United States
Securities
and Exchange Commission
Washington, D.C. 20549
Form 10-K
Annual Report Pursuant to Section 13 or 15(d)
of The
Securities Exchange Act of 1934
For the Fiscal Year Ended September 30, 2003
Commission File Number 1-3880
National
Fuel Gas Company
(Exact name of registrant as specified in its charter)
| New Jersey | 13-1086010 |
|---|---|
| (State or other jurisdiction of | (I.R.S. Employer |
| incorporation or organization) | Identification No.) |
| 6363 Main Street | 14221 |
| Williamsville, New York | (Zip Code) |
| (Address of principal executive offices) |
(716)
857-7000
Registrant's telephone number, including area code
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 | New York Stock Exchange |
| Common Stock Purchase Rights |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). YES X NO
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,733,892,000 as of March 31, 2003.
Common Stock, $1 Par Value, outstanding as of November 30, 2003: 81,600,674 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 19, 2004 are incorporated by reference into Part III of this report.
1
For the Fiscal Year Ended September 30, 2003
Contents
Part I Page
ITEM 1 BUSINESS 4
THE COMPANY AND ITS SUBSIDIARIES 4
RATES AND REGULATION 5
THE UTILITY SEGMENT 6
THE PIPELINE AND STORAGE SEGMENT 6
THE EXPLORATION AND PRODUCTION SEGMENT 7
THE INTERNATIONAL SEGMENT 7
THE ENERGY MARKETING SEGMENT 7
THE TIMBER SEGMENT 7
ALL OTHER CATEGORY AND CORPORATE OPERATIONS 7
SOURCES AND AVAILABILITY OF RAW MATERIALS 7
COMPETITION 8
SEASONALITY 10
CAPITAL EXPENDITURES 10
ENVIRONMENTAL MATTERS 10
MISCELLANEOUS 10
EXECUTIVE OFFICERS OF THE COMPANY 11
ITEM 2 PROPERTIES 13
GENERAL INFORMATION ON FACILITIES 13
EXPLORATION AND PRODUCTION ACTIVITIES 14
ITEM 3 LEGAL PROCEEDINGS 17
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 18
Part II
ITEM 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS 18
ITEM 6 SELECTED FINANCIAL DATA 19
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS 21
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 46
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 46
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE 86
ITEM 9A CONTROLS AND PROCEDURES 86
Part III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 87
ITEM 11 EXECUTIVE COMPENSATION 87
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS 87
2
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 88
ITEM 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES 88
Part IV
ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 88
SIGNATURES 95
3
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, Management’s Discussion and Analysis of Financial Condition and Results of Operation (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
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 Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s 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 733,000 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 generally from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York. The Company acquired Empire, which is regulated by the State of New York Public Service Commission (NYPSC), in February 2003. Seneca Independence Pipeline Company was formed to hold a one-third general partnership interest in Independence Pipeline Company, which was dissolved in 2002.
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 and Louisiana. 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. In September 2003, the Company sold its Southeast Saskatchewan properties, reducing its oil reserves by 19,400 thousand barrels (Mbbl) and its gas reserves by 270 million cubic feet (MMcf). At September 30, 2003, the Company had remaining U.S. and Canadian reserves of 69,764 Mbbl and 251,117 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
4
as a sole or substantial owner in various business entities. These entities include Horizon's wholly-owned subsidiary, Horizon Energy Holdings, Inc., a New York corporation, which owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company whose principal asset is majority ownership of United Energy, a.s. (UE), a wholesale power and district heating company located in the northern part of the Czech Republic. Horizon B.V. is also pursuing power development projects in other parts of Europe.
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. In August 2003, the Company sold approximately 70,000 acres of timber property. At September 30, 2003, the Company had approximately 87,000 acres of timber property remaining.
Financial information about each of the Company's business segments can be found in Item 7, MD&A and also in Item 8 at Note H - Business Segment Information.
The Company's other wholly-owned subsidiaries are not included in any of the six reportable business segments and consist of the following:
| o Upstate Energy Inc. (Upstate), a New York corporation engaged in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. On June 3, 2003, Upstate and a wholly owned subsidiary of Upstate acquired all of the partnership interests in Toro Partners, LP (Toro), a limited partnership which owns and operates eight short-distance landfill gas pipeline companies. Further information can be found in Item 7, MD&A and also in Item 8 at Note J - Acquisitions; |
| o Niagara Independence Marketing Company (NIM), a Delaware corporation which owns a one-third general partnership interest in DirectLink Gas Marketing Company (DirectLink), a Delaware general partnership which was dissolved October 31, 2003; |
| o Leidy Hub, Inc. (Leidy), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States; |
| o Data-Track Account Services, Inc. (Data-Track), a New York corporation which provides collection services principally for the Company’s subsidiaries; and |
| o 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 pipeline facilities. |
No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2003.
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 include repeal of the Holding Company Act. On November 17, 2003, a conference committee of the House and Senate approved a conference agreement (i.e., a compromise bill), which was passed by the House on November 19, 2003. The conference agreement is pending before the Senate and certain senators have indicated that it is likely to be considered in January 2004 when Congress reconvenes.* The conference agreement would repeal the Holding Company Act effective one year after the date of enactment of the new law. The measure, if enacted, would replace the Holding Company Act with provisions designed to
5
give the Federal Energy Regulatory Commission (FERC) and state public utility regulatory commissions greater access to the books and records of companies in holding company systems. Also, in some cases, FERC would have jurisdiction to approve cost allocations among holding company system companies. If the Holding Company Act is repealed, it is possible that some state legislatures will enact new laws designed to give state public utilities commissions regulatory powers over holding companies similar to those now exercised by the SEC. 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 segment’s rates, services and other matters are regulated by the 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 segment’s rates and regulation, see Item 7, MD&A under the heading “Rate Matters” and Item 8 at Note B-Regulatory Matters.
The Pipeline and Storage segment’s rates, services and other matters with respect to Supply Corporation are regulated by FERC and by the NYPSC with respect to Empire. For additional discussion of the Pipeline and Storage segment’s 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 Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.
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, as other companies doing similar business in the same locations.
The Utility segment contributed approximately 31.7% of the Company’s 2003 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 contributed approximately 25.3% of the Company’s 2003 net income available for common stock.
Supply Corporation currently has service agreements for substantially all of its firm transportation capacity, which totals approximately 2,093 thousand dekatherms (MDth) per day. The Utility segment accounts for approximately 1,179 MDth per day or 56.3% of the total capacity, and the Energy Marketing segment represents another 74 MDth per day or 3.5% of the total capacity. The remaining 841 MDth or 40.2% of Supply Corporation’s firm transportation capacity is subject to firm contracts with nonaffiliated customers.
Supply Corporation has service agreements for substantially all of its firm storage capacity, which totals approximately 68,728 MDth. The Utility segment has contracted for 31,395 MDth or 45.7% of the total capacity and the Energy Marketing segment accounts for another 3,555 MDth or 5.2% of the total capacity. Nonaffiliated customers have contracted for the remaining 33,778 MDth or 49.1% of the firm
6
storage capacity. 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.*
Empire has service agreements for substantially all of its firm transportation capacity for the 2003-2004 winter period, which totals approximately 567 MDth per day. The Utility segment accounts for approximately 60 MDth per day or 10.6% of the total capacity, and the Energy Marketing segment accounts for approximately 10 MDth per day or 1.8% of the total capacity. The remaining 497 MDth per day or 87.6% of Empire’s firm winter transportation capacity is subject to firm contracts with nonaffiliated customers.
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 incurred a net loss in 2003. The impact of this net loss in relation to the Company’s 2003 net income available for common stock was negative 17.8%.
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 incurred a net loss in 2003. The impact of this segment’s net loss in relation to the Company’s 2003 net income available for common stock was negative 5.4%.
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 contributed approximately 3.3% of the Company’s 2003 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 contributed approximately 62.8% of the Company’s 2003 net income available for common stock.
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.
The All Other category and Corporate operations contributed approximately 0.1% of the Company’s 2003 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.
Natural gas is the principal raw material for the Utility segment. In 2003, the Utility segment purchased 123.0 billion cubic feet (Bcf) of gas. Gas purchases from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 63% of these purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for 37% of the Utility segment’s 2003 gas purchases. Gas purchases from BP Energy Company (13%), Amerada Hess Corporation (13%), ConocoPhillips (12%), Anadarko Petroleum Corporation (11%) and Occidental
7
Energy Marketing, Inc. (10%) accounted for 59% of the Utility’s gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2003.
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 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 52% of the cost of raw materials needed in 2003 to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined accounted for the remaining 48% of such materials. Coal is purchased and delivered directly from the adjacent Mostecka Uhelna Spolecnost, a.s. mine in the Czech Republic for Horizon’s 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 eighty percent of the timber processed during fiscal year 2003 came from land owned by Seneca; however, this percentage is expected to drop to approximately 50% in fiscal year 2004 as a result of the previously discussed sale of approximately 70,000 acres of timber property.
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2003, this segment purchased 45 Bcf of natural gas.
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 compared with other fuels should increase the role of natural gas as an energy source.*
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 such restructuring or any future restructuring in response to the August 2003 Northeast blackout, 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.*
The changes precipitated by the FERC’s restructuring of the gas industry in Order No. 636 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, since regulators in Pennsylvania have not pursued such programs recently, and since there have not been any significant new market entrants in New York, the Utility segment’s traditional distribution function remains largely unchanged.
8
Competition for large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.*
The Utility segment is now better able to compete, through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets).* The Utility segment continues to (i) develop or promote new sources and uses of natural gas or new services, rates and contracts and (ii) emphasize and provide high quality service to its customers.
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.*
On February 6, 2003, the Company acquired Empire. 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.
Supply Corporation and TransCanada PipeLines Limited together are pursuing a proposal to construct a pipeline to transport natural gas from Kirkwall, Ontario to the storage and market hub at Leidy, Pennsylvania. This project, called the Northwinds Pipeline, is competing for customers with other proposed pipeline projects that would bring natural gas from Canada to the markets in the northeast and mid-Atlantic regions of the United States. It is likely that not all of the proposed pipelines will go forward, and that the first project built will have an advantage over other proposed projects.* If completed, the Northwinds Pipeline would likely create opportunities for increased transportation and storage services by Supply Corporation.* For further discussion of the Northwinds Pipeline project, refer to Item 7, MD&A under the heading “Investing Cash Flow.”
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.
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 Republic’s dominant state-owned energy producer.
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 is a relatively new occurrence, the competition in this area is well developed with regard to price and services from both local and regional marketers.
9
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.
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 Corporation’s 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. Empire’s 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 designed to recover variable costs associated with actual transportation of gas, to recover return on equity, and to recover income taxes.
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. The timber harvesting and processing season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months focus on pulpwood and on thinning out lower-grade species from the timber stands to encourage the growth of higher-grade species.
A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”
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.
The Company and its wholly-owned or majority-owned subsidiaries had a total of 3,037 full-time employees at September 30, 2003, with 2,140 employees in all of its U.S. operations and 897 employees in its international operations. This is a decrease of 4.4% from the 3,177 total employed at September 30, 2002.
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
10
expire in May 2009. An agreement covering employees in collective bargaining units in the Czech Republic is scheduled to expire in December 2004. Negotiations to renew such agreement are ongoing.
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 Company’s internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC.
- ---------------------------- --------------------------------------------------------------------------------------
Name and Age(2) Current Company Positions and Other Material
Business Experience During Past Five Years(3)
- ---------------------------- --------------------------------------------------------------------------------------
Philip C. Ackerman Chairman of the Board of Directors since January 2002; Chief Executive Officer
(59) 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.
- ---------------------------- --------------------------------------------------------------------------------------
Dennis J. Seeley President of Supply Corporation since March 2000; President of Empire since
(60) February 2003; Senior Vice President of Distribution Corporation since February
1997. Mr. Seeley has served as Vice President of the Company from January 2000
to April 2000 and Senior Vice President of Supply Corporation from January 1993
to February 1997.
- ---------------------------- --------------------------------------------------------------------------------------
David F. Smith President of Distribution Corporation since July 1999; Senior Vice President of
(50) Supply Corporation since July 2000. Mr. Smith served as Senior Vice President
of Distribution Corporation from January 1993 to July 1999.
- ---------------------------- --------------------------------------------------------------------------------------
James A. Beck President of Seneca since October 1996 and President of Highland since March
(56) 1998. Mr. Beck previously served as Vice President of Seneca from January 1994
to April 1995 and Executive Vice President of Seneca from May 1995 to September
1996.
- ---------------------------- --------------------------------------------------------------------------------------
Bruce H. Hale President of Horizon Power since March 2001; Senior Vice President of Supply
(54) Corporation since February 1997; and Vice President of Horizon since September
1995. Mr. Hale previously served as Senior Vice President of Distribution
Corporation from January 1993 to February 1997.
- ---------------------------- --------------------------------------------------------------------------------------
Joseph P. Pawlowski Treasurer of the Company since December 1980; Senior Vice President of
(62) Distribution Corporation since February 1992 and Treasurer of Distribution
Corporation since January 1981; Treasurer of Supply Corporation since June 1985;
Treasurer of Empire since February 2003; and Secretary of Supply Corporation
since October 1995.
- ---------------------------- --------------------------------------------------------------------------------------
11
- ---------------------------- --------------------------------------------------------------------------------------
Name and Age(2) Current Company Positions and Other Material
Business Experience During Past Five Years(3)
- ---------------------------- --------------------------------------------------------------------------------------
Walter E. DeForest Senior Vice President of Distribution Corporation since August 1993; and Senior
(62) Vice President of Supply Corporation from January 1992 to August 1993.
- ---------------------------- --------------------------------------------------------------------------------------
Anna Marie Cellino Secretary of the Company since October 1995; Senior Vice President of
(50) Distribution Corporation since July 2001; and Vice President of Distribution
Corporation from June 1994 to July 2001.
- ---------------------------- --------------------------------------------------------------------------------------
Ronald J. Tanski Controller of the Company since February 2003; Senior Vice President of
(51) Distribution Corporation since July 2001; Controller of Distribution Corporation
since February 1997; Secretary and Treasurer of Horizon since February 1997; and
Vice President of Distribution Corporation from April 1993 to July 2001.
- ---------------------------- --------------------------------------------------------------------------------------
John R. Pustulka Senior Vice President of Supply Corporation since July 2001; and Vice President
(51) of Supply Corporation from April 1993 to July 2001.
- ---------------------------- --------------------------------------------------------------------------------------
James D. Ramsdell Senior Vice President of Distribution Corporation since July 2001; and Vice
(48) President of Distribution Corporation from June 1994 to July 2001.
- ---------------------------- --------------------------------------------------------------------------------------
(1) The Company has been advised that there are no family relationships among any of the officers listed, and that there is no arrangement or understanding among any one of them and any other persons pursuant to which he or she was elected as an officer. The executive officers serve at the pleasure of the Board of Directors.
(2) Ages are as of September 30, 2003.
(3) The information provided relates to the principal subsidiaries of the Company. Many of the executive officers have served or currently serve as officers or directors for other subsidiaries of the Company.
12
The investment of the Company in net property, plant and equipment was $2.9 billion at September 30, 2003. Approximately 57% 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 (32%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, in the Gulf Coast region of Texas and Louisiana 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 (8%) which is located in the Czech Republic and the Timber segment (3%) which is located primarily in northwestern Pennsylvania. 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 $666 million, or 30%, since 1998.
The Utility segment had a net investment in property, plant and equipment of $972.0 million at September 30, 2003. The net investment in its gas distribution network (including 14,773 miles of distribution pipeline) and its service connections to customers represent approximately 57% and 29%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2003.
The Pipeline and Storage segment had a net investment of $685.6 million in property, plant and equipment at September 30, 2003. Transmission pipeline, with a net cost of $262.6 million, represents 38% of this segment’s total net investment and includes 2,601 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 $87.0 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 $925.8 million at September 30, 2003. Of this amount, $809.3 million relates to properties located in the United States. The remaining net investment of $116.5 million relates to properties located in Canada.
The International segment had a net investment in property, plant and equipment of $219.2 million at September 30, 2003. This represents UE’s net investment in district heating and electric generation facilities.
The Timber segment had a net investment in property, plant and equipment of $87.6 million at September 30, 2003. 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 Company’s 2003 peak day sendout, including transportation service, of 1,744.8 million cubic feet (MMcf), which occurred on January 23, 2003. Withdrawals from storage of 653.8 MMcf provided approximately 37.5% 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.
13
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 and Louisiana. 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. Note N sets forth proved developed and undeveloped reserve information for Seneca. During 2003, Seneca’s proved developed and undeveloped reserves decreased significantly. Natural gas reserves decreased from 258 Bcf at September 30, 2002 to 251 Bcf at September 30, 2003 and oil reserves decreased from 99,717 thousands of barrels (Mbbl) to 69,764 Mbbl. These decreases are attributed to several factors: (i) U.S. and Canadian production and sales of Canadian properties (refer to Item 7, MD&A) and (ii) downward reserve revisions, primarily related to the Canadian properties sold during the year, (reflected in Note N as revisions of previous estimates). Seneca’s proved developed and undeveloped reserves also decreased in 2002 as compared to 2001. Natural gas reserves decreased from 322 Bcf at September 30, 2001 to 258 Bcf at September 30, 2002 and oil reserves decreased from 115,328 Mbbl to 99,717 Mbbl. These decreases are attributed to several factors: (i) production and sales of properties (refer to Item 7, MD&A), (ii) limited drilling activity off-shore in the Gulf of Mexico which resulted in a reserve replacement of only 56% of consolidated production (the Company is continuing to shift its emphasis from short-lived off-shore reserves to longer-lived on-shore reserves), and (iii) a determination that certain development drilling programs in California and Canada were uneconomic (reflected in Note N as revisions of previous estimates). Seneca’s oil and gas reserves reported in Note N as of September 30, 2003 were estimated by Seneca’s 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, a statistical agency of the U. S. Department of Energy (EIA). The basis of reporting Seneca’s 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 Seneca’s records. All monetary amounts are expressed in U.S. dollars.
