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, 2002
Commission File Number 1-3880
National
Fuel Gas Company
(Exact name of registrant as specified in its charter)
| New Jersey | 13-1086010 |
|---|---|
| (State or other jurisdiction of | (I.R.S. Employer |
| incorporation or organization) | Identification No.) |
| 10 Lafayette Square | 14203 |
| Buffalo, New York | (Zip Code) |
| (Address of principal executive offices) |
(716)
857-7000
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. [ ]
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,634,293,000 as of November 30, 2002.
Common Stock, $1 Par Value, outstanding as of November 30, 2002: 80,437,839 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 20, 2003 are incorporated by reference into Part III of this report.
|
GENERAL INFORMATION ON FACILITIES |
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 Operations (MD&A), under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are designated with an asterisk (“*”) following the statement, as well as those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.
PART I
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. The Registrant is engaged in the business of owning and holding securities issued by its twelve directly owned subsidiary companies. 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 732,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation. 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. Seneca Independence Pipeline Company (SIP) held a one-third general partnership interest in Independence Pipeline Company (Independence), a Delaware general partnership that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania (the Independence Pipeline). Independence was dissolved on September 30, 2002. As discussed in Item 7, MD&A under the heading "Capital Resources and Liquidity", in June 2002 Independence submitted a motion to the Federal Energy Regulatory Commission (FERC) requesting that FERC vacate the certificate that it had issued to Independence to construct, own and operate the Independence Pipeline. FERC formally vacated the certificate in July 2002.
As discussed below under "Competition: The Pipeline and Storage Segment", in October 2002 the Company announced its intention to buy the Empire State Pipeline (Empire) from Duke Energy Corporation.
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, in Wyoming and in the Gulf Coast region of Texas and Louisiana. Also, Exploration and Production operations are conducted in the provinces of Manitoba, Alberta, Saskatchewan and British Columbia in Canada by Seneca's wholly-owned subsidiaries, National Fuel Exploration Corp. (NFE), an Alberta, Canada corporation, and Player Resources Ltd. (Player), an Alberta, Canada corporation.
4. The International segment operations are carried out by Horizon Energy Development, Inc. (Horizon), a New York corporation. Horizon engages in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include 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.
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 Pennsylvania 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 three sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods.
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 I - 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 wholesale natural gas marketing and other energy-related
activities;
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. DirectLink, was formed to engage in
natural gas marketing and related businesses in part by subscribing for firm transportation capacity on the proposed
Independence Pipeline (see Pipeline and Storage segment discussion above);
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.
No single customer, or group of customers under common control, accounted for more than 10% of the Company's consolidated revenues in 2002.
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 2002, both houses of Congress passed comprehensive energy bills that included repeal of the Holding Company Act. The bills were referred to a conference committee of the House and Senate, but no action was taken by the conferees prior to adjournment. It is likely that comprehensive energy legislation, including repeal of the Holding Company Act, will be re-introduced in the next session of Congress.* Thus far, the proposed legislation would transfer certain oversight responsibilities to the various state public utility regulatory commissions and FERC and would expand the access of these bodies to the books and records of companies in a holding company system. The proposed legislation could increase regulation, especially at the state level.* By contrast, previous SEC rule changes have reduced the number of applications required to be filed under the Holding Company Act, exempted some routine financings and expanded diversification opportunities. The Company is unable to predict at this time what the ultimate outcome of legislative or regulatory changes will be and, therefore, what impact such efforts might have on the Company.*
The Utility segment's rates, services and other matters are regulated by the State of New York Public Service Commission (NYPSC) with respect to services provided within New York and by the Pennsylvania Public Utility Commission (PaPUC) with respect to services provided within Pennsylvania. For additional discussion of the Utility 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 are regulated by FERC. 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 42.1% of the Company's 2002 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 2002 net income available for common stock.
Supply Corporation currently has service agreements for substantially all of its firm transportation capacity, which totals approximately 2,075 thousand dekatherms (MDth) per day. The Utility segment accounts for approximately 1,171 MDth per day or 56.4% of the total capacity, and the Energy Marketing segment represents another 85 MDth per day or 4.1% of the total capacity. The remaining 819 MDth or 39.5% of Supply Corporation's firm transportation capacity is subject to firm contracts with nonaffiliated customers.
Supply Corporation has available for sale approximately 68,854 MDth of firm storage capacity. The Utility segment has contracted for 31,395 MDth or 45.6% of the total capacity and the Energy Marketing segment accounts for another 3,955 MDth or 5.7% of the total capacity. Nonaffiliated customers have contracted for the remaining 33,504 MDth or 48.7% of the firm 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.*
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 contributed approximately 22.8% of the Company's 2002 net income available for common stock.
Additional discussion of the Exploration and Production segment appears below under the headings "Sources and Availability of Raw Materials" and "Competition," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The International segment incurred a net loss in 2002. The impact of this segment’s net loss in relation to the Company’s 2002 net income available for common stock was negative 3.8%.
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 7.3% of the Company's 2002 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 8.2% of the Company's 2002 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 incurred a net loss in 2002. The impact of this net loss in relation to the Company’s 2002 net income available for common stock was negative 1.9%.
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 2002, the Utility segment purchased 109.8 billion cubic feet (Bcf) of gas. Gas purchases from various producers and marketers in the southwestern United States and Canada under long-term (two years or longer) contracts accounted for 57% of these purchases. Purchases of gas on the spot market (contracts of less than a year) accounted for 36% of the Utility segment’s 2002 gas purchases. Gas purchases from Dynegy Marketing and Trade, Mirant Americas Energy Marketing, LP, BP Energy Company and Anadarko Energy Services Company represented 15%, 13%, 12% and 11%, respectively, of total 2002 gas purchases by the Utility segment. These four producers or marketers provided gas from the southwestern United States under long-term contracts. No other producer or marketer provided the Utility segment with 10% or more of its gas requirements in 2002. Currently, the Utility segment’s top suppliers of natural gas are BP Energy Company, Amerada Hess Corp., Conoco Inc., Anadarko Energy Services Company and Occidental Energy Marketing, Inc.
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. Additional discussion of proposed pipeline projects appears below under "Competition: The Pipeline and Storage Segment," in Item 7, MD&A and in Item 8 at Note H - Commitments and Contingencies.
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 I-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 2002 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 has proven reserves through 2030.* The Czech Republic government imports natural gas from sources in Russia and the North Sea and transports the gas 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. The Czech Republic government also imports oil. 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. Seventy percent of the timber processed comes from land owned by Seneca; therefore, the source and availability of this segment's primary raw material are generally known in advance.
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2002, this segment purchased 31.5 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 should continue to enhance the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, by removing some of the regulatory impediments to adding customers and responding to market forces.* In addition, the environmental advantages of natural gas compared with other fuels should increase the role of natural gas as an energy source.*
The electric industry is moving toward a more competitive environment as a result of the Federal Energy Policy Act of 1992 and initiatives undertaken by the FERC and various states. It remains unclear what impact this restructuring will have on the Company.*
The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this "Competition" heading, do not compete with the Company to any significant extent.*
Competition:
The Utility Segment
The changes precipitated by
the FERC’s restructuring of the gas industry in Order No. 636 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, the Utility
segment’s traditional distribution function remains largely unchanged. For
further discussion of state restructuring initiatives refer to Item 7, MD&A
under the heading “Rate Matters.”
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.
Competition:
The Pipeline and Storage Segment
Supply Corporation competes
for market growth in the natural gas market with other pipeline companies
transporting gas in the northeastern 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.*
In October 2002, the Company announced that it had signed an agreement to acquire Empire. Empire is a natural gas transmission pipeline that originates at the United States/Canada border at the Chippawa Channel of the Niagara River near Buffalo, New York and extends easterly for 157 miles where it terminates in Central New York just north of Syracuse, New York. Empire competes with other pipelines to transport natural gas from Canada to upstate New York. Refer to Item 7, MD&A under the heading "Capital Resources and Liquidity" and Item 8 at Note H - Commitments and Contingencies for further discussion of Empire.
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 projects, refer to Item 7, MD&A under the heading "Investing Cash Flow."
Competition:
The Exploration and Production Segment
The Exploration and
Production segment competes with other gas and oil producers and marketers with
respect to sales of oil and gas. The Exploration and Production segment also
competes, by competitive bidding and otherwise, with other oil and natural gas
exploration and production companies of various sizes for leases and drilling
rights for exploration and development prospects.
To compete in this environment, Seneca and its wholly-owned subsidiaries NFE and Player, each originate and act as operator on most prospects, minimize risk of exploratory efforts through partnership-type arrangements, apply the latest technology for both exploratory studies and drilling operations, and focus on market niches that suit their size, operating expertise and financial criteria.
Competition:
The International Segment
Horizon competes with other
entities seeking to develop or acquire foreign and domestic energy projects.
Horizon, through UE, faces competition in the sale of thermal energy. Most
customers can opt to install boilers to produce their thermal energy, rather
than purchase thermal energy from the district heating system. In addition, UE
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. UE sells electricity at the wholesale level.
Competition:
The Energy Marketing Segment
The Energy Marketing
segment competes with other marketers of natural gas and with other providers of
energy management services. Although the deregulation of natural gas utilities
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.
Competition:
The Timber Segment
With respect to the Timber
segment, Highland competes with other sawmill operations and with other
suppliers of timber, logs and lumber. These competitors may be local, regional,
national or international in scope. This competition, however, is primarily
limited to those entities which either process or supply high quality hardwoods
species such as cherry, oak and maple as veneer logs, saw logs, export logs or lumber
ultimately used in the production of high-end furniture, cabinetry and flooring.
The Timber segment sells its products both nationally and internationally.
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 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 reimburse the variable costs caused by actual transportation or storage of gas.
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 H-Commitments and Contingencies.
The Company and its wholly-owned or majority-owned subsidiaries had a total of 3,177 full-time employees at September 30, 2002, with 2,233 employees in all of its U.S. operations and 944 employees in its international operations. This is a decrease of 1.8% from the 3,235 total employed at September 30, 2001.
Agreements covering employees in collective bargaining units in New York were renegotiated, effective as of November 2000, and are scheduled to expire in February 2006. Certain agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective November 1998, and are scheduled to expire in May 2003. Other agreements covering employees in collective bargaining units in Pennsylvania were renegotiated, effective October 1, 2002, and are scheduled to expire in April 2007. An agreement covering employees in collective bargaining units in the Czech Republic was renegotiated in 2001 and is scheduled to expire in 2004.
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's Internet address is WWW.NATIONALFUELGAS.COM. This reference to the Company's Internet address shall not, under any circumstances, be deemed to incorporate the information available at such Internet address into this Form 10-K. The information available at the Company's Internet address is not part of this Form 10-K or any other report filed by the Company with the SEC.
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Name and Age(2) Current Company Positions and Other Material
Business Experience During Past Five Years(3)
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Philip C. Ackerman Chairman of the Board of Directors since January 2002; Chief Executive Officer
(58) 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.
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Dennis J. Seeley President of Supply Corporation since March 2000; Senior Vice President of
(59) 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.
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David F. Smith President of Distribution Corporation since July 1999; Senior Vice President
(49) of Supply Corporation since July 2000. Mr. Smith served as Senior Vice President
of Distribution Corporation from January 1993 to July 1999.
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James A. Beck President of Seneca since October 1996 and President of Highland since March
(55) 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.
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Gerald T. Wehrlin President of NFR since May 2001; Controller of the Company since December 1980;
(64) and Vice President of Horizon since February 1997. Mr. Wehrlin previously
served as Senior Vice President of Distribution Corporation from April 1991 to
May 2001 and as Secretary and Treasurer of Horizon from September 1995 to
February 1997.
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Bruce H. Hale President of Horizon Power since March 2001; Senior Vice President of Supply
(53) 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.
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Name and Age(2) Current Company Positions and Other Material
Business Experience During Past Five Years(3)
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Joseph P. Pawlowski Treasurer since December 1980; Senior Vice President of Distribution Corporation
(61) since February 1992 and Treasurer of Distribution Corporation since January
1981; Treasurer of Supply Corporation since June 1985; and Secretary of Supply
Corporation since October 1995.
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Walter E. DeForest Senior Vice President of Distribution Corporation since August 1993; and Senior
(61) Vice President of Supply Corporation from January 1992 to August 1993.
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Anna Marie Cellino Senior Vice President of Distribution Corporation since July 2001; Vice
(49) President of Distribution Corporation from June 1994 to July 2001; and Secretary
of the Company since October 1995.
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Ronald J. Tanski Senior Vice President of Distribution Corporation since July 2001; Controller of
(50) 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.
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John R. Pustulka Senior Vice President of Supply Corporation since July 2001; and Vice President
(50) of Supply Corporation from April 1993 to July 2001.
- ---------------------------- --------------------------------------------------------------------------------------
James D. Ramsdell Senior Vice President of Distribution Corporation since July 2001; and Vice
(47) President of Distribution Corporation from June 1994 to July 2001.
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(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, 2002.
(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.
The investment of the Company in net property, plant and equipment was $2.8 billion at September 30, 2002. Approximately 51% of this investment was in the Utility and Pipeline and Storage segments, which are primarily located in western New York and northwestern Pennsylvania. The Exploration and Production segment, which is the next largest investment in net property, plant and equipment (38%), 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 Manitoba, Alberta, Saskatchewan and British Columbia in Canada. The remaining investment in net property, plant and equipment consisted primarily of the International segment (7%) which is located in the Czech Republic and the Timber segment (4%) 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, to expand and improve transmission and distribution facilities for both retail and transportation customers, and to purchase district heating and power generation facilities in the Czech Republic. Net property, plant and equipment has increased $1.025 billion, or 56%, since 1997.
The Utility segment had a net investment in property, plant and equipment of $960.0 million at September 30, 2002. The net investment in its gas distribution network (including 14,783 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, 2002.
The Pipeline and Storage segment had a net investment of $487.8 million in property, plant and equipment at September 30, 2002. Transmission pipeline, with a net cost of $148.1 million, represents 30% of this segment's total net investment and includes 2,471 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 $87.7 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 $1.072 billion at September 30, 2002. Of this amount, $814 million relates to properties located in the United States. The remaining net investment of $258 million relates to properties located in Canada.
