 10, 2002 in File No. 1-3880)
10
.3
Administrative Rules of the Compensation
Committee of the Board of Directors of National Fuel Gas
Company, as amended and restated, effective September 9,
2004
Excerpts of Minutes from the National Fuel Gas
Company Board of Directors Meeting of March 20, 1997
regarding the Retainer Policy for Non-Employee Directors
(Exhibit 10.11, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
10
.4
Retirement and Consulting Agreement, dated
September 5, 2001, between the Company and Bernard J.
Kennedy
(12
)
Statements regarding Computation of
Ratios: Ratio of Earnings to Fixed Charges for the fiscal
years ended September 30, 1998 through 2003
(21
)
Subsidiaries of the Registrant: See Item 1
of Part I of this Annual Report on Form 10-K
(23
)
Consents of Experts:
23
.1
Consent of Ralph E. Davis Associates, Inc.
regarding Seneca Resources Corporation
23
.2
Consent of Ralph E. Davis Associates, Inc.
regarding Seneca Energy Canada, Inc.
23
.3
Consent of Independent Accountants
(31
)
Rule 13a-15(e)/15d-15(e) Certifications
31
.1
Written statements of Chief Executive Officer
pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.
31
.2
Written statements of Principal Financial Officer
pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act.
(32
)
Certification pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(99
)
Additional Exhibits:
99
.1
Report of Ralph E. Davis Associates, Inc.
regarding Seneca Resources Corporation
99
.2
Report of Ralph E. Davis Associates, Inc.
regarding Seneca Energy Canada, Inc.
99
.3
Company Maps
The Company agrees to furnish to the SEC upon
request the following instruments with respect to long-term debt
that the Company has not filed as an exhibit pursuant to the
exemption provided by Item 601(b)(4)(ii)(A):
Secured Credit Agreement, dated as of
June 5, 1997, among the Empire State Pipeline, as borrower,
Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan
Chase Bank (f/k/a The Chase Manhattan Bank), as administrative
agent, and Chase Securities, as arranger.
First Amendment to Secured Credit Agreement,
dated as of May 28, 2002, among Empire State Pipeline, as
borrower, Empire State Pipeline, Inc., St. Clair Pipeline
Company, Inc., the Lenders party to the Secured Credit
Agreement, and JPMorgan Chase Bank, as administrative agent.
Second Amendment to Secured Credit Agreement,
dated as of February 6, 2003, among Empire State Pipeline,
as borrower, Empire State Pipeline, Inc., St. Clair
Pipeline Company, Inc., the Lenders party to the Secured Credit
Agreement, as amended, and JPMorgan Chase Bank, as
administrative agent.
106
Exhibit
Number
Description of Exhibits
Incorporated herein by reference as indicated.
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.
107
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/ P. C. ACKERMAN |
|
|
P. C. Ackerman | |
Chairman of the Board, President | |
and Chief Executive Officer |
Date: December 9, 2004
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 | Date | ||||
|
|
|
||||
/s/ P. C. ACKERMAN
P. C. Ackerman |
Chairman of the Board, President, Chief Executive Officer and Director | December 9, 2004 | ||||
/s/ R. T. BRADY
R. T. Brady |
Director | December 9, 2004 | ||||
/s/ R. D. CASH
R. D. Cash |
Director | December 9, 2004 | ||||
/s/ R. E. KIDDER
R. E. Kidder |
Director | December 9, 2004 | ||||
/s/ B. S. LEE
B. S. Lee |
Director | December 9, 2004 | ||||
/s/ G. L. MAZANEC
G. L. Mazanec |
Director | December 9, 2004 | ||||
/s/ J. F. RIORDAN
J. F. Riordan |
Director | December 9, 2004 | ||||
/s/ R. J. TANSKI
R. J. Tanski |
Treasurer and Principal Financial Officer | December 9, 2004 | ||||
/s/ K. M. CAMIOLO
K. M. Camiolo |
Controller and Principal Accounting Officer | December 9, 2004 |
108
Exhibit 10.1
National Fuel Gas Company
Parameters for Executive Life Insurance Plan
to Replace the Split Dollar Plan
Once an officer reaches age 50 the Company, at the option of the CEO, may pay an insurance carrier up to $15,000 a year for one or more insurance policies selected by the officer, subject to the following guidelines:
Ø | Officer has the option to purchase one or more insurance policies from the following insurance carriers: |
° | Northwestern Mutual Life Insurance | |||
° | Guardian Life Insurance Company | |||
° | Massachusetts Mutual Life Insurance |
Ø | The above carriers will remain available so long as each carrier has a rating equivalent to or better than a Standard & Poors rating of A+. |
Ø | Officer may select one or more of the following insurance products: |
° | Term Life Life insurance which provides protection for a specific period of time. It provides a benefit only if the insured passes away during the term. | |||
° | Whole Life Life insurance which provides permanent protection for the insured persons lifetime. The stated premium remains constant over the life of the policy. This type of insurance also builds cash value which can be borrowed. | |||
° | Universal Life Life insurance which provides permanent protection characterized by flexible premiums and flexible face amount. This type of insurance builds cash value. | |||
° | Variable Life Life insurance for which the death benefit and cash value fluctuate according to investment performance, if tied to one of the following indices: S & P 500 Index, Wilshire 5000 Index, Russell 2000 Index, Russell 2500 Index or MSCI EAFE Index. |
Ø | The annual payment to the carrier by the Company will terminate upon the termination of the officers employment with the Company. |
Ø | The $15,000 will be taxable compensation to the officer. |
APPROVED:
|
APPROVED: | |
|
||
/s/ George L. Mazanec
|
/s/ Philip C. Ackerman | |
|
|
|
George L. Mazanec
Chairman, Compensation Committee |
Philip C. Ackerman
Chief Executive Officer |
|
|
||
Date:
|
Date: |
Exhibit 10.2
NATIONAL FUEL GAS COMPANY AND PARTICIPATING SUBSIDIARIES
EXECUTIVE RETIREMENT PLAN 2003 TRUST AGREEMENT (I)
TABLE OF CONTENTS
Page
|
||||
SECTION 1. Restatement and Title of the Trust
|
2 | |||
SECTION 2. Acceptance by the Trustee
|
4 | |||
SECTION 3.
Limitation on Use of Funds; Trustee Responsibility Regarding Payments to Member or Beneficiary When the Company is Insolvent; Payments to the Company
|
4 | |||
SECTION 4. Duties and Powers of the Trustee with Respect to Investments
|
6 | |||
SECTION 5. Additional Powers and Duties of the Trustee
|
8 | |||
SECTION 6. Payments by the Trustee
|
11 | |||
SECTION 7. Third Parties
|
14 | |||
SECTION 8. Taxes, Expenses and Compensation
|
14 | |||
SECTION 9. Administration and Records
|
15 | |||
SECTION 10. Removal or Resignation of the Trustee and Designation of Successor Trustee
|
17 | |||
SECTION 11. Enforcement of Trust Agreement and Legal Proceedings
|
18 | |||
SECTION 12. Change in Control Defined
|
19 | |||
SECTION 13. Termination
|
21 | |||
SECTION 14. Amendments
|
21 | |||
SECTION 15. Non-alienation
|
22 | |||
SECTION 16. Communications
|
22 | |||
SECTION 17. Miscellaneous Provisions
|
24 | |||
EXHIBIT A
|
i
NATIONAL FUEL GAS COMPANY AND PARTICIPATING SUBSIDIARIES
EXECUTIVE RETIREMENT PLAN 2003 TRUST AGREEMENT (I)
This 2003 RESTATEMENT OF THE TRUST AGREEMENT, made and entered into as of September 1, 2003, by NATIONAL FUEL GAS COMPANY, a corporation organized under the laws of the State of New Jersey, (the Company), and HSBC Bank USA, a bank organized under the laws of the state of New York (the Trustee)
W I T N E S S E T H:
WHEREAS, the Company established an excess benefit plan, within the meaning of Section 3(36) of the Employee Retirement Income Security Act of 1974, as amended (ERISA), called the National Fuel Gas Company and Subsidiaries Supplemental Executive Retirement Plan (the SERP), for the benefit of certain employees;
WHEREAS, the Company subsequently established an unfunded plan of deferred compensation under ERISA § 201(2), called the National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan (the Plan), and amended the Plan, so that the Plan provides benefits in addition to and inclusive of those provided under the SERP, and the SERP was terminated effective April 25, 1988;
WHEREAS, the Plan provides for the Company to pay all benefits from its general assets and does not require it to pay benefits from the assets of any trust or special or separate fund established by the Company to assure those payments;
WHEREAS, the Company established a revocable trust fund, subject to the Companys Insolvency, to aid it in meeting its obligations under the SERP, and amended that trust as of May 10, 1996 to aid the Company in meeting its obligations under the Plan;
WHEREAS, the Company remains concerned that benefits may not be paid under the Plan if there is a Change in Control and wishes to assure payment on and after a Change in Control;
WHEREAS, the Company wishes to benefit all participants in the Plan, called Members, whether retired or not, and Beneficiaries, on and after a Change in Control;
WHEREAS, the Company wishes to amend the trust further to provide additional protection to Members and Beneficiaries of the Plan by making the trust generally irrevocable on a Change in Control and to provide that protection as equitably as possible among those Members and Beneficiaries;
WHEREAS, the Company intends to make contributions to the trust fund to aid it in meeting its obligations under the Plan, until that trust fund is revoked by the Company under the circumstances described in this Trust Agreement, when the trust fund will be returned to the Company, and to provide for the payment of benefits on and after a Change in Control, and in other circumstances, and those contributions will be held by the Trustee, and invested, reinvested and distributed, including subject to the Companys Insolvency, in accordance with this Trust Agreement;
WHEREAS, the Trustee is under no duty to determine whether any contributions are in accordance with the Plan or to collect or enforce payment of any contribution; and
WHEREAS, it is the intention of the parties that this Trust constitute an unfunded arrangement and will not affect the status of the Plan as an unfunded plan maintained for the purpose of providing deferred compensation for a select group of management or highly compensated employees for purposes of Title I of the Employee Retirement Income Security Act of 1974, as amended (ERISA).
NOW, THEREFORE, in consideration of the mutual covenants in this Trust Agreement, the Company and the Trustee declare and agree as follows:
SECTION 1. Restatement and Title of the Trust.
1.1. The Company continues with the Trustee a Trust as restated in its entirety by this agreement, known as the The National Fuel Gas Company and Participating Subsidiaries
- 2 -
Executive Retirement Plan 2003 Trust (I) (the Trust), consisting of sums of money and other property acceptable to the Trustee as from time to time are paid or delivered to the Trustee. All that money and other property, all investments and reinvestments made with it or proceeds of it and all earnings and profits on it, less all payments and charges as authorized in this Trust Agreement, are referred to as the Trust Fund. The Trust Fund will be held by the Trustee IN TRUST and will be dealt with in accordance with the provisions of this Trust Agreement.
1.2. The Trust continued by this Trust Agreement is revocable; it will become irrevocable on a Change in Control.
1.3. The Company at all times has the power to reacquire assets of the Trust Fund by substituting readily marketable securities, other than securities of the Company or any affiliate, of an equivalent value, net of any costs of disposition, and that other property, following that substitution, will constitute the Trust Fund.
1.4. The Trust is intended to be a grantor trust, of which Company is the grantor, within the meaning of subpart E part 1, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended, (the Code) and will be construed accordingly.
1.5. The principal of the Trust, and any earnings on it, will be held separate and apart from other funds of the Company and, except with respect to the revocability of the Trust prior to a Change in Control, will be used exclusively for the uses and purposes of Members, Beneficiaries and general creditors as in set forth in this Trust Agreement. Members and Beneficiaries have no preferred claim on, or any beneficial ownership interest in, any assets of the Trust. Any rights created under the Plan and this Trust Agreement will be mere unsecured contractual rights of Members and Beneficiaries against the Company. Any assets held by the Trust will be subject to the claims of the Companys general creditors under federal and state law in the event of Insolvency.
1.6. Prior to a Change in Control, the Company, in its sole discretion, at any time, or from time to time, may make additional deposits of cash or other property in trust with
- 3 -
the Trustee to augment the principal to be held, administered and disposed of by the Trustee as provided in this Trust Agreement. Neither the Trustee nor any Member or Beneficiary has any right to compel these additional deposits.
1.7. On a Change in Control, the Company, as soon as possible, but not longer than 15 business days following the Change in Control, must make an irrevocable contribution to the Trust in an amount sufficient to pay each Member or Beneficiary the benefits to which Members and Beneficiaries would be entitled pursuant to the terms of the Plan as of the date of the Change in Control.
1.8. Within 30 business days following the end of each Plan year ending after a Change in Control, the Company is required to deposit irrevocably additional cash or other property to the Trust in an amount sufficient to pay each Member or Beneficiary the benefits payable pursuant to the terms of the Plan as of the close of the Plan year.
SECTION 2. Acceptance by the Trustee.
2.1. The Trustee continues the Trust established under this Trust Agreement on the terms and subject to the provisions set forth in this Trust Agreement, and it agrees to continue to discharge and perform fully and faithfully all the duties and obligations imposed on it under this Trust Agreement.
SECTION 3. Limitation on Use of Funds; Trustee Responsibility Regarding Payments to Member or Beneficiary When the Company is Insolvent; Payments to the Company.
3.1. Except with respect to the revocability of the Trust prior to a Change in Control, no part of the corpus or income of the Trust Fund may be recoverable by the Company, used to provide for borrowing from any lender, or used for any purpose other than for the exclusive purpose of providing payments to Members and Beneficiaries in accordance with the provisions of this Trust Agreement until all payments required by this Trust Agreement have been made. However, nothing in this Section may be deemed to limit or otherwise prevent the
- 4 -
payment from the Trust Fund of expenses and other charges to the extent provided for in Sections 8 and 17, and the Trust Fund at all times will be subject to the claims of creditors of the Company and its subsidiaries to the extent provided for in Section 3.2.
3.2. (a) The Trustee must cease payment of benefits to Members and Beneficiaries if the Company is Insolvent. The Company will be considered Insolvent if (i) the Company is unable to pay its debts as they become due, or (ii) the Company is subject to a pending proceeding as debtor under the United States Bankruptcy Code.