Production
- ------------------------------------------------------------------------------------
For the Year Ended September 30 2003 2002 2001
- ------------------------------------------------------------------------------------
United States
Gulf Coast Region
Average Sales Price per Mcf of Gas $ 5.41 $ 2.89 $ 4.93
Average Sales Price per Barrel of Oil $ 29.17 $ 22.83 $ 27.47
Average Sales Price per Mcf of Gas
(after hedging) $ 4.22 $ 3.69 $ 3.65
Average Sales Price per Barrel of Oil
(after hedging) $ 27.88 $22.51 $ 24.11
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 0.56 $ 0.60 $ 0.41
Average Production per Day (in MMcf
Equivalent of Gas and Oil Produced) 75 100 115
- ------------------------------------------------------------------------------------
West Coast Region
Average Sales Price per Mcf of Gas $ 5.01 $ 2.86 $ 10.18
Average Sales Price per Barrel of Oil $ 26.12 $ 19.94 $ 24.06
Average Sales Price per Mcf of Gas
(after hedging) $ 5.12 $ 2.86 $ 7.81
Average Sales Price per Barrel of Oil
(after hedging) $ 23.67 $ 20.09 $ 20.67
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 1.00 $ 0.81 $ 0.81
Average Production per Day (in MMcf
Equivalent of Gas and Oil Produced) 59 63 59
- ------------------------------------------------------------------------------------
Appalachian Region
Average Sales Price per Mcf of Gas $ 5.07 $ 3.74 $ 5.03
14
Average Sales Price per Barrel of Oil $ 28.77 $ 23.76 $ 28.51
Average Sales Price per Mcf of Gas
(after hedging) $ 5.10 $ 3.74 $ 4.95
Average Sales Price per Barrel of Oil
(after hedging) $ 28.77 $ 23.76 $ 28.51
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 0.43 $ 0.53 $ 0.51
Average Production per Day (in MMcf
Equivalent of Gas and Oil Produced) 14 12 11
- ------------------------------------------------------------------------------------
Total United States
Average Sales Price per Mcf of Gas $ 5.28 $ 2.99 $ 5.53
Average Sales Price per Barrel of Oil $ 27.16 $ 21.03 $ 25.43
Average Sales Price per Mcf of Gas
(after hedging) $ 4.52 $ 3.58 $ 4.25
Average Sales Price per Barrel of Oil
(after hedging) $ 25.11 $ 21.01 $ 22.06
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 0.72 $ 0.67 $ 0.55
Average Production per Day (in MMcf
Equivalent of Gas and Oil Produced) 148 175 185
- ------------------------------------------------------------------------------------
Canada
Average Sales Price per Mcf of Gas $ 4.67 $ 2.29 $ 2.41
Average Sales Price per Barrel of Oil $ 26.41 $ 19.94 $ 24.29
Average Sales Price per Mcf of Gas
(after hedging) $ 4.20 $ 3.59 $ 2.41
Average Sales Price per Barrel of Oil
(after hedging) $ 15.85 $ 18.11 $ 20.85
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 1.65 $ 1.29 $ 1.34
Average Production per Day (in MMcf
Equivalent of Gas and Oil Produced) 55 64 55
- ------------------------------------------------------------------------------------
Total Company
Average Sales Price per Mcf of Gas $ 5.18 $ 2.88 $ 5.39
Average Sales Price per Barrel of Oil $ 26.90 $ 20.63 $ 24.99
Average Sales Price per Mcf of Gas
(after hedging) $ 4.47 $ 3.58 $ 4.17
Average Sales Price per Barrel of Oil
(after hedging) $ 21.84 $ 19.94 $ 21.59
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 0.97 $ 0.84 $ 0.73
Average Production per Day (in MMcf
Equivalent of Gas and Oil Produced) 203 239 240
- ------------------------------------------------------------------------------------
15
Productive Wells
- ----------------------------------------------------------------------------------------------------------------------
United States
----------------------------------------------------------------------------------------------
Gulf Coast Region West Coast Region Appalachian Region Total U. S.
- ----------------------------------------------------------------------------------------------------------------------
At September 30,
2003 Gas Oil Gas Oil Gas Oil Gas Oil
- ----------------------------------------------------------------------------------------------------------------------
Productive Wells -
Gross 31 38 - 1,119 1,874 31 1,905 1,188
Productive Wells -
Net 18 17 - 1,108 1,792 25 1,810 1,150
- ----------------------------------------------------------------------------------------------------------------------
Productive Wells
- ---------------------------------------------------------------------------------
Canada Total Company
- ---------------------------------------------------------------------------------
At September 30, 2003 Gas Oil Gas Oil
- ---------------------------------------------------------------------------------
Productive Wells - Gross 155 47 2,060 1,235
Productive Wells - Net 114 31 1,924 1,181
- ---------------------------------------------------------------------------------
Developed and Undeveloped Acreage
- -------------------------------------------------------------------------------------------------------------------------
United States
- -------------------------------------------------------------------------------------------------------------------------
Gulf Coast West Coast Appalachian Total Total
At September 30, 2003 Region Region Region U. S. Canada Company
- -------------------------------------------------------------------------------------------------------------------------
Developed Acreage - Gross 109,635 10,343 509,021 628,999 112,893 741,892
- Net 79,489 8,532 482,596 570,617 76,000 646,617
- -------------------------------------------------------------------------------------------------------------------------
Undeveloped Acreage - Gross 259,534 1,119 439,095 699,748 439,385 1,139,133
- Net 137,817 860 414,710 553,387 336,538 889,925
- -------------------------------------------------------------------------------------------------------------------------
As of September 30, 2003, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 131,844 acres in 2004 (107,191 net acres), 129,613 acres in 2005 (109,446 net acres), 101,610 acres in 2006 (93,458 net acres), and 776,066 acres thereafter (579,830 net acres).
Drilling Activity
- ------------------------------------------------------------------------------------------------------------------
Productive Dry
- ------------------------------------------------------------------------------------------------------------------
For the Year Ended September 30 2003 2002 2001 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------
United States
Gulf Coast Region
Net Wells Completed - Exploratory 1.25 1.27 2.83 - 3.67 1.93
- Development 2.10 0.31 4.64 - - -
West Coast Region
Net Wells Completed - Exploratory - - - - - -
- Development 30.97 47.99 86.96 - 2.00 1.00
Appalachian Region
Net Wells Completed - Exploratory 3.00 3.00 9.00 0.10 1.00 3.00
- Development 58.00 27.00 17.00 - 0.10 -
Total United States
Net Wells Completed - Exploratory 4.25 4.27 11.83 0.10 4.67 4.93
- Development 91.07 75.30 108.60 - 2.10 1.00
Canada
Net Wells Completed - Exploratory 5.00 0.20 10.00 2.50 4.00 11.00
- Development 17.16 33.70 61.14 5.00 7.90 2.75
Total
Net Wells Completed - Exploratory 9.25 4.47 21.83 2.60 8.67 15.93
- Development 108.23 109.00 169.74 5.00 10.00 3.75
- ------------------------------------------------------------------------------------------------------------------
16
Present Activities
- ---------------------------------------------------------------------------------------------------------------------------
United States
- ---------------------------------------------------------------------------------------------------------------------------
Gulf Coast West Coast Appalachian Total Total
At September 30, 2003 Region Region Region U. S. Canada Company
- ---------------------------------------------------------------------------------------------------------------------------
Wells in Process of Drilling(1) - Gross 1.00 3.00 21.00 25.00 36.00 61.00
- Net 0.67 3.00 20.05 23.72 25.08 48.80
- ---------------------------------------------------------------------------------------------------------------------------
(1) Includes wells awaiting completion.
South Lost Hills Waterflood Program
In Seneca's South Lost Hills Field, a waterflood project was initiated in 1996 on the Ellis lease in the Diatomite reservoir for pressure maintenance and recovery enhancement purposes. The waterflood project has matured and injection was ceased in early 2003. The current oil production from the Ellis lease is 220 barrels of oil per day from 88 production wells.
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) Seneca's co-defendants (i) fraudulently participated in and concealed such alleged underpayment, and (ii) induced Seneca's 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 court's order states that there are approximately 749 potential class members. Discovery has begun on the merits of the claims and the case will eventually be tried or settled.
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 Corporation's denial of natural gas service in November 2000 to the plaintiff's decedent, Velma Arlene Fordham, caused decedent's death in February 2001. Plaintiff seeks damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation has denied plaintiff's 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 plaintiff's allegations lack merit. On October 24, 2003, the Supreme Court, Kings County, entered an order granting Distribution Corporation's motion to change venue of the action to New York State Supreme Court, Erie County. Plaintiff has not appealed that order. For discussion of a related matter before the NYPSC, refer to Item 7 - MD&A of this report under the heading "Regulatory Matters."
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 of these matters, and it is possible that the outcomes, individually or in the aggregate, could be material to results of operations or cash flow for a particular quarter or annual period.*
For a discussion of various environmental and other matters, refer to Item 7, MD&A and Item 8 at Note G - Commitments and Contingencies.
17
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 Company's present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
No matter was submitted to a vote of security holders during the fourth quarter of 2003.
PART II
Information regarding the market for the Company's 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, 2003, the Company issued a total of 2,400 unregistered shares of Company common stock to the eight non-employee directors of the Company then serving on the Board of Directors, 300 shares to each such director. All of these unregistered shares issued on July 1, 2003 were issued as partial consideration for such directors' services during the quarter ended September 30, 2003, pursuant to the Company's 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.
18
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30 2003 2002 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Summary of Operations (Thousands)
Operating Revenues $2,035,471 $1,464,496 $2,059,836 $1,412,416 $1,254,402
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Purchased Gas 963,567 462,857 1,002,466 488,383 397,053
Fuel Used in Heat and
Electric Generation 61,029 50,635 54,968 54,893 55,788
Operation and Maintenance 386,270 394,157 364,318 350,383 328,800
Property, Franchise and Other Taxes 82,504 72,155 83,730 78,878 91,146
Depreciation, Depletion and
Amortization 195,226 180,668 174,914 142,170 124,778
Impairment of Oil and Gas
Producing Properties 42,774 - 180,781 - -
- ----------------------------------------------------------------------------------------------------------------------------------
1,731,370 1,160,472 1,861,177 1,114,707 997,565
Gain on Sale of Timber Properties 168,787 - - - -
Loss on Sale of Oil and Gas Producing
Properties (58,472) - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 414,416 304,024 198,659 297,709 256,837
Other Income (Expense):
Income from Unconsolidated
Subsidiaries 535 224 1,794 1,669 999
Impairment of Investment in
Partnership - (15,167) - - -
Other Income 6,887 7,017 10,639 6,366 11,344
Interest Expense on Long-Term Debt (92,766) (90,543) (81,851) (67,195) (65,402)
Other Interest Expense (12,290) (15,109) (25,294) (32,890) (22,296)
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes and
Minority Interest in Foreign Subsidiaries 316,782 190,446 103,947 205,659 181,482
Income Tax Expense 128,161 72,034 37,106 77,068 64,829
Minority Interest in Foreign Subsidiaries -
(Expense) (785) (730) (1,342) (1,384) (1,616)
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of
Changes in Accounting 187,836 117,682 65,499 127,207 115,037
Cumulative Effect of Changes in
Accounting (8,892) - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income Available for Common
Stock $178,944 $117,682 $65,499 $127,207 $115,037
- ----------------------------------------------------------------------------------------------------------------------------------
Per Common Share Data
Basic Earnings per Common Share $2.21(1) $1.47 $0.83 $1.63 $1.49
Diluted Earnings per Common Share $2.20(1) $1.46 $0.82 $1.61 $1.47
Dividends Declared $1.06 $1.03 $0.99 $0.95 $0.92
Dividends Paid $1.05 $1.02 $0.97 $0.94 $0.91
Dividend Rate at Year-End $1.08 $1.04 $1.01 $0.96 $0.93
At September 30:
Number of Common Shareholders 19,217 20,004 20,345 21,164 22,336
- ----------------------------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment (Thousands)
Utility $1,036,432 $960,015 $945,693 $939,753 $919,642
Pipeline and Storage 705,927 487,793 483,222 474,972 466,524
Exploration and Production 925,833 1,072,200 1,081,622 998,852 674,813
International 219,199 207,191 178,250 172,602 210,920
Energy Marketing 171 125 262 360 489
Timber 87,600 110,624 90,453 95,607 88,623
All Other 22,042 6,797 1,209 1,241 214
19
Corporate 1,883 - 2 4 7 - ---------------------------------------------------------------------------------------------------------------------------------- Total Net Plant $2,999,087 $2,844,745 $2,780,713 $2,683,391 $2,361,232 - ---------------------------------------------------------------------------------------------------------------------------------- Total Assets (Thousands) $3,727,915 $3,401,309 $3,445,231 $3,251,031 $2,842,586 - ---------------------------------------------------------------------------------------------------------------------------------- Capitalization (Thousands) Comprehensive Shareholders' Equity $1,137,390 $1,006,858 $1,002,655 $ 987,437 $ 939,293 Long-Term Debt, Net of Current Portion 1,147,779 1,145,341 1,046,694 953,622 822,743 - ---------------------------------------------------------------------------------------------------------------------------------- Total Capitalization $2,285,169 $2,152,199 $2,049,349 $1,941,059 $1,762,036 - ---------------------------------------------------------------------------------------------------------------------------------- (1) Includes cumulative effect of changes in accounting of ($0.11) basic and diluted.
20
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 Company's 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 Company's significant accounting policies, refer to Item 8 at Note A - Summary of Significant Accounting Policies.
Oil and Gas Exploration and Development Costs. In the Company's 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.
The Company believes that determining the amount of the Company's 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 depletion until it is determined whether or not there are proved reserves that can be assigned to these properties. Once it is determined whether there are proved reserves or not, these costs 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 Securities and Exchange Commission (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 and 2001. The impairments in 2003 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
21
decline in crude oil prices subsequent to March 31, 2003. The impairment in 2001 amounted to $104.0 million (after tax) and resulted from low oil and gas prices at September 30, 2001.
It is difficult to predict what factors could lead to future impairments under the SEC's 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. Management's assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. 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 the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company's regulatory assets and liabilities, refer to Item 8 at Note B - Regulatory Matters.
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 eliminate 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 Company's derivative financial instruments.
Pension and Other Post-Retirement Benefits. The amounts reported in the Company's 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."
22
2003 Compared with 2002
The Company's earnings were $178.9 million in 2003 compared with earnings of $117.7 million in 2002.
The increase in earnings of $61.2 million is 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 is impacted by several events. In 2003, the Company's Timber segment completed the sale of
approximately 70,000 acres of its timber property, recording an after tax gain of $102.2 million. Also in 2003,
the Company's Exploration and Production segment completed the sale of the Company's Southeast Saskatchewan oil
and gas properties in Canada, recording an after tax loss of $39.6 million. The Company's Exploration and
Production segment also recorded after tax impairment charges of $28.9 million related to its Canadian oil and
gas assets, which is discussed above under Critical Accounting Policies - Oil and Gas Exploration and Development
Costs. Earnings for 2003 included an impairment in the amount of $8.3 million, representing the cumulative
effect of a change in accounting for goodwill in the Company's International segment. Earnings for 2003 also
included 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 Company's Exploration and Production segment. In 2002, earnings
included a non-cash impairment of the Company's investment in the Independence Pipeline project in the Pipeline
and Storage segment in the amount of $9.9 million (after tax). 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.
2002 Compared with 2001
The Company's earnings were $117.7 million in 2002 compared with earnings of $65.5 million in 2001. Higher
earnings in the Exploration and Production segment and the Energy Marketing segment were partially offset by
lower earnings in the Utility and Pipeline and Storage segments. The All Other category also experienced a lower
loss. As mentioned above, earnings in 2002 included a non-cash impairment of the Company's investment in the
Independence Pipeline project in the Pipeline and Storage segment in the amount of $9.9 million (after tax).
Earnings in 2001 included a non-cash impairment of oil and gas assets in the Exploration and Production segment
in the amount of $104.0 million (after tax), which is discussed above under Critical Accounting Policies - Oil
and Gas Exploration and Development Costs. These events were the main reasons for lower 2002 earnings for the
Pipeline and Storage segment and higher 2002 earnings for the Exploration and Production segment. Additional
discussion of earnings in each of the business segments can be found in the business segment information that
follows.
Earnings (Loss) by Segment - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 (Thousands) 2003 2002 2001 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Utility $56,808 $49,505 $60,707 Pipeline and Storage 45,230 29,715 40,377 Exploration and Production (31,930) 26,851 (32,284) International (9,623) (4,443) (3,042) Energy Marketing 5,868 8,642 (3,432) Timber 112,450 9,689 7,715 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Reportable Segments 178,803 119,959 70,041 All Other 193 (885) (4,277) Corporate (52) (1,392) (265) - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Consolidated $178,944 $117,682 $65,499 - ---------------------------------------------------------------- ----------------- ---------------- -----------------
23
Utility Operating Revenues
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Retail Revenues:
Residential $801,984 $538,345 $ 875,050
Commercial 137,905 86,963 154,266
Industrial 23,263 18,332 29,110
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
963,152 643,640 1,058,426
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Off-System Sales 107,220 68,606 84,078
Transportation 86,374 83,267 89,037
Other 6,237 (1,292) 3,106
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$1,162,983 $794,221 $1,234,647
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Utility Throughput - million cubic feet (MMcf)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2003 2002 2001
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Retail Sales:
Residential 76,449 64,639 73,530
Commercial 14,177 11,549 13,831
Industrial 3,537 3,715 4,089
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
94,163 79,903 91,450
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Off-System Sales 17,999 21,541 12,736
Transportation 64,232 61,909 66,283
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
176,394 163,353 170,469
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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.
The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues), coupled with an increase in retail sales volumes, as shown above. 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.” The increase in retail sales volumes was primarily the result of colder weather, as shown in the table below. 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 a three-year rate settlement approved by the State of New York Public Service Commission (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 reversed $7.6 million of the cost mitigation reserve into 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 has been recording 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.
24
2002 Compared
with 2001
Operating revenues for the
Utility segment decreased $440.4 million in 2002 compared with 2001. This
decrease largely resulted from a $414.8 million decrease in retail gas sales
revenues. Off-system sales revenues, transportation revenues, and other revenues
also decreased by $15.5 million, $5.8 million and $4.3 million, respectively.
The decrease in retail gas sales revenues for the Utility segment was largely a function of the recovery of lower gas costs resulting from a much lower cost of purchased gas. See further discussion of purchased gas below under the heading “Purchased Gas.” The decrease also resulted from a decrease in retail sales volumes, as shown above. Warmer weather, as shown in the table below, and a general economic downturn in the Utility segment’s sales territory were major factors for the decrease in retail sales volumes. Warmer weather and the general economic downturn were also factors in the decrease in transportation revenues and volumes. The decrease in off-system sales revenues was largely due to lower gas prices, which more than offset higher volumes.
The decrease in other revenues primarily reflects estimated refund provisions recorded in 2002 and 2001 amounting to $5.3 million and $2.0 million, respectively, recorded in the Utility segment’s New York jurisdiction under the earnings sharing mechanism discussed above.
Partly offsetting the decreases to revenue discussed above was the positive impact of a lower bill credit in the Utility segment’s New York jurisdiction. In connection with a New York rate settlement, the Utility’s New York customers received a $10.0 million rate decrease in the form of a bill credit for the November 1, 2000 through March 31, 2001 heating season. For the November 1, 2001 through March 31, 2002 heating season, the amount of the bill credit was reduced to $5.0 million.
2003 Compared
with 2002
The Utility segment’s
earnings in 2003 were $56.8 million, an increase of $7.3 million when compared
with the earnings of $49.5 million in 2002. The major factor driving this
increase was the impact of colder weather in the Utility segment’s
Pennsylvania jurisdiction, which contributed approximately $5.6 million to the
increase in earnings. The impact of weather on the Utility segment’s 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
segment’s New York customers. In 2003, the WNC reduced earnings by
approximately $3.8 million (after tax) because it was colder than normal in the
New York service territory. For 2002, the WNC preserved earnings of
approximately $9.9 million (after tax) because it was warmer than normal in the
New York service territory. The remainder of the increase was primarily
attributable to lower interest expense, primarily on deferred gas costs (which
declined approximately $1.0 million after tax).
2002 Compared
with 2001
The Utility segment’s
earnings in 2002 were $49.5 million, a decrease of $11.2 million when compared
with earnings of $60.7 million in 2001. Warmer weather in the Pennsylvania
jurisdiction decreased earnings in 2002 by $3.7 million. Lower normalized usage
per account (normalized usage excludes the impact of weather on consumption)
across the Utility segment’s service territory due to a downturn in the
economy significantly decreased earnings in 2002 by $2.9 million. Also
contributing to the decrease were several routine regulatory true-up adjustments
associated with income taxes, lost and unaccounted for gas and interest expense,
all of which decreased earnings by $6.5 million. In addition, 2001‘s
earnings included $3.1 million (after tax) of income associated with stock
appreciation rights and $4.2 million of after tax expense associated with early
retirement offers in the Utility segment’s New York and Pennsylvania
jurisdictions. The impact of the refund provision discussed above was largely
offset by lower operation and maintenance expenses, primarily labor. Earnings in
2002 benefitted from the impact of the lower bill credit ($5.0 million pre tax
and $3.3 million after tax), discussed above.
In 2002, the WNC preserved earnings of approximately $9.9 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 2001 through May 2002. In the Pennsylvania service territory, which does not have a WNC, weather during 2002 was 16.0% warmer than 2001 and 13.2% warmer than normal.