The International segment had a net investment in property, plant and equipment of $207.2 million at September 30, 2002. 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 $110.6 million at September 30, 2002. Located primarily in northwestern Pennsylvania, the net investment includes three sawmills and approximately 155,000 acres of land and timber.
The Utility and Pipeline and Storage segments' facilities provided the capacity to meet the Company's 2002 peak day sendout, including transportation service, of 1,568.0 million cubic feet (MMcf), which occurred on February 4, 2002. Withdrawals from storage of 682.8 MMcf provided approximately 43.5% of the requirements on that day.
Company maps are included in exhibit 99.5 of this Form 10-K.
The information that follows is disclosed in accordance with SEC regulations, and relates to the Company’s oil and gas producing activities. A further discussion of oil and gas producing activities is included in Item 8, Note N-Supplementary Information for Oil and Gas Producing Activities. Note N sets forth proved developed and undeveloped reserve information for Seneca. During 2002, Seneca’s proved developed and undeveloped reserves decreased significantly. 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 thousands of barrels (Mbbl) to 99,717 Mbbl. These decreases can be 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 shifting 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, 2002 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 (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 2002 2001 2000 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- United States Average Sales Price per Mcf of Gas(1) $2.99 $5.53 $3.31 Average Sales Price per Barrel of Oil(1) $21.03 $25.43 $25.34 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.67 $0.55 $0.51 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Canada Average Sales Price per Mcf of Gas(1) $2.29 $2.41 $ 2.52 Average Sales Price per Barrel of Oil(1) $19.94 $24.29 $29.28 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.29 $1.34 $ 1.41 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Average Sales Price per Mcf of Gas(1) $2.88 $5.39 $3.31 Average Sales Price per Barrel of Oil(1) $20.63 $24.99 $26.03 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.84 $0.73 $0.58 - ---------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Prices do no reflect gains or losses from hedging activities.
Productive Wells
- --------------------------------------- ------------------------ -------------------------- -------------------------
At September 30, 2002 United States Canada Total
- --------------------------------------- ------------------------ -------------------------- -------------------------
Gas Oil Gas Oil Gas Oil
Productive Wells - gross 1,877 1,167 160 668 2,037 1,835
- net 1,763 1,144 100 605 1,863 1,749
- --------------------------- ----------- ----------- ------------ ------------ ------------- ------------ ------------
Developed and Undeveloped Acreage
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------
At September 30, 2002 United States Canada Total
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------
Developed Acreage - gross 644,109 148,557 792,666
- net 577,463 113,800 691,263
Undeveloped Acreage - gross 792,696 781,645 1,574,341
- net 581,584 700,811 1,282,395
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------
Drilling Activity
- ----------------------------------------------------------------------------------------------------------------------
Productive Dry
--------------------------------------------------------------
For the Year Ended September 30 2002 2001 2000 2002 2001 2000
--------------------------------------------------------------
United States
Net Wells Completed - Exploratory 4.27 11.83 13.89 4.67 4.93 6.53
- Development 75.30 108.60 82.82 2.10 1.00 1.00
- ----------------------------------------------------------------------------------------------------------------------
Canada
Net Wells Completed - Exploratory 0.20 10.00 1.00 4.00 11.00 -
- Development 33.70 61.14 21.50 7.90 2.75 4.00
- ----------------------------------------------------------------------------------------------------------------------
Total
Net Wells Completed - Exploratory 4.47 21.83 14.89 8.67 15.93 6.53
- Development 109.00 169.74 104.32 10.00 3.75 5.00
- ----------------------------------------------------------------------------------------------------------------------
Present Activities
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
At September 30, 2002 United States Canada Total
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
Wells in Process of Drilling - gross 38.00 11.00 49.00
- net 34.58 11.00 45.58
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
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. Currently there are 21 injection wells and 89 production wells in the
program. The total injection and production from this waterflood project is
4,200 barrels of water per day and 230 barrels of oil per day, respectively.
In an action instituted in the New York State Supreme Court, Chautauqua County on January 31, 2000 against Seneca Resources Corporation (“Seneca”), National Fuel Resources, Inc., 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 (a) that Seneca underpaid royalties due under leases operated by it, and (b) that Seneca’s co-defendants (i) fraudulenty 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).
The defendants responded to that motion in August 2002. An oral argument on that motion took place in September 2002. The court has not yet entered a decision on the motion. If a class is certified, discovery would begin on the merits of the claims, and the case eventually tried or settled. The Company believes, based on the information presently known, that the ultimate resolution of this matter 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 outcome of this matter, and it is possible that the outcome 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 H - Commitments and Contingencies.
The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the 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 2002.
PART II
Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Securities Authorized for Issuance Under Equity Compensation Plans, Item 8 at Note D-Capitalization and Note M-Market for Common Stock and Related Shareholder Matters (unaudited).
On July 1, 2002, the Company issued a total of 1,920 unregistered shares of Company common stock to the eight non-employee directors then serving on the Board of Directors, 240 shares to each such director. On September 12, 2002, Rolland E. Kidder, Executive Director of the Robert H. Jackson Center for Justice in Jamestown, New York, was elected to the Board of Directors of the Company, and on September 25, 2002, the Company issued 50 unregistered shares of Company common stock to Mr. Kidder. All of these unregistered shares issued on July 1, 2002 and September 25, 2002 were issued as partial consideration for the directors' services during the quarter ended September 30, 2002, 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.
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30 2002 2001 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
Summary of Operations (Thousands)
Operating Revenues $1,464,496 $2,059,836 $1,412,416 $1,254,402 $1,248,000
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Purchased Gas 462,857 1,002,466 488,383 397,053 441,746
Fuel Used in Heat and
Electric Generation 50,635 54,968 54,893 55,788 37,837
Operation and Maintenance 394,157 364,318 350,383 328,800 321,411
Property, Franchise and Other Taxes 72,155 83,730 78,878 91,146 92,817
Depreciation, Depletion and
Amortization 180,668 174,914 142,170 124,778 117,238
Impairment of Oil and Gas
Producing Properties - 180,781 - - 128,996
Income Taxes 72,034 37,106 77,068 64,829 24,024
- ----------------------------------------------------------------------------------------------------------------------------------
1,232,506 1,898,283 1,191,775 1,062,394 1,164,069
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 231,990 161,553 220,641 192,008 83,931
Operations of Unconsolidated
Subsidiaries:
Income 224 1,794 1,669 999 319
Impairment of Investment in
Partnership (15,167) - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
(14,943) 1,794 1,669 999 319
- ----------------------------------------------------------------------------------------------------------------------------------
Other Income 7,017 10,639 6,366 11,344 35,551
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 224,064 173,986 228,676 204,351 119,801
Interest Charges 105,652 107,145 100,085 87,698 85,284
- ----------------------------------------------------------------------------------------------------------------------------------
Minority Interest in Foreign Subsidiaries (730) (1,342) (1,384) (1,616) (2,213)
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect 117,682 65,499 127,207 115,037 32,304
Cumulative Effect of Change in
Accounting - - - - (9,116)
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income Available for Common
Stock $117,682 $65,499 $127,207 $115,037 $23,188
- ----------------------------------------------------------------------------------------------------------------------------------
Per Common Share Data
Basic Earnings per Common Share $1.47(1) $0.83(2) $1.63 $1.49 $0.30(3)
Diluted Earnings per Common Share $1.46(1) $0.82(2) $1.61 $1.47 $0.30(3)
Dividends Declared $1.03 $0.99 $0.95 $0.92 $0.89
Dividends Paid $1.02 $0.97 $0.94 $0.91 $0.88
Dividend Rate at Year-End $1.04 $1.01 $0.96 $0.93 $0.90
At September 30:
Number of Common Shareholders 20,004 20,345 21,164 22,336 23,743
- ----------------------------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment (Thousands)
Utility $960,015 $945,693 $939,753 $919,642 $906,754
Pipeline and Storage 487,793 483,222 474,972 466,524 460,952
Exploration and Production 1,072,200 1,081,622 998,852 674,813 638,886
International 207,191 178,250 172,602 210,920 202,590
Energy Marketing 125 262 360 489 353
Timber 110,624 90,453 95,607 88,623 38,593
All Other 6,797 1,209 1,241 214 -
Corporate - 2 4 7
9
- ----------------------------------------------------------------------------------------------------------------------------------
Total Net Plant $2,844,745 $2,780,713 $2,683,391 $2,361,232 $2,248,137
- ----------------------------------------------------------------------------------------------------------------------------------
Total Assets (Thousands) $3,401,309 $3,445,231 $3,251,031 $2,842,586 $2,684,459
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (Thousands)
Comprehensive Shareholders' Equity $1,006,858 $1,002,655 $ 987,437 $ 939,293 $ 890,085
Long-Term Debt, Net of Current Portion 1,145,341 1,046,694 953,622 822,743 693,021
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $2,152,199 $2,049,349 $1,941,059 $1,762,036 $1,583,106
- ----------------------------------------------------------------------------------------------------------------------------------
(1) 2002 includes impairment of investment in partnership of ($0.12) basic and diluted.
(2) 2001 includes oil and gas asset impairment of ($1.32) basic, ($1.29) diluted.
(3) 1998 includes oil and gas asset impairment of ($1.03) basic, ($1.02) diluted and cumulative effect of a change in depletion methods of ($0.12) basic and diluted.
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 unit-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 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 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 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, 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 a non-cash impairment relating to its Canadian properties in 2001. This impairment amounted to $104.0 million (after tax) and resulted from low oil and gas prices at September 30, 2001.
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.
Accounting for Derivative Financial Instruments. The Company, primarily in its Exploration and Production and Energy Marketing segments, 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 can be categorized as price swap agreements, no cost collars, options and futures contracts. 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.
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.”
Earnings2002 Compared with 2001
The Company’s earnings
were $117.7 million, or $1.47 per common share ($1.46 per common share on a
diluted basis) in 2002. This compares with earnings of $65.5 million, or $0.83
per common share ($0.82 per common share on a diluted basis) in 2001. However,
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), or $0.12 per common share (basic and
diluted). 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), or $1.32 per common share ($1.29 per common share on a diluted basis),
which is discussed above under Critical Accounting Policies - Oil and Gas
Exploration and Development Costs. Without these non-cash impairments, earnings
for 2002 would have been $127.5 million, or $1.59 per common share ($1.58 per
common share on a diluted basis) and earnings for 2001 would have been $169.5
million, or $2.14 per common share ($2.11 per common share on a diluted basis).
The decrease in earnings of $42.0 million (exclusive of the non-cash
impairments) is primarily the result of lower earnings in 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.
2001 Compared with 2000
The Company’s earnings
were $65.5 million, or $0.83 per common share ($0.82 per common share on a
diluted basis) in 2001. This compares with 2000 earnings of $127.2 million, or
$1.63 per common share ($1.61 per common share on a diluted basis). However,
2001 earnings 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),
or $1.32 per common share ($1.29 per common share on a diluted basis). Without
this non-cash impairment, earnings for 2001 would have been $169.5 million, or
$2.14 per common share ($2.11 per common share on a diluted basis). The increase
in earnings of $42.3 million (exclusive of the non-cash impairment) was
primarily the result of higher earnings in 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) 2002 2001 2000 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Utility $49,505 $60,707 $57,662 Pipeline and Storage (1) 29,715 40,377 31,614 Exploration and Production (2) 26,851 (32,284) 34,877 International (4,443) (3,042) 3,282 Energy Marketing 8,642 (3,432) (7,790) Timber 9,689 7,715 6,133 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Reportable Segments 119,959 70,041 125,778 All Other (885) (4,277) (371) Corporate (1,392) (265) 1,800 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Consolidated (1) (2) $117,682 $65,499 $127,207 - ---------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Exclusive of the non-cash asset impairment of the Company's investment in the Independence Pipeline project, 2002 earnings for the Pipeline and Storage segment, and Total Consolidated would have been $39,574 and $127,541, respectively.
(2) Exclusive of the non-cash asset impairment of oil and gas assets, 2001 earnings for the Exploration and Production segment and Total Consolidated would have been $71,756 and $169,539, respectively.
Utility
Utility Operating Revenues
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Retail Revenues:
Residential $538,345 $ 875,050 $ 584,618
Commercial 86,963 154,266 93,914
Industrial 18,332 29,110 21,543
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
643,640 1,058,426 700,075
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Off-System Sales 68,606 84,078 47,962
Transportation 83,267 89,037 104,534
Other (1,292) 3,106 (6,112)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$794,221 $1,234,647 $ 846,459
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Utility Throughput - million cubic feet (MMcf)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2002 2001 2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Retail Sales:
Residential 64,639 73,530 68,196
Commercial 11,549 13,831 12,312
Industrial 3,715 4,089 4,276
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
79,903 91,450 84,784
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Off-System Sales 21,541 12,736 12,833
Transportation 61,909 66,283 71,862
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
163,353 170,469 169,479
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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 milion 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 (gas costs are recovered dollar for dollar in revenues) 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. However, due to profit sharing with retail customers, the margins resulting from off-system sales were minimal.
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's New York jurisdiction under an earnings sharing mechanism. This earnings sharing mechanism, which is in accordance with the three-year rate settlement reached with the NYPSC that went into effect October 1, 2000 (New York Rate Settlement), requires the Utility to share with customers 50% of earnings above a predetermined amount. The final refund for the New York Rate Settlement will not be known until the end of 2003.
Partly offsetting the decreases to revenue discussed above was the positive impact of a lower bill credit in the Utility's New York jurisdiction. In connection with the 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.
2001 Compared with 2000
Operating revenues for the
Utility segment increased $388.2 million in 2001 compared with 2000. This
resulted from an increase in retail and off-system gas sales revenues of $358.4
million and $36.1 million, respectively. Other operating revenues also increased
by $9.2 million. These increases were partly offset by a decrease in
transportation revenues of $15.5 million.