(b) At all times during the continuance of this Trust, as provided in Section 1.1, the principal and income of the Trust will be subject to claims of general creditors of the Company under federal and state law as set forth below.
(1) The Board of Directors and the Chief Executive Officer of the Company have the duty to inform the Trustee in writing of Companys Insolvency. If a person claiming to be a creditor of Company alleges in writing to the Trustee that Company has become Insolvent, the Trustee will determine whether Company is Insolvent and, pending that determination, the Trustee will discontinue payment of benefits to Members and Beneficiaries.
(2) Unless the Trustee has actual knowledge of the Companys Insolvency, or has received notice from Company or a person claiming to be a creditor alleging that Company is Insolvent, the Trustee has no duty to inquire whether the Company is Insolvent. The Trustee may rely on such evidence concerning the Companys solvency as may be furnished to the Trustee and that provides the Trustee with a reasonable basis for making a determination concerning the Companys solvency.
(3) If at any time the Trustee has determined the Company is Insolvent, the Trustee must discontinue payments to Members and Beneficiaries and will hold the assets of the Trust for the benefit of the Companys general creditors. Nothing in this Trust Agreement in any way may diminish any rights of Members and Beneficiaries as general creditors of the Company with respect to benefits due under the Plan or otherwise.
- 5 -
(4) The Trustee will resume the payment of benefits to Members and Beneficiaries in accordance with Section 6 only after the Trustee has determined the Company is not Insolvent (or is no longer Insolvent).
(c) Provided there are sufficient assets, if the Trustee discontinues the payment of benefits from the Trust pursuant to Section 3.2(b)(3) and subsequently resumes those payments, the first payment following that discontinuance will include the aggregate amount of all payments due to Members and Beneficiaries under the terms of the Plan for the period of that discontinuance, less the aggregate amount of any payments made to Members and Beneficiaries by the Company in lieu of the payments provided for under this Trust Agreement during any such period of discontinuance.
3.3. Except as provided in Sections 3.1 and 3.2, after the Trust has become irrevocable, the Company will have no right or power to direct the Trustee to return to the Company or to divert any of the Trust assets before all payment of benefits have been made to Members and Beneficiaries pursuant to the terms of the Plan.
SECTION 4. Duties and Powers of the Trustee with Respect to Investments.
4.1. The Trustee may not invest in securities (including stock or rights to acquire stock) or obligations issued by the Company, other than a de minimis amount held in common investment vehicles in which the Trustee invests. All rights associated with assets of the Trust will be exercised by the Trustee or the person designated by the Trustee, and in no event will be exercisable by or rest with Members and Beneficiaries.
4.2. The Company has the right at any time, and from time to time in its sole discretion, to substitute assets of equal fair market value for any asset held by the Trust. The right is exercisable by Company in a non-fiduciary capacity without the approval or consent of any person in a fiduciary capacity.
4.3. (a) The Company, at any time prior to a Change in Control, may direct the Trustee to, and the Trustee, at any time on or after a Change in Control, may segregate all or
- 6 -
a specified portion of the Trust Fund into a separate fund (the Directed Fund) and invest it in accordance with the directions of one or more Investment Managers appointed by the Company or the Trustee, as the case may be. Any Investment Manager so appointed must be (1) an investment adviser registered as such under the Investment Advisors Act of 1940, (2) a bank, (3) an insurance company qualified to perform investment management service, under the laws of more than one state of the United States, or (4) any other person acceptable to the Trustee. If the Company appoints an Investment Manager, the Company will deliver to the Trustee a copy of the instruments appointing the Investment Manager and evidencing the Investment Managers acceptance of the appointment. The Trustee then will be protected in assuming the appointment of an Investment Manager remains in effect until it is otherwise notified by the Company. All notifications, instructions, and directions under this Section by or from the Company, the Trustee or the Investment Manager must be in writing or they will not be considered as such.
(b) The Trustee will invest and reinvest the Directed Fund only to the extent and in the manner directed by the Investment Manager, including an investment in any open-end or closed-end investment company or companies, as defined in the Investment Company Act of 1940. In performing its investment duties, the Investment Manager will have, with respect to the Directed Fund, all of the powers of the Trustee listed in Sections 4 and 5 (other than Sections 5.9 and 5.12). If the Trustee does not receive instructions from an Investment Manager with respect to the Directed Fund, the Trustee, after providing notice to the Investment Manager, will invest those amounts in short-term securities of the United States or any agency or instrumentality of it or in one or more investment companies commonly known as money market funds, whether or not managed by the Trustee or its affiliates, and, prior to a Change in Control, with the consent of the Company, in a common fund maintained by the Trustee for short-term investments. If the Investment Manager resigns, is removed, is no longer qualified to serve as an Investment Manager under applicable law, the Trustee will reassume complete investment responsibility for the Directed Fund until, prior to a Change in Control, a new Investment Manager is appointed by the Company, or on and after a Change in Control, a new Investment Manager is appointed by the Trustee. On a Change in Control, the Trustee will notify the Investment Manager either it, the Trustee, is appointing the Investment Manager to
- 7 -
continue or it, the Trustee, is reassuming complete investment responsibility for the Directed Fund.
(c) Any Investment Manager acting may issue orders for the purchase or sale of securities directly to a broker or dealer and the Trustee, on request from the Investment Manager, will execute and deliver appropriate trading authorization. Notification of the issuance of each such order must be given promptly to the Trustee by the Investment Manager, and the execution of each such order will be confirmed by the broker to the Investment Manager and to the Trustee. That notification is authority to the Trustee to receive securities purchased against payment for those securities and to deliver securities sold against receipt of the proceeds from them, as the case may be. Unless the Trustee participates knowingly in, or knowingly undertakes to conceal, an act or omission of the Investment Manager, knowing that act or omission to be a breach of the Investment Managers responsibilities with respect to the Trust, the Trustee will not be liable for any act or omission of the Investment Manager and will not be under any obligation to invest or otherwise manage the assets of the Plan that are subject to the management of the Investment Manager, and the Trustee has no liability or responsibility for acting or not acting in accordance with any written direction of the Investment Manager or, subject to Section 4.4(b), failing to act in the absence of any such direction. The Company agrees, to the extent permitted by applicable law, to indemnify the Trustee and hold it harmless from and against any claim or liability that may be asserted against it, other than on account of the Trustees own negligence or willful misconduct, by reason of the Trustees taking or refraining from taking any action in accordance with this Section, including, any claim or liability that may be asserted against the Trustee on account of failure to receive securities purchased, or failure to deliver securities sold, pursuant to orders issued by the Investment Manager directly to a broker or dealer.
SECTION 5. Additional Powers and Duties of the Trustee.
The Trustee has the following additional powers and authority with respect to all property constituting a part of the Trust Fund:
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5.1. To sell, exchange or transfer any such property at public or private sale for cash or on credit and grant options for the purchase or exchange of it.
5.2. To participate in any plan or reorganization, consolidation, merger, combination, liquidation or other similar plan relating to any such property, and to consent to or oppose any such plan or any action thereunder or any contract, lease, mortgage, purchase, sale or other action by any corporation or other entity.
5.3. To deposit any such property with any protective, reorganization or similar committee; to delegate discretionary power to any such committee; and to pay part of the expenses and compensation of any such committee and any assessments levied with respect to any property so deposited.
5.4. To exercise any conversion privilege or subscription right available in connection with any such property; to oppose or to consent to the reorganization, consolidation, merger or readjustment of the finances of any corporation company or association, or to the sale, mortgage, pledge or lease of the property or any of the securities that at any time may be held in the Trust Fund and to do any act with reference to the property, including the exercise of options, the making of agreements or subscriptions and the payment of expenses, assessments or subscriptions, that may be deemed necessary or advisable in connection with those actions, and to hold and retain any securities or other property that it may so acquire.
5.5. To commence or defend suits or legal proceedings and to represent the Trust in all suits or legal proceedings; to settle, compromise or submit to arbitration, any claims, debts or damages, due or owing to from the Trust.
5.6. To exercise, personally or by general or limited power of attorney, any right, including the right to vote, appurtenant to any securities or other such property.
5.7. To borrow money from any lender in amounts and on terms and conditions as are deemed advisable or proper to carry out the purposes of the Trust and to pledge any securities or other property for the repayment of any such loan.
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5.8. To hold any mortgage in its own name or in the name of a nominee, with or without the addition of words indicating that the mortgage is held in a fiduciary capacity, and to cause to be formed a corporation, partnership, trust or other entity to hold title to any mortgage with those powers, all on terms and conditions as are deemed advisable; to renew or extend or participate in the renewal or extension of any mortgage, and to agree to a reduction in the rate of interest on any mortgage or to any other modification or change in the terms of any mortgage or of any guarantee pertaining to it, in any manner and of any guarantee pertaining to it, in any manner and to any extent that is deemed advisable for the protection of the Trust or the preservation of any covenant or condition of any mortgage or in the performance of any guarantee, or to enforce any default in the manner and to the extent as is deemed advisable; and to exercise and enforce any and all rights of foreclosure, to bid on any property on foreclosure, to take a deed in lieu of foreclosure with or without paying a consideration for it and in connection with it to release the obligation on the bond secured by that mortgage, and to exercise and enforce in any action, suit or proceeding at law or in equity any rights or remedies in respect of any such mortgage or guarantee.
5.9. To engage any legal counsel, including counsel to the Company, or any other suitable agents, to consult with that counsel or those agents with respect to the construction of this Trust Agreement, the duties of the Trustee under it, the transactions contemplated by this Trust Agreement or any act the Trustee proposes to take or omit, to rely on the advice of such counsel or agents, and to pay its reasonable fees, expenses and compensation from the Trust, unless paid by the Company.
5.10. To register any securities held by it in its own name or in the name of any custodian of such property or of its nominee, including the nominee of any system for the central handling of securities, with or without the addition of words indicating that such securities are held in a fiduciary capacity, to deposit or arrange for the deposit of any such securities with such a system and to hold any securities in bearer form.
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5.11. On the direction of the Company, to enter into or assume any contract or policy with an insurance company or companies for the purpose of investment, insurance coverage or otherwise, to pay from the Trust Fund premiums, assessments, dues, charges and interest, if any, with respect to those contracts or policies, to exercise any and all of the rights, options or privileges (including, but not limited to, the right to borrow) under those contracts or policies, to otherwise take actions that may be available under those contracts or policies. However, the Trustee will be the sole owner of all those contracts held as assets of the Trust Fund. The Trustee will have no power to name a beneficiary of the policy other than the Trust, to assign the policy (as distinct from conversion of the policy to a different form) other than to a successor trustee, or to loan to any person the proceeds of any borrowing against that policy.
5.12. To make, execute and deliver, as the Trustee, any and all deeds, leases, notes, bonds, guarantees, mortgages, conveyances, contracts, waivers, releases or other instruments in writing necessary or proper for the accomplishment of any of the powers listed above.
5.13. Notwithstanding any powers granted to the Trustee pursuant to this Trust Agreement or to applicable law, the Trustee may not have any power that could give this Trust the objective of carrying on a business and dividing the gains from it, within the meaning of section 301.7701-2 of the Procedure and Administrative Regulations promulgated pursuant to the Code.
SECTION 6. Payments by the Trustee.
6.1. The Company will deliver to the Trustee at least annually a schedule (the Payment Schedule) that indicates the amounts payable in respect of each Member and Beneficiary, that provides a formula or other instructions acceptable to the Trustee for determining the amounts so payable, the form in which that amount is to be paid (as provided for or available under the Plan), and the time of commencement for payment of that amount. Except as otherwise provided in this Trust Agreement, the Trustee will make payments to the Members and Beneficiaries in accordance with the Payment Schedule. On and after a Change in Control,
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the Trustee will make provision for the reporting and withholding of any federal, state or local taxes that may be required to be withheld with respect to the payment of benefits pursuant to the terms of the Plan and will pay amounts withheld to the appropriate taxing authorities or determine that those amounts have been reported, withheld and paid by the Company. Prior to a Change in Control, the Company is responsible for that reporting, withholding and payment.
6.2. The entitlement of a Member or Beneficiary to benefits under the Plan will be determined by Company or a party it designates under the Plan, and any claim for those benefits will be considered and reviewed under the procedures set out in the Plan.
6.3. Prior to a Change in Control or, if earlier, until it notifies the Trustee otherwise, the Company will make payment of benefits directly to Members and Beneficiaries as they become due under the terms of the Plan. The Company will notify the Trustee of its decision to not make payment of benefits directly prior to the time amounts are payable to Members and Beneficiaries. In addition, if the principal of the Trust, and any earnings on it, are not sufficient to make payments of benefits in accordance with the terms of the Plan, the Company will make the balance of each such payment as it falls due. The Trustee will notify the Company when principal and earnings are not sufficient.
6.4. (a) On a Change in Control, the Trustee first must obtain from the Company a current Payment Schedule, and then determine if the Company has paid any of the amounts listed on it. To the extent the Company has not paid any amount due to be paid pursuant to the Payment Schedule, the Trustee will pay the amount specified or determined from the formulas and adjustments, in the then current Payment Schedule, subject to Sections 6.5 and 6.6, to each Member listed as a former employee of the Company or to the Beneficiary in a cash lump sum. The Trustee will file with the Company a written report of that payment within 15 days after making the payment. For all purposes of this Trust Agreement, a Beneficiary is the beneficiary of a deceased Member designated directly to the Trustee, or the beneficiary designated to the Company and reflected on the current Payment Schedule (and substantiated with a copy of the beneficiary designation held by the Company), if it is more recent, or, if there
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is none of either of those or the Trustee cannot reasonably determine the beneficiary designated in either manner, the legal representative of the deceased Members estate.
(b) At any time following a Change in Control, on termination of the Companys employment of a Member listed on the Payment Schedule, the amount specified or determined from the formulas and adjustments contained in the then current Payment Schedule, subject to Sections 6.5 and 6.6, will be paid by the Trustee to the Member or Beneficiary in a cash lump sum after the Trustee determines the extent to which the amount has not been paid by the Company. If the Company does not notify the Trustee of the Members termination of employment, the Member may deliver to the Trustee two duly executed and notarized Affidavits and Receipts in substantially the form attached as Exhibit A, and, in the case of a deceased Member, the Beneficiary may deliver two copies of the Members death certificate. The Trustee will file with the Company a written report of that payment, with one Affidavit and Receipt or one copy of the death certificate, if any, within 15 days after making the payment.