25
Degree Days
- ---------------------------------- -------------- -------------- -------------------- --------------------------------
Percent (Warmer)
Colder Than
--------------------------------
Year Ended September 30 Normal Actual Normal Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
2003: Buffalo 6,815 7,137 4.7% 22.9%
Erie 6,135 6,769 10.3% 26.9%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
2002: Buffalo 6,847 5,808 (15.2%) (12.6%)
Erie 6,146 5,334 (13.2%) (16.0%)
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
2001: Buffalo 6,865 6,648 (3.2%) 5.3%
Erie 6,179 6,351 2.8% 12.3%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Purchased Gas
The cost of purchased gas
is the Company’s 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 Corporation’s average cost of purchased gas, including the cost of transportation and storage, was $6.94 per thousand cubic feet (Mcf) in 2003, an increase of 48% from the average cost of $4.68 per Mcf in 2002. The average cost of purchased gas in 2002 was 36% lower than the average cost of $7.35 per Mcf in 2001. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.
Pipeline and Storage Operating Revenues
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation $109,508 $88,082 $91,611
Interruptible Transportation 3,944 3,315 1,917
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
113,452 91,397 93,528
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Storage Service 63,223 62,733 61,559
Interruptible Storage Service 36 7 670
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
63,259 62,740 62,229
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Other 24,709 13,247 15,334
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$201,420 $167,384 $171,091
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Pipeline and Storage Throughput - (MMcf)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2003 2002 2001
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation 340,925 290,507 304,183
Interruptible Transportation 10,004 7,315 17,372
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
350,929 297,822 321,555
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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 State Pipeline (Empire) from Duke
Energy Corporation on February 6, 2003 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 ($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 $6.5 million
increase in revenues from unbundled pipeline sales and open access
transportation included in other revenues in the table above. The increase in
revenues from unbundled pipeline sales and open access transportation primarily
reflects higher natural gas commodity prices.
26
While transportation volumes increased during the year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design.
2002 Compared
with 2001
Operating revenues for the
Pipeline and Storage segment decreased $3.7 million in 2002 as compared with
2001. For 2002, the decrease resulted primarily from a $2.1 million decrease in
transportation revenues, as shown in the table above, and a $1.6 million
decrease in cashout revenues 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 Corporation’s system by the customer’s
shipper. Cashout revenues are offset by purchased gas expense. The decrease in
transportation revenues primarily reflects lower gathering rates (the rates
charged by Supply Corporation to its transportation customers to move gas from a
third-party well site or nearby meter to Supply Corporation’s transmission
pipelines for delivery) as a result of a provision in a February 1996 settlement
with FERC that ended in 2001. However, this rate decrease is largely offset by a
reduction in amortization expense, thus having little impact on net income.
Another impact of this settlement was that Supply Corporation no longer had the
responsibility to process gas for local producers. As such, there was a
reduction in gas processing revenues. However, this reduction was offset by
higher revenues from unbundled pipeline sales and open access transportation.
Both gas processing revenues and revenues from unbundled pipeline sales and open
access transportation are included in other revenues in the table above. While
transportation volumes decreased during the year, volume fluctuations generally
do not have a significant impact on revenues as a result of Supply
Corporation’s straight fixed-variable rate design.
2003 Compared
with 2002
The Pipeline and Storage
segment’s 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 Company’s 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 and open access transportation ($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.
2002 Compared
with 2001
The Pipeline and Storage
segment’s earnings in 2002 were $29.7 million, a decrease of $10.7 million
when compared with earnings of $40.4 million in 2001. As discussed above, the
earnings for 2002 included a $9.9 million after tax impairment charge associated
with the Company’s investment in Independence Pipeline Company. Other
factors contributing to the decrease included $4.2 million of earnings
associated with stock appreciation rights recorded in 2001 and $2.6 million of
earnings in 2001 associated with a termination fee received from a customer to
cancel a long-term transportation contract. These decreases were partially
offset by the fact that 2001 included $1.1 million of after tax expense
associated with early retirement offers. Aside from the decrease in operation
and maintenance expense associated with the early retirement offers in 2001, the
Pipeline and Storage segment also experienced operation and maintenance expense
savings in 2002 of $1.6 million after tax. A lower effective tax rate in 2002
compared to 2001 also helped to reduce the earnings decrease in 2002 by $3.2
million.
27
Exploration and Production Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Gas (after Hedging) $150,982 $148,467 $171,045
Oil (after Hedging) 147,101 152,746 169,613
Gas Processing Plant 28,879 16,995 39,986
Other 1,308 6,627 17,700
Intrasegment Elimination (1) (22,956) (13,855) (43,339)
- --------------------------------------------------------------- ----------------- ---------------- -----------------
$305,314 $310,980 $355,005
- --------------------------------------------------------------- ----------------- ---------------- -----------------
(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 plant's purchased gas expense.
Production Volumes
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2003 2002 2001
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Gas Production (MMcf)
Gulf Coast 18,441 25,776 30,663
West Coast 4,467 4,889 4,383
Appalachia 5,123 4,402 4,142
Canada 5,774 6,387 1,816
- --------------------------------------------------------------- ----------------- ---------------- -----------------
33,805 41,454 41,004
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Oil Production (Mbbl)
Gulf Coast 1,473 1,815 1,914
West Coast 2,872 3,004 2,875
Appalachia 10 9 7
Canada 2,382 2,834 3,061
- --------------------------------------------------------------- ----------------- ---------------- -----------------
6,737 7,662 7,857
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Average Prices
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2003 2002 2001
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Average Gas Price/Mcf
Gulf Coast $5.41 $2.89 $4.93
West Coast $5.01 $2.86 $10.18
Appalachia $5.07 $3.74 $5.03
Canada $4.67 $2.29 $2.41
Weighted Average $5.18 $2.88 $5.39
Weighted Average After Hedging(1) $4.47 $3.58 $4.17
Average Oil Price/Barrel (bbl)
Gulf Coast $29.17 $22.83 $27.47
West Coast(2) $26.12 $19.94 $24.06
Appalachia $28.77 $23.76 $28.51
Canada $26.41 $19.94 $24.29
Weighted Average $26.90 $20.63 $24.99
Weighted Average After Hedging(1) $21.84 $19.94 $21.59
- --------------------------------------------------------------- ----------------- ---------------- -----------------
(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.
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
28
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 of Mexico (a 7,335 MMcf decline). The Company had anticipated some of this decline in gas and oil production due to its plan to phase out of 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 Company's Southeast Saskatchewan oil properties, which is discussed below. Also, earlier in the year certain production in the Gulf Coast region was shut-in during Hurricane Lili and some of those wells are not expected to return to pre-hurricane production levels.* Gas processing plant revenues increased $11.9 million due to higher gas prices (because there is a similar increase in purchased gas expense, the impact on earnings is insignificant). Other revenues decreased $5.3 million largely due to the Exploration and Production segment experiencing negative mark-to-market adjustments on derivative financial instruments of $1.9 million during 2003 compared to positive mark-to-market adjustments on derivative financial instruments of $2.7 million in 2002.
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.
2002 Compared
with 2001
Operating revenues for the Exploration and Production segment decreased $44.0 million in 2002 as compared with
2001. Oil production revenue after hedging decreased $16.9 million due primarily to a $1.65 per bbl decrease in
the weighted average price of oil after hedging. Gas production revenue after hedging, decreased $22.6 million.
Decreases in the weighted average price of gas after hedging ($0.59 per Mcf) more than offset an overall increase
in gas production. The overall increase in gas production is largely attributable to the Canadian properties
acquired in June 2001 (i.e., the Player Petroleum Corporation acquisition) (Player) offset partially by decreased
production in the Gulf Coast region. As discussed above, the plan to phase out of the Gulf Coast region
contributed to this decrease in oil and gas production. Gas processing plant revenues decreased $23.0 million
due to significantly lower gas prices. Other revenues decreased $11.1 million largely due to mark-to-market gains
on derivative financial instruments that were recorded in 2001.
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 Company's 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. The sale of these properties is expected to reduce the Exploration and Production
segment's 2004 oil and gas production in Canada by approximately 2,000 Mbbl and 140 MMcf, respectively.*
However, the impact to 2004 earnings is expected to be minimal as lower production revenues will be offset by lower
depletion expense.* After tax impairment charges of $28.9 million recorded in 2003 related to the Company's
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 (attributable to the production decline) and lower general
and administrative expenses of $2.1 million (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.
2002 Compared
with 2001
The Exploration and Production segment's earnings in 2002 were $26.9 million, an increase of $59.2 million when
compared with a loss of $32.3 million in 2001. A major reason for the increase was that 2001 earnings included
a non-cash impairment of this segment's oil and gas assets totaling $104.0 million after tax, as previously
discussed. Partially offsetting this positive impact was a decline in oil and gas revenues, which decreased
earnings by approximately $25.7 million, due to lower weighted average commodity prices of crude oil and natural
gas after hedging due to an increase in workover expenses ($1.65 per bbl and $0.59 per Mcf, respectively). Also,
the decrease in other revenues associated with mark-to-market gains recorded in 2001, as discussed above, reduced
earnings by $7.2 million. Higher
29
lease operating expenses in the Gulf Coast region, due to an increase in workover expenses, also reduced earnings by approximately $3.0 million. The major workover expenditures occurred on Vermilion 252 and Eugene Island Block 264.
International
International Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Heating $80,752 $65,386 $69,072
Electricity 29,386 26,960 26,398
Other 3,932 2,969 2,440
- --------------------------------------------------------------- ----------------- ---------------- -----------------
$114,070 $95,315 $97,910
- --------------------------------------------------------------- ----------------- ---------------- -----------------
International Heating and Electric Volumes
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2003 2002 2001
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Heating Sales (Gigajoules) (1) 8,714,806 8,689,887 9,978,118
Electricity Sales (megawatt hours) 973,968 972,832 1,019,901
- --------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Gigajoules = one billion joules. A joule is a unit of energy.
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 (CZK)
compared to the U.S. dollar.
2002 Compared
with 2001
Operating revenues for the International segment decreased $2.6 million in 2002 as compared with 2001. The
decrease in heat revenues in 2002 compared to 2001 reflects the June 2001 sale of Jablonecka teplarenska a
realitni, a.s. (a district heating plant located in the Czech Republic which had heating revenues of $7.1 million
in 2001, and heating volumes of 685,137 gigajoules in 2001). It also reflects the impact of weather in the Czech
Republic, which was 5% warmer in 2002 than in the prior year. However, an increase in the average value of the
CZK compared to the U.S. dollar offset much of the impact of these negative factors.
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
Company's change in accounting for goodwill. The Company's goodwill balance as of October 1, 2002 totaled $8.3
million and was related to the Company's investments in the Czech Republic, which are included in the
International segment. In accordance with SFAS 142, "Goodwill and Other Intangible Assets" (SFAS 142), the
Company stopped amortization of goodwill and tested its goodwill for impairment as of October 1, 2002. The
Company used discounted cash flows to estimate the fair value of its goodwill at October 1, 2002 and determined
that the goodwill had no remaining value. Based on projected restructuring in the Czech electricity market, the
Company cannot be assured that the level of future cash flows from the Company's investments in the Czech
Republic will attain the level that was originally forecasted.* In accordance with SFAS 142, this impairment was
reported as a cumulative effect of a change in accounting in the quarter ending December 31, 2002. Partially
offsetting the negative impact of the impairment, an increase in the value of the CZK compared to the U.S. dollar
reduced the 2003 loss by approximately $1.0 million. Lower operating costs at the U.S. level (primarily lower
project development costs and pension costs) further reduced the 2003 loss by approximately $1.0 million.
30
2002 Compared
with 2001
The International segment experienced a loss of $4.4 million in 2002 compared with a loss of $3.0 million in
2001. Higher operation and maintenance expense of approximately $4.0 million after tax, largely associated with
the Company's European power development projects, was the main factor in the higher loss in 2002. Lower
interest expense of approximately $0.8 million after tax, and a higher effective tax rate (the impact of which
was approximately $1.6 million) partially offset the impact of higher operation and maintenance expenses.
Energy Marketing Operating Revenues
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Natural Gas (after Hedging) $304,390 $151,219 $257,005
Electricity - - 1,362
Other 270 38 839
- ------------------------------------------------------------- ------------------- ------------------ -------------------
$304,660 $151,257 $259,206
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Energy Marketing Volumes
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 2003 2002 2001
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Natural Gas - (MMcf) 45,325 33,042 36,753
- ------------------------------------------------------------- ------------------- ------------------ -------------------
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 customers and colder weather, also
contributed to the increase in operating revenues.
2002 Compared
with 2001
Operating revenues for the
Energy Marketing segment decreased $107.9 million in 2002, as compared with
2001. This decrease was primarily the result of lower natural gas commodity
prices that were recovered through revenues. Lower volumes, which were
principally the result of warmer weather, also contributed to the decrease in
operating revenues.
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, primarily due to end of winter local distribution
company operational constraints, combined with price volatility and weather
related demand swings.
2002 Compared
with 2001
The Energy Marketing
segment earnings in 2002 were $8.6 million, an increase of $12.0 million when
compared with a loss of $3.4 million in 2001. This increase primarily reflects
higher margins on gas sales and lower interest and operation and maintenance
expenses. Margins increased as a result of improved operational strategies put
in place by the Energy Marketing segment’s new management team.
31
Timber Operating Revenues
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Log Sales $27,341 $21,528 $23,460
Green Lumber Sales 6,200 6,567 5,597
Kiln Dry Lumber Sales 21,814 15,976 12,320
Other 871 3,336 3,537
- ------------------------------------------------------------- ------------------- ------------------ -------------------
$56,226 $47,407 $44,914
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Timber Board Feet
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Log Sales 8,764 8,174 8,839
Green Lumber Sales 11,913 12,878 10,332
Kiln Dry Lumber Sales 13,300 10,794 8,804
- ------------------------------------------------------------- ------------------- ------------------ -------------------
33,977 31,846 27,975
- ------------------------------------------------------------- ------------------- ------------------ -------------------
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.
2002 Compared
with 2001
Operating revenues for the
Timber segment increased $2.5 million in 2002, as compared with 2001. When
comparing 2002 to 2001, log sales decreased $1.9 million as weather that was
warmer and wetter than normal during the first and second quarters of 2002
hampered the ability to cut and haul logs, specifically cherry veneer logs. The
Company made up for this lost revenue through higher sales of lumber. Green
lumber sales increased $1.0 million and kiln dry lumber sales increased $3.7
million (mostly due to an increase in kiln dry cherry volumes).
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 an
after tax gain of approximately $102.2 million. The Company decided to sell
the timber property as a means of financing its acquisition of Empire, which is discussed below under “Capital Resources and Liquidity
– Investing Cash Flow – Timber”. Earnings from the Timber segment
(exclusive of the $102.2 million after tax gain referred to above) are expected
to decline in 2004 due to the fact that a greater portion of timber sales will
be made from higher cost basis properties.* In prior fiscal years, sales from
lower cost basis properties (a large portion of which were sold in 2003)
represented a more significant percentage of total timber sales. After the
August sale, the Company had approximately 87,000 acres of timber property remaining.
2002 Compared
with 2001
The Timber segment earnings
in 2002 were $9.7 million, an increase of $2.0 million when compared with
earnings of $7.7 million in 2001. The increase was primarily due to higher
operating revenues, as mentioned above, and lower interest expense. The increase
in operating revenues was primarily due to an increase in kiln dry cherry lumber
sales volumes.
32
2003 Compared
with 2002
Corporate and All Other
operations had earnings of $0.1 million in 2003, an increase of $2.4 million
when compared with a loss of $2.3 million in 2002. Earnings increased largely
due to lower interest and operation costs.
2002 Compared
with 2001
Corporate and All Other
operations experienced a loss of $2.3 million in 2002, an improvement of $2.2
million over the loss of $4.5 million in 2001. The loss for 2001 included $0.7
million of earnings associated with stock appreciation rights and $3.5 million
of after tax expense associated with a mark-to-market loss on natural gas
inventory by Upstate, the Company’s wholly-owned subsidiary which was
engaged in wholesale natural gas marketing and other energy-related activities
in 2001 (as noted in Item 1, Upstate is currently engaged primarily in the
purchase, sale and transportation of landfill gas).
Operations of
Unconsolidated Subsidiaries
The Company’s
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. The Company also had a 33-1/3% equity method investment in
Independence Pipeline Company which was written off in 2002, as previously
discussed. The write-off of $15.2 million ($9.9 million after tax) is recorded
on the Consolidated Statement of Income as Impairment of Investment in
Partnership.
2003 Compared
with 2002
Income from unconsolidated
subsidiaries (which represents the Company’s equity method interest in the
income or loss from its investment in unconsolidated subsidiaries) increased
$0.3 million in 2003 compared with 2002. The improvement can largely be
attributed to increases in income from the Company’s investments in Seneca
Energy ($0.8 million) and Model City ($0.3 million). Higher electric generation
revenues and lower repair and maintenance expenditures on the generating engines
were the main factors for the Seneca Energy and Model City increases. Partially
offsetting these positive contributions, the ESNE investment experienced higher
losses in 2003 compared to 2002 ($0.8 million). ESNE experienced lower electric
generation revenues in 2003 compared to 2002, largely due to the fact that the
spring and summer of 2003 was not as warm as the spring and summer of 2002. ESNE
generates most of its electricity during the spring and summer months when
electricity demand peaks for air conditioning requirements.
2002 Compared
with 2001
Income from unconsolidated
subsidiaries decreased $1.6 million in 2002 compared with 2001. This decrease is
largely attributable to losses experienced by the ESNE investment during 2002 of
$0.1 million compared to income in the prior year of $0.9 million. ESNE was
formed on April 30, 2001 so income for 2001 did not reflect any of the normal
operating losses that ESNE incurs during the fall and winter months. ESNE
generates most of its electricity during the spring and summer months when
electricity demand peaks for air conditioning requirements. ESNE experienced
higher electric generation revenues in the spring and summer of 2001 compared
with the same period in 2002. The Seneca Energy investment also experienced an
earnings decrease of $0.6 million due to lower electric generation revenues and
higher repair and maintenance expenditures on the generating engines.
Other Income
and Interest Charges
Although most of the
variances in Other Income items and Interest Charges are discussed in the
earnings discussion by segment above, following is a summary on a consolidated
basis:
Other income decreased $0.1 million and $3.6 million in 2003 and 2002, respectively. The decrease in 2002 resulted primarily from a $4.0 million termination fee received in 2001 from a customer in the Pipeline and Storage segment to cancel a long-term transportation contract. The Company was able to market the excess capacity resulting from this termination.
33
Interest Charges
Interest on long-term debt
increased $2.2 million in 2003 and $8.7 million in 2002. The increase in both
years 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 $2.8 million in 2003 and $10.2 million in 2002. 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.
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
Sources (Uses) of Cash - ----------------------------------------------------------- -------------------- ------------------- -------------------- Year Ended September 30 (Millions) 2003 2002 2001 - ----------------------------------------------------------- -------------------- ------------------- -------------------- Provided by Operating Activities $326.8 $345.6 $414.0 Capital Expenditures (152.2) (232.4) (292.7) Investment in Subsidiaries, Net of Cash Acquired (228.8) - (90.6) Investment in Partnerships (0.4) (0.5) (1.8) Net Proceeds from Sale of Timber Properties 186.0 - - Net Proceeds from Sale of Oil and Gas Producing Properties 78.5 22.1 2.1 Other Investing Activities 12.1 5.0 (4.9) Short-Term Debt, Net Change (147.6) (224.8) (143.4) Long-Term Debt, Net Change 20.7 139.6 187.2 Issuance of Common Stock 17.0 10.9 11.5 Dividends Paid on Common Stock (84.5) (81.0) (76.7) Effect of Exchange Rates on Cash 1.6 1.5 (0.6) - ----------------------------------------------------------- -------------------- ------------------- -------------------- Net Increase (Decrease) in Cash and Temporary Cash Investments $29.2 $(14.0) $4.1 - ----------------------------------------------------------- -------------------- ------------------- --------------------
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 and 2001), 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 on sale of timber properties, 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 segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation’s 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 and futures contracts in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $326.8 million in 2003, a decrease of $18.8 million compared with the $345.6 million provided by operating activities in 2002. Higher working capital requirements in the Utility and Energy Marketing segments were the main reasons for this decrease.