The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs, coupled with an increase in retail sales volumes, as shown above. The 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 the migration of residential and small commercial customers from transportation service to retail service in both the New York and Pennsylvania jurisdictions, coupled with the impact of colder weather. This migration from transportation service resulted from one marketer entering bankruptcy proceedings, another marketer exiting the residential market, and the conclusion of a marketer pilot program in Pennsylvania. Off-system sales revenues increased because of higher gas prices. The decrease in transportation revenues and volumes was primarily due to the migration from transportation service discussed above and the fact that certain commercial and industrial customers were reducing usage due to a slowing economy or they were fuel switching.
The increase in other operating revenues was due primarily to $5.5 million of various revenue reductions in 2000 that did not recur in 2001 (of which $2.2 million was offset by lower operation and maintenance expense in 2000). These revenue reductions related to the September 30, 2000 conclusion of the 1998 two-year rate settlement approved by the NYPSC. In addition to these adjustments, a $3.5 million lower provision for refund was recorded in 2001 as compared with 2000. The provision for refund in 2000 related to the conclusion of the 1998 two-year rate settlement and the provision for refund in 2001 related to the three-year rate settlement approved by the NYPSC in October 2000 (referred to above as New York Rate Settlement).
Revenues in 2001 as compared to revenues in 2000 were reduced by a $10.0 million rate decrease for the Utility's New York customers that went into effect October 1, 2000 in connection with the aforementioned New York Rate Settlement. This rate decrease was provided in the form of a bill credit included in rates during the November 1, 2000 through March 31, 2001 heating season.
Earnings2002 Compared with 2001
The Utility segment’s
earnings in 2002 were $49.5 million, a decrease of $11.2 million when compared
with the earnings of $60.7 million in 2001. However, the earnings for 2001
included $3.1 million of non-recurring earnings associated with stock
appreciation rights (refer to Item 8 at Note D - Capitalization for a discussion
of the November 2001 cancellation of stock appreciation rights) and $4.2 million
of non-recurring after tax expense associated with early retirement offers in
the Utility’s New York and Pennsylvania jurisdictions. Exclusive of these
two items, the decrease in earnings was $12.3 million. Warmer weather in the
Pennsylvania jurisdiction and lower normalized usage per account (normalized
usage excludes the impact of weather on consumption) across the Utility’s
service territory due to a downturn in the economy significantly decreased
earnings in 2002. Also contributing to the decrease were several routine
regulatory true-up adjustments associated with income taxes, lost and
unaccounted for gas and interest expense. The impact of the refund provision
discussed above was largely offset by lower operation and maintenance expenses,
primarily labor. The impact of the lower bill credit ($5.0 million pre tax and
$3.3 million after tax), discussed above, partly offset these decreases.
The impact of weather on the Utility segment's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on 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 2002, the WNC in New York 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. Since the Pennsylvania jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, weather during 2002 was 16.0% warmer than 2001 and 13.2% warmer than normal.
2001 Compared with 2000
In the Utility segment,
2001 earnings were $60.7 million, up $3.0 million from the prior year. However,
the earnings for 2001 included $4.2 million of non-recurring after tax expense
associated with early retirement offers in the Utility’s New York and
Pennsylvania jurisdictions, and the earnings for 2000 included $2.2 million of
non-recurring after tax revenue adjustments ($3.3 million pretax) related to the
conclusion of the 1998 two-year rate settlement, as discussed in the revenue
section above. Stock appreciation rights also had a significant impact on
earnings as 2001 had earnings of $3.1 million and 2000 had $3.0 million of after
tax expense. This was due to a significant change in the market price of the
Company’s common stock as the market price increased significantly in 2000
followed by a significant decrease in the market price in 2001. Exclusive of
these four items, there was actually a decrease in earnings of $1.1 million. A
main reason for the decrease was the $10.0 million rate decrease in the Utility
segment’s New York jurisdiction, as previously discussed, which more than
offset the positive earnings impact of colder weather in the Utility
segment’s Pennsylvania jurisdiction.
In 2001, the WNC in New York preserved earnings of approximately $1.2 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 2000 through May 2001. In the Pennsylvania service territory, which does not have a WNC, weather during 2001 was 12.3% colder than 2000 and 2.8% colder than normal.
Degree Days
- ---------------------------------- -------------- -------------- -------------------- --------------------------------
Percent (Warmer)
Colder Than
--------------------------------
Year Ended September 30 Normal Actual Normal Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
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%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
2000: Buffalo 6,932 6,312 (8.9%) 2.1%
Erie 6,230 5,657 (9.2%) 0.9%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Purchased Gas
The cost of purchased gas
is the Company’s single largest operating expense. Annual variations in
purchased gas costs can be attributed directly to changes in gas sales volumes,
the price of gas purchased and the operation of purchased gas adjustment
clauses.
Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and 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 can satisfy a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation's average cost of purchased gas, including the cost of transportation and storage, was $4.68 per thousand cubic feet (Mcf) in 2002, a decrease of 36% from the average cost of $7.35 per Mcf in 2001. The average cost of purchased gas in 2001 was 49% higher than the $4.93 per Mcf in 2000. 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
Pipeline and Storage Operating Revenues
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation $88,082 $91,611 $92,305
Interruptible Transportation 3,315 1,917 1,578
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
91,397 93,528 93,883
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Storage Service 62,733 61,559 62,899
Interruptible Storage Service 7 670 287
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
62,740 62,229 63,186
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Other 13,247 15,334 12,590
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$167,384 $171,091 $169,659
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Pipeline and Storage Throughput - (MMcf)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2002 2001 2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation 290,507 304,183 291,818
Interruptible Transportation 7,315 17,372 21,730
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
297,822 321,555 313,548
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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.
2001 Compared with 2000
Operating revenues for the
Pipeline and Storage segment increased $1.4 million in 2001 compared with 2000.
The increase is attributable primarily to a $2.1 million increase in revenues
from unbundled pipeline sales and open access transportation due to higher
prices and volumes. While transportation volumes increased 8.0 Bcf during the
fiscal 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
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. However, as discussed
above, the earnings for 2002 included a $9.9 million non-recurring after tax
expense ($15.2 million pre tax) associated with the impairment of the
Company’s investment in the Independence Pipeline project. Earnings for
2001 included $4.2 million of non-recurring earnings associated with stock
appreciation rights, $2.6 million of non-recurring earnings associated with a
termination fee received from a customer to cancel a long-term transportation
contract, and $1.1 million of non-recurring after tax expense associated with
early retirement offers. Exclusive of these four items, there was an increase in
earnings of $4.9 million. This increase resulted primarily from lower operation
and maintenance expenses, which were the result of the Company’s recent
early retirement offers, and a lower effective income tax rate.
2001 Compared with 2000
The Pipeline and Storage
segment’s earnings for 2001 were $40.4 million, an increase of $8.8 million
when compared with earnings for 2000. However, earnings for 2001 included $2.6
million of non-recurring earnings associated with a termination fee received
from a customer to cancel a long-term transportation contract, and $1.1 million
of non-recurring after tax expense associated with early retirement offers.
Stock appreciation rights also had a significant impact on earnings as 2001 had
earnings of $4.2 million and 2000 had $4.6 million of after tax expense. As
previously discussed, significant swings in the market price of the
Company’s common stock caused this earnings impact. Exclusive of these four
items, there was a decrease in earnings of $1.5 million. While revenues from
unbundled pipeline sales and open access transportation increased, the increase
was more than offset by additional executive retirement benefit expenses in
2001.
Exploration and Production Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2002 2001 2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Gas (after Hedging) $148,467 $171,045 $108,832
Oil (after Hedging) 152,746 169,613 117,606
Gas Processing Plant 16,995 39,986 17,666
Other 6,627 17,700 (6,034)
Intrasegment Elimination (1) (13,855) (43,339) (15,234)
- --------------------------------------------------------------- ----------------- ---------------- -----------------
$310,980 $355,005 $222,836
- --------------------------------------------------------------- ----------------- ---------------- -----------------
(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 2002 2001 2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Gas Production(MMcf)
Gulf Coast 25,776 30,663 32,760
West Coast 4,889 4,383 4,374
Appalachia 4,402 4,142 4,344
Canada 6,387 1,816 192
- --------------------------------------------------------------- ----------------- ---------------- -----------------
41,454 41,004 41,670
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Oil Production (Mbbl)
Gulf Coast 1,815 1,914 1,415
West Coast 3,004 2,875 2,824
Appalachia 9 7 9
Canada 2,834 3,061 899
- --------------------------------------------------------------- ----------------- ---------------- -----------------
7,662 7,857 5,147
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Average Prices
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2002 2001 2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Average Gas Price/Mcf
Gulf Coast $2.89 $4.93 $3.29
West Coast $2.86 $10.18 $3.62
Appalachia $3.74 $5.03 $3.16
Canada $2.29 $2.41 $2.52
Weighted Average $2.88 $5.39 $3.31
Weighted Average After Hedging(1) $3.58 $4.17 $2.61
Average Oil Price/barrel (bbl)
Gulf Coast $22.83 $27.47 $28.27
West Coast(2) $19.94 $24.06 $23.87
Appalachia $23.76 $28.51 $25.12
Canada $19.94 $24.29 $29.28
Weighted Average $20.63 $24.99 $26.03
Weighted Average After Hedging(1) $19.94 $21.59 $22.85
- --------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Refer to further discussion of hedging activities below under "Market Risk Sensitive Instruments" and in Note F - Financial Instruments in Item 8 of this report.
(2) Includes low gravity oil which generally sells for a lower price.
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 Corp. acquisition) (Player) offset partially by decreased
production in the Gulf Coast region. The decrease in Gulf Coast production is
the result of the previously announced strategy to exit the Gulf of Mexico and
shift emphasis to longer-lived on-shore reserves. The Company is shifting its
emphasis because it believes that future quality off-shore reserves will require
deeper and riskier off-shore drilling that will be more expensive than the
reserves it has been able to find under its current drilling program in the
shallow waters of the Gulf of Mexico.* The Company anticipates that shifting to
longer-lived on-shore reserves will allow it to drill and develop lower cost, lower
risk reserves.* Gas processing plant revenues decreased $23.0 million due to
significantly lower gas prices. Other revenues decreased $11.1 million largely
due to the non-recurring mark-to-market gains on derivative financial
instruments that were recorded in 2001, as discussed below.
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.
2001 Compared with 2000
Operating revenues for the
Exploration and Production segment increased $132.2 million in 2001 compared
with 2000. Gas production revenue after hedging increased $62.2 million due
primarily to an increase in the weighted average price of gas after hedging.
Overall gas production decreased, primarily in the Gulf Coast region, as there
were delays in placing new platforms on production (due to rig availability
constraints) and delays in work-over activity, mostly during the first and
second quarters of 2001. New Gulf Coast production in the second half of 2001
was primarily oil production. Gas production from the Player acquisition in June
2001 helped mitigate the gas production decline in the Gulf Coast region. Oil
production revenue after hedging increased $52.0 million in 2001 compared with
2000. This increase is due primarily to a 53% increase in oil production,
largely attributable to the Exploration and Production segment’s Canadian
properties acquired as part of the June 2000 acquisition of Tri Link Resources,
Ltd. (Tri Link). Revenue from this segment’s gas processing plant was up
$22.3 million due to higher prices. In addition, this segment recognized other
revenue increases of $23.8 million due to mark-to-market adjustments related to
derivative financial instruments. These mark-to-market adjustments largely
related to written options that did not qualify for hedge accounting. The
written options covered the period from January 1999 to December 2000.
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. However, 2001
earnings included a non-cash impairment of this segment’s oil and gas
assets totaling $104.0 million after tax, as previously discussed. Excluding the
impact of this impairment, there was a decrease in earnings of $44.8 million. As
discussed above, decreases in the weighted average commodity prices of crude oil
and natural gas after hedging ($1.65 per bbl and $0.59 per Mcf, respectively)
were primarily responsible for this earnings decrease. Higher workover expenses
in the Gulf Coast region also contributed to the earnings decrease. The major
workover expenditures occurred on Vermilion 252 and Eugene Island Block 264.
2001 Compared with 2000
The Exploration and
Production segment experienced a loss of $32.3 million in 2001, a decrease of
$67.2 million when compared to 2000 earnings of $34.9 million. Excluding the
$104.0 million after tax non-cash impairment discussed above, this segment had
2001 earnings of $71.8 million, an increase of $36.9 million from 2000 earnings.
A 53% increase in oil production, largely attributable to the Tri Link
acquisition in June 2000, combined with higher natural gas prices, were major
factors in this segment’s earnings increase, exclusive of the non-cash
asset impairment. Also, this segment’s earnings benefited from the
mark-to-market revenue increases discussed above. Partly offsetting higher
revenues was an increase in production related expenses, including higher
depletion, higher purchased gas expense (for the gas processing plant), an
increase in lease operating costs and higher production taxes. General and
administrative expenses increased, largely due to the Player and Tri
Link acquisitions. Greater interest expense due to higher borrowings related to
the Player and Tri Link acquisitions also partially offset the positive impact
of higher revenues.
Revenues
International Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2002 2001 2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Heating $65,386 $69,072 $69,387
Electricity 26,960 26,398 31,426
Other 2,969 2,440 3,923
- --------------------------------------------------------------- ----------------- ---------------- -----------------
$95,315 $97,910 $104,736
- --------------------------------------------------------------- ----------------- ---------------- -----------------
International Heating and Electric Volumes
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2002 2001 2000
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Heating Sales (Gigajoules) (1) 8,689,887 9,978,118 10,222,024
Electricity Sales (megawatt hours) 972,832 1,019,901 1,147,303
- --------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Gigajoules = one billion joules. A joule is a unit of energy.
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 Czech koruna (CZK)
compared to the U.S. dollar offset much of the impact of these negative factors.
2001 Compared with 2000
Operating revenues for the
International segment decreased $6.8 million in 2001 compared with 2000. The
revenue decrease largely reflects a decrease in the average value of the CZK
compared to the U.S. dollar during the 2001 heating season compared to the 2000
heating season. Exclusive of the exchange rate impact, heating revenues
increased due to rate increases offset partly by lower volumes associated with
warmer weather. Electric revenues, exclusive of the exchange rate impact,
decreased as a result of lower volumes (principally attributable to the
scheduled shutdown of a generating turbine that had reached the end of its
useful life) and a decline in electric rates.