(c) If, at any time after a Change in Control the Trust finally is determined by the Internal Revenue Service (the IRS) not to be a grantor trust with the result that the income of the Trust Fund is not treated as income of the Company pursuant to Code §§ 671-679, or if a tax is finally determined by the IRS or by counsel to the Trustee to be payable by one or more Members in respect of any right, title or interest in any assets of the Trust Fund prior to termination of employment with the Company, then the amount specified or determined from the formulas and adjustments contained in the then current Payment Schedule, subject to Sections 6.5 and 6.6, will be paid by the Trustee in a cash lump sum as soon as practicable to each Member or Beneficiary, subject to reduction for amounts paid by the Company, regardless of whether that Members employment with the Company has terminated and without the necessity of presentation of an Affidavit and Receipt or death certificate.
6.5. If the Trustee holds life insurance contracts or policies on the life of any Member, the Member may elect, with the consent of the Company prior to a Change in Control and the consent of the Trustee on and after a Change in Control, under procedures adopted by the
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Trustee and subject to Section 6.6, to have those contracts or policies assigned to him or her and distributed to that Member in satisfaction of that portion of the cash lump sum payment to which the Member otherwise would be entitled under the preceding subsections that those contracts or policies represent. The determination of the fair market value of such a contract or policy will be made by the Trustee after consultation with an actuary.
6.6. On and after a Change in Control, any payment made to a Member or Beneficiary at any time under this Trust Agreement may not exceed the pro rata portion of the assets of the Trust Fund determined to be allocable to that payment, based on the then current Payment Schedule. The Trustee will determine the sufficiency of the Trust Fund at the time of any such payment. If the Trustee determines the Trust Fund is not sufficient to make all payments due at that time and in the future, the Member or Beneficiary, as the case may be, will receive a pro rata payment based on the amount to be paid to the Member or Beneficiary compared to the aggregate amount otherwise payable at that time and in the future to all Members and Beneficiaries. Any amount not paid because of this reduction will be considered as part of the payments to be made subsequently, subject to the same pro rata limitations. The Trustee must engage an actuary to determine the present value of amounts payable in the future and will use reasonable actuarial assumptions as determined by the Trustee, in consultation with the actuary.
SECTION 7. Third Parties.
7.1. A third party dealing with the Trustee is not required to make inquiry as to the authority of the Trustee to take any action nor under any obligation to follow the proper application by the Trustee of the proceeds of sale of any property sold by the Trustee or to inquire into the validity or propriety of any act of the Trustee.
SECTION 8. Taxes, Expenses and Compensation.
8.1. The Company from time to time will pay taxes of any kind lawfully levied or assessed on or payable in respect of the Trust Fund, the income or any property forming a part
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of it, or any security transaction pertaining to it. To the extent that any taxes lawfully levied or assessed on the Trust Fund are not paid by the Company, the Trustee will pay those taxes out of the Trust Fund. On and after a Change in Control, no taxes (other than applicable withholding taxes and charges pursuant to Section 6.1 and other taxes relating to the Trust Fund for which the Trustee has been assessed by the appropriate federal, state or local taxing authority) may be paid from the Trust Fund. The Trustee will contest the validity of those taxes in any manner deemed appropriate by the Company or its counsel, but at Company expense, or the Company itself may contest the validity of any of those taxes.
8.2. Any other reasonable expenses incurred by the Trustee in the performance of its duties under this Trust Agreement, including brokerage commissions, will be charged against and paid from the Trust Fund to the extent the Company does not pay those expenses.
8.3. The Company will pay the Trustee reasonable compensation for its services as may be agreed on in writing from time to time by the Company and the Trustee. That compensation will be charged against and paid from the Trust Fund to the extent the Company does not pay that compensation.
SECTION 9. Administration and Records.
9.1. The Trustee will keep or cause to be kept accurate and detailed accounts of any investments, receipts, disbursements and other transactions under this Trust Agreement, and all accounts, books and records relating to that will be open to inspection and audit at all reasonable times by any person designated by the Company and, on and after a Change in Control, by any Member. All those accounts, books and records will be preserved (in original form, or on microfilm, magnetic tape or any other similar process) for the period the Trustee determines, but the Trustee may destroy those accounts, books and records only after first notifying the Company and, on and after a Change in Control, all the Members in writing of its intention to do so and transferring to the Company, with, on and after a Change in Control, a copy to a representative of the Members, any of those accounts, books and records requested.
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9.2. Within 60 days after the close of each calendar year, and within 60 days after the removal or resignation of the Trustee or the termination of the Trust, the Trustee will file with the Company a written account setting forth all investments, receipts, disbursements and other transactions effected by it during the preceding calendar year or during the period from the close of the preceding calendar year to the date of its removal, resignation or termination, including a description of all investments and securities purchased and sold with the cost or net proceeds of those purchases or sales and showing all cash, securities and other property held at the end of that calendar year or other period. After 90 days from the date of filing that annual or other account, the Trustee will be forever released and discharged from all liability and accountability with respect to the propriety of its acts and transactions shown in that account, except with respect to any acts or transactions as to which the Company, or, on and after a Change in Control, a representative of the Members, within that 90-day period files with the Trustee written objections.
9.3. The Trustee from time to time must permit an independent public accountant selected by the Company (except one to which the Trustee has reasonable objection) to have access during ordinary business hours to records as may be necessary to audit the Trustees accounts.
9.4. As of the last day of each calendar year, the fair market value of the assets held in the Trust Fund will be determined. The Trustee will file with the Company, and, on and after a Change in Control, a representative of the Members, the written report of the determination of that fair market value.
9.5. Nothing contained in this Trust Agreement may be construed as depriving the Trustee or the Company of the right to have a judicial settlement of the Trustees accounts, and on any proceeding for a judicial settlement of the Trustees accounts or for instructions the only necessary parties to it in addition to the Trustee are the Company and, on and after a Change in Control, a representative of the Members.
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9.6. If the Trustee is removed or resigns, the Trustee will deliver to the successor trustee all records required by the successor trustee to enable it to carry out the provisions of this Trust Agreement.
9.7. In addition to any returns required of the Trustee by law, the Trustee must prepare and file tax reports and other returns as the Company and the Trustee from time to time agree.
9.8. The Members at any time may chose a representative to receive information, notices, make objections, and the like under this Section. The Trustee is not required to deal with more than one representative. If more than one representative purports to represent the Members, that person or entity representing the most Members will be considered by the Trustee to be the representative of the Members under this Section.
9.9. In any case in this Trust Agreement where the Trustee is protected, that protection is to the maximum extent of the law.
SECTION 10. Removal or Resignation of the Trustee and Designation of Successor Trustee.
10.1. At any time prior to a Change in Control, the Company may remove the Trustee with or without cause, on at least 60 days notice in writing to the Trustee. On and after a Change in Control, the Trustee may not be removed, except by order of a court having competent jurisdiction.
10.2. The Trustee may resign at any time upon at least 60 days notice in writing to the Company and, on and after a Change in Control, the Members.
10.3. If the Trustee is removed or resigns, the Trustee will duly file with the Company a written account as provided in Section 9.2 for the period since the last previous annual accounting, listing the investments of the Trust Fund and any uninvested cash balance of it, and setting forth all receipts, disbursements, distributions and other transactions respecting the
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Trust not included in any previous account, and if written objections to that account are not filed as provided in Section 9.2, the Trustee is forever released and discharged from all liability and accountability with respect to the propriety of its acts and transactions shown in that account.
10.4. Within 60 days after any notice of removal or resignation of the Trustee, the Company will designate a successor trustee qualified to act under this Trust Agreement. However, if a Trustee resigns on or after a Change in Control, then the successor Trustee qualified to act under this Trust Agreement may be only any bank, trust company or other financial institution that may serve as Trustee under applicable law acceptable to at least 50% of the members of the Board immediately prior to the Change in Control then living and readily available and willing to make that decision. If no designation has been made, the Trustee may apply to a court of competent jurisdiction for appointment of a successor or for instructions. All expenses of the Trustee in connection with the proceeding will be allowed as administrative expenses of the Trust. Each successor Trustee, during the period it acts as such, has the powers and duties conferred in this Agreement on an individual Trustee, and the word Trustee wherever used in this Agreement, except where the context otherwise requires, is deemed to include any successor Trustee. On designation of a successor Trustee and delivery to the resigned or removed Trustee of written acceptance by the successor Trustee of the designation, the resigned or removed Trustee promptly will assign, transfer, delivery and pay over to that successor Trustee, in conformity with the requirements of applicable law, the funds and properties in its control or possession then consisting the Trust Fund. The transfer will be completed within 30 days after receipt of notice of resignation, removal or transfer.
SECTION 11. Enforcement of Trust Agreement and Legal Proceedings.
11.1. The Company has the right to enforce any provision of this Trust Agreement, and, on or after a Change in Control, any Member has the right as a beneficiary of the Trust to enforce any provision of this Trust Agreement that affects the right, title and interest of that Member in the Trust. Except to the extent provided in Section 3.2 or as otherwise required by applicable law, in any actions or proceedings affecting the Trust, the only necessary
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parties are the Company, the Trustee, and, on or after a Change in Control, the Members and, except as otherwise required by applicable law, no other person is entitled to any notice or service of process. Any judgment entered in such an action or proceeding will be binding and conclusive on all persons having or claiming to have any interest in the Trust.
11.2. If the Trustee receives notification pursuant to Section 3.2 that the Company is Bankrupt or Insolvent, the Trustee promptly will give notice of that in writing to all Members and Beneficiaries listed on the then current Payment Schedule as soon as it is reasonably practicable.
SECTION 12. Change in Control Defined.
(a) A Change in Control will be deemed to have occurred if any of the following has occurred:
(i) either (a) the Company receives a report on Schedule 13D, or an amendment to such a report, filed with the Securities and Exchange Commission (SEC) pursuant to Section 13(d) of the Securities Exchange Act of 1934 (the 1934 Act) disclosing that any person (as that term is used in Section 13(d) of the 1934 Act) (Person), is the beneficial owner, directly or indirectly, of 20% or more of the outstanding stock of the Company or (b) the Company has actual knowledge of facts that would require any Person to file such a report on Schedule 13D, or to make an amendment to such a report, with the SEC (or would be required to file such a report or amendment upon the lapse of the applicable period of time specified in Section 13(d) of the 1934 Act) disclosing that such Person is the beneficial owner, directly or indirectly, of 20% or more of the outstanding stock of the Company;
(ii) purchase by any Person, other than the Company or a wholly-owned subsidiary of the Company or an employee benefit plan sponsored or maintained by the Company or a wholly-owned subsidiary of the Company, of shares pursuant to a tender or exchange offer to acquire any stock of the Company (or securities convertible into stock) for cash, securities or any other consideration provided that after consummation of the offer, that
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Person is the beneficial owner (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of 20% or more of the outstanding stock of the Company (calculated as provided in paragraph (d) of Rule 13d-3 under the 1934 Act in the case of rights to acquire stock);
(iii) approval by the shareholders of the Company of (a) any consolidation or merger of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of stock of the Company would be converted into cash, securities or other property, other than a consolidation or merger of the Company in which holders of its stock immediately prior to the consolidation or merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the consolidation or merger as immediately before, or (b) any consolidation or merger in which the Company is the continuing or surviving corporation but in which the common shareholders of the Company immediately prior to the consolidation or merger do not hold at least a majority of the outstanding common stock of the continuing or surviving corporation (except where such holders of common stock hold at least a majority of the common stock of the corporation which owns all of the common stock of the Company), or (c) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all the assets of the Company; or
(iv) a change in the majority of the members of the Board within a 24-month period unless the election or nomination for election by the Companys shareholders of each new director was approved by the vote of at least 2/3 of the directors then still in office who were in office at the beginning of the 24-month period.
12.2. No Change in Control may be deemed to have occurred for purposes of this Trust Agreement until the Trustee has actual knowledge from a reliable source, not including a Member acting in his or her individual capacity, of that Change in Control. A written notarized statement that a Change in Control has occurred, delivered to the Trustee and signed by at least 50% of the individuals then living who were members of the Board as of any date during the one-year period ending on the date that notice is received by the Trustee will be deemed to be
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actual knowledge from a reliable source, and a report filed with the Securities and Exchange Commission, a public statement issued by the Company, or a periodical of general circulation, including but not limited to The New York Times or The Wall Street Journal , is deemed to be a reliable source, regardless of the manner in which that report of a change in Control is made known to the Trustee.
SECTION 13. Termination.
13.1. The Company may terminate this Trust on 30 days written notice to the Trustee. On receipt by the Trustee of that notice of termination of the Trust and documentation of the approval of all Members, the Trustee, with reasonable promptness after receipt of any such notice, will arrange for the orderly distribution of the Trust property, or remaining amounts of it, in conformity with the provisions of applicable law.
13.2. Except as provided in Section 13.1, on and after a Change in Control, the Trust may not terminate until the date on which Members and Beneficiaries are no longer entitled to benefits pursuant to the terms of the Plan.
13.3. On termination of the Trust, any assets remaining in the Trust will be returned to Company.
SECTION 14. Amendments.
14.1. At any time prior to a Change in Control, the Company from time to time may amend or modify, in whole or in part, any or all of the provisions of this Trust Agreement that cannot adversely affect the interests of any Members and that do not conflict with the terms of the Plan. Any such amendment may be made only with notice to all Members, but need not have the consent of any Member.
14.2. Except as provided in Section 14.1, this Trust Agreement may not be amended by the Company or its successor, except as may be required by applicable law or with the consent of the Trustee and, on and after a Change in Control, all Members.
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14.3. The Company and the Trustee will execute supplements to, or amendments of, this Trust Agreement necessary to give effect to any amendment or modification.
SECTION 15. Non-alienation.
15.1. Benefits payable to Members and Beneficiaries under this Trust Agreement may not be anticipated, assigned (either at law or in equity), alienated, pledged, encumbered or subjected to attachment, garnishment, levy, execution or other legal or equitable process.
SECTION 16. Communications.