34
These decreases were partially offset by higher cash from operations in the Exploration and Production segment.
Investing Cash FlowExpenditures
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 Company’s expenditures for long-lived assets totaled $381.4 million in 2003. The table below presents these expenditures:
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Total
Investments Expenditures
Capital in Corporations For Long-
Year Ended September 30, 2003 (Millions) Expenditures or Partnerships Lived Assets
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Utility $49.9 $ - $49.9
Pipeline and Storage 18.2 181.2(1) 199.4
Exploration and Production 75.8 - 75.8
International 2.5 - 2.5
Energy Marketing 0.2 - 0.2
Timber 3.5 - 3.5
All Other and Corporate 2.1 48.0(2) 50.1
- ----------------------------------------------------------- ------------------- ------------------- -----------------
$152.2 $229.2 $381.4
- ----------------------------------------------------------- ------------------- ------------------- -----------------
(1) Investment amount is net of $8.0 million of cash acquired.
(2) Investment amount is net of $0.2 million of cash acquired.
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 segment’s capital expenditures were made for
additions, improvements and replacements to this segment’s transmission and
gas storage systems.
On February 6, 2003, the Company acquired the Empire State Pipeline (Empire) from a subsidiary of Duke Energy Corporation for $189.2 million in cash (including cash acquired) plus $57.8 million of project debt. The acquisition, which was made through Highland (a direct subsidiary having timber property and sawmill operations in New York and Pennsylvania), consisted of acquiring 100% of two companies. Each of these companies had 50% ownership of Empire, which is a joint venture. Empire’s results of operations were incorporated into the Company’s 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 Company’s 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. Refer to Item 1, “The Pipeline and Storage Segment” for a discussion of Empire’s transportation capacity. Empire delivers natural gas supplies to major industrial companies, utilities (including the Company’s Utility segment) and power producers. 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.* The initial financing of the acquisition was accomplished through short-term borrowings. These short-term borrowings were repaid when the Company completed the sale of 70,000 acres of timber property on August 1, 2003. The sale of this timber property is discussed below under “Timber.”
Exploration
and Production
The Exploration and
Production segment’s capital expenditures included approximately $54.0
million of capital expenditures for on-shore drilling, construction and
recompletion costs for wells located in Louisiana, Texas, California and Canada
as well as on-shore geological and geophysical costs and fixed
35
asset purchases. Of the $54.0 million discussed above, $30.8 million was spent on the Exploration and Production segment’s Canadian properties. The Exploration and Production segment’s capital expenditures also included approximately $21.8 million for its off-shore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construction, lease acquisition costs and geological and geophysical expenditures. During 2003, the Company spent $1.7 million (included in the amounts above) developing proved undeveloped reserves.
In September 2003, the Company sold its Southeast Saskatchewan oil and gas properties in Canada for approximately $76.0 million as previously discussed. The Company used the proceeds from the sale to repay short-term borrowings.
International
The majority of the
International segment’s 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
segment’s capital expenditures were for purchases of timber, as well as
equipment and vehicles for this segment’s sawmill and kiln operations.
As discussed above, the Company sold approximately 70,000 acres of its timber property located in various counties in Pennsylvania and Allegany County in New York in August 2003. The sale price was approximately $186.0 million. The Company recorded a pre-tax gain on this sale of approximately $168.8 million ($102.2 million after tax). The Company used the proceeds from this sale to repay short-term borrowings in connection with the Empire acquisition.
The remaining capital expenditures were for smaller purchases of land and timber for Seneca’s timber operations as well as equipment for Highland’s sawmill and kiln operations.
All Other and
Corporate
The majority of the All
Other and Corporate capital expenditures were for capital improvements to the
Company’s new corporate headquarters.
On June 3, 2003, the Company acquired for approximately $47.8 million in cash (including cash acquired of $0.2 million) all of the partnership interests in Toro Partners, LP (Toro), limited partnership which owns and operates eight 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. Toro’s results of operations were incorporated into the Company’s 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.*
In May 2003, the Company made a capital contribution of $0.4 million to Seneca Energy. This capital contribution was related to the expansion of Seneca Energy’s electric generation facilities to a new site at a landfill in Ontario County, New York.
Estimated
Capital Expenditures
The Company's estimated capital expenditures for the next three years are:*
------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Millions) 2004 2005 2006
------------------------------------------------------------- ----------------- ---------------- -----------------
Utility $53.0 $51.0 $51.0
Pipeline and Storage 27.0 29.0 26.0
Exploration and Production (1) 90.0 95.0 95.0
International 11.0 6.0 5.0
Timber 1.0 - -
All Other 10.0 1.0 -
------------------------------------------------------------- ----------------- ---------------- -----------------
$192.0 $182.0 $177.0
------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Includes estimated expenditures for the years ended September 30, 2004, 2005 and
2006 of approximately $24 million, $17 million and $26 million, respectively, to
develop proved undeveloped reserves.
36
Estimated capital expenditures for the Utility segment in 2004 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 2004 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. This includes the Northwinds Pipeline that the Company and TransCanada PipeLines Limited have proposed. This project presently contemplates a 215-mile, 30-inch natural gas pipeline that would originate in Kirkwall, Ontario, cross into the United States near Buffalo, New York and follow a southerly route to its destination in the Ellisburg-Leidy area in Pennsylvania. At September 30, 2003, the Company had incurred approximately $1.4 million in costs (all of which have been expensed) associated with this project. The initial capacity of the pipeline would be approximately 500 million cubic feet of natural gas per day with the estimated cost of the pipeline ranging from $350.0 million to $400.0 million. If the pipeline is constructed, it is possible that a significant amount of the construction costs would be financed by banks or other financial institutions with the pipeline serving as collateral for the financing arrangement.*
Estimated capital expenditures in 2004 for the Exploration and Production segment include approximately $38.2 million for Canada, $24.1 million for the Gulf Coast region ($23.5 million on the off-shore program in the Gulf of Mexico), $15.1 million for the West Coast region and $12.6 million for the Appalachian region.*
The estimated capital expenditures for the International segment in 2004 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 Company’s European power development projects. Currently, any costs incurred on these power development projects are expensed. The Company’s European power development projects are primarily in Italy and 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 127-megawatt gas-fired combustion turbines. The estimated cost of this project is $180.0 million to $200.0 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.*
Estimated capital expenditures in the Timber segment will be concentrated on the construction or purchase of new facilities and equipment for this segment’s sawmill and kiln operations.*
The estimated capital expenditures in the All Other category in 2004 will be concentrated on the purchase and installation of a gas turbine and steam turbine by Horizon Power to create a 55-megawatt facility in Buffalo, New York.*
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 storage facilities and the expansion of transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.*
Financing Cash FlowIn February 2003, the Company issued $250.0 million of 5.25% long-term notes due in March 2013. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to approximately $248.5 million. The proceeds of this debt issuance were used to refund $150.0 million of
37
7.30% medium-term notes which matured in February 2003. The remaining proceeds were used to reduce short-term borrowings.
In March 2003, the Company redeemed $50.0 million of 8.48% medium-term notes at a redemption price of $52.5 million. The Company also redeemed $2.3 million of 6.214% medium-term notes in March 2003 at a redemption price of $2.25 million. The Company used short-term borrowings to redeem this debt.
Consolidated short-term debt decreased $147.2 million during 2003. Proceeds of $76.0 million received from the sale of the Company’s Southeast Saskatchewan oil and gas properties were used to reduce short-term debt, as previously discussed. The other major factors contributing to the fluctuation in short-term debt were the issuance of long-term debt in February 2003 and the redemption of long-term debt in March 2003, both of which are discussed above. 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, 2003, the Company had outstanding short-term notes payable to banks and commercial paper of $55.2 million and $63.0 million, respectively. The Company has Securities and Exchange Commission (SEC) authorization under the Public Utility Holding Company Act of 1935, as amended, 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 $415.0 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 Company’s commercial paper program is $200.0 million. The commercial paper program is backed by a committed credit facility totaling $220.0 million. Of that amount, $110.0 million is committed to the Company through September 26, 2004 and $110.0 million is committed to the Company through September 30, 2005.
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not at the last day of any fiscal quarter, exceed .65 from September 30, 2002 through September 30, 2003, .625 from October 1, 2003 through September 30, 2004 and .60 from October 1, 2004 and thereafter. At September 30, 2003, the Company’s debt to capitalization ratio (as calculated under the facility) was .57. The constraints specified in the committed credit facility would permit an additional $145.0 million in short-term and/or long-term debt to be outstanding before the Company’s debt to capitalization ratio would exceed .625. If a downgrade in any of the Company’s 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 Company’s existing indenture covenants, at September 30, 2003, the Company would have been permitted to issue up to a maximum of $289.0 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 Company’s present liquidity position is believed to be adequate to satisfy known demands.*
The Company’s indenture pursuant to which $624.0 million (or 45%) of the Company’s long-term debt (as of September 30, 2003) 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 to become due prior to its stated maturity, unless cured or waived.
38
The Company’s committed $220.0 million, 364-day/3-year 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 its significant subsidiaries fail 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 such indebtedness to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2003, the Company had no debt outstanding under the committed credit facility.
The Company’s embedded cost of long-term debt was 6.5% at September 30, 2003 and 7.0% at September 30, 2002. Refer to “Interest Rate Risk” in this Item for a more detailed break-down of the Company’s embedded cost of long-term debt.
The Company also has authorization from the SEC, 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 order’s authorization period, which commenced in November 2002 and extends to December 31, 2005. In January 2003, the Company registered $800.0 million of debt and equity securities under the Securities Act of 1933. After the February 2003 debt issuance discussed above, the Company has available capacity to issue an additional $550.0 million of debt and equity securities registered under the Securities Act of 1933. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company’s 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 Company’s 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 $28.9 million. These leases have been entered into for the use of
vehicles, construction tools, meters, computer equipment and other items and are
accounted for as operating leases. The Company’s unconsolidated
subsidiaries, which are accounted for under the equity method, have capital
leases of electric generating equipment having a remaining lease commitment of
approximately $10.2 million. The Company has guaranteed 50%, or $5.1 million, of
these capital lease commitments.
Contractual
Obligations
The following table summarizes the Company’s expected future contractual
cash obligations as of September 30, 2003, and the twelve-month periods over
which they occur:
- ------------------------------ -----------------------------------------------------------------------------------------------
Payments by Expected Maturity Dates
-----------------------------------------------------------------------------------------------
------------ ----------- ------------ ------------ -------------- -------------- --------------
(Millions) 2004 2005 2006 2007 2008 Thereafter Total
- ------------------------------ ------------ ----------- ------------ ------------ -------------- -------------- --------------
Long-Term Debt $241.7 $14.6 $13.9 $9.3 $209.3 $900.7 $1,389.5
Short-Term Bank Notes $55.2 $ - $ - $ - $ - $ - $55.2
Commercial Paper $63.0 $ - $ - $ - $ - $ - $63.0
Operating Lease
Commitments $7.4 $6.0 $4.5 $3.5 $2.7 $4.8 $28.9
Capital Lease
Commitments $0.8 $0.9 $1.1 $0.7 $0.7 $0.9 $5.1
- ------------------------------ ------------ ----------- ------------ ------------ -------------- -------------- --------------
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 SFAS 133 (see Item 7, MD&A under the heading “Critical Accounting Policies Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase
39
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 Company’s 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 equal to the maximum funding requirements of applicable laws and regulations. In light of the dramatic decline in the stock market over the last several years, the Company anticipates that it will continue making contributions to the Retirement Plan.* During 2003, the Company contributed $35.1 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2004 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.*
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 and
futures contracts, as part of the Company’s 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 Company’s 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, 2003 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, 2003. At September 30, 2003, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2009.
40
----------------------------------- --------------------------------------------------------------------------
Expected Maturity Dates
--------------------------------------------------------------------------
2004 2005 2006 2007 2008 2009 Total
----------------------------------- --------- ---------- --------- --------- ---------- ---------- -----------
Notional Quantities (Equivalent
(Bcf) 8.4 0.9 1.2 1.2 1.1 0.3 13.1
Weighted Average Fixed Rate (per
Mcf) $3.87 $4.75 $4.85 $4.91 $4.94 $4.95 $4.24
Weighted Average Variable Rate
(per Mcf) $4.94 $4.67 $4.83 $4.78 $4.79 $4.83 $4.88
----------------------------------- --------- ---------- --------- --------- ---------- ---------- -----------
Crude Oil Price Swap Agreements
- ------------------------------------------------------- -----------------------------------------------------------
Expected Maturity Dates
-----------------------------------------------------------
2004 2005 2006 Total
- ------------------------------------------------------- --------------- ------------- ------------- ---------------
Notional Quantities (Equivalent bbls) 1,734,000 375,000 75,000 2,184,000
Weighted Average Fixed Rate (per bbl) $25.59 $24.83 $24.98 $25.44
Weighted Average Variable Rate (per bbl) $27.46 $25.56 $25.17 $27.05
- ------------------------------------------------------- --------------- ------------- ------------- ---------------
At September 30, 2003, the Company would have had to pay its respective counterparties an aggregate of approximately $8.8 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $3.4 million to its counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2003.
At September 30, 2002, the Company had natural gas price swap agreements covering 18.5 Bcf at a weighted average fixed rate of $3.73 per Mcf. The Company also had crude oil price swap agreements covering 3,252,000 bbls at a weighted average fixed rate of $21.28 per bbl. Lower anticipated production in the Exploration and Production segment is the primary reason for the decrease in price swap agreements from September 2002 to September 2003.
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, 2003, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2005.
- ---------------------------------------------------- ------------------------------------------
Expected Maturity Dates
------------- -------------- -------------
2004 2005 Total
- ---------------------------------------------------- ------------- -------------- -------------
Natural Gas
Notional Quantities (Equivalent Bcf) 3.0 0.7 3.7
Weighted Average Ceiling Price (per Mcf) $7.15 $7.47 $7.21
Weighted Average Floor Price (per Mcf) $3.51 $3.28 $3.46
Crude Oil
Notional Quantities (Equivalent bbls) 1,185,000 105,000 1,290,000
Weighted Average Ceiling Price (per bbl) $27.95 $28.56 $28.00
Weighted Average Floor Price (per bbl) $23.81 $25.00 $23.91
- ---------------------------------------------------- ------------- -------------- -------------
At September 30, 2003, the Company would have had to pay an aggregate of approximately $0.4 million to terminate the natural gas no cost collars outstanding at that date. The Company would have had to pay an aggregate of approximately $1.1 million to terminate the crude oil no cost collars outstanding at that date.
41
At September 30, 2002, the Company had natural gas no cost collars covering 8.8 Bcf at a weighted average floor price of $3.80 per Mcf and a weighted average ceiling price of $5.71 per Mcf. The Company also had crude oil no cost collars covering 1,395,000 bbls at a weighted average floor price of $21.97 per bbl and a weighted average ceiling price of $26.29 per bbl. As discussed above, lower anticipated production in the Exploration and Production segment is the primary reason for the overall decrease in no cost collars from September 2002 to September 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, 2003, the Company held no futures contracts with maturity dates extending beyond 2006.
- ------------------------------------------------------ --------------------------------- ----------
Expected Maturity Dates
--------------------------------- ----------
2004 2005 2006 Total
- ------------------------------------------------------ ----------- --------- ----------- ----------
Net Contract Volumes Purchased (Sold)
(Equivalent Bcf) 3.7 (0.1) -* 3.6
Weighted Average Contract Price (per Mcf) $5.65 $5.16 $4.23 $5.60
Weighted Average Settlement Price (per Mcf) $5.35 $5.17 $4.76 $5.33
- ------------------------------------------------------ ----------- --------- ----------- ----------
* The Company had two short (sold) futures contracts at September 30, 2003.
At September 30, 2003, the Company would have received $1.7 million to terminate these futures contracts.
At September 30, 2002, the Company had futures contracts covering 3.4 Bcf (net long position) at a weighted average contract price of $3.67 per Mcf.
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 derivative financial instruments. At September 30, 2003, the Company used seven counterparties for its over the counter derivative financial instruments. At September 30, 2003, no individual counterparty represented greater than 37% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company's total volumes hedged).
Exchange Rate Risk
The International segment's 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 segment's 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 Company's 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 Sheet.
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 Company's exposure to interest rate risk arises primarily from its borrowing under short-term debt
instruments. At September 30, 2003, these instruments consisted of domestic short-term bank loans and commercial
paper totaling $118.2 million. The interest rate on these short-term bank loans and commercial paper approximated
1.2% at September 30, 2003.
The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company's long-term fixed rate debt as well as the other long-term
42
debt of certain of the Company's subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2003:
- --------------------------------------- ------------------------------------------------------------------ -----------
Principal Amounts by Expected Maturity Dates
------------------------------------------------------------------
(Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter Total
- --------------------------------------- ---------- --------- ---------- ---------- --------- ------------- -----------
National Fuel Gas Company
Long-Term Fixed Rate Debt $225.0 $ - $ - $ - $200.0 $896.4 $1,321.4
Weighted Average Interest
Rate Paid 7.3% -% -% -% 6.3% 6.4% 6.6%
Fair Value = $1,452.5 million
- --------------------------------------- ---------- --------- ---------- ---------- --------- ------------- -----------
Other Notes
Long-Term Debt(1) $16.7 $14.6 $13.9 $9.3 $9.3 $4.3 $68.1
Weighted Average Interest
Rate Paid(2) 3.2% 3.3% 3.3% 1.8% 1.8% 1.8% 2.8%
Fair Value = $68.1 million
- --------------------------------------- ---------- --------- ---------- ---------- --------- ------------- -----------
(1)$54.4 million is variable rate debt; $13.7 million is fixed rate debt.
(2) Weighted average interest rate excludes the impact of an interest rate collar on $50.8 million of variable rate
debt.
The Company uses an interest rate collar to eliminate interest rate fluctuations on $50.8 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 $4.2 million to terminate the interest rate collar at September 30, 2003.
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.
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. For a complete discussion of this Agreement, refer to “Rate Matters” in Item 7 of the Company’s 2002 Form 10-K. On July 25, 2003, the Parties and other interests executed a settlement agreement (“Settlement”) to extend the terms of the Agreement and Distribution Corporation’s 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 continues existing base rates, and reduces the level above which earnings are shared 50/50 with customers from the current 11.5% return on equity to 11.0%. In addition, the Settlement increases the combined pension and other post employment benefit expense by $8.0 million, without a corresponding increase in revenues. Most other features of Distribution Corporation’s service remain largely unchanged.
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. According to the NYPSC and intervenors, the alleged violations may have caused or contributed to the death of an individual in an unheated apartment. On December 3, 2001, Distribution Corporation filed its response and requested that the NYPSC either
43
close (dismiss) the Show Cause proceeding based on the evidence presented in Distribution Corporation’s response, or hold investigatory hearings “to demonstrate that a penalty action is unwarranted.” On July 25, 2002, the NYPSC issued an order granting Distribution Corporation’s request for hearings, and referred the matter to an administrative law judge for scheduling and other matters. The adoption of a procedural schedule has been adjourned because the major parties to the proceeding are involved in settlement discussions. The Company believes and will continue to vigorously assert that the NYPSC’s allegations lack merit. For a discussion of related legal matters, refer to Item 3, “Legal Proceedings”.
On April 16, 2003, Distribution Corporation filed a request with the Pennsylvania Public Utility Commission (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 Corporation’s 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 thereafter, 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 OPEB expenses. The settlement was approved by the PaPUC on December 18, 2003, with rates scheduled to become effective January 15, 2004.