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 expenses associated with the
Company’s European power development projects (refer to Capital Resources
and Liquidity under the heading “Estimated Capital Expenditures”) were
the main factors for the higher loss in 2002. Lower interest expense and a
higher effective tax rate partially offset the impact of higher operation and
maintenance expenses.
2001 Compared with 2000
The International segment
experienced a loss of $3.0 million in 2001 compared with 2000 earnings of $3.3
million. Lower heat and electric margins, as a result of warmer weather and the
scheduled shutdown of a generating turbine, were the primary reasons for this
decrease. The decrease also reflects a decrease in value of the CZK compared to
the U.S. dollar, as previously discussed.
Energy Marketing Operating Revenues
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Natural Gas (after Hedging) $151,219 $257,005 $139,614
Electricity - 1,362 1,941
Other 38 839 (7,626)
- ------------------------------------------------------------- ------------------- ------------------ -------------------
$151,257 $259,206 $133,929
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Energy Marketing Volumes
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 2002 2001 2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Natural Gas - (MMcf) 33,042 36,753 35,465
- ------------------------------------------------------------- ------------------- ------------------ -------------------
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.
Refer to further discussion of derivative financial instruments in the "Market Risk Sensitive Instruments" section that follows.
2001 Compared with 2000
Operating revenues for the
Energy Marketing segment increased $125.3 million in 2001 compared with 2000.
The primary reason for this increase was the higher gas costs that are reflected
in the natural gas marketing revenues. Higher marketing volumes are primarily
due to colder weather in 2001 compared to 2000. This compensated for a 4%
decrease in NFR’s customers from September 30, 2000 to September 30, 2001.
In addition, the Energy Marketing segment recognized a negative $8.6 million
mark-to-market adjustment in 2000 (included in “Other” on the table
above) related to written options and futures contracts that did not qualify for
hedge accounting.
2002 Compared with 2001
Earnings in the Energy
Marketing segment increased $12.1 million in 2002 as compared with 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.
2001 Compared with 2000
The Energy Marketing
segment incurred a loss for 2001 of $3.4 million, a decrease of $4.4 million
compared with the loss of $7.8 million in 2000. However, the loss for 2001
included $1.3 million of non-recurring after tax expense associated with a
mark-to-market loss on natural gas inventory. Exclusive of this item, the loss
in 2001 was $2.1 million, a decrease of $5.7 million from the loss incurred in
2000. The most significant reason for the lower loss was the change in
mark-to-market adjustments from 2000 to 2001 ($5.9 million positive contribution
after tax), referred to above.
Timber Operating Revenues
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Log Sales $21,528 $23,460 $24,091
Green Lumber Sales 6,567 5,597 4,397
Kiln Dry Lumber Sales 15,976 12,320 10,152
Other 3,336 3,537 2,905
- ------------------------------------------------------------- ------------------- ------------------ -------------------
$47,407 $44,914 $41,545
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Timber Board Feet
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ------------------------------------------------------------- ------------------- ------------------ -------------------
Log Sales 8,174 8,839 9,370
Green Lumber Sales 12,878 10,332 8,193
Kiln Dry Lumber Sales 10,794 8,804 6,987
- ------------------------------------------------------------- ------------------- ------------------ -------------------
31,846 27,975 24,550
- ------------------------------------------------------------- ------------------- ------------------ -------------------
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. 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).
2001 Compared with 2000
Operating revenues for the
Timber segment increased $3.4 million in 2001, as compared with 2000. Green
lumber sales were up due to an increase in board feet sold at slightly higher
prices. The increase in kiln dry lumber sales was due to the operation of two
additional kilns brought on line in August 2000. The decrease in log sales
revenues primarily reflects lower sales of quality logs offset partly by higher
average prices.
2002 Compared with 2001
Earnings in the Timber
segment increased $2.0 million in 2002 as compared with 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.
2001 Compared with 2000
Timber segment earnings of
$7.7 million in 2001 were up $1.6 million compared with 2000. The increase was
primarily due to higher operating revenues, as mentioned above, and lower
interest expense.
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. However, the loss for 2001
included $0.7 million of non-recurring earnings associated with stock
appreciation rights and $3.5 million of non-recurring after tax expense
associated with a mark-to-market loss on natural gas inventory by Upstate, the
Company’s wholly-owned subsidiary which is engaged in wholesale natural gas
marketing and other energy-related activities. Exclusive of these items,
earnings decreased $0.6 million largely due to higher interest costs, partially
offset by lower operation costs.
2001 Compared with 2000
Corporate and all other
operations experienced a loss of $4.5 million in 2001, a decrease of $5.9
million over the gain of $1.4 million in 2000. However, the loss for 2001
included $3.5 million of non-recurring after tax expense associated with a
mark-to-market loss on natural gas inventory by Upstate, as discussed above.
Stock appreciation rights also had a significant impact on earnings as 2001 had
earnings of $0.7 million and 2000 had $0.7 million of after tax expense. As
previously discussed, significant swings in the market price of the
Company’s common stock caused this earnings impact. Exclusive of these
three items, earnings decreased $3.8 million largely due to higher interest
costs and higher operation costs.
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 50% ownership 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. 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 Independence 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.
2002 Compared with 2001
Income from unconsolidated
subsidiaries (which represents the Company’s equity method interest in the
income or loss from its investment in 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. Some repairs were delayed
from 2001 to 2002 to enable Seneca Energy to operate more hours while market
prices for electricity were higher than normal.
2001 Compared with 2000
Income from unconsolidated
subsidiaries increased $0.1 million in 2001 compared with 2000. The ESNE and
Model City investments added income of $0.9 million and $0.1 million,
respectively, as 2001 was the first year of operation for both investments. The
Seneca Energy investment also saw an increase in income of $0.5 million as 2001
was the first complete year of operation for this investment. These increases
were largely offset by a $1.4 million reduction in equity method income from
Independence Pipeline Company.
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
Other income decreased $3.6
million in 2002 compared with 2001. This decrease 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 has
been able to market the excess capacity resulting from this termination.
Other income increased $4.8 million in 2001 compared with 2000. This increase resulted primarily from the same $4.0 million buyout of a long-term transportation contract in the Pipeline and Storage segment discussed above.
Interest Charges
Interest on long-term debt
increased $8.7 million in 2002 and $14.7 million in 2001. The increase in both
years resulted mainly from a higher average amount of long-term debt
outstanding. Long-term debt balances have grown significantly over the past few
years primarily as a result of acquisition activity in the Exploration and
Production segment. These acquisitions were initially financed with short-term
debt which was subsequently repaid through the proceeds from the issuance of
long-term debt.
Other interest charges decreased $10.2 million in 2002 and $7.6 million in 2001. The decrease in 2002 was the result of a decrease in the average amount of short-term debt outstanding (short-term debt was refinanced with long-term debt) and lower weighted average interest rates. The decrease in 2001 was primarily the result of lower weighted average interest rates on short-term debt.
Capital Resources and LiquidityThe 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) 2002 2001 2000 - ----------------------------------------------------------- -------------------- ------------------- -------------------- Provided by Operating Activities $345.6 $414.0 $238.2 Capital Expenditures (232.4) (292.7) (269.4) Investment in Subsidiaries, Net of Cash Acquired - (90.6) (123.8) Investment in Partnerships (0.5) (1.8) (4.4) Other Investing Activities 27.1 (2.8) 13.3 Short-Term Debt, Net Change (224.8) (143.4) 226.5 Long-Term Debt, Net Change 139.6 187.2 (18.1) Issuance of Common Stock 10.9 11.5 14.3 Dividends Paid on Common Stock (81.0) (76.7) (73.0) Dividends Paid to Minority Interest - - (0.2) Effect of Exchange Rates on Cash 1.5 (0.6) (0.5) - ----------------------------------------------------------- -------------------- ------------------- -------------------- Net Increase (Decrease) in Cash and Temporary Cash Investments $(14.0) $4.1 $2.9 - ----------------------------------------------------------- -------------------- ------------------- --------------------Operating Cash Flow
Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, impairment of oil and gas producing properties (in 2001), deferred income taxes, impairment of investment in partnership, income or loss from unconsolidated subsidiaries net of cash distributions and minority interest in foreign subsidiaries.
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 options in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $345.6 million in 2002, a decrease of $68.4 million compared with the $414.0 million provided by operating activities in 2001. Lower cash receipts from the sale of oil and gas in the Exploration and Production segment more than offset higher margins on gas sales in the Energy Marketing segment. Oil and gas prices were down significantly in the Exploration and Production segment for much of 2002 and oil and gas production was slightly lower than 2001.
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 $232.9 million in 2002. The table below presents these expenditures:
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Total
Investments Expenditures
Capital in Corporations For Long-
Year Ended September 30, 2002 (Millions) Expenditures or Partnerships Lived Assets
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Utility $ 51.5 $ - $ 51.5
Pipeline and Storage 29.8 0.5 30.3
Exploration and Production 114.6 - 114.6
International 4.2 - 4.2
Energy Marketing 0.1 - 0.1
Timber 25.6 - 25.6
All Other 6.6 - 6.6
- ----------------------------------------------------------- ------------------- ------------------- -----------------
$232.4 $0.5 $232.9
- ----------------------------------------------------------- ------------------- ------------------- -----------------
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. Approximately $4.4 million was spent on expansion of
transportation capacity on Line YM53 running from Ellisburg, Pennsylvania to
Leidy, Pennsylvania.
During 2002, SIP made an additional $536,000 investment in Independence Pipeline Company (Independence), bringing SIP's total investment to $15.2 million. In June 2002, Independence submitted a motion to FERC requesting that FERC vacate the certificate issued to Independence on July 12, 2000 to construct, own and operate the Independence Pipeline. Independence took this action because it had been unable to obtain sufficient customer contracts to proceed with the project. In connection with the filing of the motion by Independence, SIP wrote off its $15.2 million investment in Independence, as previously discussed. FERC formally vacated the certificate in an order issued in July 2002.
Exploration and Production
The Exploration and
Production segment’s capital expenditures included approximately $81.5
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, including the purchase of
certain three-dimensional seismic data and fixed asset purchases. Of the $81.5
million discussed above, $27.0 million was spent on the Exploration and
Production segment’s Canadian properties. The Exploration and Production
segment’s capital expenditures also included approximately $33.1 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 2002, the Exploration and Production segment sold oil and gas properties amounting to $22.1 million. Most of these properties were in the Gulf Coast region. These proceeds were recorded as a reduction of property, plant and equipment and are reflected in Other Investing Activities on the Consolidated Statement of Cash Flows.
International
The majority of the
International segment’s capital expenditures were concentrated on the
construction of boilers at a district heating and power generation plant in the
Czech Republic. The expenditures also included improvements and replacements
within the district heating and power generation plants.
Timber
The majority of the Timber
segment capital expenditures were made for the purchase of land and timber
rights in Potter County, Pennsylvania in June 2002. The land, consisting of
approximately 3,656 acres, was purchased by Seneca from Wending Creek 3656, LLC,
an entity controlled by certain members of the John Rigas family for $464,930. A
Form 8-K filed by Adelphia Communications Corporation (Adelphia) on June 14,
2002 states that the Rigas family had previously agreed to transfer the land to
Adelphia in exchange for a $464,930 reduction in the amount of the Rigas
family’s primary co-borrowing obligations, and Seneca paid the purchase
price of the land directly to Adelphia. Highland purchased the timber rights
associated with the land from ACC Operations, Inc., a wholly owned subsidiary of
Adelphia, for $19,535,070. The remaining capital expenditures were for smaller
purchases of land and timber as well as equipment for this segment’s
sawmill and kiln operations.
Estimated Capital Expenditures
The Company's estimated capital expenditures for the next three years are:*
------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Millions) 2003 2004 2005
------------------------------------------------------------- ----------------- ---------------- -----------------
Utility $48.1 $48.1 $48.1
Pipeline and Storage 24.0 30.2 24.8
Exploration and Production 81.6 82.4 83.6
International 9.6 4.3 4.7
Timber 0.8 0.3 0.3
All Other 10.5 - -
------------------------------------------------------------- ----------------- ---------------- -----------------
$174.6 $165.3 $161.5
------------------------------------------------------------- ----------------- ---------------- -----------------
Estimated capital expenditures for the Utility segment in 2003 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 2003 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines.* The estimated capital expenditures also include $5.0 million for an expansion of transportation capacity on Line YM53 running from Ellisburg, Pennsylvania to Leidy, Pennsylvania.* The estimated capital expenditures do not include any partnership investments for Northwinds Pipeline.
The estimated capital expenditures also do not include the Empire State Pipeline (Empire), which the Company agreed to purchase in October 2002 from Duke Energy Corporation for $180.0 million in cash plus assumed debt of $60.0 million or any subsequent capital expenditures that would occur upon completion of the acquisition. Empire is a 157-mile, 24-inch pipeline that begins at the Canadian border 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 is regulated by the NYPSC. Empire has the capacity to transport 525 million cubic feet of gas per day and currently 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. Empire would better position 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 Company notified the Department of Justice and Federal Trade Commission of the proposed acquisition as required under the antitrust laws, and the Company's request for early termination of the antitrust waiting period has been granted. The Company has also made a filing seeking approval of the transaction from the NYPSC. Subject to NYPSC approval, it is anticipated that the purchase will be completed in the beginning of calendar 2003.* The Company is evaluating various alternatives to finance this acquisition. Those alternatives could include the sale of certain non-regulated assets, the issuance of equity, or the issuance of debt. *
The Company continues to explore various opportunities to participate in transporting gas to the Northeast, either through Supply Corporation's system or in partnership with others. This includes the proposed Northwinds Pipeline that the Company and TransCanada PipeLines Limited are pursuing. 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, 2002, the Company had incurred approximatley $1.3 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 to $400 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 2003 for the Exploration and Production segment include approximately $37.6 million for Canada, $22.0 million for the Gulf Coast region ($15.4 million on the off-shore program in the Gulf of Mexico), $12.8 million for the West Coast region and $9.2 million for the Appalachian region.* Overall, estimated capital expenditures in 2003 for the Exploration and Production segment are lower than the prior year as the Company intends to live within cash flow and pay down debt.* It should also be noted that estimated off-shore expenditures are lower than the prior year as the Company continues to shift its emphasis from short-lived off-shore reserves to longer-lived on-shore reserves.