16.1. All communications of any kind under all provisions of this Trust Agreement, including instructions, elections, notifications, and directions, must be in writing and all communications to parties required under this Agreement must be in writing and (a) delivered in person, (b) mailed by registered or certified mail, return receipt requested, (any mailed notice to be effective four days after the date it is mailed) or (c) sent by facsimile transmission, with confirmation sent by way of one of the above methods, to the party at the address given below for that party (or to such other address as such party designates in a writing complying with this Section, delivered to the other party):
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If to the Company: | ||
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National Fuel Gas Company | |
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Prior to October 6, 2003: | |
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10 Lafayette Square | |
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Buffalo, New York 14203 | |
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After October 5, 2003: | |
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6363 Main Street | |
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Williamsville, New York 14221 | |
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Attention: General Counsel | |
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Telephone: (716) 857-7548 | |
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Fax: (716) 857-7195 | |
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with a copy to: | ||
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Hodgson Russ LLP | |
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One M&T Plaza, Suite 2000 | |
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Buffalo, New York 14203-2391 | |
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Attention: Dianne Bennett | |
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Telephone: (716) 848-1406 | |
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Fax: (716) 849-0349 |
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If to the Trustee: | ||
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HSBC Bank USA | |
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17 th Floor | |
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One HSBC Center | |
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Buffalo, New York 14203 | |
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Attention: Retirement Financial Services | |
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Telephone: (716) 841-2424 | |
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Fax: (716) 841-4244 |
16.2. All communications of any kind to a Member, Beneficiary or representative of Members must be in writing and delivered as in Section 16.1 and delivered to the address on the Payment Schedule, or a more updated address as specified by the Member, Beneficiary or representative pursuant to Section 16.1.
16.3. No communication is binding on any entity until received by that entity.
16.4. Any action of the Company pursuant to this Trust Agreement, including all orders, requests, directions, instructions, approvals and objections of the Company to the Trustee, must be in writing signed on behalf of the Company by any duly authorized officer of the company. The Trustee may rely on, and will be fully protected with respect to, any such action taken or omitted in reliance on, any information, order, request, direction, instruction, approval, objection list and Payment Schedule delivered to the Trustee by the Company or, to the extent applicable under this Trust Agreement, by a Member or the legal representatives of his or her estate.
SECTION 17. Miscellaneous Provisions.
17.1. This Trust Agreement is binding on and inures to the benefit of the Company and the Trustee and their respective successors and assigns.
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17.2. The Company will pay and protect, indemnify and save harmless the Trustee and its officers, employees and agents from and against any and all losses, liabilities (including liabilities for penalties), actions, suits, judgments, demands, damages, costs and expenses (including, without limitation, attorneys fees and expenses) of any nature arising from or relating to any action by or any failure to act by the Trustee, its officers, employees and agents or the transactions contemplated by this Trust Agreement, including, but not limited to, any claim made by a Member or his or her Beneficiary with respect to payments made or to be made by the Trustee, any claim made, whether before or after a Change in Control, by the Company or its successor, whether pursuant to a sale of assets, merger, consolidation, liquidation or otherwise, that this Trust Agreement is invalid or ultra vires , except to the extent that any such loss, liability, action, suit, judgment, demand, damage, cost or expense has been determined by final judgment of a court of competent jurisdiction to be the result of the gross negligence or willful misconduct of the Trustee, its officers employees or agents. To the extent the Company has not fulfilled its obligations under this Section, the Trustee will be reimbursed out of the assets of the Trust Fund or may set up reasonable reserves for the payment of those obligations. No personal liability will attach to or be incurred by any employee, officer or director of the Company, as such, under or by reason of the terms or conditions contained in or implied from this Trust Agreement.
17.3. The Trustee assumes no obligation or responsibility with respect to any action required by this Trust Agreement on the part of the Company.
17.4. Any corporation into which the Trustee may be merged or with which it may be consolidated, or any corporation resulting from any merger, reorganization or consolidation to which the Trustee may be a party, or any corporation to which all or substantially all the trust business of the Trustee may be transferred is the successor of the Trustee without the execution or filing of any instrument or the performance of any act.
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17.5. Any provision of this Trust Agreement prohibited by law is ineffective to the extent of any such prohibition, without invalidating the remaining provisions of this Trust Agreement.
17.6. Titles to the Sections of this Trust Agreement are included for convenience only and do not control the meaning or interpretation of any provision of this Trust Agreement.
17.7. To the maximum extent consistent with ERISA, this Trust Agreement and the Trust established under it will be governed by and construed, enforced and administered in accordance with the laws of the State of New York, and the Trustee will be liable to account only in the courts of that state.
17.8. This Trust Agreement may be executed in any number of counterparts, each of which will be deemed to be the original, although the others are not produced.
IN WITNESS WHEREOF, this Trust Agreement has been duly executed by the parties to it as of the day and year first above written.
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NATIONAL FUEL GAS COMPANY | |||
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By: /s/ Philip C. Ackerman | |||
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Name: Philip C. Ackerman | |||
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Title: Chairman, President, CEO |
Attest:
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/s/ Anna Marie Cellino
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Secretary
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HSBC BANK USA, AS TRUSTEE | |||
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By: /s/ Paul L. Morris | |||
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Name: Paul L. Morris | |||
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Title: Vice President |
Attest:
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/s/ Paul L. Morris
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/s/ James S. Buccella
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First Vice President
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STATE OF NEW YORK
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COUNTY OF ERIE
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On the 27th day of August , 2003, before me personally came Philip C. Ackerman to me known, who, being by me duly sworn, did depose and say that he /she resides in Erie County, New York , and that he /she is the Chairman/President/CEO of National Fuel Gas Company, one of the corporations described in and which executed the foregoing instrument; and that he/she signed his/her name thereto by order of the Board of Directors of said corporation.
PAULA M. CIPRICH
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/s/ Paula M. Ciprich | |||
Notary
Public, State of New York
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Qualified
in Erie County
My Commission Expires May 19, 2006 |
Notary Public |
STATE OF
New York
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COUNTY OF
Erie
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On the 27th day of August , 2003, before me personally came Paul L. Morris to be known, who, being by me duly sworn, did depose and say that he /she resides in Hamburg, New York ; that he /she is the Vice President of HSBC Bank USA, one of the corporation described in and which executed the foregoing instrument; and that he/she signed his/her name thereto by order of the Board of Directors of said corporation.
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/s/ Cynthia M. Wylegala | |||
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Notary Public |
CYNTHIA
M. WYLEGALA
Notary Public, State of New York Qualified in Erie County My Commission Expires July 23, 2006 |
- 27 -
EXHIBIT A
AFFIDAVIT AND RECEIPT
I, , under penalties of perjury, do hereby solemnly state:
That I make this Affidavit in order to induce the Trustee of the National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan Trust to pay me $ pursuant to its terms; and
That my employment with the National Fuel Gas Company or any of its subsidiaries was terminated on .
STATE OF
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COUNTY OF
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On the day of , 200 , before me personally came to me known, who, being by me duly sworn, did depose and say that he/she resides at , and that the statements herein are all materially correct.
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Notary Public |
Exhibit 10.3
Administrative Rules
of the
Compensation Committee
of the
Board of Directors
of
National Fuel Gas Company
As amended and restated
effective September 9, 2004
TABLE OF CONTENTS
I. Meetings
|
1 | |||
II. Quorum and Voting; Delegation
|
1 | |||
III. Grants and Awards Under the Plans
|
2 | |||
A. General Rules Regarding Awards Under
the 1997 and 1993 Plans
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3 | |||
1. Making of An Award
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3 | |||
2. Contemporaneous Awards
|
3 | |||
3. Stock-Based Awards
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3 | |||
a. Source
|
3 | |||
b. Cash Dividends and Cash Dividend Equivalents
|
3 | |||
i. Stock Based Awards Other
Than Restricted Stock
|
3 | |||
ii.Restricted Stock Awards
|
4 | |||
c. Payment
|
4 | |||
4. Withholding Taxes
|
4 | |||
5. Deferral of Payment
|
5 | |||
B. Stock Options Under the 1997 and 1993 Plans
|
5 | |||
1. Designation
|
5 | |||
2. Price
|
6 | |||
3. Exercise Period/Duration
|
6 | |||
a. Non-Qualified Stock Options Under
the 1997 and 1993 Plans
|
6 | |||
b. Incentive
Stock Options Under the 1997 and 1993 Plans
|
6 | |||
4. Death or Other Termination of Employment
|
6 | |||
a. Definitions
|
6 | |||
b. Non-Qualified Stock Options Under
the 1997 and 1993 Plans
|
7 | |||
c. Incentive Stock Options Under the
1997 and 1993 Plans
|
7 | |||
d. Extension of Incentive Stock Options Under the
1997 and 1993 Plans
|
8 | |||
5. Mechanics of Exercise
|
10 | |||
6. Reload Options
|
10 | |||
C. SARs Under the 1997 Plan
|
10 | |||
D. Restricted Stock Under the 1997 and 1993 Plans
|
11 |
2
1. Restrictions on Transferability; Vesting
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11 | |||
2. Mechanics of Grant
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11 | |||
E.
Performance Units and Performance Shares Under The 1997 Plan
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11 | |||
IV. Procedures For Exercising Stock Options
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12 | |||
A. Authority and Scope
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12 | |||
B. Notice of Exercise
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12 | |||
1. Form and Delivery
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12 | |||
2. Exercise Date
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13 | |||
C. Payment of Exercise Price
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13 | |||
1. Cash Payment
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13 | |||
2. Payment with Existing Company Stock
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14 | |||
3. Additional Time to Pay Exercise Price
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14 | |||
4. Cashless Exercise
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15 |
3
ADMINISTRATIVE
RULES OF THE
COMPENSATION COMMITTEE
OF THE
BOARD OF DIRECTORS
OF
NATIONAL FUEL GAS COMPANY
As amended and restated
effective September 9, 2004
I. MEETINGS
Each meeting (Meeting) of the Compensation Committee (Committee) of the Board of Directors of National Fuel Gas Company (Company) shall be held as indicated in a notice made in accordance with these rules. Notice of each Meeting, stating the place, date and hour thereof, shall be given to each member of the Committee (Member) by mailing written notice not less than five days before the Meeting to each Member, or by telegraphing, telephoning or delivering oral or written notice to each Member personally not less than one day before the Meeting.
Any one or more Members of the Committee may participate in a Meeting by means of a conference telephone or similar equipment. Participation by such means shall constitute presence in person at a Meeting.
The Committee may also take action by unanimous written consent.
II. QUORUM AND VOTING; DELEGATION
At all Meetings, a quorum shall be required for the transaction of business and shall consist of a majority of the entire Committee. The majority vote of the Members at a Meeting at which a quorum is present shall decide any question that may come before the meeting.
Consistently with limitations imposed by the Plans, the Committee may delegate in these rules or by resolution any or all of its authority to the Chief Executive Officer, to the Secretary and to any other officer of the Company (individually, Delegate), so long as the Delegate has no potential conflict of interest which would cause him or her not to exercise his or her good faith independent
business judgment in respect of a delegated matter, and so long as such delegation would not result in the requirement under applicable law that the Delegates name appear beneath the Committees report required to be included in Company filings with the Securities and Exchange Commission. Subject to such limitations, the Committee hereby delegates the power to implement its decisions to appropriate officers of the Company.
III. GRANTS AND AWARDS UNDER THE PLANS
The following rules and regulations shall apply with respect to grants and awards of stock options, stock appreciation rights (SARs) and shares of restricted stock (Restricted Stock) under the Companys 1997 Award and Option Plan (1997 Plan) and 1993 Award and Option Plan (1993 Plan) (together, the Plans). These rules also address other Awards under the Plans.
Any capitalized term not defined in these rules shall have the same meaning as in the applicable Plan. The following rules are intended to supplement the Plans and, to the extent that any rule is determined to be inconsistent with any Plan, the Plan shall control.
These rules may be amended by the Committee at any time and from time to time. Except to the extent otherwise specified in the particular Award Notice or at the time these rules are amended, any grant or award under the Plans shall be subject to these rules as in effect on the date of the grant or award.
2
A. GENERAL RULES REGARDING AWARDS UNDER THE 1997 AND 1993 PLANS
1. Making of An Award
An Award within the meaning of these rules occurs upon the grant by the Committee of any stock option, SAR, Restricted Stock, performance unit, performance share or other incentive award. An Award Notice within the meaning of these rules means a written notice from the Company to a Participant that sets forth the terms and conditions of an Award in addition to those established in the applicable Plan and by the Committees exercise of its administrative powers.
2. Contemporaneous Awards
An Award of one type granted contemporaneously with an Award of any other type shall be treated as having been granted in combination, and not in the alternative, with the Award of the other type.
3. Stock-based Awards
a. Source. Stock-based Awards, to the extent actually paid in Common Stock, shall reduce treasury shares first and thereafter authorized but unissued shares.
b. Cash Dividends and Cash Dividend Equivalents.
(i) Stock-Based Awards Other Than Restricted Stock. No stock-based Award carries with it the entitlement to receive cash dividends or cash dividend equivalents until such stock-based Award is exercised (in the case of a stock option) or earned. If a stock-based Award is exercised or earned prior to or on the record date for determination of stockholders entitled to receive a cash dividend, then such stock-based Award or the securities resulting from the exercise thereof, as the case may be, shall be entitled to receive such cash dividend.
(ii) Restricted Stock Awards. Notwithstanding clause (i) of this paragraph (b) or §26 of the 1993 Plan or the 1997 Plan, dividends shall be payable with respect to each
3
outstanding Award of Restricted Stock whether or not the restrictions in such Award have been satisfied or have lapsed.
c. Payment. Payment of stock-based Awards (other than SARs and performance shares, which shall be paid in cash) shall be made with Common Stock.
4. Withholding Taxes
At the time a Participant is taxable with respect to Options, SARs or Restricted Stock granted under the Plans, or the exercise or surrender of the same, the Company shall have the right to withhold from amounts payable to the Participant under the Plan or from other compensation payable to the Participant in its sole discretion, or require the Participant to pay to it, an amount sufficient to satisfy all federal, state and/or local withholding tax requirements. A Participant may pay, in whole or in part, such tax withholding amounts by requesting that the Company withhold such amounts of taxes from the amounts owed to the Participant or by delivering as payment to the Company, shares of Common Stock having a Fair Market Value less than or equal to the amount of such required withholding taxes (with the remainder payable in cash).