Supply Corporation currently does not have a rate case on file with the Federal Energy Regulatory Commission (FERC). Management will continue to monitor Supply Corporation’s 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 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. Order 2004 provides that companies may request waivers, and also provides an exemption from this rule for local distribution corporations that are affiliated with interstate pipelines, (such as Distribution Corporation), but the exemption is limited to local distribution corporations that do not make any off-system sales. Distribution Corporation currently does make such off-system sales and would like to continue doing so, whether by waiver, amendment or clarification of the new rule. Order 2004 also appears to define Empire State Pipeline as an energy affiliate of Supply Corporation, which is looking into both the possible costs of complying and the possibilities of a waiver, amendment or clarification that would allow Supply Corporation and Empire to operate together as they do now. Until there is further clarification from the FERC on the scope of these exemptions, the Company is unable to predict the impact Order 2004 will have on the Company.
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 Company’s
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 in the range of $9.5 million to $10.5
million.* The minimum liability of $9.5 million has been recorded on the
Consolidated Balance Sheet at September 30, 2003. 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
44
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.”
Effects of
Inflation
Although the rate of
inflation has been relatively low over the past few years, the Company’s
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 exprssions, are “forward-looking”
statements as defined in the Private Securities Litigation Reform Act of 1995
and accordingly involve risks and uncertainties which could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements. The forward-looking statements contained herein are based on various
assumptions, many of which are based, in turn, upon further assumptions. The
Company’s expectations, beliefs and projections are expressed in good faith
and are believed by the Company to have a reasonable basis, including, without
limitation, management’s examination of historical operating trends, data
contained in the Company’s records and other data available from third
parties, but there can be no assurance that management’s expectations,
beliefs or projections will result or be achieved or accomplished. In addition
to other factors and matters discussed elsewhere herein, the following are
important factors that, in the view of the Company, could cause actual results
to differ materially from those discussed in the forward-looking statements:
45
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.
Report of Independent Auditors - 48
Consolidated Balance Sheets at September 30, 2003 and 2002 - 50
Consolidated Statement of Cash Flows, three years ended September 30, 2003 - 52
46
Consolidated Statement of Comprehensive Income, three years ended September 30, 2003 - 53
Notes to Consolidated Financial Statements - 54
Financial Statement Schedules:
For the three years ended September 30, 2003
II-Valuation and Qualifying Accounts - 86
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 DataSupplementary 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.
Report of ManagementManagement is responsible for the preparation and integrity of the Company’s financial statements. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and necessarily include some amounts that are based on management’s best estimates and judgment.
The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management’s authorization. The Company’s financial statements have been examined by our independent auditors, PricewaterhouseCoopers LLP, which also conducts a review of internal controls to the extent required by auditing standards generally accepted in the United States of America.
The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors and PricewaterhouseCoopers LLP to review planned audit scope and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent auditors have direct access to the Audit Committee and periodically meet with it without management representatives present.
47
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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2003, 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 Company’s 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 auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for 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
October 23, 2003
48
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands of Dollars,
Except Per Common Share Amounts) 2003 2002 2001
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Income
Operating Revenues $2,035,471 $1,464,496 $2,059,836
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Expenses
Purchased Gas 963,567 462,857 1,002,466
Fuel Used in Heat and Electric Generation 61,029 50,635 54,968
Operation and Maintenance 386,270 394,157 364,318
Property, Franchise and Other Taxes 82,504 72,155 83,730
Depreciation, Depletion and Amortization 195,226 180,668 174,914
Impairment of Oil and Gas Producing
Properties 42,774 - 180,781
- -------------------------------------------------------------- ----------------- ---------------- -----------------
1,731,370 1,160,472 1,861,177
Gain on Sale of Timber Properties 168,787 - -
Loss on Sale of Oil and Gas Producing Properties (58,472) - -
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Income 414,416 304,024 198,659
Other Income (Expense):
Income from Unconsolidated Subsidiaries 535 224 1,794
Impairment of Investment in Partnership - (15,167) -
Other Income 6,887 7,017 10,639
Interest Expense on Long-Term Debt (92,766) (90,543) (81,851)
Other Interest Expense (12,290) (15,109) (25,294)
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Income Before Income Taxes and Minority
Interest in Foreign Subsidiaries 316,782 190,446 103,947
Income Tax Expense 128,161 72,034 37,106
Minority Interest in Foreign Subsidiaries - (Expense) (785) (730) (1,342)
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Income Before Cumulative Effect of Changes
In Accounting 187,836 117,682 65,499
Cumulative Effect of Changes in Accounting (8,892) - -
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Net Income Available for Common Stock 178,944 117,682 65,499
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Earnings Reinvested in the Business
Balance at Beginning of Year 549,397 513,488 525,847
- -------------------------------------------------------------- ----------------- ---------------- -----------------
728,341 631,170 591,346
Dividends on Common Stock 85,651 81,773 77,858
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Balance at End of Year $642,690 $549,397 $513,488
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Earnings Per Common Share:
Basic:
Income Before Cumulative Effect of Changes in
Accounting $2.32 $1.47 $0.83
Cumulative Effect of Changes in Accounting (0.11) - -
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Net Income Available for Common Stock $2.21 $1.47 $0.83
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Diluted:
Income Before Cumulative Effect of Changes in
Accounting $2.31 $1.46 $0.82
Cumulative Effect of Changes in Accounting (0.11) - -
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Net Income Available for Common Stock $2.20 $1.46 $0.82
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 80,808,794 79,821,430 79,053,444
Used in Diluted Calculation 81,357,896 80,534,453 80,361,258
- -------------------------------------------------------------- ----------------- ---------------- -----------------
See Notes to Consolidated Financial Statements
Back to Index of Financial Statements49
National Fuel Gas Company
Consolidated Balance Sheets
- ---------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands of Dollars) 2003 2002
- ---------------------------------------------------------------------------- ------------------- -------------------
Assets
Property, Plant and Equipment $4,657,343 $4,512,651
Less - Accumulated Depreciation,
Depletion and Amortization 1,658,256 1,667,906
- ---------------------------------------------------------------------------- ------------------- -------------------
2,999,087 2,844,745
- ---------------------------------------------------------------------------- ------------------- -------------------
Current Assets
Cash and Temporary Cash Investments 51,421 22,216
Receivables - Net 136,532 95,510
Unbilled Utility Revenue 27,443 21,918
Gas Stored Underground 89,640 77,250
Materials and Supplies - at average cost 32,311 31,582
Unrecovered Purchased Gas Costs 28,692 12,431
Prepayments 43,225 41,354
Fair Value of Derivative Financial Instruments 1,698 3,807
- ---------------------------------------------------------------------------- ------------------- -------------------
410,962 306,068
- ---------------------------------------------------------------------------- ------------------- -------------------
Other Assets
Recoverable Future Taxes 84,818 82,385
Unamortized Debt Expense 22,119 20,635
Other Regulatory Assets 49,616 26,104
Deferred Charges 7,528 5,914
Other Investments 64,025 65,090
Investments in Unconsolidated Subsidiaries 16,425 16,753
Goodwill 5,476 8,255
Intangible Assets 49,664 11,451
Other 18,195 13,909
- ---------------------------------------------------------------------------- ------------------- -------------------
317,866 250,496
- ---------------------------------------------------------------------------- ------------------- -------------------
$3,727,915 $3,401,309
- ---------------------------------------------------------------------------- ------------------- -------------------
See Notes to Consolidated Financial Statements
Back to Index of Financial Statements50
National Fuel Gas Company
Consolidated Balance Sheets
- ---------------------------------------------------------------------------- ----------------- ----------------
At September 30 (Thousands of Dollars) 2003 2002
- ---------------------------------------------------------------------------- ----------------- ----------------
Capitalization and Liabilities
Capitalization:
Comprehensive Shareholders' Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued and
Outstanding - 81,438,290 Shares and 80,264,734
Shares, Respectively $81,438 $80,265
Paid In Capital 478,799 446,832
Earnings Reinvested in the Business 642,690 549,397
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Common Shareholder Equity Before Items
Of Other Comprehensive Loss 1,202,927 1,076,494
Accumulated Other Comprehensive Loss (65,537) (69,636)
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Comprehensive Shareholders' Equity 1,137,390 1,006,858
Long-Term Debt, Net of Current Portion 1,147,779 1,145,341
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Capitalization 2,285,169 2,152,199
- ---------------------------------------------------------------------------- ----------------- ----------------
Minority Interest in Foreign Subsidiaries 33,281 28,785
- ---------------------------------------------------------------------------- ----------------- ----------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 118,200 265,386
Current Portion of Long-Term Debt 241,731 160,564
Accounts Payable 125,779 100,886
Amounts Payable to Customers 692 -
Other Accruals and Current Liabilities 52,851 46,402
Fair Value of Derivative Financial Instruments 17,928 31,204
- ---------------------------------------------------------------------------- ----------------- ----------------
557,181 604,442
- ---------------------------------------------------------------------------- ----------------- ----------------
Deferred Credits
Accumulated Deferred Income Taxes 423,282 356,220
Taxes Refundable to Customers 13,519 15,596
Unamortized Investment Tax Credit 8,199 8,897
Cost of Removal Regulatory Liability 84,821 -
Other Regulatory Liabilities 69,867 82,676
Pension Liability 154,871 75,116
Asset Retirement Obligation 27,493 -
Other Deferred Credits 70,232 77,378
- ---------------------------------------------------------------------------- ----------------- ----------------
852,284 615,883
- ---------------------------------------------------------------------------- ----------------- ----------------
Commitments and Contingencies - -
- ---------------------------------------------------------------------------- ----------------- ----------------
$3,727,915 $3,401,309
- ---------------------------------------------------------------------------- ----------------- ----------------
See Notes to Consolidated Financial Statements
Back to Index of Financial Statements51
National Fuel Gas Company
Consolidated Statement of Cash Flows
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Year Ended September 30 (Thousands of Dollars) 2003 2002 2001
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Operating Activities
Net Income Available for Common Stock $178,944 $117,682 $65,499
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Gain on Sale of Timber Properties (168,787) - -
Loss on Sale of Oil and Gas Producing Properties 58,472 - -
Impairment of Oil and Gas Producing Properties 42,774 - 180,781
Depreciation, Depletion and Amortization 195,226 180,668 174,914
Deferred Income Taxes 78,369 62,013 (55,849)
Impairment of Investment in Partnership - 15,167 -
Cumulative Effect of Changes in Accounting 8,892 - -
(Income) Loss from Unconsolidated Subsidiaries,
Net of Cash Distributions 703 361 (1,199)
Minority Interest in Foreign Subsidiaries 785 730 1,342
Other 11,289 9,842 6,553
Change in:
Receivables and Unbilled Utility Revenue (35,118) 40,786 (2,277)
Gas Stored Underground and Materials and
Supplies (12,421) 8,717 (37,054)
Unrecovered Purchased Gas Costs (16,261) (8,318) 25,568
Prepayments 862 (1,737) (399)
Accounts Payable 20,435 (24,025) 20,419
Amounts Payable to Customers 692 (51,223) 41,640
Other Accruals and Current Liabilities 8,595 (27,332) 13,969
Other Assets (29,916) 11,869 (33,169)
Other Liabilities (16,698) 10,350 13,289
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Provided by Operating Activities 326,837 345,550 414,027
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Investing Activities
Capital Expenditures (152,251) (232,368) (292,706)
Investment in Subsidiaries, Net of Cash Acquired (228,814) - (90,567)
Investment in Partnerships (375) (536) (1,830)
Net Proceeds from Sale of Timber Properties 186,014 - -
Net Proceeds from Sale of Oil and Gas Producing
Properties 78,531 22,068 2,069
Other 12,065 5,012 (4,892)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Used in Investing Activities (104,830) (205,824) (387,926)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper (147,622) (224,845) (143,397)
Net Proceeds from Issuance of Long-Term Debt 248,513 243,844 210,221
Reduction of Long-Term Debt (227,826) (104,212) (23,052)
Proceeds from Issuance of Common Stock 17,019 10,915 11,545
Dividends Paid on Common Stock (84,530) (80,974) (76,671)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Used in Financing Activities (194,446) (155,272) (21,354)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Effect of Exchange Rates on Cash 1,644 1,535 (645)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Increase (Decrease) in Cash and
Temporary Cash Investments 29,205 (14,011) 4,102
Cash and Temporary Cash Investments
at Beginning of Year 22,216 36,227 32,125
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Cash and Temporary Cash Investments
at End of Year $51,421 $22,216 $36,227
52
- ------------------------------------------------------------------ ----------------- ---------------- ----------------- Supplemental Disclosure of Cash Flow Information Cash Paid For: Interest $104,452 $100,397 $104,491 Income Taxes $56,146 $29,985 $77,662 - ------------------------------------------------------------------ ----------------- ---------------- -----------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Statement of Comprehensive Income
- ------------------------------------------------------- -------------------------- ------------------------ -------------------------
Year Ended September 30 (Thousands of Dollars) 2003 2002 2001
- ------------------------------------------------------- -------------------------- ------------------------ -------------------------
Net Income Available for Common Stock $178,944 $117,682 $ 65,499
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before Tax:
Minimum Pension Liability Adjustment (86,170) (52,977) -
Foreign Currency Translation Adjustment 54,472 24,278 (7,158)
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 2,419 (2,086) (712)
Unrealized Gain (Loss) on Derivative Financial
Instruments Arising During the Period (47,777) (42,584) 58,355
Reclassification Adjustment for Realized
(Gain) Loss on Derivative Financial
Instruments in Net Income 69,809 (20,063) 83,218
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before
Tax: (16,854) (93,432) 133,703
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Income Tax Benefit Related to Minimum
Pension Liability Adjustment (30,159) (18,542) -
Income Tax Expense (Benefit) Related to
Unrealized Gain (Loss) on Securities
Available for Sale Arising During the Period 847 (730) (249)
Income Tax Expense (Benefit) Related to
Unrealized Gain (Loss) on Derivative
Financial Instruments Arising During the
Period (18,594) (17,341) 23,053
Reclassification Adjustment for Income Tax
(Expense) Benefit on Realized (Gain)
Loss on Derivative Financial Instruments
In Net Income 26,953 (8,040) 32,032
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Income Taxes - Net (20,953) (44,653) 54,836
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before
Cumulative Effect 4,099 (48,779) 78,867
Cumulative Effect of Change in Accounting,
Net of Tax - - (69,767)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), After
Cumulative Effect 4,099 (48,779) 9,100
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Comprehensive Income $183,043 $ 68,903 $ 74,599
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
See Notes to Consolidated Financial Statements
Back to Index of Financial Statements53
National Fuel Gas Company
Notes to Consolidated Financial Statements
Principles of
Consolidation
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.
Reclassification
Certain prior year amounts
have been reclassified to conform with current year presentation.
Regulation
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.
Revenues
The Company’s Utility
and International segments record 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
Company’s Pipeline and Storage and Energy Marketing segments record revenue
as bills are rendered for service supplied on a calendar month basis. The
Company’s Timber segment records revenue on lumber and log sales as
products are shipped.
The Company’s 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 Company’s 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.
Regulatory
Mechanisms
The Company’s 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.
Estimated refund liabilities to ratepayers represent management’s 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 segment’s 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
54
being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s 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 Corporation’s revenues but may have a significant impact on Empire’s revenues.
Property,
Plant and Equipment
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 Company’s capitalized costs exceeded the full-cost ceiling for the Company’s Canadian properties at June 30, 2003, September 30, 2003 and September 30, 2001. The Company recognized impairments of $31.8 million and $11.0 million at June 30, 2003 and September 30, 2003, respectively. At September 30, 2001, the Company recognized an impairment of $180.8 million.
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.
Depreciation,
Depletion and Amortization
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 annual 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:
As of September 30 (Thousands) 2003 2002
------------------------------------------------ ------------------- --------------------
Utility $1,380,278 $1,346,706
Pipeline and Storage 928,415 690,453
Exploration and Production 1,673,827 1,806,284
International 349,133 310,117
Energy Marketing 1,159 996
Timber 96,315 119,074
All Other and 20,541 7,115
Corporate
------------------- --------------------
$4,449,668 $4,280,745
=================== ====================
Average depreciation, depletion and amortization rates were are follows:
55
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Year Ended September 30 2003 2002 2001
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Utility 2.8% 2.8% 2.8%
Pipeline and Storage 4.6% 3.6% 3.6%
Exploration and Production, per Mcfe(1) $1.34 $1.19 $1.12
International 4.2% 4.2% 5.1%
Energy Marketing 10.9% 16.4% 23.1%
Timber 7.0% 3.2% 3.2%
All Other and Corporate 1.7% 2.7% 8.0%
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
(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 $1.30, $1.16 and $1.08 per Mcfe of production in 2003, 2002 and 2001,
respectively.
Cumulative
Effect of Changes in Accounting
Effective October 1, 2002,
the Company adopted the Financial Accounting Standards Board’s (FASB)
Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for
Asset Retirement Obligations” (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 Company’s
case, SFAS 143 changed the accounting for plugging and abandonment costs
associated with the Exploration and Production segment’s crude oil and
natural gas wells. In prior fiscal years, the Company accounted for plugging and
abandonment costs using the Securities and Exchange Commission’s 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 Company’s asset retirement obligation calculated in
accordance with SFAS 143 is shown below ($000s):
Balance at Adoption on October 1, 2002 $36,090
Liabilities Incurred During 2003 242
Liabilities Settled During 2003 (13,227)
Accretion Expense 2,602
Exchange Rate Impact 1,786
-------
Balance at September 30, 2003 $27,493
=======
In the Company's 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, 2003, the costs of removal reclassified to other regulatory liabilities amounted to $84.8 million.
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 Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and is related to the Company’s 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 cannot be assured that the level of future cash flows from the Company’s investments in the Czech Republic will attain the level that was originally forecasted. In accordance with SFAS 142, this impairment has been reported as a cumulative effect of change in accounting. Goodwill amortization amounted to $0.6 million in both 2002 and 2001.
Effective October 1, 2000, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities – Deferral of the Effective Date of FASB Statement No. 133” and by
56
SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133” (collectively, SFAS 133). The cumulative effect of this change decreased other comprehensive income by $69.8 million (after tax) at adoption on October 1, 2000. The cumulative effect of this change did not have a material impact on net income at adoption on October 1, 2000. Of the cumulative effect recorded in other comprehensive income, $46.3 million (after tax) was reclassified into the Consolidated Statement of Income during 2001. The derivative financial instruments that comprise the cumulative effect recorded in other comprehensive income have been designated and qualify as cash flow hedges, as discussed below.
Financial
Instruments
Unrealized gains or losses
from the Company’s 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.
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 and futures contracts. As discussed above, on October 1, 2000, the Company adopted SFAS 133. In accordance with the provisions of these standards, 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 Sheet 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 Sheet. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statement of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 2003, 2002 or 2001. 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 Statement 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 Statement of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheet 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 Statement 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 2003, 2002 or 2001.
Accumulated
Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
---------------------------------------------------------------- -------------------- --------------------
Year Ended September 30 (Thousands) 2003 2002
---------------------------------------------------------------- -------------------- --------------------
Minimum Pension Liability Adjustment $(90,446) $(34,435)
Cumulative Foreign Currency Translation Adjustment 30,050 (14,815)
Net Unrealized Loss on Derivative Financial
Instruments (6,872) (20,545)
Net Unrealized Gain on Securities Available for Sale 1,731 159
---------------------------------------------------------------- -------------------- --------------------
Accumulated Other Comprehensive Loss $(65,537) $(69,636)
---------------------------------------------------------------- -------------------- --------------------
At September 30, 2003, it is estimated that $8.4 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 2004. As disclosed in Note E - Financial Instruments, the Company’s derivative financial instruments extend out to 2009.
57
Gas Stored
Underground - Current
In the Utility segment, gas
stored underground - current in the amount of $75.2 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 2003, 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
$98.6 million at September 30, 2003. All other gas stored underground - current
is carried at lower of cost or market on an average cost method.
Unamortized
Debt Expense
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.
Foreign
Currency Translation
The functional currency for
the Company’s 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).
Income Taxes
The Company and its
domestic subsidiaries file a consolidated federal income tax return. Investment
tax credit, prior to its repeal in 1986, was deferred and is being amortized
over the estimated useful lives of the related property, as required by
regulatory authorities having jurisdiction. 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.