The estimated capital expenditures for the International segment in 2003 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 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 purchase of land and timber as well as 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 2003 will be concentrated on the purchase and installation of a gas turbine and steam turbine by Horizon Power to create a 55-megawatt cogeneration 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 August 2002, $97.7 million of the Company’s $100.0 million 6.214% medium-term notes due August 2027 were repaid by the Company at par plus accrued interest. The Company used short-term debt to temporarily refund the $97.7 million to the debt holders. The remaining $2.3 million of the original $100.0 million issuance is scheduled to mature in August 2027.
In September 2002, the Company issued $97.7 million of 6.5% senior unsecured notes due in September 2022. These notes become callable by the Company at par in September 2006. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $94.9 million. The proceeds of this debt issuance were used to repay the short-term debt used to temporarily refund the $97.7 million discussed in the previous paragraph.
In November 2001, the Company issued $150.0 million of 6.70% medium-term notes due in November 2011. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $149.0 million. The proceeds of this debt issuance were used to reduce short-term debt.
Consolidated short-term debt decreased $224.3 million during 2002 primarily due to the November 2001 medium-term note issuance discussed above, and the use of cash from operations to pay down short-term debt. The Company continues to consider short-term debt an important source of cash for temporarily financing capital expenditures and investments in corporations 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 issuance and repayment. The Company has SEC authorization under the Public Utility Holding Company Act of 1935, to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2005. 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 $220 million, 364-day and 3-year credit facility, which was effective on September 30, 2002. Under this committed credit facility, the Company agrees 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 at all times thereafter. With regards to the Company's short-term notes payable to banks, the Company uses uncommitted bank lines of credit aggregating $415.0 million. These uncommitted bank lines of credit 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.* If a downgrade in the Company's credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company could borrow under its uncommitted bank lines of credit or seek other liquidity sources, including cash provided by operations. At September 30, 2002, the Company had outstanding short-term notes payable to banks and commercial paper of $91.3 million and $174.1 million, respectively.
The Company's present liquidity position is believed to be adequate to satisfy known demands.* Under the Company's existing indenture covenants, at September 30, 2002, the Company would have been permitted to issue up to a maximum of $179.0 million in additional long-term unsecured indebtedness at projected market interest rates in addition to being able to issue new indebtedness to replace maturing debt.
The Company's indenture also contains certain cross-default provisions wherein the failure by the Company to pay the scheduled interest or principal on its outstanding short-term or long-term debt (if such failure is not cured) could trigger the obligation to re-pay the debt outstanding under said indenture. The Company believes that it has adequate committed credit facilities in place to protect against such defaults.*
The Company's embedded cost of long-term debt was 7.0% at both September 30, 2002 and 2001, respectively.
The Company also has authorization from the SEC, under the Holding Company Act, to issue long-term debt securities and equity securities in amounts not exceeding $1.5 billion at any one time outstanding during the order's authorization period, which extends to December 31, 2005. The Company currently has $27.3 million of securities registered under the Securities Act of 1933. Any additional public offerings above the $27.3 million would require the filing of a registration statement with the SEC.
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.
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 $31.6 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 minority owned entities, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $9.8 million. The Company has guaranteed 50% or $4.9 million of these capital lease commitments.
The following table summarizes the Company's expected future contractual cash obligations as of September 30, 2002, and the twelve-month periods over which they occur:
- ------------------------------ -----------------------------------------------------------------------------------------------
Payments by Expected Maturity Dates
-----------------------------------------------------------------------------------------------
------------ ----------- ------------ ------------ -------------- -------------- --------------
(Millions) 2003 2004 2005 2006 2007 Thereafter Total
- ------------------------------ ------------ ----------- ------------ ------------ -------------- -------------- ------------
Long-Term Debt $160.6 $235.6 $6.2 $4.4 $ - $899.1 $1,305.9
Short-Term Bank Notes 91.3 - - - - - 91.3
Commercial Paper 174.1 - - - - - 174.1
Operating Lease
Commitments 8.2 6.4 5.0 3.5 2.7 5.8 31.6
Capital Lease
Commitments 0.6 0.6 0.7 0.7 0.7 1.6 4.9
- ------------------------------ ------------ ----------- ------------ ------------ -------------- -------------- --------------
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) Utility segment obligations to purchase gas to be resold in its regulated business in accordance with established regulatory mechanisms to pass through the cost of that gas to its retail customers; (iii) NFR or Upstate obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the consolidated balance sheet as a current liability; and (iv) 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.*
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 months, the Company anticipates that it will continue making maximum funding contributions to the Retirement Plan.* During 2002, the Company contributed $15.4 million to the Retirement Plan. The Company anticipates annual contributions to the Retirement Plan will be in the range of $20.0 to $30.0 million for 2003 - 2005.* 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, through short-term borrowings or through cash from operations.*
Market Risk Sensitive InstrumentsEnergy Commodity Price Risk
The Company, primarily in
its Exploration and Production and Energy Marketing segments, uses various
derivative financial instruments (derivatives), including price swap agreements,
no cost collars, options 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, 2002 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, 2002. At September 30, 2002, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2004.
Natural Gas Price Swap Agreements
----------------------------------------------------- ----------------------------------------------------------
Expected Maturity Dates
----------------------------------------------------------
2003 2004 Total
----------------------------------------------------- ------------------- ------------------- ------------------
Notional Quantities (Equivalent Bcf) 12.3 6.2 18.5
Weighted Average Fixed Rate (per Mcf) $3.81 $3.59 $3.73
Weighted Average Variable Rate (per Mcf) $4.30 $4.20 $4.27
----------------------------------------------------- ------------------- ------------------- ------------------
Crude Oil Price Swap Agreements
- ------------------------------------------------------ -----------------------------------------------------------
Expected Maturity Dates
-----------------------------------------------------------
2003
- ------------------------------------------------------ ------------------- ------------------ --------------------
Notional Quantities (Equivalent bbls) 3,252,000
Weighted Average Fixed Rate (per bbl) $21.28
Weighted Average Variable Rate (per bbl) $27.92
- ------------------------------------------------------ ------------------- ------------------ --------------------
At September 30, 2002, the Company would have had to pay the respective counterparties an aggregate of approximately $9.3 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $19.7 million to the counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2002.
At September 30, 2001, the Company had natural gas price swap agreements covering 27.5 Bcf at a weighted average fixed rate of $3.77 per Mcf. The Company also had crude oil price swap agreements covering 6,643,980 bbls at a weighted average fixed rate of $22.15 per bbl. As indicated in the tables above, the Company has significantly reduced its use of natural gas and crude oil price swap agreements, which is primarily attributable to low commodity prices during much of 2002, which prevented the Company from locking in favorable prices for its oil and gas production. As commodity prices have improved in the first quarter of 2003, the Company may increase its use of natural gas and crude oil price swap agreements.*
The following tables disclose 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, 2002, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2004.
No Cost Collars
- ---------------------------------------------------- ------------------------------------------
Expected Maturity Dates
------------------------------------------
2003 2004 Total
- ---------------------------------------------------- ------------- -------------- -------------
Natural Gas
Notional Quantities (Equivalent Bcf) 8.6 0.2 8.8
Weighted Average Ceiling Price (per Mcf) $5.74 $4.40 $5.71
Weighted Average Floor Price (per Mcf) $3.80 $3.71 $3.80
Crude Oil
Notional Quantities (Equivalent bbls) 1,125,000 270,000 1,395,000
Weighted Average Ceiling Price (per bbl) $26.41 $25.80 $26.29
Weighted Average Floor Price (per bbl) $21.96 $22.00 $21.97
- ---------------------------------------------------- ------------- -------------- -------------
At September 30, 2002, the Company would have received from the respective counterparties an aggregate of approximately $1.7 million to terminate the natural gas no cost collars outstanding at that date. The Company would have paid an aggregate of approximately $2.4 million to terminate the crude oil no cost collars outstanding at that date.
At September 30, 2001, the Company had natural gas no cost collars covering 9.2 Bcf at a weighted average floor price of $4.06 per Mcf and a weighted average ceiling price of $5.36 per Mcf. The Company also had crude oil no cost collars covering 2,730,000 bbls at a weighted average floor price of $21.94 per bbl and a weighted average ceiling price of $27.25 per bbl. As discussed above, low commodity prices during much of 2002 were the primary factors for the decrease in no cost collars from September 2001 to September 2002. With improvements in commodity prices during the first quarter of 2003, the Company may increase its use of natural gas and crude oil no cost collars.*
The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for options used by the Company to manage natural gas price risk. The put options provide for the Exploration and Production segment of the Company to receive monthly payments from other parties when a variable price falls below an established floor or "strike" price. The call options provide for the Energy Marketing segment of the Company to receive monthly payments from other parties when a variable price rises above an established ceiling or "strike" price. At September 30, 2002, the Company held no options with maturity dates extending beyond 2003.
Options Purchased
- ---------------------------------------------------------- --------------------------------------------------------------
Expected Maturity Date
--------------------------------------------------------------
2003
- ---------------------------------------------------------- ------------------ -------------------------------------------
Natural Gas Put Options
Notional Quantities (Equivalent Bcf) 0.2
Weighted Average Strike Price (per Mcf) $3.98
Natural Gas Call Options
Notional Quantities (Equivalent Bcf) 0.2
Weighted Average Strike Price (per Mcf) $4.73
- ---------------------------------------------------------- ------------------ ------------------------ ------------------
At September 30, 2002, the Company would have received from the respective counterparties an aggregate of approximately $0.1 million to terminate the put options outstanding at that date. The Company would have received an aggregate of approximately $0.1 million to terminate the call options outstanding at that date.
At September 30, 2001, the Exploration and Production segment of the Company had natural gas put options covering 2.7 Bcf at a weighted average strike price of $4.11 per Mcf. The Company did not have any call options outstanding at that date. Because of the low commodity prices during much of 2002, the Company did not enter into any new put options during 2002. As for the call options, the Energy Marketing segment of the Company began purchasing call options in 2002 as it began to offer variable price deals with a price cap to its residential customers.
The following table discloses the net notional quantities, 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, 2002, the Company held no futures contracts with maturity dates extending beyond 2004.
Futures Contracts
- ---------------------------------------------------------------------- ---------------------------------------------
Expected Maturity Dates
---------------------------------------------
2003 2004 Total
- ---------------------------------------------------------------------- -------------- -------------- ---------------
Net Contract Volumes Purchased (Equivalent Bcf) 3.1 0.3 3.4
Weighted Average Contract Price (per Mcf) $3.70 $2.79 $3.67
Weighted Average Settlement Price (per Mcf) $4.50 $4.44 $4.49
- ---------------------------------------------------------------------- -------------- -------------- ---------------
At September 30, 2002, the Company would have received $2.1 million to terminate these futures contracts.
At September 30, 2001, the Company had futures contracts covering 13.2 Bcf (net long position) at a weighted average contract price of $4.17 per Mcf. As indicated in the table above, the Company has significantly reduced its use of natural gas futures contracts. This reduction can be attributed primarily to a reduction in fixed price gas sales commitments in the Energy Marketing segment . At September 30, 2001, natural gas prices were low and many of the customers in the Energy Marketing segment entered into fixed price contracts to lock in the commodity price of natural gas at that time. At September 30, 2002, with natural gas prices being much higher than the prior year, many of the customers in the Energy Marketing segment chose to enter into variable price contracts that provided the opportunity to enter into a fixed price contract at a later date. With variable price contracts, commodity price risk is moved from the Company to the customer.
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, 2001, the Company used five counterparties for its over the counter derivative financial instruments. To further reduce credit risk, the Company increased the number of its counterparties to seven at September 30, 2002. At September 30, 2002, no individual counterparty represented greater than 25% 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. At September 30, 2002 compared to September
30, 2001, the Czech koruna was higher in value in relation to the U.S. dollar,
resulting in a $24.1 million positive adjustment to the Cumulative Foreign
Currency Translation Adjustment (CTA) (a component of Accumulated Other
Comprehensive Income/Loss). At September 30, 2002 compared to September 30,
2001, the Canadian dollar was slightly higher in value in relation to the U.S.
dollar, resulting in a $0.2 million positive adjustment to the CTA. Further
valuation changes to the Czech koruna and Canadian dollar would result in
corresponding positive or negative adjustments to the CTA. Management cannot
predict whether the Czech koruna or Canadian dollar will increase or decrease in
value against the U.S. dollar.*
Interest Rate Risk
The Company’s exposure
to interest rate risk arises primarily from its borrowing under short-term debt
instruments. At September 30, 2002, these instruments included domestic
short-term bank loans and commercial paper totaling $254.0 million. The interest
rate on these short-term bank loans and commercial paper approximated 2.0% at
September 30, 2002. The Company’s short-term debt instruments also included
$11.4 million of short-term bank loans in Canada and the Czech Republic at
September 30, 2002. The weighted average interest rates on the Canadian and
Czech Republic loans approximated 3.7% and 3.3%, respectively, at September 30,
2002.
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 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, 2002:
- --------------------------------------- ------------------------------------------------------------------- ----------
Principal Amounts by Expected Maturity Dates
-------------------------------------------------------------------
(Millions of Dollars) 2003 2004 2005 2006 2007 Thereafter Total
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------
National Fuel Gas Company
Long-Term Fixed Rate Debt $150 $225 $ - $ - $ - $899 $1,274
Weighted Average Interest
Rate Paid 7.3% 7.3% -% -% -% 6.9% 7.0%
Fair Value = $1,362.0 million
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------
Other Notes
Long-Term Debt(1) $10.6 $10.6 $6.2 $4.4 $ - $0.1 $31.9
Weighted Average Interest
Rate Paid 5.1% 5.1% 5.6% 6.1% -% 3.1% 5.3%
Fair Value = $31.9 million
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------
(1) $15.6 million is variable rate debt; $16.3 million is fixed rate debt.