4
5. Deferral of Payment
The Committee intends to permit Participants to elect, at any time prior to one year before the date of exercise, to defer the receipt of payment of Awards that are payable in cash; provided, however, that (1) under the then applicable income tax rules the Participant is not in constructive receipt of, and subject to income tax on, the payment prior to its actual receipt, (2) such deferral does not result in any of the Plans being subject to the Employee Retirement Income Security Act of 1974, as amended, and (3) if the Participant is an Executive Officer ( i.e. , is subject to Section 16 of the Securities Exchange Act of 1934, including a retired officer who is, at the relevant time, a director), such election shall comply with Rule 16b-3 promulgated pursuant to the Securities Exchange Act of 1934, as then in effect.
B. STOCK OPTIONS UNDER THE 1997 AND 1993 PLANS
1. Designation
The Award Notice setting forth the terms and conditions of a grant of a stock option shall indicate the applicable Plan under which the stock option is granted and whether the stock option is an incentive stock option (within the meaning of Section 422 of the Code, an ISO) or a non-qualified stock option (NSO). The Committee hereby delegates to the President and Chief Executive Officer of the Company the authority to prepare, execute and deliver Award Notices consistent with actions taken by the Committee. The Committee hereby directs that any action taken by the Committee granting stock options without specifying whether the stock options are ISOs be interpreted as follows:
a. an award of stock options to a Participant who is younger than 60 on the grant date shall be deemed to be an award of ISOs to the maximum extent permitted in accordance with Section 422 of the Internal Revenue Code, with the remainder awarded as NSOs; and
5
b. an award of stock options to a Participant who is 60 or older on the grant date shall be deemed to be awards of NSOs only.
2. Price
The price at which Common Stock may be purchased upon exercise of a stock option (the exercise price) shall be the Fair Market Value of the Common Stock on the date of the Award.
3. Exercise Period/Duration
a. Non-Qualified Stock Options Under the 1997 and 1993 Plans. A non-qualified stock option granted under the 1997 Plan or the 1993 Plan first may be exercised twelve months after the date of grant, or, if earlier, on the date of the optionees death.
b. Incentive Stock Options Under the 1997 and 1993 Plans. An incentive stock option granted under the 1997 Plan or the 1993 Plan first may be exercised twelve months after the date of grant, or, if earlier, on the date of the optionees death.
4. Death or Other Termination of Employment
a. Definitions. For purposes of these rules, the following terms shall have the following meanings:
(i) Disability shall mean that the Participant is eligible to receive disability benefits under Article 3 of The National Fuel Gas Company Retirement Plan (Retirement Plan), as from time to time amended.
(ii) Principal Subsidiary shall mean a Subsidiary that has a net income of at least $5,000,000 as of the end of the most recent fiscal year.
(iii) Retirement shall mean that the Participant has commenced receiving retirement benefits under the Retirement Plan at or after attaining age 65.
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(iv) Subsidiary shall mean a corporation or other business entity in which the Company directly or indirectly has an ownership interest of eighty percent (80%) or more.
b. Non-Qualified Stock Options Under the 1997 and 1993 Plans. With respect to the President and Chief Executive Officer of the Company and the Presidents of each Principal Subsidiary, if termination of employment occurs by reason of death, Disability or Retirement, each non-qualified option awarded under the 1997 Plan or the 1993 Plan shall remain exercisable for the balance of its unexpired term. If termination occurs by reason of discharge by the Company for cause or voluntary resignation of the Participant prior to age 60, each such non-qualified option shall lapse unless extended by the Committee in its discretion. If termination of any such officer occurs for any other reason, each such non-qualified option shall remain exercisable for five years from such termination (or in the case of non-qualified options awarded under the 1997 Plan, such greater period as the Committee deems appropriate) or the balance of its unexpired term, whichever is less.
For all other Participants, if termination of employment occurs by reason of death, Disability or retirement at or after age 60, each non-qualified option awarded under the 1997 Plan or the 1993 Plan shall remain exercisable for five years from such termination or the balance of its unexpired term, whichever is less. If termination occurs for any other reason, each such non-qualified option shall lapse unless extended by the Committee in its discretion.
c. Incentive Stock Options Under the 1997 and 1993 Plans. Pursuant to §16(a) of the 1997 Plan and the 1993 Plan, the Committee hereby establishes that, with respect to an incentive stock option granted under the 1997 Plan or the 1993 Plan which has not theretofore expired, upon termination of employment by reason of the optionees Disability, the optionee may within one year after the date of termination of employment, exercise all or part of the incentive stock option which the optionee was entitled to exercise on the date of termination of employment.
7
d. Extension of Incentive Stock Options Under the 1997 and 1993 Plans.
Pursuant to the last paragraph of §16(b) of the 1997 Plan and the 1993 Plan, the Committee hereby determines that:
(i) With respect to the President and Chief Executive Officer of the Company and the Presidents of each Principal Subsidiary, if termination of employment occurs by reason of death, Disability or Retirement, another officer of the Company shall, within thirty days of such termination, offer in writing to extend the period during which any incentive stock option granted to such optionee under the 1997 Plan or the 1993 Plan may be exercised to the date on which the incentive stock option would have otherwise expired absent such termination of employment.
If termination of any such officers employment occurs for any other reason, another officer of the Company, if the Committee so authorizes, shall, within thirty days of such termination, offer in writing to extend the period during which any incentive stock option granted to such optionee may be exercised to the date specified in the offer, which shall not be later than the date on which the incentive stock option would have otherwise expired absent such termination of employment;
(ii) With respect to all Participants other than the President and Chief Executive Officer of the Company and the Presidents of each Principal Subsidiary, if termination of employment occurs by reason of death, Disability or Retirement, an officer of the Company other than such Participant shall, within thirty days of such termination, offer in writing to extend the period during which any incentive stock option granted to such optionee under the 1997 Plan or the 1993 Plan may be exercised,
8
to the date which is the earlier of five years from such termination or the balance of the unexpired term of such incentive stock option.
If termination of such Participants employment occurs for any other reason, an officer of the Company other than such Participant, if the Committee so authorizes, shall, within thirty days of such termination, offer to extend the period during which any incentive stock option granted to such optionee may be exercised to the date specified in the offer, which shall not be later than the earlier of five years from such termination of employment or the date on which the incentive stock option would have otherwise expired absent such termination of employment.
The written offer shall notify the optionee, or the optionees estate or the person to whom the optionees rights under the incentive stock option are transferred by will or the laws of descent and distribution, of the right to accept the offer by consenting to the extension, in writing, within thirty days of the offer. If such consent is timely received the incentive stock option may be exercised during the period specified in the offer, but not later than the expiration of the exercise period specified in the Award Notice.
5. | Mechanics of Exercise |
To exercise a stock option, the Participant shall provide a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which options are being exercised, how the exercise price is to be paid and any other appropriate information. Appropriate delivery of a signed notice of exercise binds the Participant to pay the exercise price. Part IV of these Rules contains procedures for exercising stock options.
6. | Reload Options |
No optionee shall be issued a new stock option automatically upon exercise of a stock option. However, if the Award Notice provides for the issuance of such new stock option, the
9
new stock option shall have an option price equal to the Fair Market Value of the Common Stock on the date the new stock option is issued and shall otherwise be subject, as nearly as possible, to the same terms and conditions as the exercised stock option.
C. | SARs UNDER THE 1997 PLAN |
All outstanding SARs granted under the 1997 Plan are Independent SARs as described in the Plan. The Plan has been amended to eliminate future awards of SARs.
The base price of an Independent SAR shall be the Fair Market Value of the Common Stock on the date of the grant of the Independent SAR, and shall otherwise be subject to the terms and conditions imposed by the Award Notice upon the Independent SAR, by the 1997 Plan, and by these Rules upon non-qualified stock options. An Independent SAR shall be outstanding and exercisable during the entire exercise period otherwise applicable to a non-qualified stock option granted on the same day as the Independent SAR (as adjusted in accordance with paragraph III.B.4 above in the event of death or other termination of employment).
To exercise a SAR, the Participant shall deliver a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which SARs are being exercised, and any other appropriate information. The Committee hereby delegates to appropriate officers of the Company the authority to establish and revise appropriate procedures with respect to the exercise of SARs.
D . RESTRICTED STOCK UNDER THE 1997 AND 1993 PLANS |
1. | Restrictions on Transferability; Vesting |
The restrictions on transferability and vesting and all other terms and conditions of Restricted Stock granted under the 1997 and 1993 Plans shall be specified in the Award Notice. All shares of Restricted Stock shall be subject to the Participants continued employment with the
10
Company or a Subsidiary until vesting. The Committee may accelerate the vesting of Restricted Stock on its own motion as it deems appropriate and in the best interests of the Company.
2. | Mechanics of Grant |
The Committee hereby delegates to appropriate officers of the Company the authority to establish and revise appropriate procedures with respect to the issuance of certificates representing Restricted Stock and the payment of dividends thereon.
E. | PERFORMANCE UNITS AND PERFORMANCE SHARES UNDER THE 1997 PLAN |
The performance period and performance objectives of a performance unit or performance share granted under the 1997 Plan shall be specified in the Award Notice.
The Committee shall consider any written submission from a Participant, regarding revision of the performance period and/or performance objectives of an Award on the basis of events which may have been unforeseen by the Committee, or circumstances which have changed since the Award, and may consider such matters on its own motion. Upon such consideration, the Committee shall revise such performance period and/or performance objectives when such revision is determined to be in the best interests of the Company and consistent with the purposes of the 1997 Plan or the 1993 Plan.
IV. PROCEDURES FOR EXERCISING STOCK OPTIONS
A. | AUTHORITY AND SCOPE |
Notwithstanding any provision of any award letter issued before 1998, these are the exercise procedures for Incentive Stock Options (ISOs) and Non-Qualified Stock Options (NSOs) issued under the 1993 Plan, the 1997 Plan, and (unless the Compensation Committee specifically orders otherwise) any other compensation plan which in the future is adopted by the Company.
B. | NOTICE OF EXERCISE |
1. | Form and Delivery |
11
A Participant holding options granted under any of the Plans elects to exercise options by delivering (by personal delivery or fax) to the office of the Companys Secretary or Assistant Secretary a Notice of Exercise. A Notice of Exercise is a writing signed by the Participant indicating that the Participant thereby elects to exercise options identified in the Notice (including the quantity and exercise price), and describing the method by which the Participant will pay the exercise price. Appropriate delivery of a Notice of Exercise binds the Participant to pay the exercise price. An optional form of Notice of Exercise is attached to these Rules (see Exhibit A).
2. | Exercise Date |
The effective date of a Notice of Exercise is the Exercise Date. An exercise will be effective as of the date the Notice of Exercise is received by the office of the Secretary or Assistant Secretary; provided, however , that:
(i) a Notice of Exercise received on a business day before trading opens that day on the New York Stock Exchange may validly designate the Exercise Date to be the preceding business day; and
(ii) a Notice of Exercise may validly designate the Exercise Date to be any date later than the date the Notice of Exercise is received.
(iii) if the exercise is accomplished through a cashless exercise as described in Section IV (C)(4) below, the Exercise Date shall be the date the broker sells Company stock into the market regarding that exercise.
C. | Payment of Exercise Price |
1. | Cash Payment |
To pay the exercise price in cash, a Participant must deliver to the Secretary or Assistant Secretary payment in full, in cash or by check payable in immediately available U.S. funds to the Company, within three business days after the Exercise Date (except as additional time may be
12
allowed under Section IV (C)(3) below). Payment of the exercise price may be partly in cash and partly in Company stock as described in Section IV (C)(2) below, or may be accomplished through a cashless exercise as described in Section IV (C)(4) below.
2. | Payment with Existing Company Stock |
To pay the exercise price in shares of Company stock already owned by a Participant, the Participant must surrender to the Company shares having a total Market Value (as of the Exercise Date) of at least the total exercise price, or pay any shortfall in cash. The Participant must, within three business days after the Exercise Date (except as additional time may be allowed under Section IV (C)(3) below) do one or both of the following:
a. regarding shares in the Companys Direct Registration System, comply with the Companys procedures (including signature guarantee requirements) for transferring book-entry shares to the Company; or
b. regarding shares that are evidenced by a paper stock certificate, deliver the certificate to the Secretary or Assistant Secretary. Each certificate delivered must have a guaranteed signature either on the back or on a stock power to be attached. Recommended procedure for mailing certificates is to mail the certificate and signed stock power separately.
3. | Additional Time to Pay Exercise Price |
If, at any time the Participants payment of the exercise price would otherwise be required pursuant to Section IV (C)(1) or (2) above, a Participant is either
a. traveling away from his or her usual place of Company employment, or
b. disabled, as defined in the applicable Plan or these Administrative Rules,
13
then the Participant may pay the exercise price on or before the first business day after the Participants return to his or her usual place of NFG employment, but no later than the tenth business day after the Exercise Date. However, the President, Chief Executive Officer, or Treasurer of the Company shall have the authority to grant such additional time to pay the exercise price as is reasonably necessary to accommodate the travel or disability of the Participant.
4. | Cashless Exercise |
The broker-assisted method of exercising options described in this Section IV (C)(4) (cashless exercise) requires no cash outlay by the Participant. A Participant wishing to do a cashless exercise must first establish a trading account with a registered securities broker-dealer. Establishing that trading account will likely include the Participants commitment to pay the broker as described in their agreement. Upon request by a Participant, the Secretary or Assistant Secretary will provide information that may help the Participant find a broker who has previously done cashless exercises with the Company and/or may be willing to do so at a discounted commission rate. The Participant must provide the Secretary or Assistant Secretary with the Participants brokers name, firm, address, telephone and fax numbers.
To do a cashless exercise, the Participant must deliver a Notice of Exercise as described in Section IV (B)(1), and notify the Participants broker to proceed with the exercise. The Participants broker will sell Company stock for the Participants account and pay to the Company the exercise price, plus any necessary tax withholding. The Company will have share certificates delivered to the Participants broker within three business days after the Exercise Date, unless the Company elects to retain the certificates pending receipt of the exercise price. The Participant will be required to pay the Participants broker according to the agreement between them, typically a few days interest on the exercise price plus a commission on the shares sold.