Consolidated
Statement of Cash Flows
For purposes of the
Consolidated Statement of Cash Flows, the Company considers all highly liquid
debt instruments purchased with a maturity of 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. The amounts held in margin accounts amounted to $1.5 million and $0.4
million at September 30, 2003 and 2002, respectively.
Earnings Per
Common Share
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 2003, 2002 and 2001, 7,789,688, 5,260,633 and 1,290,747 stock
options, respectively, were excluded as being antidilutive.
Stock-Based
Compensation
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, 2003, 2002 and 2001. 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
Company’s net income and earnings per share would have been reduced to the
pro forma amounts below:
58
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Year Ended September 30 (Thousands, Except
Per Share Amounts) 2003 2002 2001
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Net Income Available for Common Stock
As Reported $178,944 $117,682 $65,499
Deduct: Total Compensation Expense
Determined Based on Fair Value at the
Grant Dates 3,105 4,641 6,391
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Pro Forma Net Income Available for
Common Stock $175,839 $113,041 $59,108
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Earnings Per Common Share:
Basic - As Reported $2.21 $1.47 $0.83
Basic - Pro Forma $2.18 $1.42 $0.75
Diluted - As Reported $2.20 $1.46 $0.82
Diluted - Pro Forma $2.16 $1.40 $0.73
- ---------------------------------------------------------- ------------------- ------------------- -------------------
The weighted average fair value per share of options granted in 2003, 2002 and 2001 was $4.17, $4.32 and $5.25, 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:
- ---------------------------------------------------------- ------------------- ------------------- ------------------- Year Ended September 30 2003 2002 2001 - ---------------------------------------------------------- ------------------- ------------------- ------------------- Quarterly Dividend Yield 1.10% 1.07% 0.87% Annual Standard Deviation (Volatility) 22.24% 21.83% 20.51% Risk Free Rate 3.33% 4.88% 5.26% Expected Term - in Years 6.5 5.5 5.0 - ---------------------------------------------------------- ------------------- ------------------- -------------------
Regulatory
Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
- --------------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands) 2003 2002
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Assets(1)
Recoverable Future Taxes (Note C) $84,818 $82,385
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A)
28,692 12,431
Unamortized Debt Expense (Note A) 11,364 10,021
Pension and Post-Retirement Benefit Costs (2) (Note F) 47,750 24,146
Other (2) 1,866 1,958
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Assets 174,490 130,941
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Liabilities:
Cost of Removal Regulatory Liability (See Cumulative Effect
Discussion in Note A) 84,821 -
Amounts Payable to Customers (See Regulatory Mechanisms in
Note A) 692 -
New York Rate Settlements(3) 30,900 34,323
Taxes Refundable to Customers (Note C) 13,519 15,596
Pension and Post-Retirement Benefit Costs(3) (Note F) 23,719 39,946
Other(3) 15,248 8,407
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Liabilities 168,899 98,272
- --------------------------------------------------------------------------------- ------------------- -------------------
Net Regulatory Position $5,591 $32,669
- --------------------------------------------------------------------------------- ------------------- -------------------
(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.
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
59
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.
New York Rate
Settlements
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 $11.4 million and $9.5 million at September 30, 2003
and 2002, respectively. Other aspects of the settlements include a special
reserve of $5.4 million and $6.5 million at September 30, 2003 and 2002,
respectively, to be applied against the Company’s incremental costs
resulting from the NYPSC’s gas restructuring effort and a “cost
mitigation reserve” of $8.2 million and $15.3 million at September 30, 2003
and 2002, 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 $5.9 million and $3.0 million at September 30, 2003 and 2002,
respectively.
The components of federal, state and foreign income taxes included in the Consolidated Statement of Income are as follows:
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Expenses:
Current Income Taxes -
Federal $37,336 $7,743 $67,429
State 11,990 1,384 21,330
Foreign 467 894 4,196
Deferred Income Taxes -
Federal 53,310 50,205 18,444
State 12,983 9,968 431
Foreign 12,075 1,840 (74,724)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
128,161 72,034 37,106
Other Income:
Deferred Investment Tax Credit (693) (697) (348)
Minority Interest in Foreign Subsidiaries (566) (277) (614)
Cumulative Effect of Change in Accounting (354) - -
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Total Income Taxes $126,548 $71,060 $36,144
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
The U.S. and foreign components of income (loss) before income taxes are as follows:
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
U.S. $383,695 $180,349 $267,270
Foreign (78,202) 8,394 (165,627)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$305,493 $188,743 $101,643
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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:
60
- --------------------------------------------------------------- ------------------- --------------- ---------------- Year Ended September 30 (Thousands) 2003 2002 2001 - --------------------------------------------------------------- ------------------- --------------- ---------------- Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $106,923 $66,060 $35,575 Increase (Reduction) in Taxes Resulting from: State Income Taxes 16,232 7,379 14,145 Foreign Tax Differential 3,318 (481) (13,172) Depreciation 1,322 1,744 1,790 Miscellaneous (1,247) (3,642) (2,194) - --------------------------------------------------------------- ------------------- --------------- ---------------- Total Income Taxes $126,548 $71,060 $36,144 - --------------------------------------------------------------- ------------------- --------------- ----------------
Significant components of the Company's deferred tax liabilities and assets are as follows:
- --------------------------------------------------------------- ------------------- ---------------
At September 30 (Thousands) 2003 2002
- --------------------------------------------------------------- ------------------- ---------------
Deferred Tax Liabilities:
Property, Plant and Equipment $519,578 $417,673
Other 21,532 27,930
- --------------------------------------------------------------- ------------------- ---------------
Total Deferred Tax Liabilities 541,110 445,603
- --------------------------------------------------------------- ------------------- ---------------
Deferred Tax Assets:
Minimum Pension Liability Adjustment (48,701) (18,542)
Capital Loss Carryover (18,607) -
Other (56,877) (70,841)
- --------------------------------------------------------------- ------------------- ---------------
(124,185) (89,383)
Valuation Allowance 6,357 -
- --------------------------------------------------------------- ------------------- ---------------
Total Deferred Tax Assets (117,828) (89,383)
- --------------------------------------------------------------- ------------------- ---------------
Total Net Deferred Income Taxes $423,282 $356,220
- --------------------------------------------------------------- ------------------- ---------------
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 $13.5 million and $15.6 million at September 30, 2003 and 2002, 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 $84.8 million and $82.4 million at September 30, 2003 and 2002, respectively.
Undistributed earnings of foreign subsidiaries of $57 million at September 30, 2003 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.
A capital loss carryover of $53 million exists at September 30, 2003, 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.
61
Summary of Changes in Common Stock Equity
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Earnings Accumulated
Paid Reinvested Other
(Thousands, Except Per Share Common Stock In in the Comprehensive
Amounts) Shares Amount Capital Business Income (Loss)
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 2000 78,660 $78,660 $412,887 $525,847 $(29,957)
Net Income Available
for Common Stock 65,499
Dividends Declared on
Common Stock
($0.99 Per Share) (77,858)
Other Comprehensive
Income, Net of Tax 9,100
Common Stock Issued
Under Stock and
Benefit Plans 746 746 17,731
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 2001 79,406 79,406 430,618 513,488 (20,857)
Net Income Available
for Common Stock 117,682
Dividends Declared on
Common Stock
($1.03 Per Share) (81,773)
Other Comprehensive
Loss, Net of Tax (48,779)
Common Stock Issued
Under Stock and
Benefit Plans 859 859 16,214
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 2002 80,265 80,265 446,832 549,397 (69,636)
Net Income Available
for Common Stock 178,944
Dividends Declared on
Common Stock
($1.06 Per Share) (85,651)
Other Comprehensive
Income, Net of Tax 4,099
Cancellation of Shares (3) (3) (63)
Common Stock Issued
Under Stock and
Benefit Plans 1,176 1,176 32,030
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 2003 81,438 $81,438 $478,799 $642,690(1) $(65,537)
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
(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, 2003, $568.3 million of
accumulated earnings was free of such limitations.
62
Common Stock
The Company has various
plans which allow shareholders, customers and employees to purchase shares of
Company common stock. The National Fuel Direct Stock Purchase and Dividend
Reinvestment Plan allows shareholders to reinvest cash dividends or make cash
investments in the Company’s common stock and provides investors the
opportunity to acquire shares of Company common stock without the payment of any
brokerage commissions or service charges in connection with such acquisitions.
The 401(k) Plans allow employees the opportunity to invest in Company common
stock, in addition to a variety of other investment alternatives. At the
discretion of the Company, shares purchased under these plans are either
original issue shares purchased directly from the Company or shares purchased on
the open market by an independent agent.
The Company also has a Director Stock Program under which it issues shares of Company common stock to its non-employee directors as partial consideration for their services as directors.
Shareholder
Rights Plan
In 1996, the Company’s
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 Company’s common stock have one right (Right) for each of their shares. Each Right, which will initially be evidenced by the Company’s 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 Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s 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 Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s 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 Company’s 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 Company’s 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 Company’s 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 Company’s 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
63
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.
Stock Option
and Stock Award Plans
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, stock appreciation rights, 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:
- ------------------------------------------------------------- ---------------------------- ---------------------------
Number of
Shares Subject Weighted Average
to Option Exercise Price
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2000 8,027,100 $20.38
Granted in 2001 1,787,200 $27.61
Exercised in 2001(1) (372,040) $15.89
Forfeited in 2001 (69,574) $22.36
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2001 9,372,686 $21.92
Granted in 2002(2) 5,673,172 $22.26
Exercised in 2002(1) (247,910) $15.76
Forfeited in 2002 (168,444) $25.56
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2002 14,629,504 $22.12
Granted in 2003 233,500 $24.61
Exercised in 2003(1) (673,866) $16.56
Forfeited in 2003 (123,800) $23.55
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2003 14,065,338 $22.41
- ------------------------------------------------------------- ---------------------------- ---------------------------
Option shares exercisable at September 30, 2003 12,420,444 $22.16
Option shares available for future grant
at September 30, 2003(3) 807,351
- ------------------------------------------------------------- ---------------------------- ---------------------------
(1) In connection with exercising these options, 200,708, 43,834 and 78,850 shares were surrendered and canceled
during 2003, 2002 and 2001, 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.
The following table summarizes information about options outstanding at September 30, 2003:
- --------------------------------------------------------------------------------- -------------------------------------
Options Outstanding Options Exercisable
- --------------------------------------------------------------------------------- -------------------------------------
Weighted
Number Average Weighted Number Weighted
Range of Outstanding Remaining Average Exercisable Average
Exercise Price at 9/30/03 Contractual Life Exercise Price at 9/30/03 Exercise Price
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
$11.12 - $16.68 1,161,104 1.6 years $14.69 1,161,104 $14.69
$16.69 - $22.24 4,322,972 4.9 years $20.36 4,138,572 $20.30
$22.25 - $27.80 8,581,262 6.5 years $24.49 7,120,768 $24.46
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
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 Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
64
The following table summarizes the awards of restricted stock over the past three years:
- ----------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 2003 2002 2001 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Shares of Restricted Stock Awarded - 100,000 4,000 Weighted Average Market Price of Stock on Award Date - $24.50 $27.80 - ----------------------------------------------------------------- ----------------- ---------------- -----------------
As of September 30, 2003, 136,128 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2004 – 36,600 shares; 2005 – 34,600 shares; 2006 – 34,600 shares; 2007 – 29,000 shares; and 2010 - 1,328 shares.
Compensation expense related to restricted stock under the Company’s stock plans was $1.0 million, $0.7 million and $0.3 million for the years ended September 30, 2003, 2002 and 2001, respectively.
Redeemable
Preferred Stock
As of September 30, 2003,
there were 10,000,000 shares of $1 par value Preferred Stock authorized but
unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
- ----------------------------------------------------------------------------------- ---------------- -----------------
At September 30 (Thousands) 2003 2002
- ----------------------------------------------------------------------------------- ---------------- -----------------
Debentures(1):
7-3/4% due February 2004 $125,000 $125,000
Medium-Term Notes(1):
6.0% to 7.50% due August 2004 to June 2025 849,000 1,051,300
Notes(1):
5.25% to 6.50% due March 2013 to September 2022(2) 347,400 97,700
- ----------------------------------------------------------------------------------- ---------------- -----------------
1,321,400 1,274,000
- ----------------------------------------------------------------------------------- ---------------- -----------------
Other Notes:
Secured(3) 50,767 -
Unsecured 17,343 31,905
- ----------------------------------------------------------------------------------- ---------------- -----------------
Total Long-Term Debt 1,389,510 1,305,905
Less Current Portion 241,731 160,564
- ----------------------------------------------------------------------------------- ---------------- -----------------
$1,147,779 $1,145,341
- ----------------------------------------------------------------------------------- ---------------- -----------------
(1) These debentures, medium-term notes and notes are unsecured.
(2) $97,400,000 of these notes are callable at par at any time after September 15, 2006. The estate of an
individual note holder may exercise a put option in the event of 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.
As of September 30, 2003, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $241.7 million in 2004, $14.6 million in 2005, $13.9 million in 2006, $9.3 million in 2007, $209.3 million in 2008 and $900.7 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 $415.0 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 Company’s commercial paper program is $200.0 million. The commercial paper program is backed by a committed credit facility totaling $220.0 million. Of that amount, $110.0 million is committed to the Company through September 26, 2004, and $110.0 million is committed to the Company through September 30, 2005.
65
At September 30, 2003, the Company had outstanding short-term notes payable to banks and commercial paper of $55.2 million and $63.0 million, respectively. All of this debt was domestic. At September 30, 2002, the Company had outstanding notes payable to banks and commercial paper of $91.3 million (including $79.9 million in domestic debt and $11.4 million in foreign debt) and $174.1 million, respectively.
The weighted average interest rate on domestic notes payable to banks was 1.27% and 2.05% at September 30, 2003 and 2002, respectively. The interest rate on the foreign notes payable to banks was 3.64% at September 30, 2002. The weighted average interest rate on commercial paper was 1.18% and 2.04% at September 30, 2003 and 2002, respectively.
Under the Company’s 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 .65 from September 30, 2002 through September 30, 2003, .625 from October 1, 2003 through September 30, 2004 and .60 from October 1, 2004 and thereafter. At September 30, 2003, the Company’s debt to capitalization ratio (as calculated under the facility) was .57. The constraints specified in the committed credit facility would permit an additional $145.0 million in short-term and/or long-term debt to be outstanding before the Company’s debt to capitalization ratio would exceed .625. If a downgrade in any of the Company’s 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 Company’s existing indenture covenants, at September 30, 2003, the Company would have been permitted to issue up to a maximum of $289.0 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 Company’s indenture pursuant to which $624.0 million (or 45%) of the Company’s long-term debt (as of September 30, 2003) 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 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 to become due prior to its stated maturity, unless cured or waived.
The Company’s committed $220.0 million, 364-day/3-year 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 its significant subsidiaries fail 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 such indebtedness to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2003, the Company had no debt outstanding under the committed credit facility.
Fair Values
The fair market value of
the Company’s long-term debt is estimated based on quoted market prices of
similar issues having the same remaining maturities, redemption terms and credit
ratings. Based on these criteria, the fair market value of long-term debt,
including current portion, was as follows:
66
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
2003 2003 2002 2002
Carrying Fair Carrying Fair
At September 30 (Thousands) Amount Value Amount Value
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
Long-Term Debt $1,389,510 $1,520,606 $1,305,905 $1,393,949
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
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
Other investments includes
cash surrender values of insurance contracts and marketable equity securities.
The cash surrender values of the insurance contracts amounted to $53.5 million
and $57.1 million at September 30, 2003 and 2002, respectively. The fair
value of the equity mutual fund was $4.8 million and $3.8 million at September
30, 2003 and 2002, respectively. The gross unrealized loss on the equity mutual
fund was $0.6 million and $1.5 million at September 30, 2003 and 2002,
respectively. The fair value of the stock of an insurance company was $5.7
million and $4.2 million at September 30, 2003 and 2002, respectively. The gross
unrealized gain on this stock was $3.2 million and $1.7 million at September 30,
2003 and 2002, respectively. The insurance contracts and marketable equity
securities are primarily informal funding mechanisms for various benefit
obligations the Company has to certain employees.
Derivative
Financial Instruments
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 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. At September 30, 2003, the Company had natural gas price swap agreements covering a notional amount of 13.1 Bcf extending through 2009 at a weighted average fixed rate of $4.24 per Mcf. Of this amount, 0.2 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $5.02 per Mcf. The remaining 12.9 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $4.22 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 2,184,000 bbls extending through 2006 at a weighted average fixed rate of $25.44 per bbl. At September 30, 2003, the Company would have had to pay a net $12.2 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, 2003, the Company had no cost collars on natural gas covering a notional amount of 3.7 Bcf extending through 2005 with 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 no cost collars on crude oil covering a notional amount of 1,290,000 bbls extending through 2005 with a weighted average floor price
67
of $23.91 per bbl and a weighted average ceiling price of $28.00 per bbl. At September 30, 2003, the Company would have had to pay $1.5 million to terminate the no cost collars.
At September 30, 2003, the Company had long (purchased) futures contracts covering 11.4 Bcf of gas extending through 2005 at a weighted average contract price of $5.49 per Mcf. These derivative financial instruments are accounted for as fair value hedges. They are used by the Company’s 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 Company would have had to pay $1.8 million to terminate these futures contracts at September 30, 2003.
At September 30, 2003, the Company had short (sold) futures contracts covering 7.8 Bcf of gas extending through 2006 at a weighted average contract price of $5.76 per Mcf. Of this amount, 4.4 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 3.4 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 received $3.5 million to terminate these futures contracts at September 30, 2003.
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, 2003, the Company used seven counterparties for its over the counter derivative financial instruments. At September 30, 2003, no individual counterparty represented greater than 37% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company’s total volumes hedged).
The Company uses an interest rate collar to eliminate 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, 2003 the notional amount on the collar was $53.7 million. The Company would have had to pay $4.2 million to terminate the interest rate collar at September 30, 2003.
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 Company’s 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.
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
68
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 NYPSC’s 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.
Retirement Plan
Reconciliations of the
Benefit Obligation, Retirement Plan Assets and Funded Status, as well as the
components of Net Periodic Benefit Cost and the Weighted Average Assumptions are
as follows:
- ----------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 (Thousands) 2003 2002 2001 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Benefit Obligation Benefit Obligation at Beginning of Period $625,470 $580,046 $535,894 Service Cost 13,043 11,639 11,550 Interest Cost 40,967 40,720 39,061 Amendments - 420 2,343 Actuarial Loss 51,302 28,880 25,358 Benefits Paid (35,822) (36,235) (34,160) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Benefit Obligation at End of Period $694,960 $625,470 $580,046 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Plan Assets Fair Value of Assets at Beginning of Period $485,927 $536,625 $569,936 Actual Return on Plan Assets 6,145 (29,898) (19,248) Employer Contribution 35,083 15,435 20,097 Benefits Paid (35,822) (36,235) (34,160) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Fair Value of Assets at End of Period $491,333 $485,927 $536,625 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Reconciliation of Funded Status Funded Status $(203,627) $(139,543) $(43,421) Unrecognized Net Actuarial Loss 222,250 132,064 23,222 Unrecognized Transition Asset - (3,716) (7,432) Unrecognized Prior Service Cost 10,274 11,451 12,236 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Prepaid (Accrued) Benefit Cost $28,897 $ 256 $(15,395) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Accumulated Benefit Obligation $611,858 $550,099 $510,155 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Amounts Recognized in the Balance Sheets Consist of: Pension Liability $(154,871) $(75,116) $(15,395) Prepayments 12,413 10,944 - Regulatory Assets 21,934 - - Intangible Assets 10,274 11,451 - Accumulated Other Comprehensive Loss (Pre-Tax) 139,147 52,977 - - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Net Amount Recognized $28,897 $ 256 $(15,395) - ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
2003 2002 2001
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate 6.00% 6.75% 7.25%
Expected Return on Plan Assets 8.25% 8.50% 8.50%
Rate of Compensation Increase 6.11% 6.11% 6.11%
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
69
Year Ended September 30 (Thousands) Components of Net Periodic Benefit Cost Service Cost $13,043 $11,639 $11,550 Interest Cost 40,967 40,720 39,061 Expected Return on Plan Assets (47,260) (48,454) (45,703) Amortization of Prior Service Cost 1,176 1,205 1,050 Amortization of Transition Amount (3,716) (3,716) (3,716) Recognition of Actuarial (Gain) or Loss 2,231 (1,061) (2,256) Early Retirement Window - - 7,337 Net Amortization and Deferral for Regulatory Purposes 3,781 7,379 4,787 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Net Periodic Benefit Cost $10,222 $7,712 $12,110 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Other Comprehensive Loss (Pre-Tax) Attributable to Change In Additional Minimum Liability Recognition $86,170 $52,977 $ - - ----------------------------------------------------------------- ----------------- ---------------- -----------------
In accordance with the provisions of SFAS No. 87, “Employers’ Accounting for Pensions,” the Company recorded an additional minimum liability at September 30, 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 effects of the discount rate changes in 2003, 2002 and 2001 were to increase the Benefit Obligation by $57.4 million, $34.0 million and $15.6 million as of the end of each period, respectively.