RATE MATTERSBase rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
New York JurisdictionOn 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) that establishes rates for a three-year period beginning October 1, 2000. The Agreement provided that customers receive a bill credit of $17.6 million for the November 1, 2000 through March 31, 2001 heating season, of which $7.6 million related to customers’ share of earnings accumulated under previous settlements. The credit was reduced to $5.0 million for the November 1, 2001 through March 31, 2002 heating season. The credit will remain at $5.0 million for the November 1, 2002 through March 31, 2003 heating season and subsequent heating seasons unless the Company can demonstrate that it is no longer justified. Also, earnings beyond a target level of 11.5% return on equity will be shared equally between shareholders and customers. The Agreement provides further that the Company and interested parties will resume discussions to address the NYPSC’s competition initiatives, including changes to “customer choice” transportation services, among other things. Those discussions commenced in November 2000 and ultimately produced an interim “Joint Proposal,” or settlement agreement, addressing several discrete issues of interest to the parties and the NYPSC. In an order issued on May 30, 2001, the NYPSC adopted the parties’ Joint Proposal. As recommended by the parties, the Joint Proposal modifies Distribution Corporation’s operations relating to transportation services and transactions with marketers and producers of indigenous natural gas. Under the Joint Proposal, the parties also agreed to continue negotiations to implement additional features of the NYPSC’s restructuring initiative (described below). Those confidential discussions, dubbed “Phase III negotiations,” concluded on January 18, 2002 when the parties executed a “Comprehensive Joint Proposal”. The Comprehensive Joint Proposal proposes a number of changes to Distribution Corporation’s rates and services through September 30, 2003, including the following:
o Modification of transportation balancing services and upstream capacity rules for the benefit of marketers and to preserve
reliability;
o A customer funded "back-out credit" provided to marketers (or marketer customers) to reduce marketer costs and thereby
promote competition;
o Provisions to promote increased marketer usage of indigenous natural gas;
o An expanded low-income program that provides arrearage forgiveness and a discounted rate for up to 30,000 customers;
o Increased customer funding to offset the cost of uncollectibles;
o Unbundling of gas costs from delivery rates; and
o Mechanisms for recovery of stranded pipeline and unbundling costs.
The Comprehensive Joint Proposal was filed with the NYPSC on January 23, 2002 and approved with immaterial modifications on April 18, 2002, effective May 1, 2002. Distribution Corporation’s base rates will not be materially changed under the Comprehensive Joint Proposal, which is not intended to modify the rate and revenue requirements established in the Agreement described above.
On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was Ordered to Show Cause why an action for penalties up to $19 million should not be commenced against it for alleged violations of consumer protection requirements. According to the NYPSC, 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 (submitted under a seal of confidentiality imposed by the Supreme Court, Erie County designed to protect the personal privacy interests of the deceased individual) and requested that the NYPSC either close (dismiss) the Show Cause proceeding based on the evidence presented in Distribution’s response, or hold administrative evidentiary 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. The Company believes and will continue to vigorously assert that the NYPSC’s allegations lack merit.
Pennsylvania JurisdictionDistribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission (PaPUC). Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future.
Pipeline and StorageSupply Corporation currently does not have a rate case on file with the FERC. Management will continue to monitor Supply Corporation’s financial position to determine the necessity of filing a rate case in the future.
The federal law under which FERC regulates Supply Corporation’s rates, practices, and terms and conditions of service requires, among other things, that Supply Corporation not grant any undue preference or advantage to any person. In March 2001, FERC staff began a routine audit of Supply Corporation’s practices and dealings with “marketing affiliates,” i.e., other Company subsidiaries which conduct natural gas transportation and/or storage transactions with Supply. On July 11, 2002, FERC adopted an order instituting an investigation directed to Supply Corporation and its natural gas marketing affiliates, under Sections 4 and 5 of the Natural Gas Act and Section 501 of the Natural Gas Policy Act. This is not an investigation into Supply’s currently effective rates, or any energy trading activities, “wash sales,” “round-trip transactions,” sales of electricity into the California market, or other activities that have been the subjects of recent news stories regarding other publicly traded energy companies. The Company does not engage in any such energy trading activities. The stated basis for instituting the investigation is information received during the audit which indicates there may have been violations of FERC regulations, specifically:
| 18 CFR Section 161.3(f), which requires that, to the extent Supply Corporation provides to a gas marketing affiliate information related to gas transportation, Supply Corporation must provide that information contemporaneously to all potential shippers [FERC staff has indicated that they believe Supply Corporation violated this regulation by e-mailing information describing daily operationally available capacity on its gas transportation system to a large number of shippers (including one Supply Corporation marketing affiliate) a few hours before that information was posted on Supply Corporation’s website later that same day; Supply Corporation now provides such e-mails after the information is posted on its website]; and |
| 18 CFR Section 161.3(l), which requires that Supply Corporation must timely post on its website lists of gas marketing affiliates, organizational charts and job descriptions of various individuals (Supply Corporation has updated this information). |
Supply Corporation and its affiliates continue to cooperate with FERC staff by providing responses to multiple document requests in connection with this investigation and the preceding audit, and by making individuals available for interviews. The Company believes, based on the information presently known, that neither Supply Corporation nor any affiliate has received any benefit from any violations of FERC regulations which may have occurred, and that the ultimate resolution of this proceeding will not materially affect the Company's operations or financial condition.
Other MattersEnvironmental 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 $5.1 million to $6.1
million.* The minimum liability of $5.1 million has been recorded on the
Consolidated Balance Sheet at September 30, 2002. Other than discussed in Note H
(referred to below), the Company is currently not aware of any material
additional exposure to environmental liabilities. However, adverse changes in
environmental regulations or other factors could impact the Company.* The
Company is subject to various federal, state and local laws and regulations
(including those of the Czech Republic) 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 H - Commitments and Contingencies under the heading "Environmental Matters."
New Accounting Pronouncements
In 2001, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (SFAS
142) and SFAS No. 143, “Accounting for Asset Retirement Obligations”
(SFAS 143). For a discussion of SFAS 142 and SFAS 143 and their impact on the
Company, see disclosure in Item 8 at Note A – Summary of Significant
Accounting Policies.
Effects of Inflation
Although the rate of
inflation has been relatively low over the past few years, the 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.
Approval of Audit and Non-Audit Services
On September 12, 2002, the
Company’s audit committee approved audit services relating to the audit of
the Company’s financial statements for the fiscal year ending September 30,
2002, and the provision of comfort letters in connection with securities
underwritings. The audit committee also approved certain non-audit services to
be performed by the Company’s independent accountant,
PricewaterhouseCoopers, LLP, including advice concerning methodologies for
valuing certain assets, tax advice concerning financing arrangements, and other
customary consultation or advice.
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 those which
are designated with an asterisk (“*”), 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:
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 Accountants
Consolidated Balance Sheets at September 30, 2002 and 2001
Consolidated Statement of Cash Flows, three years ended September 30, 2002
Consolidated Statement of Comprehensive Income, three years ended September 30, 2002
Notes to Consolidated Financial Statements
Financial Statement Schedules:
For the three years ended September 30, 2002
II-Valuation and Qualifying Accounts
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 accountants, 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 accountants have direct access to the Audit Committee and periodically meet with it without management representatives present.
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, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2002, 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.
PricewaterhouseCoopers LLP
Buffalo, New York
October 23, 2002
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) 2002 2001 2000
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Income
Operating Revenues $1,464,496 $2,059,836 $1,412,416
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Expenses
Purchased Gas 462,857 1,002,466 488,383
Fuel Used in Heat and Electric Generation 50,635 54,968 54,893
Operation and Maintenance 394,157 364,318 350,383
Property, Franchise and Other Taxes 72,155 83,730 78,878
Depreciation, Depletion and Amortization 180,668 174,914 142,170
Impairment of Oil and Gas Producing
Properties - 180,781 -
Income Taxes 72,034 37,106 77,068
- -------------------------------------------------------------- ----------------- ---------------- -----------------
1,232,506 1,898,283 1,191,775
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Income 231,990 161,553 220,641
Operations of Unconsolidated Subsidiaries:
Income 224 1,794 1,669
Impairment of Investment in Partnership (15,167) - -
- -------------------------------------------------------------- ----------------- ---------------- -----------------
(14,943) 1,794 1,669
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Other Income 7,017 10,639 6,366
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 224,064 173,986 228,676
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Interest Charges
Interest on Long-Term Debt 90,543 81,851 67,195
Other Interest 15,109 25,294 32,890
- -------------------------------------------------------------- ----------------- ---------------- -----------------
105,652 107,145 100,085
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Minority Interest in Foreign Subsidiaries (730) (1,342) (1,384)
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Net Income Available for Common Stock 117,682 65,499 127,207
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Earnings Reinvested in the Business
Balance at Beginning of Year 513,488 525,847 472,517
- -------------------------------------------------------------- ----------------- ---------------- -----------------
631,170 591,346 599,724
Dividends on Common Stock 81,773 77,858 73,877
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Balance at End of Year $549,397 $513,488 $525,847
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Earnings Per Common Share:
Basic $1.47 $0.83 $1.63
Diluted $1.46 $0.82 $1.61
- -------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 79,821,430 79,053,444 78,233,842
Used in Diluted Calculation 80,534,453 80,361,258 79,166,200
- -------------------------------------------------------------- ----------------- ---------------- -----------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Balance Sheets
- ---------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands of Dollars) 2002 2001
- ---------------------------------------------------------------------------- ------------------- -------------------
Assets
Property, Plant and Equipment $4,512,651 $4,273,716
Less - Accumulated Depreciation,
Depletion and Amortization 1,667,906 1,493,003
- ---------------------------------------------------------------------------- ------------------- -------------------
2,844,745 2,780,713
- ---------------------------------------------------------------------------- ------------------- -------------------
Current Assets
Cash and Temporary Cash Investments 22,216 36,227
Receivables - Net 95,510 131,379
Unbilled Utility Revenue 21,918 25,375
Gas Stored Underground 77,250 83,231
Materials and Supplies - at average cost 31,582 33,710
Unrecovered Purchased Gas Costs 12,431 4,113
Prepayments 41,354 39,520
Fair Value of Derivative Financial Instruments 3,807 37,585
- ---------------------------------------------------------------------------- ------------------- -------------------
306,068 391,140
- ---------------------------------------------------------------------------- ------------------- -------------------
Other Assets
Recoverable Future Taxes 82,385 86,586
Unamortized Debt Expense 20,635 19,796
Other Regulatory Assets 26,104 23,253
Deferred Charges 5,914 8,440
Other Investments 65,090 62,924
Investments in Unconsolidated Subsidiaries 16,753 31,768
Goodwill 8,255 8,804
Other 25,360 31,807
- ---------------------------------------------------------------------------- ------------------- -------------------
250,496 273,378
- ---------------------------------------------------------------------------- ------------------- -------------------
$3,401,309 $3,445,231
- ---------------------------------------------------------------------------- ------------------- -------------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Balance Sheets
- ---------------------------------------------------------------------------- ----------------- ----------------
At September 30 (Thousands of Dollars) 2002 2001
- ---------------------------------------------------------------------------- ----------------- ----------------
Capitalization and Liabilities
Capitalization:
Comprehensive Shareholders' Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued and
Outstanding - 80,264,734 Shares and 79,406,105
Shares, Respectively $80,265 $ 79,406
Paid In Capital 446,832 430,618
Earnings Reinvested in the Business 549,397 513,488
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Common Shareholder Equity Before Items
Of Other Comprehensive Loss 1,076,494 1,023,512
Accumulated Other Comprehensive Loss (69,636) (20,857)
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Comprehensive Shareholders' Equity 1,006,858 1,002,655
Long-Term Debt, Net of Current Portion 1,145,341 1,046,694
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Capitalization 2,152,199 2,049,349
- ---------------------------------------------------------------------------- ----------------- ----------------
Minority Interest in Foreign Subsidiaries 28,785 22,324
- ---------------------------------------------------------------------------- ----------------- ----------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 265,386 489,673
Current Portion of Long-Term Debt 160,564 109,435
Accounts Payable 100,886 123,246
Amounts Payable to Customers - 51,223
Other Accruals and Current Liabilities 121,518 89,893
Fair Value of Derivative Financial Instruments 31,204 17,081
- ---------------------------------------------------------------------------- ----------------- ----------------
679,558 880,551
- ---------------------------------------------------------------------------- ----------------- ----------------
Deferred Credits
Accumulated Deferred Income Taxes 356,220 340,224
Taxes Refundable to Customers 15,596 16,865
Unamortized Investment Tax Credit 8,897 9,599
Other Regulatory Liabilities 82,676 68,957
Other Deferred Credits 77,378 57,362
- ---------------------------------------------------------------------------- ----------------- ----------------
540,767 493,007
- ---------------------------------------------------------------------------- ----------------- ----------------
Commitments and Contingencies - -
- ---------------------------------------------------------------------------- ----------------- ----------------
$3,401,309 $3,445,231
- ---------------------------------------------------------------------------- ----------------- ----------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Statement of Cash Flows
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Year Ended September 30 (Thousands of Dollars) 2002 2001 2000
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Operating Activities
Net Income Available for Common Stock $117,682 $65,499 $127,207
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Impairment of Oil and Gas Producing Properties - 180,781 -
Depreciation, Depletion and Amortization 180,668 174,914 142,170
Deferred Income Taxes 62,013 (55,849) 41,858
Impairment of Investment in Partnership 15,167 - -
(Income) Loss from Unconsolidated Subsidiaries,
Net of Cash Distributions 361 (1,199) (1,440)
Minority Interest in Foreign Subsidiaries 730 1,342 1,384
Other 9,842 6,553 5,946
Change in:
Receivables and Unbilled Utility Revenue 40,786 (2,277) (26,365)
Gas Stored Underground and Materials and
Supplies 8,717 (37,054) (13,707)
Unrecovered Purchased Gas Costs (8,318) 25,568 (25,105)
Prepayments (1,737) (399) (3,420)
Accounts Payable (24,025) 20,419 (16,489)
Amounts Payable to Customers (51,223) 41,640 3,649
Other Accruals and Current Liabilities (37,372) 13,969 (10,233)
Other Assets 11,869 (33,169) 826
Other Liabilities 20,390 13,289 11,965
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Provided by Operating Activities 345,550 414,027 238,246
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Investing Activities
Capital Expenditures (232,368) (292,706) (269,371)
Investment in Subsidiaries, Net of Cash Acquired - (90,567) (123,809)
Investment in Partnerships (536) (1,830) (4,442)
Other 27,080 (2,823) 13,283
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Used in Investing Activities (205,824) (387,926) (384,339)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper (224,845) (143,397) 226,477
Net Proceeds from Issuance of Long-Term Debt 243,844 210,221 149,334
Reduction of Long-Term Debt (104,212) (23,052) (167,426)
Proceeds from Issuance of Common Stock 10,915 11,545 14,278
Dividends Paid on Common Stock (80,974) (76,671) (73,046)
Dividends Paid to Minority Interest - - (152)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash (Used in) Provided by Financing Activities (155,272) (21,354) 149,465
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Effect of Exchange Rates on Cash 1,535 (645) (469)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Increase (Decrease) in Cash and
Temporary Cash Investments (14,011) 4,102 2,903
Cash and Temporary Cash Investments
at Beginning of Year 36,227 32,125 29,222
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Cash and Temporary Cash Investments
at End of Year $22,216 $36,227 $ 32,125
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Supplemental Disclosure of Cash Flow Information
Cash Paid For:
Interest $98,493 $100,871 $97,042
Income Taxes 29,985 77,662 41,928
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
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) 2002 2001 2000
- ------------------------------------------------------- -------------------------- ------------------------ -------------------------
Net Income Available for Common Stock $117,682 $ 65,499 $127,207
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before Tax:
Minimum Pension Liability Adjustment (52,977) - -
Foreign Currency Translation Adjustment 24,278 (7,158) (27,463)
Unrealized Gain (Loss) on Securities Available
for Sale Arising During the Period (2,086) (712) 2,441
Unrealized Gain (Loss) on Derivative Financial
Instruments Arising During the Period (42,584) 58,355 -
Reclassification Adjustment for Realized
(Gain) Loss on Derivative Financial
Instruments in Net Income (20,063) 83,218 -
Reclassification Adjustment for Realized Gain
on Securities Available for Sale in Net
Income - - (103)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before
Tax: (93,432) 133,703 (25,125)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Income Tax Benefit Related to Minimum
Pension Liability Adjustment (18,542) - -
Income Tax Expense (Benefit) Related to
Unrealized Gain (Loss) on Securities
Available for Sale Arising During the Period (730) (249) 855
Income Tax Expense (Benefit) Related to
Unrealized Gain (Loss) on Derivative
Financial Instruments Arising During the
Period (17,341) 23,053 -
Reclassification Adjustment for Income Tax
(Expense) Benefit on Realized (Gain)
Loss on Derivative Financial Instruments
In Net Income (8,040) 32,032 -
Reclassification Adjustment for Income Tax
Expense on Realized Gain on Securities
Available for Sale in Net Income - - (36)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Income Taxes - Net (44,653) 54,836 819
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), Before
Cumulative Effect (48,779) 78,867 (25,944)
Cumulative Effect of Change in Accounting,
Net of Tax - (69,767) -
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Other Comprehensive Income (Loss), After
Cumulative Effect (48,779) 9,100 (25,944)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
Comprehensive Income $ 68,903 $ 74,599 $101,263
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ----------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Notes to Consolidated Financial Statements
Back to Index of Financial StatementsPrinciples of
Consolidation
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
Revenues are recorded as
bills are rendered, except that service supplied but not billed is reported as
unbilled utility revenue and is included in operating revenues for the year in
which service is furnished.