14
Exhibit 10.4
RETIREMENT AND CONSULTING AGREEMENT
This Retirement and Consulting Agreement (Agreement) is entered into by and between Bernard J. Kennedy, an individual residing at 33 Ruskin Road, Amherst, New York, 14226, (hereinafter Kennedy) and National Fuel Gas Company (National Fuel), a New Jersey corporation, on September 5, 2001. For purposes of this Agreement, as appropriate, the term National Fuel refers, collectively, to National Fuel Gas Company and its subsidiaries and other affiliates.
RECITALS
WHEREAS, Kennedy is employed by National Fuel pursuant to an employment agreement dated September 17, 1981, as amended, and currently extended to September 1, 2002 (the Employment Agreement), which affords him the minimum base salary hereinafter set forth, and (during as well as after the term thereof) participation in all National Fuel benefits, plans and programs (including improvements therein) on at least a par with other executive officers of National Fuel;
WHEREAS, Kennedy has agreed to waive his rights to any automatic extension of the term of the Employment Agreement and to certain payments and benefits to which he otherwise would be entitled under the Employment Agreement during the usual automatic extension thereof and following termination of employment;
WHEREAS, National Fuel wishes to secure for itself the availability of Kennedy so that it might benefit from Kennedys experience, knowledge, talents, reputation and prominence in the energy industry, and desires that Kennedy continue to advise National Fuel on issues relating to expansions, mergers, acquisitions, dispositions and other important matters;
WHEREAS, Kennedy has agreed to cooperate with National Fuel in connection with National Fuels request on the timing of payments under the Executive Retirement Plan, and, in connection therewith, Kennedy has agreed to certain adjustments in Pension Benefit Guarantee Corporation rates, and to certain other assumptions and interest rates;
WHEREAS, Kennedys employment at the request of National Fuel with National Fuel after age 65 has reduced the value of benefits he accrued through that date under National Fuels pension plans;
WHEREAS, in lieu of seeking other opportunities, Kennedy has agree to remain available and to continue to provide services to National Fuel, to serve as a bridge in the event his successor should become incapacitated, and not to compete with National Fuel after the termination of his employment;
WHEREAS, Kennedy recognizes that National Fuels business and goodwill are dependent upon National Fuels trade secrets and confidential and proprietary information and that National Fuel will sustain great loss and damage if Kennedy discloses, utilizes or causes to be disclosed or utilized National Fuels trade secrets and/or confidential and proprietary information to third parties or for Kennedys own benefit, and Kennedy has agreed that he will not disclose, utilize or cause to be disclosed or utilized any such trade secrets and/or confidential and proprietary information;
WHEREAS, Kennedy is not otherwise entitled to the total sums being paid under this Agreement, except as provided herein;
NOW, THEREFORE, in consideration of the mutual promises, terms, covenants and conditions described above and set forth below, the parties to this Agreement agree as follows:
1. Effective Date of Agreement . This Agreement shall become effective as of the date first above written.
2. Employment .
(a) | Kennedy shall, and Kennedy agrees to, relinquish his current position of chief executive officer of National Fuel effective October 1, 2001; provided, however, National Fuel requests that Kennedy commit to continue to serve on the Board of Directors of National Fuel (the Board) after October 1, 2001. Kennedy agrees to resign as a member of the Board following the first annual meeting of stockholders following his 72nd birthday consistent with the director tenure policy to be proposed by Kennedy to the Board at its scheduled September 13, 2001 meeting. | |||
(b) | Kennedy shall remain an employee of National Fuel and Chairman of the Board through January 2, 2002 at which time Kennedy will terminate his employment with National Fuel and relinquish his position as Chairman of the Board. | |||
(c) | Kennedy shall (i) receive his regular monthly base salary of $70,679.16, payable by National Fuel and its affiliated corporations in accordance with their customary practices through January 2, 2002; (ii) remain a participant in National Fuels Annual At Risk Compensation Incentive Program (the AARCIP) through September 30, 2001, and be paid, in a manner consistent with past practice, during calendar 2001 and as soon as practicable following the award thereof, a bonus for fiscal 2001 as shall be determined by the Boards Compensation Committee; and (iii) for the months of October, November and December 2001 be paid (in lieu of all other bonuses otherwise available to him under the Employment Agreement or otherwise) a monthly bonus of $149,320.84. | |||
(d) | Upon termination of Kennedys employment on January 2, 2002, Kennedy shall, in addition to the payments and benefits provided herein (including, but not by way of limitation, the benefits provided pursuant to section 4(c)), be |
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eligible for and entitled to (i) retiree medical benefit coverage, subject to the terms and conditions of the respective benefit plan(s) and/or program(s); (ii) life insurance benefits pursuant to, and as limited by, the Amended and Restated Split Dollar Insurance Agreement dated August 28, 1991, as last amended effective as of June 15, 2000 (Life Insurance Agreement); (iii) retirement benefits pursuant to the National Fuel Gas Company Retirement Plan; (iv) annuity payments pursuant to National Fuel Gas Company Deferred Compensation Plan (the DCP) Cycles I, II-A, III and III-A; (v) a Distribution of Savings Account pursuant to DCP Cycle V; (vi) Tophat benefits pursuant to the National Fuel Gas Company Top Hat Plan; and (vii) unexercised stock options and SARs granted under the National Fuel Gas Company 1997 Award and Option Plan and the predecessors thereof. |
(e) | Except insofar as is necessary to accommodate the express provision of Section 2(a), 2(b) and 2(c) of this Agreement, the Employment Agreement shall remain in full force and effect through January 2, 2002, at which time it shall terminate, provided however such termination shall not limit or impact Kennedys receipt of the benefits and entitlements identified in clauses (i) through (vii) of Section 2(d) of this Agreement which benefits for purposes of Section 4 of the Pension Settlement Agreement shall be deemed to be payable to Kennedy pursuant to the terms of this Agreement. |
3. Consulting Services .
(a) | From January 2, 2002 until June 30, 2004 (the Consulting Period), Kennedy shall, subject to the terms and conditions hereof, make himself available to render consultation services as requested by the Chief Executive Officer of National Fuel, for which he shall receive a non-refundable monthly retainer of $20,833.33 payable on or before January 2, 2002, and on the 1st day of each succeeding month during the Consulting Period. The retainer specified in this section 3(a) shall entitle National Fuel to Kennedys consultation services for up to 48 days during any 16 month period in the Consulting Period. In the event Kennedy performs consulting services for National Fuel for more than 48 days during any 16 month period in the Consulting Period or for more than 4 days during any calendar month during such period, National Fuel shall, upon receipt of an appropriate invoice, compensate Kennedy for such additional days at the rate of $3,500 per day. For purposes of this section 3(a), a day of consulting services shall mean any calendar day or part thereof during which Kennedy renders consulting services (including any days during which Kennedy is required to travel on consultation related business). | |||
(b) | As needed during the Consulting Period at the request of the chief executive officer of National Fuel from time to time (and subject to the limitations provided in section 3(a) above), Kennedy shall advise and assist National Fuel concerning mergers and acquisitions, regulatory matters, marketing and customer relations, business strategy and such other matters as may arise that |
3
the Chief Executive Officer of National Fuel determines, from time to time, require Kennedys experience and knowledge. In addition, Kennedy shall represent National Fuel with trade or business associations as selected by the chief executive officer of National Fuel from time to time. Service for or in connection with AEGIS, shall not be considered consultation service for National Fuel for purposes of this Agreement. |
(c) | During the Consulting Period, Kennedy shall be an independent contractor and, as such, shall control the detail, manner and means of providing consulting services pursuant to this Agreement. Accordingly, Kennedy shall not be required to work any particular schedule, but shall use his best efforts to meet National Fuels deadlines. Further, Kennedy shall not, within reason, be required to work at any particular location; however, during the Consulting Period, National Fuel shall provide reasonable and sufficient executive office space and executive secretarial assistance, telephone, fax service, computer, other customary office equipment and support, together with a garage space and related support when Kennedys presence is required at National Fuel offices. Subject to the approval of the chief executive officer of National Fuel or his or her designee, and upon receipt of proper documentation, National Fuel shall reimburse Kennedy for any reasonable expenses incurred in connection with the performance of consulting services under this Agreement. Kennedy shall be entitled to utilize first class commercial air travel, the company plane or jet service, or comparable facility. |
(d) | During the Consulting Period, National Fuel shall provide such other support and facilities as the chief executive officer of National Fuel shall decide facilitates Kennedys business and industry related exposure and contacts that Kennedy has cultivated, and will cultivate, for National Fuel. |
(e) | In view of the success the Company has enjoyed under his leadership and the record performance it has achieved in recent years, Kennedy shall, if requested by the Board during the three years following his retirement, serve on any committee of the Board established to review any transaction which, if consummated, would constitute a Change in Control under the National Fuel Gas Company 1997 Award and Option Plan. Such service shall not reduce, or be considered a part of, the consultation obligation of Section 3(a) or entitle Kennedy to any compensation pursuant to Section 3(a). Upon the occurrence of any such Change in Control transaction prior to January 1, 2005 (or thereafter, if the transaction was publicly announced prior to January 1, 2005), in recognition of the success of Kennedys efforts in bringing the Company to its current position and taking into account the additional value shareholders receive through consummation of such Change in Control transaction, the Compensation Committee shall consider and recommend to the Board, and the Board shall make, an award of National Fuel common |
4
stock to Kennedy in such amount(s), as the Compensation Committee and the Board, respectively, shall equitably determine in the exercise of their discretion. |
4. | Retirement . In addition to the compensation and benefits provided pursuant to sections 2 and 3 of this Agreement and the compensation and benefits to which Kennedy is entitled under the terms of National Fuels compensation and benefit plans and policies for directors, Kennedy shall be entitled to the following compensation and benefits, except as otherwise provided in Section 4(d), upon termination of his employment by National Fuel: |
(a) | Kennedy shall receive such support and benefits provided to a retired chief executive officer and chairman of the Board, commensurate with National Fuels past practice; as outlined to Kennedy in a letter of even date herewith from the Chairman of the Boards Compensation Committee (the Letter) and any other support or benefits as may be approved by National Fuels chief executive officer; |
(b) | All of Kennedys stock options and SARs, whether granted before or after the effective date of this Agreement, shall remain exercisable for their remaining terms (disregarding, for purposes of determining the terms of such options and SARs, the termination of Kennedys employment); |
(c) | To the extent not provided under the Companys retiree welfare benefits plans and programs (pursuant to Section 2(d) herein), for the rest of Kennedys life, he and, as applicable, his spouse and his daughter Maureen shall be entitled to all medical, health care and dental benefits under National Fuels medical, health care and dental plans and/or programs as if Kennedy were still employed, at the same level of benefits and at the same net dollar cost to Kennedy as is available to all of National Fuels senior executives generally or, if greater, at the same level of benefits and at the same dollar cost to Kennedy as Kennedy was receiving or was eligible to receive prior to his retirement on January 2, 2002; provided, however, that if National Fuel cannot provide such benefits under its existing plan(s) and/or program(s) because of limitations under applicable law, National Fuel shall provide equivalent benefits on an individual basis; provided, further, that following Kennedys death, Kennedys spouse and his daughter Maureen shall (at their expense, to the extent not paid for by National Fuel pursuant to National Fuels retiree welfare benefit plan(s) or program(s) pursuant to Section 2(d) of this Agreement) remain eligible to participate for their lives in the medical and dental benefit plan(s) and/or program(s) that Kennedy and/or his spouse and his daughter Maureen were participating in prior to Kennedys death; and |
(d) | As consideration for past services, Kennedys agreement to waive the compensation and other benefits he would otherwise be entitled to receive |
5
under his Employment Agreement through the remaining term thereof and Kennedys agreement to be bound by the non-competition covenants contained in section 8 hereof, the following: |
(i) | An award effective October 1, 2001 of (or awards aggregating) 50,000 shares of stock (such number being adjusted to reflect a stock split, stock dividend or consolidation after the date of this Agreement, but prior to October 1, 2001). | |||
(ii) | The payments set forth in the Pension Settlement Agreement by and between National Fuel and Kennedy to be executed contemporaneously with this Agreement (the Pension Settlement Agreement). |
5. | Death or Disability . In the event of Kennedys death or total disability prior to termination during the term of employment described in Section 2(b), National Fuels obligation to pay base salary and any unearned bonuses as described in section 2(c) shall end with its prorated payment thereof for the pay period during which such death or disability occurs. In the event of Kennedys death or total disability during the Consulting Period, National Fuels obligation to pay the monthly retainer described in section 3(a) shall end with its payment thereof for the month during which such death or disability occurs. | |||
6. | Non-Disclosure Agreement . |
(a) | As part of the consideration for the compensation provided in this Agreement and for the other covenants made by National Fuel in this Agreement, Kennedy shall hold in a fiduciary capacity, for the benefit of National Fuel, all of National Fuels trade secrets and confidential and proprietary information. Kennedy shall not, without the prior written consent of National Fuel, at any time following the termination of Kennedys employment with National Fuel, utilize, communicate or divulge to anyone other than National Fuel or those designated by it any of National Fuels trade secrets or confidential and proprietary information. Kennedy shall provide National Fuel with prompt notice of any subsequent employment, including, but not limited to, the name and address of any subsequent employer and the title and duties of Kennedys position therewith so that National Fuel can take whatever steps it deems appropriate in order to protect its interests under this Agreement. Kennedy understands that, under appropriate circumstances, National Fuel can sue Kennedy and/or any of Kennedys future employers for tortious interference with National Fuels contracts, interference with National Fuels prospective business relations, and/or misappropriation of National Fuels trade secrets or confidential and proprietary information. Except with respect to the monthly retainer described in section 3(a), in no event shall an asserted violation of the provisions of this section 6 constitute |
6