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 $5.1 million, $8.5 million and $6.1 million in 2003, 2002 and 2001, respectively. The benefit obligation for this plan was $40.0 million and $37.2 million at September 30, 2003 and 2002, respectively. The actuarial valuations for this plan were determined based on a discount rate of 6.0%, 6.75% and 7.25% as of September 30, 2003, 2002 and 2001, respectively; a rate of compensation increase of 8.11%, 8.11% and 7.32% as of September 30, 2003, 2002 and 2001, respectively; and an expected long-term rate of return on plan assets of 8.25%, 8.50% and 8.50% at September 30, 2003, 2002 and 2001, respectively. Under a provision of an agreement previously entered into between the Company and a participant of this plan, the participant has made an irrevocable election to receive a $23.0 million lump sum payment on January 3, 2004. When paid, this constitutes a partial settlement of the projected benefit obligations of this plan. Accordingly, the pro rata portion of this plan’s unrecognized actuarial losses resulting from experience different from that assumed and from changes in assumptions is required to be recognized upon settlement. The estimated settlement loss is $10.5 million, before tax.
Other
Post-Retirement Benefits
Reconciliations of the
Benefit Obligation, Post-Retirement Plan Assets and Funded Status, as well as
the components of Net Periodic Benefit Cost and the Weighted Average Assumptions
are as follows:
- ----------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 (Thousands) 2003 2002 2001 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Benefit Obligation Benefit Obligation at Beginning of Period $393,851 $304,548 $ 266,460 Service Cost 5,844 4,658 4,234 Interest Cost 26,124 21,617 19,557 Plan Participants' Contributions 682 610 524 Amendments - - 33 Actuarial Loss 57,983 76,972 26,661 Benefits Paid (17,066) (14,554) (12,921) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Benefit Obligation at End of Period $467,418 $393,851 $ 304,548 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Plan Assets Fair Value of Assets at Beginning of Period $150,293 $161,959 $ 176,357
70
Actual Return on Plan Assets 390 (18,181) (19,685)
Employer Contribution 32,195 20,459 17,684
Plan Participants' Contributions 682 610 524
Benefits Paid (17,066) (14,554) (12,921)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Fair Value of Assets at End of Period $166,494 $150,293 $ 161,959
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Reconciliation of Funded Status
Funded Status $(300,923) $(243,558) $(142,589)
Unrecognized Net Actuarial Loss 212,242 157,247 52,832
Unrecognized Transition Obligation 71,272 78,399 85,526
Unrecognized Prior Service Cost 25 30 33
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Accrued Benefit Cost $(17,384) $ (7,882) $ (4,198)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
2003 2002 2001
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate 6.00% 6.75% 7.25%
Expected Return on Plan Assets 8.25% 8.50% 8.50%
Rate of Compensation Increase 6.11% 6.11% 6.11%
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost $5,844 $4,658 $4,234
Interest Cost 26,124 21,617 19,557
Expected Return on Plan Assets (12,268) (13,551) (14,787)
Amortization of Prior Service Cost 4 4 -
Amortization of Transition Obligation 7,127 7,127 7,127
Amortization of (Gain) Loss 14,866 4,289 (374)
Net Amortization and Deferral for
Regulatory Purposes (15,423) (729) 4,075
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Periodic Benefit Cost $26,274 $23,415 $19,832
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The effects of the discount rate changes in 2003, 2002 and 2001 were to increase the Benefit Obligation by $45.1 million, $21.7 million and $9.8 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 Postretirement Benefit Obligation by $22.6 million.
Other actuarial experience increased the Accumulated Postretirement 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 Postretirement 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 9.0% for 2001, 12.0% for 2002, 11.0% for 2003 and gradually decline to 5.5% by the year 2009 and remain level thereafter. The annual rate of increase for medical care benefits provided by healthcare maintenance organizations was assumed to be 9.0% in 2001, 12.0% in 2002, 11.0% in 2003 and gradually decline to 5.5% by the year 2009 and remain level thereafter. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 13.0% for 2001, 15.0% for 2002, 13.5% for 2003 and gradually decline to 5.5% by the year 2009 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 9.0% for 2001, 8.0% for 2002, 7.0% for 2003 and gradually decline to 5.5% by the year 2009 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, 2003 would be increased by $68.7 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 2003 by $5.4 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2003 would be decreased by $56.3 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 2003 by $4.0 million.
71
Environmental
Matters
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 Company’s 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 in the range of $9.5 million to $10.5 million. The minimum estimated liability of $9.5 million has been recorded on the Consolidated Balance Sheet at September 30, 2003. 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.
(i) Former Manufactured Gas Plant Sites
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 Company’s 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.
(ii) Third Party Waste Disposal Sites
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.
(iii) Other
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.
Other
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 99% 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
72
extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s 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 Company’s
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 Pennsylvania Public Utility Commission (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 Federal Energy Regulatory Commission (FERC) regulates the operations of Supply Corporation and the NYPSC regulates the operations of Empire, an intrastate pipeline which was acquired on February 6, 2003 and is discussed in 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 and Louisiana and in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Seneca’s 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. Proved reserves associated with the properties sold were 19.4 million barrels of oil and 0.3 Bcf of natural gas.
The International segment’s 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. Horizon’s 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 NFR’s 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 segment’s 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.
73
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.
74
Year Ended September 30, 2003 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers $1,145,336 $106,499 $305,314 $114,070 $304,660 $56,226 $2,032,105 $3,366 $ - $2,035,471
Intersegment
Revenues $17,647 $94,921 $ - $ - $ - $ - $112,568 $ - $(112,568) $ -
Interest Expense $29,122 $14,000 $53,326 $8,700 $33 $2,507 $107,688 $521 $(3,153) $105,056
Depreciation,
Depletion and
Amortization $38,186 $35,940 $99,292 $13,910 $117 $7,543 $194,988 $238 $ - $195,226
Income Tax
Expense $36,857 $30,863 $(17,537) $876 $3,350 $72,692 $127,101 $279 $781 $128,161
Significant
Item: Gain on
Sale of Timber
Properties $ - $- $- $ - $ - $168,787 $168,787 $ - $ - $168,787
Significant
Item: Loss on
Sale of Oil and
Gas Producing
Properties $ - $ - $58,472 $ - $ - $ - $58,472 $ - $ - $58,472
Significant Non-
Cash Item:
Impairment of Oil
And Gas
Producing
Properties $ - $ - $42,774 $ - $ - $ - $42,774 $ - $ - $42,774
Segment Profit
(Loss): Income
Before
Cumulative
Effect of
Changes in
Accounting $56,808 $45,230 $(31,293) $(1,368) $5,868 $112,450 $187,695 $193 $(52) $187,836
Expenditures for
Additions to
Long-Lived Assets $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)
- -----------------------------------------------------------------------------------------------------------------------------------------
Segment Assets $1,413,858 $812,435 $969,512 $254,937 $54,134 $125,915 $3,630,791 $77,195 $19,929 $3,727,915
- -----------------------------------------------------------------------------------------------------------------------------------------
(1) Amount includes the acquisition of all of the partnership interests in Toro Partners, L.P. and is discussed in Note J -
Acquisitions.
75
Year Ended September 30, 2002 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers $776,577 $ 80,165 $310,980 $95,315 $151,257 $47,407 $1,461,701 $ 2,795 $ - $1,464,496
Intersegment
Revenues $17,644 $87,219 $- $ - $- $- $104,863 $7,340 $ (112,203) $ -
Interest Expense $30,790 $10,424 $55,367 $8,045 $76 $2,896 $107,598 $420 $(2,366) $105,652
Depreciation,
Depletion and
Amortization $37,412 $23,626 $103,946 $11,977 $161 $3,429 $180,551 $115 $2 $180,668
Income Tax
Expense $31,657 $18,148 $15,108 $(2,030) $5,103 $4,476 $72,462 $(473) $45 $72,034
Significant Non-
Cash Item:
Impairment of
Investment in
Partnership $- $15,167 $- $- $- $- $15,167 $- $- $15,167
Segment Profit
(Loss): Net
Income $49,505 $29,715 $26,851 $(4,443) $8,642 $9,689 $119,959 $(885) $(1,392) $117,682
Expenditures for
Additions to
Long-Lived Assets $51,550 $30,329 $114,602 $4,244 $51 $25,574 $226,350 $6,554 $- $232,904
At September 30, 2002 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
Segment Assets $1,248,426 $532,543 $1,161,310 $241,466 $ 52,850 $131,721 $3,368,316 $33,563 $(570) $3,401,309
- -----------------------------------------------------------------------------------------------------------------------------------------
76
Year Ended September 30, 2001 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers $1,214,614 $ 81,057 $355,005 $97,910 $259,206 $44,914 $2,052,706 $7,130 $ - $2,059,836
Intersegment
Revenues $20,033 $90,034 $- $- $- $- $110,067 $11,192 $ (121,259) $-
Interest Expense $27,489 $12,131 $56,291 $9,966 $1,649 $3,830 $111,356 $692 $(4,903) $107,145
Depreciation,
Depletion and
Amortization $36,607 $23,746 $98,408 $12,634 $212 $3,186 $174,793 $119 $2 $174,914
Income Tax
Expense $42,985 $29,091 $(36,075) $253 $(1,660) $4,566 $39,160 $(2,281) $227 $37,106
Significant Non-
Cash Item:
Impairment of
Oil and Gas
Producing
Properties $- $- $180,781 $- $- $- $180,781 $- $- $180,781
Segment Profit
(Loss): Net
Income $60,707 $40,377 $(32,284) $(3,042) $(3,432) $7,715 $70,041 $(4,277) $(265) $65,499
Expenditures for
Additions to
Long-Lived Assets $42,374 $25,978 $296,419 $15,585 $116 $3,694 $384,166 $937 $- $385,103
At September 30, 2001 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
Segment Assets $1,284,189 $549,991 $1,194,393 $206,361 $ 68,178 $113,294 $3,416,406 $26,858 $1,967 $3,445,231
- -----------------------------------------------------------------------------------------------------------------------------------------
77
- -------------------------------------------------------- ------------------ -------------------- --------------------
Geographic Information 2003 2002 2001
-------------------------------------------------------- ------------------ -------------------- --------------------
For the Year Ended September 30 (Thousands)
Revenues from External Customers(1):
United States $1,818,980 $1,293,239 $1,887,958
Czech Republic 114,070 95,315 97,910
Canada 102,421 75,942 73,968
-------------------------------------------------------- ------------------ -------------------- --------------------
$2,035,471 $1,464,496 $2,059,836
At September 30 (Thousands)
-------------------------------------------------------- ------------------ -------------------- --------------------
Long-Lived Assets:
United States $2,982,301 $2,624,810 $2,645,429
Czech Republic 219,695 216,044 187,961
Canada 116,655 258,196 257,939
-------------------------------------------------------- ------------------ -------------------- --------------------
$3,318,651 $3,099,050 $3,091,329
-------------------------------------------------------- ------------------ -------------------- --------------------
(1) Revenue is based upon the country in which the sale originates.
The Company's 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 Company's investments in unconsolidated subsidiaries at September 30, 2003 and 2002 is as follows:
---------------------------------------------------------------- --------------------- ---------------------
At September 30 (Thousands)
2003 2002
---------------------------------------------------------------- --------------------- ---------------------
ESNE $11,113 $12,522
Seneca Energy 4,445 3,625
Model City 867 606
- ---------------------------------------------------------------- --------------------- -----------------------
$16,425 $16,753
---------------------------------------------------------------- --------------------- ---------------------
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. Empire’s results of operations were incorporated into the Company’s 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 Company’s 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 delivers natural gas supplies to major industrial companies, utilities (including the Company’s 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):
Assets Acquired (see Condensed Balance Sheet below) $257,397
Liabilities Assumed (see Condensed Balance Sheet below) (68,192)
Cash Acquired at Acquisition (8,053)
--------
Cash Paid, Net of Cash Acquired $181,152
========
78
Condensed Balance Sheet:
Property, Plant and Equipment $220,792
Current Assets 14,984
Goodwill 5,476
Intangible Assets (see Note K) 8,580
Other Assets 7,565
--------
Total Assets $257,397
========
Equity $189,205
Long-Term Debt, Net of Current Portion 48,433
--------
Total Capitalization 237,638
Current Liabilities 15,265
Other Liabilities 4,494
--------
Total Capitalization and Liabilities $257,397
========
On June 3, 2003, the Company acquired for approximately $47.8 million in cash (including cash acquired) all of the partnership interests in Toro Partners, L.P. (Toro), which owns and operates eight 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. Toro's results of operations were incorporated into the Company's 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):
Assets Acquired $48,319
Liabilities Assumed (497)
Cash Acquired at Acquisition (160)
-------
Cash Paid, Net of Cash Acquired $47,662
=======
In June 2001, the Company acquired the outstanding shares of Player Petroleum Corporation (Player), an oil and gas exploration and development company, with operations based primarily in the Province of Alberta, Canada. The cost of acquiring the outstanding shares of Player was approximately $90.6 million and the acquisition was accounted for in accordance with the purchase method. Player's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition on June 30, 2001. Player's name has been changed to Seneca Energy Canada, Inc.
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 Empire's customers. In the case of 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 7 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:
- -------------------------------------------------- ------------------------------------- -------------------------------------
At September 30, 2003 (Thousands) Gross Carrying Amount Accumulated Amortization
- -------------------------------------------------- ------------------------------------- -------------------------------------
Long-Term Transportation Contracts $ 8,580 $ (713)
Long-Term Gas Purchase Contracts 31,864 (341)
- -------------------------------------------------- ------------------------------------- -------------------------------------
$40,444 $(1,054)
- -------------------------------------------------- ------------------------------------- -------------------------------------
- -------------------------------------------------- ------------------------------------- -------------------------------------
Aggregate Amortization Expense
For the Year Ended September 30, 2003 $ 1,054
- -------------------------------------------------- ------------------------------------- -------------------------------------
79
Amortization expense for the transportation contracts is estimated to be $1.1 million annually for 2004, 2005, 2006, 2007 and 2008. Amortization expense for the gas purchase contracts is estimated to be $1.6 million annually for 2004, 2005, 2006, 2007 and 2008.
At September 30, 2003 and 2002, the Company also has recorded intangible assets of $10.3 million and $11.5 million, respectively, related to its Retirement Plan, as discussed in Note F - Retirement Plan and Other Post -Retirement Benefits.
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 year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.
- --------------------- ------------------- ------------------ -------------------- ---------------- -----------------
Net
Income
Available
for Earnings (Loss) Per
Quarter Operating Operating Common Common Share
----------------------------------
Ended Revenues Income Stock Basic Diluted
- --------------------- ------------------- ------------------ -------------------- ---------------- -----------------
2003 (Thousands, except per common share amounts)
- --------------------- ----------------------------------------------------------- ----------------------------------
9/30/2003 $297,170 $122,674 $58,146(1) $0.71 $0.71
6/30/2003 $449,530 $35,411 $2,219(2) $0.03 $0.03
3/31/2003 $809,065 $156,703 $80,538 $1.00 $0.99
12/31/2002 $479,706 $99,628 $38,041(3) $0.47 $0.47
- --------------------- ----------------------------------------------------------------- ----------------------------
2002 (Thousands, except per common share amounts)
- --------------------- ----------------------------------------------------------------- ----------------------------
9/30/2002 $244,610 $28,268 $4,875 $0.06 $0.06
6/30/2002 $350,123 $71,113 $17,676(4) $0.22 $0.22
3/31/2002 $477,436 $123,136 $61,924 $0.78 $0.77
12/31/2001 $392,327 $81,507 $33,207 $0.42 $0.41
- --------------------- ------------------- ------------------ -------------------- ---------------- -----------------
(1) Includes a gain of $102.2 million from the sale of timber properties, a loss of $39.6 million related to
the sale of oil and gas properties and expense of $6.3 million related to the impairment of oil and gas
producing properties.
(2) Includes expense of $22.6 million related to the impairment of oil and gas producing properties.
(3) 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).
(4) Includes expense of $9.9 million related to the impairment of investment in partnership.
At September 30, 2003, there were 19,217 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 (based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2003 and 2002, are shown below:
- --------------------------------------------------------------- ------------------------------------ -----------------
Price Range Dividends
------------------------------------
Quarter Ended High Low Declared
- --------------------------------------------------------------- ------------------- ---------------- -----------------
2003
- --------------------------------------------------------------- ------------------- ---------------- -----------------
9/30/2003 $27.51 $22.51 $.270
6/30/2003 $26.90 $21.60 $.270
3/31/2003 $22.25 $18.97 $.260
12/31/2002 $21.86 $17.95 $.260
- --------------------------------------------------------------- ------------------- ---------------- -----------------
2002
- --------------------------------------------------------------- ------------------- ---------------- -----------------
9/30/2002 $22.84 $15.61 $.260
6/30/2002 $24.98 $21.38 $.260
3/31/2002 $25.70 $22.00 $.2525
12/31/2001 $24.95 $21.95 $.2525
- --------------------------------------------------------------- ------------------- ---------------- -----------------
80
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.
- --------------------------------------------------------------------------------- ------------------ -----------------
At September 30 (Thousands)
2003 2002
- --------------------------------------------------------------------------------- ------------------ -----------------
Proved Properties $1,628,995 $1,779,962
Unproved Properties 30,955 50,925
- --------------------------------------------------------------------------------- ------------------ -----------------
1,659,950 1,830,887
Less - Accumulated Depreciation, Depletion
and Amortization 763,258 776,477
- --------------------------------------------------------------------------------- ------------------ -----------------
$896,692 $1,054,410
- --------------------------------------------------------------------------------- ------------------ -----------------
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, 2003:
- ---------------------------- -------------------------- --------------------------------------------------------------
Total as of Year Costs Incurred
--------------------------------------------------------------
(Thousands) September 30, 2003 2003 2002 2001 Prior
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
Acquisition Costs $30,955 $8,129 $5,102 $7,861 $9,863
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
Proved $ (13) $ 9,316 $ 1,713
Unproved 1,920 698 15,296
Exploration Costs 17,947 25,583 42,338
Development Costs 23,649 51,792 88,987
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
43,503 87,389 148,334
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
Proved 181 (536) 115,643
Unproved 6,217 2,804 2,612
Exploration Costs 6,641 8,779 8,523
Development Costs 17,745 15,332 36,554
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
30,784 26,379 163,332
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs: (1)
Proved 168 8,780 117,356
Unproved 8,137 3,502 17,908
Exploration Costs 24,588 34,362 50,861
Development Costs 41,394 67,124 125,541
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
$74,287 $113,768 $311,666
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Total proved and unproved property acquisition costs for 2001 of $135.3 million include $107.6 million
related to the Player acquisition.