Unrecovered Purchased Gas Costs and Refunds
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.
Estimated refund liabilities to ratepayers represent management's current estimate of such refunds. Reference is made to Note B - Regulatory Matters for further discussion.
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. As a result of low oil and gas prices, the Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling for the Company's Canadian properties at September 30, 2001. The Company was required to recognize a $180.8 million ($104.0 million after tax) impairment of its oil and gas producing properties in the quarter ended September 30, 2001.
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
Depreciation, depletion and
amortization are computed by application of either the straight-line method or
the units of production method in amounts sufficient to recover costs over the
estimated service lives of property in service, and for oil and gas properties,
based on quantities produced in relation to proved reserves. The costs of
unevaluated oil and gas properties are 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. The provisions for depreciation,
depletion and amortization, as a percentage of average depreciable property,
were 4.4% in 2002, 4.7% in 2001 and 4.2% in 2000 on a consolidated basis.
Cumulative Effect of Change in Accounting
Effective October 1, 2000,
the Company adopted the Financial Accounting Standards Board’s (FASB)
Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for
Derivative Instruments and Hedging Activities” (SFAS 133) 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
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 F
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, options 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 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 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 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 2002 or 2001.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
---------------------------------------------------------------- -------------------- --------------------
Year Ended September 30 (Thousands) 2002 2001
---------------------------------------------------------------- -------------------- --------------------
Minimum Pension Liability Adjustment $(34,435) $ -
Cumulative Foreign Currency Translation Adjustment (14,815) (39,093)
Net Unrealized Gain (Loss) on Derivative Financial
Instruments (20,545) 16,721
Net Unrealized Gain on Securities Available for Sale 159 1,515
---------------------------------------------------------------- -------------------- --------------------
Accumulated Other Comprehensive Loss $(69,636) $(20,857)
---------------------------------------------------------------- -------------------- --------------------
At September 30, 2002, it is estimated that $18.1 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 2003.
Gas Stored Underground - Current
In the Utility segment, gas
stored underground - current in the amount of $66.4 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 2002, 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
$46.0 million at September 30, 2002. All other gas stored underground - current
is carried at lower of cost or market on either an average cost or first-in,
first-out method.
Unamortized Debt Expense
Costs associated with the
issuance of debt by the Company are deferred and amortized over the lives of the
related issues. Costs associated with the reacquisition of debt related to
rate-regulated subsidiaries are deferred and amortized over the remaining life
of the issue or the life of the replacement debt in order to match regulatory
treatment.
Foreign Currency Translation
The functional currency for
the Company’s foreign operations is the 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 $0.4 million and
$22.5 million at September 30, 2002 and 2001, 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 2002 and 2001, 5,260,633 and 1,290,747 stock options,
respectively, were excluded as being antidilutive.
New Accounting Pronouncements
In 2001, the FASB issued
SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142) and
SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS
143). SFAS 142 addresses financial accounting and reporting for acquired
goodwill and other intangible assets. Under this standard, goodwill and
intangible assets that have indefinite useful lives will not be amortized but
rather will be tested at least annually for impairment. Intangible assets that
have finite useful lives will continue to be amortized over their useful lives,
but the amortization period will not be limited to a certain period of time. The
Company will adopt SFAS 142 during the first quarter of fiscal 2003 and is in
the process of completing its initial impairment test of the goodwill on its
balance sheet. The Company does not believe that adoption of SFAS 142 will have
a material impact on its financial condition and results of operations.
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 cost by increasing 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. When the liability is settled, the entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company will adopt SFAS 143 during the first quarter of fiscal 2003. The Company does not believe that adoption of SFAS 143 will have a material impact on its financial condition and results of operations.
Regulatory Assets and LiabilitiesRegulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
- --------------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands) 2002 2001
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Assets:
Recoverable Future Taxes (Note C) $82,385 $86,586
Unrecovered Purchased Gas Costs (Note A) 12,431 4,113
Unamortized Debt Expense (Note A) 10,021 11,738
Pension and Post-Retirement Benefit Costs (1) (Note G) 24,146 21,065
Other (1) 1,958 2,188
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Assets 130,941 125,690
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) - 51,223
New York Rate Settlements(2) 34,323 27,630
Taxes Refundable to Customers (Note C) 15,596 16,865
Pension and Post-Retirement Benefit Costs(2) (Note G) 39,946 33,829
Other(1) 8,407 7,498
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Liabilities 98,272 137,045
- --------------------------------------------------------------------------------- ------------------- -------------------
Net Regulatory Position $32,669 $(11,355)
- --------------------------------------------------------------------------------- ------------------- -------------------
(1) Included in other regulatory assets on the Consolidated Balance Sheets.
(2) 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 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%
return on equity are to be shared equally between shareholders and customers. As
a result of this sharing mechanism, the Company had liabilities of $9.5 million
and $5.8 million at September 30, 2002 and 2001, respectively. Other aspects of
the settlements include a special reserve of $6.5 million and $8.2 million at
September 30, 2002 and 2001, respectively, to be applied against the
Company’s incremental costs resulting from the NYPSC’s gas
restructuring effort and a “refund pool” of $15.3 million and $6.0
million at September 30, 2002 and 2001, respectively. The refund pool 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 $3.0 million and $7.7 million at September 30, 2002
and 2001, 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) 2002 2001 2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Expenses:
Current Income Taxes -
Federal $7,743 $ 67,429 $ 26,352
State 1,384 21,330 13,067
Foreign 894 4,196 (4,209)
Deferred Income Taxes -
Federal 50,205 18,444 29,604
State 9,968 431 2,495
Foreign 1,840 (74,724) 9,759
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
72,034 37,106 77,068
Other Income:
Deferred Investment Tax Credit (697) (348) (1,051)
Minority Interest in Foreign Subsidiaries (277) (614) (259)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Total Income Taxes $71,060 $ 36,144 $ 75,758
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
The U.S. and foreign components of income (loss) before income taxes are as follows:
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
U.S. $180,349 $267,270 $182,813
Foreign 8,394 (165,627) 20,152
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$188,743 $101,643 $202,965
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
- --------------------------------------------------------------- ------------------- --------------- ---------------- Year Ended September 30 (Thousands) 2002 2001 2000 - --------------------------------------------------------------- ------------------- --------------- ---------------- Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $66,060 $35,575 $71,038 Increase (Reduction) in Taxes Resulting from: State Income Taxes 7,379 14,145 10,115 Foreign Tax Rate Differential (481) (13,172) (1,762) Depreciation 1,744 1,790 1,925 Miscellaneous (3,642) (2,194) (5,558) - --------------------------------------------------------------- ------------------- --------------- ---------------- Total Income Taxes $71,060 $36,144 $75,758 - --------------------------------------------------------------- ------------------- --------------- ----------------
Significant components of the Company's deferred tax liabilities and assets are as follows:
- --------------------------------------------------------------- ------------------- --------------- At September 30 (Thousands) 2002 2001 - --------------------------------------------------------------- ------------------- --------------- Deferred Tax Liabilities: Property, Plant and Equipment $417,673 $389,879 Deferred Gas Costs 5,469 - Other 22,461 27,047 - --------------------------------------------------------------- ------------------- --------------- Total Deferred Tax Liabilities 445,603 416,926 - --------------------------------------------------------------- ------------------- --------------- Deferred Tax Assets: Deferred Gas Costs - (20,178) Other (89,383) (56,524) - --------------------------------------------------------------- ------------------- --------------- Total Deferred Tax Assets (89,383) (76,702) - --------------------------------------------------------------- ------------------- --------------- Total Net Deferred Income Taxes $356,220 $340,224 - --------------------------------------------------------------- ------------------- ---------------
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 $15.6 million and $16.9 million at September 30, 2002 and 2001, 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 $82.4 million and $86.6 million at September 30, 2002 and 2001, respectively.
Undistributed earnings of foreign subsidiaries of $32 million at September 30, 2002 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 in the form of dividends, the Company may be subject to U.S. income taxes and foreign withholding taxes, net of allowable foreign tax credits.
At September 30, 2002, there are Canadian operating loss carryforwards of $23 million which begin to expire if not utilized by the tax year ending September 30, 2006.
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
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, 1999 77,674 $77,674 $393,115 $472,517 $(4,013)
Net Income Available
for Common Stock 127,207
Dividends Declared on
Common Stock
($0.95 Per Share) (73,877)
Other Comprehensive
Loss, Net of Tax (25,944)
Acquisition of
Natural Gas Assets 110 110 2,702
Common Stock Issued
Under Stock and
Benefit Plans 876 876 17,070
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
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 (81,773)
($1.03 Per Share)
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 (1) $(69,636)
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
(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, 2002, $475.0 million of accumulated earnings was free of such limitations.
Common Stock
The Company has various
plans which allow shareholders, customers and employees to purchase shares of
Company common stock. The 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 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.