a basis for deferring or withholding any amounts otherwise payable or provided to Kennedy under this Agreement or the Pension Settlement Agreement. |
(b) | The prohibition against Kennedys use of National Fuels trade secrets and confidential and proprietary information, other than for the benefit of National Fuel, includes, but is not limited to, (i) the exploitation of any products or services that embody or are derived from National Fuels trade secrets or confidential and proprietary information, and (ii) the exercise of judgment or the performance of analysis based upon knowledge of National Fuels trade secrets and confidential and proprietary information. Kennedy represents, warrants and agrees that he has no proprietary or ownership rights or title to any of National Fuels trade secrets or confidential and proprietary information and no legal right to use, disclose, disseminate, or publish any of National Fuels trade secrets or confidential and proprietary information in any locality. |
7. | Definition of Confidential Material . National Fuels trade secrets and confidential and proprietary information include, but are not limited to, any and all memoranda, software, data bases, computer programs, interface systems, pricing and client information, and records pertaining to National Fuels methods or practices of doing business and marketing its services and products, whether or not developed or prepared by Kennedy during the term of his employment with National Fuel or in connection with his providing consulting service to National Fuel. National Fuels trade secrets and confidential and proprietary information also include writing or writings, which shall mean and include all works, expressed in words, numbers or other verbal or numerical symbols, regardless of the physical manner in which they are embodied, including, but not limited to, books, articles, manuscripts, memoranda, computer programs, computer software systems, maps, charts, diagrams, technical drawings, manuals, video and audio tape recordings, and photographs, whether or not developed or prepared by Kennedy during the term of his employment with National Fuel or in connection with his providing consulting services to National Fuel. National Fuels trade secrets and confidential and proprietary information shall include any information or material not generally known to the public (other than by act of Kennedy or his representatives in breach of this Agreement) which gives the holder thereof an opportunity to obtain an advantage over competitors without knowledge of such information, as well as any information received from third parties under confidential conditions and information subject to National Fuels attorney-client or work-product privilege, the use or disclosure of which might reasonably be construed to be contrary to National Fuels interests. | |||
8. | Non-Compete Covenants . |
(a) | In order to protect and safeguard National Fuels trade secrets and confidential and proprietary information, and also National Fuels goodwill |
7
with its customers, during the period beginning on the date of this Agreement and ending January 2, 2005, Kennedy will not, within any state in which National Fuel does business at any time during such period, directly or indirectly and without the prior written consent of National Fuel engage in or be interested in (as owner, partner, shareholder, employee, director, agent, consultant or otherwise), any business that is a competitor of National Fuel, as hereafter defined, or any business that is such a customer. For purposes of this Agreement, a competitor of National Fuel is any entity including, without limitation, a corporation, sole proprietorship, partnership, joint venture, syndicate, trust or any other form of organization or parent, subsidiary or division of any of the foregoing, which, during such period or the immediately preceding fiscal year of such entity, was engaged in (i) the exploration for or production, transportation, purchase, brokering, marketing, distribution or trading of natural gas or other energy products or services or (ii) the timber business. |
(b) | Anything contained herein to the contrary notwithstanding, nothing in section 8(a) shall be interpreted to prohibit (i) Kennedys present or future investments in the securities of competing companies listed on a national securities exchange or traded on the over-the-counter market to the extent such investments do not exceed 5% of the total outstanding shares of such company, (ii) Kennedys employment with a competitor of National Fuel provided such employment is limited to areas unrelated to the exploration for or production, transportation, purchase, brokering, marketing, distribution or trading of natural gas or other energy products or services or the timber business, (iii) continuation of business and professional relationships with the entities identified on Exhibit A to the Employment Agreement, or (iv) Kennedys engagement in or interest in any business after obtaining the prior written consent of National Fuel. | |||
(c) | For the period beginning on the date hereof and ending on January 2, 2004 (the second anniversary of Kennedys retirement on January 2, 2002), Kennedy shall not induce or otherwise entice any employee of National Fuel to leave National Fuel, nor shall Kennedy attempt to hire any of National Fuels employees. | |||
(d) | The foregoing restrictions contain reasonable limitations as to the time, geographic area, and scope of activity to be restrained and these restrictions do not impose any greater restraint than is necessary to protect the goodwill and other legitimate business interests of National Fuel. If and to the extent a court of competent jurisdiction finds one or more restriction contained in this section 8 to be unreasonable in terms of geographic scope, time limitation, or otherwise, the restriction(s) found to be unreasonable shall be deemed modified to the extent necessary so that the provisions of this section 8 are enforceable to the greatest extent possible. |
8
9. | Obligations, Enforcement . Except as otherwise provided in section 6 of this Agreement, National Fuels obligation to make the payments provided for in this Agreement or the Pension Settlement Agreement shall not be affected by any set-off, counter-claim, recoupment, defense or other claim, right or action National Fuel may have against Kennedy or others. In no event shall Kennedy be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to him under any of the provisions of this Agreement. National Fuel shall pay, or on an ongoing basis promptly reimburse Kennedy, for all legal fees and expenses reasonably incurred by Kennedy in connection with Kennedys enforcement of his rights under this Agreement. | |||
10. | Binding Consideration . Kennedy understands, represents, warrants and agrees that National Fuel has no contractual obligation or legal duty to pay Kennedy severance compensation or wages in lieu of notice of termination. | |||
11. | Binding Agreement . This Agreement is and shall be binding upon and inure to the benefit of the parties hereto and their respective successors (including any and all successors of National Fuel or to all or substantially all of its assets, whether by way of merger, acquisition, consolidation, share exchange or other business combination), heirs, executors, administrators and assigns. Kennedy represents, warrants and agrees that he has read, understands and intends to be bound by this Agreement and its recitals, terms, conditions and representations. | |||
12. | Miscellaneous . |
(a) | This Agreement, the Pension Settlement Agreement and the Letter (the Documents) contain and state the entire agreement of the parties hereto with respect to the subject matters of the Documents and, except as otherwise expressly provided in the Documents, supersede and cancel all prior written and oral agreements and understandings with respect to the subject matter of the Documents; provided, however, that notwithstanding the foregoing, this Agreement shall have no effect upon (i) the Employment Agreement, prior to its termination on January 2, 2002 except as insofar as is necessary to accommodate the express provision of Sections 2(a), 2(b) and 2(c) of this Agreement, and (ii) Kennedys rights under the Life Insurance Agreement. Except for awards or payouts to be made prior to Kennedys termination of employment as provided herein, no payments shall be made after January 31, 2002, hereunder unless and until the release required in Section 8 of the Pension Settlement Agreement is received by National Fuel and may not be revoked by Kennedy. |
(b) | The term affiliate as used in this Agreement with respect to a party, means any individual or entity that owns or controls, is owned or controlled by, or is under common ownership or control with, such party. |
9
(c) | All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows: | |||
If to Kennedy:
Bernard J. Kennedy 33 Ruskin Road Amherst, New York 14226 |
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If to National Fuel:
National Fuel Gas Company 10 Lafayette Square Buffalo, New York 14203 Attention: Corporate Secretary |
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or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notices and communications shall be effective when actually received by the addressee | ||||
(d) | This Agreement shall be governed by the laws of the State of New York and may be amended or modified only by written agreement signed by both parties. | |||
(e) | Notwithstanding any other provision of this Agreement, National Fuel may withhold from amounts payable under this Agreement all federal, state, local and foreign taxes that are required to be withheld by applicable laws or regulations; provided, however, without prior approval of Kennedy, shall not withhold more than the minimum amount National Fuel reasonably determines is required to be withheld under such laws or regulations. | |||
(f) | The obligations of Kennedy hereunder are personal and cannot be assigned. | |||
(g) | If any term or other provision of this Agreement shall be declared to be invalid, illegal, or incapable of being enforced by any rule of law or public policy, all other terms, provisions and conditions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party to this Agreement. Upon any binding determination that any term or other provision of this Agreement is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties to this Agreement as closely as possible in an acceptable and legally enforceable manner, to the end that the transactions contemplated hereby may be effected to the full extent possible. |
10
(h) | The headings in this Agreement are not part of the provisions hereof and shall have no force or effect. | |||
(i) | Except as otherwise provided herein, this Agreement shall terminate upon satisfaction of each partys obligations hereunder. |
IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written.
BERNARD J. KENNEDY
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NATIONAL FUEL GAS COMPANY | |||
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/s/ Bernard J. Kennedy
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By: |
/s/ G. L. Mazanec
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Its: | Chairman of the Compensation Committee of the Board of Directors |
11
The following page is the letter referenced in Section 4(a) of the
Retirement and Consulting Agreement, dated September 5, 2001,
between National Fuel Gas Company and Bernard J. Kennedy
GEORGE L. MAZANEC
302 Fall River Court
Houston, TX 77024
713-627-4623
Bernard J. Kennedy
National Fuel Gas Company
10 LaFayette Square
Buffalo, NY 14203
Dear Bernie:
In connection with your proposed retirement, you have asked for National Fuel Gas Companys (National Fuel) current policy and past practice regarding provision of support and benefits to a retired CEO and Chairman of the Board.
For a period of five years beginning on the date of your termination of employment with National Fuel, and such additional period as determined in the sole discretion of National Fuels CEO, that support and benefits include the following:
1. | Exclusive use of an executive office in National Fuels headquarters office building, or such other location as the parties may mutually agree upon, including an executive secretary, telephone, fax service, computer, and other customary office equipment and support, together with a garage space and related support. | |||
2. | Continued provision of tax consultation, planning and preparation assistance, paid for by National Fuel under the same terms and conditions as received prior to retirement. | |||
3. | Reimbursement for relocation-related expenses and other relocation benefits pursuant to National Fuels relocation policy for executive officers. |
In addition, since it is proposed that you will provide consulting services following retirement, National Fuel will continue to provide during the consulting period payment for business club dues and related expenses at certain clubs to which the executive was a member prior to retirement and with respect to which the executives continued membership in, and attendance at functions of, such clubs would be a continuing benefit to National Fuel.
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Very truly yours,
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/s/ George L. Mazanec | |
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George L. Mazanec | |
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Chairman of the Compensation Committee
of the Board of Directors of National Fuel Gas Company |
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Dated: September 5, 2001 |
13
EXHIBIT 12
COMPUTATION OF RATIO OF | ||||||||||||||||||||||||
EARNINGS TO FIXED CHARGES | ||||||||||||||||||||||||
UNAUDITED | ||||||||||||||||||||||||
Fiscal Year Ended September 30
|
||||||||||||||||||||||||
For the Twelve | ||||||||||||||||||||||||
Months Ended | ||||||||||||||||||||||||
September 30, 2004
|
2003
|
2002
|
2001
|
2000
|
1999
|
|||||||||||||||||||
EARNINGS:
|
||||||||||||||||||||||||
Income Before Cumulative Effect of
Changes in Accounting
|
$ | 166,586 | $ | 187,836 | $ | 117,682 | $ | 65,499 | $ | 127,207 | $ | 115,037 | ||||||||||||
Plus Minority Interest in Foreign
Subsidiaries
|
1,933 | 785 | 730 | 1,342 | 1,384 | 1,616 | ||||||||||||||||||
Plus Income Tax Expense
|
92,737 | 128,161 | 72,034 | 37,106 | 77,068 | 64,829 | ||||||||||||||||||
Less Investment Tax Credit (1)
|
(697 | ) | (693 | ) | (702 | ) | (353 | ) | (1,051 | ) | (729 | ) | ||||||||||||
(Less Income) Plus Loss from
Unconsolidated Subsidiaries (3)
|
(805 | ) | (535 | ) | 14,943 | (1,794 | ) | (1,669 | ) | (999 | ) | |||||||||||||
Plus Distributions from Unconsolidated
Subsidiaries
|
785 | 1,238 | 585 | 595 | 229 | | ||||||||||||||||||
Plus Interest Expense on Long-Term Debt
|
83,826 | 92,766 | 90,543 | 81,851 | 67,195 | 65,402 | ||||||||||||||||||
Plus Other Interest Expense
|
6,763 | 12,290 | 15,109 | 25,294 | 32,890 | 22,296 | ||||||||||||||||||
Less Amortization of Loss on
Reacquired Debt
|
(1,350 | ) | (2,078 | ) | (1,927 | ) | (1,927 | ) | (1,979 | ) | (1,839 | ) | ||||||||||||
Plus (Less) Allowance for Borrowed
Funds Used in Construction
|
298 | (102 | ) | 446 | 438 | 424 | 303 | |||||||||||||||||
Plus Rentals (2)
|
4,286 | 4,573 | 4,906 | 4,893 | 4,561 | 4,281 | ||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||
|
$ | 354,362 | $ | 424,241 | $ | 314,349 | $ | 212,944 | $ | 306,259 | $ | 270,197 | ||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||
FIXED CHARGES:
|
||||||||||||||||||||||||
Interest & Amortization of Premium and
Discount of Funded Debt
|
$ | 83,826 | $ | 92,766 | $ | 90,543 | $ | 81,851 | $ | 67,195 | $ | 65,402 | ||||||||||||
Plus Other Interest Expense
|
6,763 | 12,290 | 15,109 | 25,294 | 32,890 | 22,296 | ||||||||||||||||||
Less Amortization of Loss on
Reacquired Debt
|
(1,350 | ) | (2,078 | ) | (1,927 | ) | (1,927 | ) | (1,979 | ) | (1,839 | ) | ||||||||||||
Plus (Less) Allowance for Borrowed
Funds Used in Construction
|
298 | (102 | ) | 446 | 438 | 424 | 303 | |||||||||||||||||
Plus Rentals (2)
|
4,286 | 4,573 | 4,906 | 4,893 | 4,561 | 4,281 | ||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||
|
$ | 93,823 | $ | 107,449 | $ | 109,077 | $ | 110,549 | $ | 103,091 | $ | 90,443 | ||||||||||||
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|
|
|
|
|
|
||||||||||||||||||
RATIO OF EARNINGS TO FIXED CHARGES
|
3.78 | 3.95 | 2.88 | 1.93 | 2.97 | 2.99 |
(1) | Investment Tax Credit is included in Other Income | |
(2) | Rentals shown above represent the portion of all rentals (other than delay rentals) deemed representative of the interest factor. | |
(3) | Fiscal 2002 includes the Impairment of Investment in Partnership of $15,167. |
Exhibit 23.1
CONSENT OF ENGINEER
We hereby consent to the reproduction of our audit report for Seneca
Resources Corporation dated October 15, 2004, and to the reference to our
estimate dated September 30, 2004, appearing in this National Fuel Gas Company
Annual Report on Form 10-K.