81
For the years ended September 30, 2003, 2002 and 2001, the Company spent $1.7 million, $18.2 million and $41.1 million, respectively, developing proved undeveloped reserves.
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands, Except Per Mcfe Amounts) 2003 2002 2001
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates
of $69, $43 and $4, respectively) $148,104 $104,954 $216,729
Oil, Condensate and Other Liquids 118,277 101,549 121,973
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 266,381 206,503 338,702
Production/Lifting Costs 39,162 42,956 37,068
Depreciation, Depletion and Amortization
($1.29, $1.25 and $1.13 per Mcfe of production) 70,127 80,142 76,686
Income Tax Expense 63,398 30,253 83,649
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) 93,694 53,152 141,299
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas 26,992 14,621 4,379
Oil, Condensate and Other Liquids 62,908 56,511 74,349
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 89,900 71,132 78,728
Production/Lifting Costs 33,038 30,109 27,089
Depreciation, Depletion and Amortization
($1.30, $0.93 and $0.93 per Mcfe of production) 26,165 21,707 18,719
Impairment of Oil and Gas Producing Properties(2) 42,774 - 180,781
Income Tax Expense (Benefit) (3,069) 4,672 (63,795)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) (9,008) 14,644 (84,066)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates
of $69, $43 and $4, respectively) 175,096 119,575 221,108
Oil, Condensate and Other Liquids 181,185 158,060 196,322
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 356,281 277,635 417,430
Production/Lifting Costs 72,200 73,065 64,157
Depreciation, Depletion and Amortization
($1.30, $1.16 and $1.08 per Mcfe of production) 96,292 101,849 95,405
Impairment of Oil and Gas Producing Properties(2) 42,774 - 180,781
Income Tax Expense 60,329 34,925 19,854
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) $84,686 $ 67,796 $ 57,233
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(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)
The Company’s 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.
82
------------------------------------------------------------------------------------
Gas MMcf
------------------------------------------------------------------------------------
U. S.
--------------------------------------------------------
Gulf Coast West Coast Appalachian Total Total
Region Region Region U. S. Canada Company
- --------------------------------------------------------------------------------------------------------------------------------------
Proved Developed and
Undeveloped Reserves:
September 30, 2000 113,402 110,364 74,744 298,510 3,157 301,667
Extensions and Discoveries 25,363 2,021 8,576 35,960 15,681 51,641
Revisions of Previous Estimates (12,178) (9,914) (721) (22,813) (34) (22,847)
Production (30,663) (4,383) (4,142) (39,188) (1,816) (41,004)
Sales of Minerals in Place (6,066) - - (6,066) (280) (6,346)
Purchases of Minerals in Place and Other - 410 - 410 38,859 39,269
- --------------------------------------------------------------------------------------------------------------------------------------
September 30, 2001 89,858 98,498 78,457 266,813 55,567 322,380
Extensions and Discoveries 6,530 5,770 4,242 16,542 20,263 36,805
Revisions of Previous Estimates 1,613 (26,063) 342 (24,108) (20,676) (44,784)
Production (25,776) (4,889) (4,402) (35,067) (6,387) (41,454)
Sales of Minerals in Place (14,361) - (365) (14,726) - (14,726)
Purchases of Minerals in Place and Other - - - - - -
- --------------------------------------------------------------------------------------------------------------------------------------
September 30, 2002 57,864 73,316 78,274 209,454 48,767 258,221
Extensions and Discoveries 10,538 - 5,844 16,382 11,641 28,023
Revisions of Previous Estimates (2,278) 1,213 2,224 1,159 (2,211) (1,052)
Production (18,441) (4,467) (5,123) (28,031) (5,774) (33,805)
Sales of Minerals in Place - - - - (270) (270)
Purchases of Minerals in Place and Other - - - - - -
- --------------------------------------------------------------------------------------------------------------------------------------
September 30, 2003 47,683 70,062 81,219 198,964 52,153 251,117
- --------------------------------------------------------------------------------------------------------------------------------------
Proved Developed Reserves:
September 30, 2000 107,921 44,585 74,744 227,250 3,157 230,407
September 30, 2001 87,893 47,442 78,457 213,792 53,463 267,255
September 30, 2002 57,274 57,286 78,273 192,833 39,253 232,086
September 30, 2003 45,402 54,180 81,218 180,800 42,745 223,545
- --------------------------------------------------------------------------------------------------------------------------------------
Oil Mbbl
------------------------------------------------------------------------------------
U.S.
--------------------------------------------------------
Gulf Coast West Coast Appalachian Total Total
Region Region Region U. S. Canada Company
- --------------------------------------------------------------------------------------------------------------------------------------
Proved Developed and
Undeveloped Reserves:
September 30, 2000 8,488 68,944 79 77,511 42,186 119,697
Extensions and Discoveries 393 531 - 924 3,625 4,549
Revisions of Previous Estimates 12 1,720 5 1,737 (5,396) (3,659)
Production (1,914) (2,875) (7) (4,796) (3,061) (7,857)
Sales of Minerals in Place (685) - - (685) (80) (765)
Purchases of Minerals in Place and Other - 104 - 104 3,259 3,363
- --------------------------------------------------------------------------------------------------------------------------------------
September 30, 2001 6,294 68,424 77 74,795 40,533 115,328
Extensions and Discoveries 57 1,360 20 1,437 586 2,023
Revisions of Previous Estimates 781 129 6 916 (10,278) (9,362)
Production (1,815) (3,004) (9) (4,828) (2,834) (7,662)
Sales of Minerals in Place (200) - - (200) (410) (610)
Purchases of Minerals in Place and Other - - - - - -
- --------------------------------------------------------------------------------------------------------------------------------------
September 30, 2002 5,117 66,909 94 72,120 27,597 99,717
Extensions and Discoveries 104 - 46 150 729 879
83
Revisions of Previous Estimates (365) (185) 8 (542) (4,119) (4,661) Production (1,473) (2,872) (10) (4,355) (2,382) (6,737) Sales of Minerals in Place - - - - (19,434) (19,434) Purchases of Minerals in Place and Other - - - - - - - -------------------------------------------------------------------------------------------------------------------------------------- September 30, 2003 3,383 63,852 138 67,373 2,391 69,764 - -------------------------------------------------------------------------------------------------------------------------------------- Proved Developed Reserves: September 30, 2000 8,224 57,771 79 66,074 35,130 101,204 September 30, 2001 6,259 44,304 77 50,640 33,676 84,316 September 30, 2002 5,111 41,735 94 46,940 24,100 71,040 September 30, 2003 2,533 40,079 139 42,751 2,391 45,142 - --------------------------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited) The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
United States 2003 2002 2001
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows $2,684,286 $2,764,556 $2,127,601
Less:
Future Production Costs 579,321 546,182 602,479
Future Development Costs 116,639 117,999 121,240
Future Income Tax Expense at
Applicable Statutory Rate 613,893 653,347 376,667
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 1,374,433 1,447,028 1,027,215
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 641,185 665,941 421,865
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows 733,248 781,087 605,350
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows 279,772 888,515 890,381
Less:
Future Production Costs 85,817 413,006 533,848
Future Development Costs 9,787 25,398 19,608
Future Income Tax Expense at
Applicable Statutory Rate 58,436 101,919 76,191
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 125,732 348,192 260,734
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 40,575 103,097 79,295
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows 85,157 245,095 181,439
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows 2,964,058 3,653,071 3,017,982
84
Less:
Future Production Costs 665,138 959,188 1,136,327
Future Development Costs 126,426 143,397 140,848
Future Income Tax Expense at
Applicable Statutory Rate 672,329 755,266 452,858
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 1,500,165 1,795,220 1,287,949
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 681,760 769,038 501,160
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows $818,405 $1,026,182 $ 786,789
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2003 2002 2001
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $781,087 $605,350 $1,240,375
Sales, Net of Production Costs (227,219) (163,548) (301,634)
Net Changes in Prices, Net of Production Costs 11,130 441,085 (921,719)
Purchases of Minerals in Place - - 1,191
Sales of Minerals in Place - (27,197) (17,552)
Extensions and Discoveries 29,266 42,970 52,062
Changes in Estimated Future Development Costs (35,062) (42,069) (3,157)
Previously Estimated Development Costs Incurred 36,423 45,310 61,482
Net Change in Income Taxes at
Applicable Statutory Rate 24,796 (126,263) 363,425
Revisions of Previous Quantity Estimates (3,572) (32,646) (29,841)
Accretion of Discount and Other 116,399 38,095 160,718
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 733,248 781,087 605,350
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year 245,095 181,439 277,757
Sales, Net of Production Costs (56,862) (41,023) (51,638)
Net Changes in Prices, Net of Production Costs 8,167 111,148 (161,461)
Purchases of Minerals in Place - - 30,575
Sales of Minerals in Place (120,960) (3,084) (761)
Extensions and Discoveries 28,241 29,813 39,752
Changes in Estimated Future Development Costs (14,045) 18,151 (31,009)
Previously Estimated Development Costs Incurred 29,657 12,361 12,176
Net Change in Income Taxes at
Applicable Statutory Rate (6,280) (6,910) 73,865
Revisions of Previous Quantity Estimates (41,205) (88,571) (64,368)
Accretion of Discount and Other 13,349 31,771 56,551
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 85,157 245,095 181,439
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year 1,026,182 786,789 1,518,132
Sales, Net of Production Costs (284,081) (204,571) (353,272)
Net Changes in Prices, Net of Production Costs 19,297 552,233 (1,083,180)
Purchases of Minerals in Place - - 31,766
Sales of Minerals in Place (120,960) (30,281) (18,313)
Extensions and Discoveries 57,507 72,783 91,814
Changes in Estimated Future Development Costs (49,107) (23,918) (34,166)
85
Previously Estimated Development Costs Incurred 66,080 57,671 73,658
Net Change in Income Taxes at
Applicable Statutory Rate 18,516 (133,173) 437,290
Revisions of Previous Quantity Estimates (44,777) (121,217) (94,209)
Accretion of Discount and Other 129,748 69,866 217,269
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $818,405 $1,026,182 $ 786,789
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Schedule II - Valuation and Qualifying Accounts
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Additions Additions
Balance at Charged to Charged to Balance at
(Thousands) Beginning Costs and Other End of
Description of Period Expenses Accounts(1) Deductions(2) Period
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 2003
Reserve for Doubtful Accounts $17,299 $17,275 $ - $16,631 $17,943
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 2002
Reserve for Doubtful Accounts $18,521 $16,082 $2,834 $20,138 $17,299
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 2001
Reserve for Doubtful Accounts $12,013 $17,445 $ - $10,937 $18,521
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
(1) Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate
settlements.
(2) Amounts represent net accounts receivable written-off.
None
The following information includes the evaluation of disclosure controls and procedures by the Company’s 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 Company’s management, including the Chief Executive Officer and Treasurer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Treasurer concluded that the Company’s 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 Company’s transactions are properly authorized, the Company’s assets are safeguarded against unauthorized or improper use, and the Company’s transactions are properly recorded and reported to permit preparation of the Company’s financial statements in conformity with GAAP. There were no changes in the Company’s 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 Company’s internal control over financial reporting.
86
PART III
The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 19, 2004 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2003. 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 2006,” “Directors Whose Terms Expire in 2005,” “Directors Whose Terms Expire in 2004,” and “Compliance with Section 16(a) of the Securities Exchange Act of 1934” and is incorporated herein by reference. Information concerning the Company’s 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 Company’s directors, officers and employees and will post such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuelgas.com, together with certain other corporate governance documents, as soon as reasonably practicable after this report is filed with, or furnished to, the SEC. Copies of the Company’s 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.
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 19, 2004 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2003. 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.
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Plan category Number of securities to Weighted-average Number of securities
be issued upon exercise exercise price of out- remaining available for
of outstanding options, standing options, future issuance under
warrants and rights warrants and rights equity compensation
plans (excluding
securities reflected in
column (a))
(a) (b) (c)
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Equity compensation
plans approved by 14,065,338 $22.41 807,351
security holders
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Equity compensation
plans not approved by
security holders 0 0 0
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Total 14,065,338 $22.41 807,351
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
(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 Company’s definitive Proxy Statement for its February 19, 2004 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2003. The information concerning security ownership of certain beneficial
87
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.
(b) Security Ownership of Management
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 19, 2004 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2003. 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
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 19, 2004 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2003. 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.
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 19, 2004 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2003. The information concerning principal accountant fees and services is set forth in the definitive Proxy Statement under the caption “Independent Auditor’s Fees” and is incorporated herein by reference.
PART IV
(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:
o 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:
o National Fuel Gas Company By-Laws as amended on December 12, 2002 (Exhibit 3(ii), Form
10-Q for quarterly period ended December 31, 2002 in File No. 1-3880)
(4) Instruments Defining the Rights of Security Holders, Including Indentures:
88
o 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)
o 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)
o Tenth Supplemental Indenture, dated as of February 1, 1992, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a), Form
8-K dated February 14, 1992 in File No. 1-3880)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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 Company's business is substantially dependent:
o 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)
89
(10.1) First Amendment to Credit Agreement, among the Company, the Lenders and JPMorgan Chase Bank, dated
September 29, 2003
(iii) Compensatory plans for officers:
(10.2) Retirement Benefit Agreement, dated September 22, 2003, between the Company and David F. Smith
o Retirement and Consulting Agreement, dated September 5, 2001, between the Company and Bernard J.
Kennedy (Exhibit 10(iii)(a), Form 8-K dated September 19, 2001 in File No. 1-3880)
o Pension Settlement Agreement, dated September 5, 2001, between the Company and Bernard J. Kennedy
(Exhibit 10(iii)(b), Form 8-K for dated September 19, 2001 in File No. 1-3880)
o Agreement, dated August 1, 1986, between the Company and Joseph P. Pawlowski (Exhibit 10.1, Form 10-K
for fiscal year ended September 30,1997 in File No. 1-3880)
o Agreement, dated August 1, 1986, between the Company and Gerald T. Wehrlin (Exhibit 10.2, Form 10-K
for fiscal year ended September 30, 1997 in File No. 1-3880)
o 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, Walter E. DeForest, Joseph P. Pawlowski, James D. Ramsdell, Dennis J. Seeley,
David F. Smith, Ronald J. Tanski and Gerald T. Wehrlin (Exhibit 10.1, Form 10-Q for the quarterly
period ended June 30, 1999 in File No. 1-3880)
o 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)
o 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)
o National Fuel Gas Company 1983 Incentive Stock Option Plan, as amended and restated through February
18, 1993 (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 1993 in File No.
1-3880)
o National Fuel Gas Company 1984 Stock Plan, as amended and restated through February 18, 1993 (Exhibit
10.3, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880)
o Amendment to the National Fuel Gas Company 1984 Stock Plan, dated December 11, 1996 (Exhibit 10.7,
Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
o 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)
o 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)
o 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)
o 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)
o 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)
90
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o Death Benefits Agreement, dated August 28, 1991, between the Company and Bernard J. Kennedy (Exhibit
10-TT, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880)
o Amendment to Death Benefit Agreement of August 28, 1991, between the Company and Bernard J. Kennedy,
dated March 15, 1994 (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1995 in File
No. 1-3880)
o 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)
o 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)
o 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)
o 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)
91
o 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)
o 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)
o Second Amended and Restated Split Dollar Insurance Agreement dated June 15,
1999, between the Company and Gerald T. Wehrlin (Exhibit 10.6, Form 10-K for
fiscal year ended September 30, 1999 in File No. 1-3880)
o Amended and Restated Split Dollar Insurance and Death Benefit Agreement,
dated September 15, 1997, between the Company and Walter E. DeForest (Exhibit
10.7, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
o Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit
Agreement by and between the Company and Walter E. DeForest, dated March 29,
1999 (Exhibit 10.8, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
o 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)
o 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)
o 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)
o 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)
o 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)
o 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)
o Split Dollar Insurance Agreement, dated March 6, 2001, between the Company and James A. Beck
(Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2002 in File No. 1-3880)
o 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)
o 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)
o 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)
92
o 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)
o 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)
o 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)
o Retirement Supplement Agreement, dated September 14, 2000, between the Company and
Gerald T. Wehrlin (Exhibit 10.5, Form 10-K/A for fiscal year ended September 30, 2001
in File No. 1-3880)
o Retirement Supplement Agreement, dated January 11, 2002, between the C ompany and
Joseph P. Pawlowski (Exhibit 10.6, Form 10-K/A for fiscal year ended September
30, 2001 in File No. 1-3880)
o 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)
o 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)
o Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas
Company, as amended and restated, effective December 10, 1998 (Exhibit 10.3, Form 10-Q for the
quarterly period ended December 31, 1998 in File No. 1-3880)
o Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of February 20,
1997 regarding the Retirement Benefits for Bernard J. Kennedy (Exhibit 10.10, Form 10-K for
fiscal year ended September 30, 1997 in File No. 1-3880)
o 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)
(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 13(a)-15(e)/15(d)-15(e) of the Exchange
Act.
31.2 Written statements of Principal Financial Officer pursuant to Rule 13(a)-15(e)/15(d)-15(e) of the
Exchange Act.
93
(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
o 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.
o 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.
(b) Reports on Form 8-K
A report on Form 8-K dated July 29, 2003 was furnished to the SEC on July 31, 2003, to report the sale of
certain Canadian properties on July 29, 2003 and earnings for the quarter ended June 30, 2003 under
Item 12, "Results of Operations and Financial Condition." Related exhibits were reported under
Item 7, "Financial Statements and Exhibits."
94
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 29, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title
/s/ P. C. Ackerman Chairman of the Board, President,
P. C. Ackerman Chief Executive Officer and Director
Date: December 29, 2003
/s/ R. T. Brady Director
R. T. Brady
Date: December 29, 2003
/s/ R. D. Cash Director
R. D. Cash
Date: December 29, 2003
/s/ J. V. Glynn Director
J. V. Glynn
Date: December 29, 2003
/s/ B. J. Kennedy Director
B. J. Kennedy
Date: December 29, 2003
/s/ R. E. Kidder Director
R. E. Kidder
Date: December 29 2003
95
/s/ B. S. Lee Director
B. S. Lee
Date: December 29, 2003
/s/ G. L. Mazanec Director
G. L. Mazanec
Date: December 29, 2003
/s/ J. F. Riordan Director
J. F. Riordan
Date: December 29, 2003
/s/ J. P. Pawlowski Treasurer, Principal Financial
J. P. Pawlowski Officer and Principal Accounting Officer
Date: December 29, 2003
96
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 2003
Two pie graphs detailing the revenue dollar in 2003: where it came from and where it went to, broken down as follows:
Where it came from:
$ 0.363 Residential Gas Sales
0.138 Energy Marketing Revenues
0.135 Oil and Gas Production Revenues
0.121 Commercial, Industrial and Off-System Gas Sales
0.102 Timber and Sawmill Revenues
0.058 Gas Transportation Revenues
0.037 District Heating Revenues
0.013 Gas Storage Service Revenues
0.013 Electric Generation Revenues
0.020 Other Revenues
------
$1.000 Total
Where it went to:
$ 0.436 Gas Purchased
0.095 Taxes
0.091 Wages, Including Benefits
0.088 Depreciation
0.084 Other Materials and Services
0.081 Earnings
0.047 Interest
0.028 Fuel Used in Heat and Electric Generation
0.027 Loss on Sale of Oil and Gas Producing Properties
0.019 Impairment of Oil and Gas Producing Properties
0.004 Cumulative Effect of Changes in Accounting
------
$1.000 Total
Exhibit Index
-------------
10.1 First Amendment to Credit Agreement, dated September 29, 2003
between National Fuel Gas Company and JPMorgan Chase Bank
10.2 Retirement Benefit Agreement, dated September 22, 2003,
between the Company and David F. Smith
12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the fiscal years
ended September 30, 1999 through 2003
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
31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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