We also consent to the incorporation by reference in (i) the Registration
Statement (Form S-8, No. 2-94539), as amended, relating to the National Fuel
Gas Company 1983 Incentive Stock Option Plan and the National Fuel Gas Company
1984 Stock Plan, and in the related Prospectuses, (ii) the Registration
Statements (Form S-8, Nos. 33-28037, 333-3055 and 333-102220, and Nos. 2-97641,
33-17341, 333-03057 and 333-102211), as amended, relating to the National Fuel
Gas Company Tax-Deferred Savings Plan and the National Fuel Gas Company
Tax-Deferred Savings Plan for Non-Union Employees, respectively, and in the
related Prospectuses, (iii) the Registration Statement (Form S-3, No.
333-03803), as amended, relating to $500,000,000 of National Fuel Gas Company
debentures and/or medium term notes and, in the related Prospectus, (iv) the
Registration Statements (Form S-3, No. 33-51881 and Form S-3D, No. 333-51769),
as amended, relating to the National Fuel Gas Company Dividend Reinvestment and
Stock Purchase Plan, and in the related Prospectuses, (v) the Registration
Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel
Gas Company Customer Stock Purchase Plan, and in the related Prospectus, (vi)
the Registration Statements (Form S-8, Nos. 33-49693 and 333-117132), as
amended, relating to the National Fuel Gas Company 1993 Award and Option Plan,
and in the related Prospectus, (vii) the Registration Statements (Form S-8,
Nos. 333-51595, 333-55124 and 333-117131), relating to the National Fuel Gas
Company 1997 Award and Option Plan, and in the related Prospectus, (viii) the
Registration Statement (Form S-3, No. 333-83497), as amended, relating to
$625,000,000 of National Fuel Gas Company debentures and/or common stock, and
in the related Prospectus, (ix) the Registration Statement (Form S-3, No.
333-102200), as amended, relating to $800,000,000 of National Fuel Gas Company
debt securities, common stock, stock purchase contracts and stock purchase
units, and in the related Prospectus, and (x) the Registration Statement (Form
S-3, No. 333-85711), as amended, relating to the National Fuel Gas Company
Direct Stock Purchase and Dividend Reinvestment Plan, and in the related
Prospectus, of the reproduction of our report dated October 15, 2004, appearing
in this National Fuel Gas Company Annual Report on Form 10-K.
Houston, Texas
RALPH E. DAVIS ASSOCIATES, INC.
/s/ Allen C. Barron, P.E.
Allen C. Barron, P.E.
President
October 22, 2004
Exhibit 23.2
CONSENT OF ENGINEER
We hereby consent to the reproduction of our audit report for Seneca
Energy Canada, Inc. dated October 15, 2004, and to the reference to our
estimate dated September 30, 2004, appearing in this National Fuel Gas Company
Annual Report on Form 10-K.
We also consent to the incorporation by reference in (i) the Registration
Statement (Form S-8, No. 2-94539), as amended, relating to the National Fuel
Gas Company 1983 Incentive Stock Option Plan and the National Fuel Gas Company
1984 Stock Plan, and in the related Prospectuses, (ii) the Registration
Statements (Form S-8, Nos. 33-28037, 333-3055 and 333-102220, and Nos. 2-97641,
33-17341, 333-03057 and 333-102211), as amended, relating to the National Fuel
Gas Company Tax-Deferred Savings Plan and the National Fuel Gas Company
Tax-Deferred Savings Plan for Non-Union Employees, respectively, and in the
related Prospectuses, (iii) the Registration Statement (Form S-3, No.
333-03803), as amended, relating to $500,000,000 of National Fuel Gas Company
debentures and/or medium term notes and, in the related Prospectus, (iv) the
Registration Statements (Form S-3, No. 33-51881 and Form S-3D, No. 333-51769),
as amended, relating to the National Fuel Gas Company Dividend Reinvestment and
Stock Purchase Plan, and in the related Prospectuses, (v) the Registration
Statement (Form S-3, No. 33-36868), as amended, relating to the National Fuel
Gas Company Customer Stock Purchase Plan, and in the related Prospectus, (vi)
the Registration Statements (Form S-8, Nos. 33-49693 and 333-117132), as
amended, relating to the National Fuel Gas Company 1993 Award and Option Plan,
and in the related Prospectus, (vii) the Registration Statements (Form S-8,
Nos. 333-51595, 333-55124 and 333-117131), relating to the National Fuel Gas
Company 1997 Award and Option Plan, and in the related Prospectus, (viii) the
Registration Statement (Form S-3, No. 333-83497), as amended, relating to
$625,000,000 of National Fuel Gas Company debentures and/or common stock, and
in the related Prospectus, (ix) the Registration Statement (Form S-3, No.
333-102200), as amended, relating to $800,000,000 of National Fuel Gas Company
debt securities, common stock, stock purchase contracts and stock purchase
units, and in the related Prospectus, and (x) the Registration Statement (Form
S-3, No. 333-85711), as amended, relating to the National Fuel Gas Company
Direct Stock Purchase and Dividend Reinvestment Plan, and in the related
Prospectus, of the reproduction of our report dated October 15, 2004, appearing
in this National Fuel Gas Company Annual Report on Form 10-K.
Houston, Texas
RALPH E. DAVIS ASSOCIATES, INC.
/s/ Allen C. Barron, P.E.
Allen C. Barron, P.E.
President
October 22, 2004
Exhibit 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration
Statement on Forms S-3 (Nos. 333-85711, and 333-102200) and Forms S-8 (Nos.
2-94539, 33-49693, 333-03055, 333-51595, 333-55124, 333-102211, 333-102220,
333-117131 and 333-117132) of National Fuel Gas Company of our report dated
December 9, 2004 relating to the financial statements and financial statement
schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Buffalo, New York
December 14, 2004
Exhibit 31.1
CERTIFICATION
I, P. C. Ackerman, certify that:
1. I have reviewed this annual report on Form 10-K of National Fuel Gas
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrants other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being prepared;
(b) Evaluated the effectiveness of the registrants disclosure controls
and procedures and presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures as of the end of the
period covered by this annual report based on such evaluation; and
(c) Disclosed in this annual report any change in the registrants
internal control over financial reporting that occurred during the registrants
most recent fiscal quarter (the registrants fourth fiscal quarter in the case
of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrants internal control over financial reporting;
and
5. The registrants other certifying officer and I have disclosed, based
on our most recent evaluation of internal control over financial reporting, to
the registrants auditors and the audit committee of the registrants board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrants ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrants internal control over
financial reporting.
Date: December 9, 2004
/s/ P. C. Ackerman
Chairman of the Board, President and
Chief Executive Officer
Exhibit 31.2
CERTIFICATION
I, R. J. Tanski, certify that:
1. I have reviewed this annual report on Form 10-K of National Fuel Gas
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrants other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being prepared;
(b) Evaluated the effectiveness of the registrants disclosure controls
and procedures and presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures as of the end of the
period covered by this annual report based on such evaluation; and
(c) Disclosed in this annual report any change in the registrants
internal control over financial reporting that occurred during the registrants
most recent fiscal quarter (the registrants fourth fiscal quarter in the case
of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrants internal control over financial reporting;
and
5. The registrants other certifying officer and I have disclosed, based
on our most recent evaluation of internal control over financial reporting, to
the registrants auditors and the audit committee of the registrants board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrants ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrants internal control over
financial reporting.
Date: December 9, 2004
/s/ R. J. Tanski
Treasurer and Principal Financial Officer
Exhibit 32
NATIONAL FUEL GAS COMPANY
Certification Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Each of the undersigned, P. C. ACKERMAN, the Chairman of the Board, President and Chief Executive Officer, and R. J. TANSKI, the Treasurer and Principal Financial Officer, of NATIONAL FUEL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:
1. | The Companys Annual Report on Form 10-K for the year ended September 30, 2004 (the Annual Report) fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934, as amended; and | |||
2. | Information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
IN WITNESS WHEREOF, each of the undersigned has executed this statement this 9th day of December, 2004.
/s/ P. C. Ackerman | ||||
Chairman of the Board, President and | ||||
Chief Executive Officer | ||||
/s/ R. J. Tanski | ||||
Treasurer and Principal Financial Officer | ||||
Exhibit 99.1
October 15, 2004
Seneca Resources Corporation
1201 Louisiana, Suite 400
Houston, Texas 77002
Attention: |
Mr. James A. Beck
President |
Re: |
Oil, Condensate and Natural Gas Reserves,
Seneca Resources Corporation As of September 30, 2004 |
Gentlemen:
At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which Seneca Resources Corporation has certain interests. This report presents a summary of the Proved Developed (producing and non-producing) and Proved Undeveloped reserves anticipated to be produced from Seneca Resources interest.
The reserves associated with these estimates have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Rule 4-10(a) of regulation S-X of the Securities Exchange Act of 1934. We have also estimated the future net revenue and discounted present value associated with these reserves as of September 30, 2004, utilizing a scenario of non escalated product prices as well as non escalated costs of operations, i.e., prices and costs were not escalated above
Consultants to the Petroleum and Natural Gas Industries Since the 1920s
RALPH E. DAVIS ASSOCIATES, INC.
Seneca Resources Corporation
Oil, Condensate and Natural Gas Reserves Mr. James A. Beck |
October 15, 2004
Page 2 |
current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.
The summarized results of the reserve audit are as follows:
Estimated Proved Reserves
Net to Seneca Resources Corporation
As of September 30, 2004
Proved Developed
Proved
Division:
Producing
Non Producing
Undeveloped
Total Proved
147.4
0.0
0.0
147.4
78,741.2
19.2
0.0
78,760.4
1,813.4
247.9
19.1
2,080.4
11,817.1
14,009.3
1,907.7
27,734.1
38,475.4
155.8
22,250.4
60,881.6
52,633.2
402.1
14,408.1
67,443.4
40,436.2
403.7
22,269.5
63,109.4
143,191.5
14,430.6
16,315.8
173,937.9
Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.
RALPH E. DAVIS ASSOCIATES, INC.
Seneca Resources Corporation
Oil, Condensate and Natural Gas Reserves
Mr. James A. Beck
October 15, 2004
Page 3
DISCUSSION:
The scope of this study was to audit the proved reserves attributable to the interests of Seneca Resources Corporation. Reserve estimates were prepared by Seneca using acceptable evaluation principals for each source. The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty.
Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. In each of Senecas producing divisions all current year additions and those properties of significant value were reviewed by Ralph E. Davis. Reserve estimates of current producing zones, productive zones behind pipe and undrilled well locations were reviewed in detail. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by Seneca Resources. It is our opinion that the reserves presented herein meet all the criteria of Proved Reserves.
Neither Ralph E. Davis Associates, Inc. nor any of its employees have any significant interest in Seneca Resources Corporation or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves.
We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.
Very truly yours,
RALPH E. DAVIS ASSOCIATES, INC.
Allen C.
Barron, P. E.
President
RALPH E. DAVIS ASSOCIATES, INC.
CLASSIFICATION OF RESERVES
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
1. | Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. | |||
2. | Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. | |||
3. | Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. |
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
(Classification of reserves as found in Rule 4-10(a) of Regulation S-X of the per Securities and Exchange Act)
Exhibit 99.2
October 15, 2004
Seneca Energy Canada, Inc.
550 6
th
Avenue SW
Suite 1000
Calgary, Alberta T2P O2S
Attention: |
Mr. Darrell Ibach
President |
Re: |
Oil, Condensate and Natural Gas Reserves,
Seneca Energy Canada, Inc. As of September 30, 2004 |
Gentlemen:
At your request, the firm of Ralph E. Davis Associates, Inc. has audited an evaluation of the proved oil, condensate and natural gas reserves on leaseholds in which Seneca Energy Canada, Inc. has certain interests. This report presents a summary of the Proved Developed (producing and non-producing) and Proved Undeveloped reserves anticipated to be produced from Seneca Energy Canadas interest.
The reserves associated with these estimates have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Rule 4-10(a) of regulation S-X of the Securities Exchange Act of 1934. We have also estimated the future net revenue and discounted present value associated with these reserves as of September 30, 2004, utilizing a scenario of non escalated product prices as well as non escalated costs of operations, i.e., prices and costs were not
Consultants to the Petroleum and Natural Gas Industries Since the 1920s
RALPH E. DAVIS ASSOCIATES, INC.
Seneca Energy Canada, Inc. | |
Oil, Condensate and Natural Gas Reserves | October 15, 2004 |
Mr. Darrell Ibach | Page 2 |
escalated above current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.
Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.
The summarized results of the reserve audit are as follows:
Estimated Proved Reserves
Net to Seneca Energy Canada, Inc.
As of September 30, 2004
Proved Developed
Producing
Non Producing
Undeveloped
Total Proved
1,820.5
81.7
0.0
1,902.2
153.4
48.3
0.0
201.7
32,580.5
13,642.2
4,623.0
50,845.7
DISCUSSION:
The scope of this study was to audit the proved reserves attributable to the interests of Seneca Energy Canada, Inc. Reserve estimates were prepared by Seneca Energy Canada using acceptable evaluation principals for each source. The quantities presented herein are estimated reserves of oil, condensate and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under existing economic conditions with reasonable certainty.
RALPH E. DAVIS ASSOCIATES, INC.
Seneca Energy Canada, Inc.
Oil, Condensate and Natural Gas Reserves
Mr. Darrell Ibach
October 15, 2004
Page 3
Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data incorporated into preparing the estimates and the methodology used to evaluate the reserves. In each of Seneca Energy Canadas producing areas all current year additions and those properties of significant value were reviewed by Ralph E. Davis. Reserve estimates of current producing zones, productive zones behind pipe and undrilled well locations were reviewed in detail. Certain changes to either individual reserve estimates or the categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and accepted by Seneca Energy Canada. It is our opinion that the reserves presented herein meet all the criteria of Proved Reserves.
Neither Ralph E. Davis Associates, Inc. nor any of its employees have any significant interest in Seneca Energy Canada, Inc. or Seneca Resources Corporation or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves.
We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.
Very truly yours,
RALPH E. DAVIS ASSOCIATES, INC.
Allen C. Barron, P. E.
President
RALPH E. DAVIS ASSOCIATES, INC.
CLASSIFICATION OF RESERVES
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
1. | Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. | |||
2. | Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. | |||
3. | Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. |
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
(Classification of reserves as found in Rule 4-10(a) of Regulation S-X of the per Securities and Exchange Act)
Exhibit 99.3