For the years ended September 30, 2002, 2001 and 2000, no compensation expense was recognized for options granted under these plans. Had compensation expense for stock options granted under the Company's stock option and stock award plans been determined based on fair value at the grant dates, the Company's net income and earnings per share would have been reduced to the pro forma amounts below:
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Year Ended September 30 2002 2001 2000
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Net Income (Thousands):
As reported $117,682 $65,499 $127,207
Pro forma $113,041 $59,108 $123,107
Earnings Per Common Share:
Basic - As reported $1.47 $0.83 $1.63
Basic - Pro forma $1.42 $0.75 $1.58
Diluted - As reported $1.46 $0.82 $1.61
Diluted - Pro forma $1.40 $0.73 $1.56
- ---------------------------------------------------------- ------------------- ------------------- -------------------
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, 1999 6,728,184 $19.65
Granted in 2000 1,782,200 $21.87
Exercised in 2000(1) (455,484) $15.08
Forfeited in 2000 (27,800) $23.08
- ------------------------------------------------------------- ---------------------------- ---------------------------
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
$25.56
Forfeited in 2002 (168,444)
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 2002 14,629,504 $22.12
- ------------------------------------------------------------- ---------------------------- ---------------------------
Option shares exercisable at September 30, 2002 11,766,044 $21.68
Option shares available for future
grant at September 30, 2002 (3) 942,669
- ------------------------------------------------------------- ---------------------------- ---------------------------
(1) In connection with exercising these options, 43,834, 78,850 and 116,916 shares were surrendered and canceled during 2002, 2001 and 2000, 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 weighted average fair value per share of options granted in 2002, 2001 and 2000 was $4.32, $5.25 and $4.17, 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 2002 2001 2000 - ---------------------------------------------------------- ------------------- ------------------- ------------------- Quarterly Dividend Yield 1.07% 0.87% 1.07% Annual Standard Deviation (Volatility) 21.83% 20.51% 19.05% Risk Free Rate 4.88% 5.26% 6.74% Expected Term - in Years 5.5 5.0 5.5 - ---------------------------------------------------------- ------------------- ------------------- -------------------
The following table summarizes information about options outstanding at September 30, 2002:
- --------------------------------------------------------------------------------- -------------------------------------
Options Outstanding Options Exercisable
- --------------------------------------------------------------------------------- -------------------------------------
Number Weighted Average Weighted Number Weighted
Range of Outstanding Remaining Average Exercisable Average
Exercise Price at 9/30/02 Contractual Life Exercise Price at 9/30/02 Exercise Price
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
$11.12 - $16.68 1,635,916 2.2 years $14.91 1,635,916 $14.91
$16.69 - $22.24 4,572,226 5.9 years $20.31 4,291,226 $20.21
$22.25 - $27.80 8,421,362 7.5 years $24.50 5,838,902 $24.66
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is being recorded as compensation expense over the periods during which the vesting restrictions exist. Certificates for shares of restricted stock awarded under the Company's stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
The following table summarizes the awards of restricted stock over the past three years:
- ----------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 2002 2001 2000 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Shares of Restricted Stock Awarded 100,000 4,000 15,178 Weighted Average Market Price of Stock on Award Date $24.50 $27.80 $24.47 - ----------------------------------------------------------------- ----------------- ---------------- -----------------
As of September 30, 2002, 149,728 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2003 - 13,600 shares; 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 $0.7 million, $0.3 million and $0.7 million for the years ended September 30, 2002, 2001 and 2000, respectively.
Redeemable Preferred Stock
As of September 30, 2002, 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) 2002 2001
- ----------------------------------------------------------------------------------- ---------------- -----------------
Debentures:
7-3/4% due February 2004 $125,000 $ 125,000
Medium-Term Notes:
6.00% to 8.48% due February 2003 to August 2027(1) 1,051,300 999,000
Senior Unsecured Notes:
6.50% due September 2022(2) 97,700 -
- ----------------------------------------------------------------------------------- ---------------- -----------------
1,274,000 1,124,000
- ----------------------------------------------------------------------------------- ---------------- -----------------
Other Notes 31,905 32,129
- ----------------------------------------------------------------------------------- ---------------- -----------------
Total Long-Term Debt 1,305,905 1,156,129
Less Current Portion 160,564 109,435
- ----------------------------------------------------------------------------------- ---------------- -----------------
$1,145,341 $1,046,694
- ----------------------------------------------------------------------------------- ---------------- -----------------
(1) Includes $50 million of 8.48% medium-term notes due July 2024 which are callable at a redemption price of 105.09% through July 2003. The redemption price will decline in subsequent years.
(2) 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.
As of September 30, 2002, the aggregate principal amounts of long-term debt maturing for the next five years and thereafter are as follows: $160.6 million in 2003, $235.6 million in 2004, $6.2 million in 2005, $4.4 million in 2006, none in 2007 and $899.1 million thereafter.
The Company has 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.
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 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. These credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. The commercial paper program is backed by a committed $220 million, 364-day and 3-year credit facility, which was effective on September 30, 2002.
At September 30, 2002, the Company had outstanding short-term notes payable to banks and commercial paper of $91.3 million (domestic = $79.9 million; foreign = $11.4 million) and $174.1 million, respectively. At September 30, 2001, the Company had outstanding notes payable to banks and commercial paper of $289.7 million (domestic = $259.9 million; foreign = $29.8 million) and $200.0 million, respectively.
The weighted average interest rate on domestic notes payable to banks was 2.05% and 3.39% at September 30, 2002 and 2001, respectively. The interest rate on the foreign notes payable to banks was 3.64% and 4.65% at September 30, 2002 and 2001, respectively. The weighted average interest rate on commercial paper was 2.04% and 3.13% at September 30, 2002 and 2001, respectively.
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:
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
2002 2002 2001 2001
Carrying Fair Carrying Fair
At September 30 (Thousands) Amount Value Amount Value
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
Long-Term Debt $1,305,905 $1,393,949 $1,156,129 $1,186,795
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay.
Temporary cash investments, notes payable to banks and commercial paper are stated at amounts which approximate their fair value due to the short-term maturities of those financial instruments. Investments in life insurance are stated at their cash surrender values as discussed below. Investments 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 $57.1 million
and $52.9 million at September 30, 2002 and 2001, respectively. The fair
value of the equity mutual fund was $3.8 million and $4.8 million at September
30, 2002 and 2001, respectively. The gross unrealized loss on the equity mutual
fund was $1.5 million and $0.4 million at September 30, 2002 and 2001,
respectively. The fair value of the stock of an insurance company was $4.2
million and $5.2 million at September 30, 2002 and 2001, respectively. The gross
unrealized gain on this stock was $1.7 million and $2.7 million at September 30,
2002 and 2001, 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, options and
futures contracts.
Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed price and a variable price as specified by the agreement. The variable price is either a crude oil price quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural gas price in "Inside FERC." 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. At September 30, 2002, the Company had natural gas price swap agreements covering a notional amount of 18.5 Bcf extending through 2004 at a weighted average fixed rate of $3.73 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 3,252,000 bbls extending through 2003 at a weighted average fixed rate of $21.28 per bbl. At September 30, 2002, the Company would have had to pay a net $29.0 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, 2002, the Company had no cost collars on natural gas covering a notional amount of 8.8 Bcf extending through 2004 with 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 no cost collars on crude oil covering a notional amount of 1,395,000 bbls extending through 2004 with a weighted average floor price of $21.97 per bbl and a weighted average ceiling price of $26.29 per bbl. At September 30, 2002, the Company would have had to pay $0.7 million to terminate the no cost collars.
At September 30, 2002, the Company had purchased call and put options outstanding on natural gas extending through 2003. The call options purchased by the Energy Marketing segment cover a notional amount of 0.2 Bcf at a weighted average strike price of $4.73 per Mcf. The put options, purchased by the Exploration and Production segment cover a notional amount of 0.2 Bcf at a weighted average strike price of $3.98 per Mcf. These derivative financial instruments are accounted for as cash flow hedges. The call options are used to establish a ceiling price (the Company receives payment from the counterparty when a variable price rises above the ceiling price) for the anticipated purchase of natural gas in the Energy Marketing segment. At September 30, 2002, the Company would have received $0.1 million to terminate these call options. The put options are used to establish a floor price (the Company receives payment from the counterparty when a variable price falls below the floor price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2002, the Company would have received $0.1 million to terminate these put options.
At September 30, 2002, the Company had long (purchased) futures contracts covering 7.2 Bcf of gas extending through 2004 at a weighted average contract price of $3.71 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 received $5.4 million to terminate these futures contracts at September 30, 2002.
At September 30, 2002, the Company had short (sold) futures contracts covering 3.8 Bcf of gas extending through 2003 at a weighted average contract price of $3.68 per Mcf. Of this amount, 3.6 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 remaining 0.2 Bcf is accounted for as fair value hedges, since these contracts hedge against falling prices, a risk to which the Energy Marketing segment and All Other category are exposed on their gas storage inventory and fixed price gas purchase commitments. The Company would have had to pay $3.3 million to terminate these futures contracts at September 30, 2002.
The Company may be exposed to credit risk on some of its derivative financial instruments. 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, 2001, the Company used five counterparties for its over the counter derivative financial instruments. To further reduce credit risk, the Company increased the number of its counterparties to seven at September 30, 2002. At September 30, 2002, no individual counterparty represented greater than 25% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company's total volumes hedged).
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. 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 expects to recover substantially all 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, 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. 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.
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) 2002 2001 2000 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Benefit Obligation Benefit Obligation at Beginning of Period $580,046 $535,894 $538,796 Service Cost 11,639 11,550 11,692 Interest Cost 40,720 39,061 37,954 Amendments 420 2,343 - Actuarial (Gain) Loss 28,880 25,358 (20,216) Benefits Paid (36,235) (34,160) (32,332) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Benefit Obligation at End of Period $625,470 $580,046 $535,894 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Plan Assets Fair Value of Assets at Beginning of Period $536,625 $569,936 $537,958 Actual Return on Plan Assets (29,898) (19,248) 36,584 Employer Contribution 15,435 20,097 27,726 Benefits Paid (36,235) (34,160) (32,332) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Fair Value of Assets at End of Period $485,927 $536,625 $569,936 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Reconciliation of Funded Status Funded Status $(139,543) $(43,421) $34,042 Unrecognized Net Actuarial Loss (Gain) 132,064 23,222 (62,008) Unrecognized Transition Asset (3,716) (7,432) (11,148) Unrecognized Prior Service Cost 11,451 12,236 10,943 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Prepaid (Accrued) Benefit Cost $ 256 $(15,395) $(28,171) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Accumulated Benefit Obligation $550,099 $510,155 $464,334 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Amounts Recognized in the Balance Sheets Consist of: Prepaid Benefit Cost $ 256 $ - $ - Accrued Benefit Cost (64,428) (15,395) (28,171) Intangible Asset 11,451 - - Accumulated Other Comprehensive Loss (Pre Tax) 52,977 - - - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Net Amount Recognized $ 256 $(15,395) $(28,171) - ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
2002 2001 2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate 6.75% 7.25% 7.50%
Expected Return on Plan Assets 8.50% 8.50% 8.50%
Rate of Compensation Increase 6.11% 6.11% 5.00%
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost $11,639 $11,550 $ 11,692
Interest Cost 40,720 39,061 37,954
Expected Return on Plan Assets (48,454) (45,703) (41,077)
Amortization of Prior Service Cost 1,205 1,050 1,106
Amortization of Transition Amount (3,716) (3,716) (3,716)
Recognition of Actuarial (Gain) or Loss (1,061) (2,256) 60
Early Retirement Window - 7,337 -
Net Amortization and Deferral for
Regulatory Purposes 7,379 4,787 206
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Periodic Benefit Cost $7,712 $12,110 $ 6,225
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Other Comprehensive Loss (Pre Tax) Attributable to
Change In Additional Minimum Liability Recognition $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, 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 2002 and 2001 were to increase the Benefit Obligation by $34.0 million and $15.6 million as of the end of each period, respectively.
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) 2002 2001 2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period $304,548 $ 266,460 $ 255,615
Service Cost 4,658 4,234 4,156
Interest Cost 21,617 19,557 18,142
Plan Participants' Contributions 610 524 414
Amendments - 33 -
Actuarial (Gain) Loss 76,972 26,661 (355)
Benefits Paid (14,554) (12,921) (11,512)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Benefit Obligation at End of Period $393,851 $ 304,548 $ 266,460
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Plan Assets
Fair Value of Assets at Beginning of Period $161,959 $ 176,357 $ 149,884
Actual Return on Plan Assets (18,181) (19,685) 18,527
Employer Contribution 20,459 17,684 19,044
Plan Participants' Contributions 610 524 414
Benefits Paid (14,554) (12,921) (11,512)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Fair Value of Assets at End of Period $150,293 $ 161,959 $ 176,357
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Reconciliation of Funded Status
Funded Status $(243,558) $(142,589) $(90,103)
Unrecognized Net Actuarial (Gain) Loss 157,247 52,832 (8,676)
Unrecognized Transition Obligation 78,399 85,526 92,653
Unrecognized Prior Service Cost 30 33 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Accrued Benefit Cost $ (7,882) $ (4,198) $ (6,126)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
2002 2001 2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate 6.75% 7.25% 7.50%
Expected Return on Plan Assets 8.50% 8.50% 8.50%
Rate of Compensation Increase 6.11% 6.11% 5.00%
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost $4,658 $4,234 $4,156
Interest Cost 21,617 19,557 18,142
Expected Return on Plan Assets (13,551) (14,787) (12,574)
Amortization of Transition Obligation 7,127 7,127 7,127
Amortization of (Gain) Loss 4,289 (374) (24)
Net Amortization and Deferral for
Regulatory Purposes (729) 4,075 7,269
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Periodic Benefit Cost $23,411 $19,832 $ 24,096
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The effects of the discount rate changes in 2002 and 2001 were to increase the Benefit Obligation by $21.7 million and $9.8 million as of the end of each period, respectively.
The health care trend assumptions were changed in 2002 to better reflect anticipated future experience. The effect of the changed medical care, prescription drug and Medicare Part B assumptions was to increase the Accumulated Postretirement Benefit Obligation by $57.9 million. In 2000, the impact of changes in health care trend assumptions was an increase in the Accumulated Postretirement Benefit Obligation of $13.7 million.
The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 10.0% for 2000, 9.0% for 2001, 12% for 2002 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase for medical care benefits provided by healthcare maintenance organizations was assumed to be 10.0% in 2000, 9.0% in 2001, 12% in 2002 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 15.0% for 2000, 13.0% for 2001, 15% for 2002 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 10.0% for 2000, 9.0% for 2001, 8% for 2002 and gradually decline to 5.5% by the year 2005 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, 2002 would be increased by $58.2 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 2002 by $4.3 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2002 would be decreased by $47.8 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 2002 by $3.5 million.
Environmental Matters
The Company is subject to
various federal, state and local laws and regulations (including those of the
Czech Republic) 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 $5.1 million to $6.1 million. The minimum estimated liability of $5.1 million has been recorded on the Consolidated Balance Sheet at September 30, 2002. 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 four 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. The fourth site, which allegedly contains, among other things, manufactured gas plant waste, is in the investigation stage.
(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 $5.5 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. The majority of these contracts (representing
95% of contracted demand capacity) expire within the next five years. Costs
incurred under these contracts are purchased gas costs, subject to state
commission review, and are being recovered in customer rates. Management
believes that, to the extent any stranded pipeline costs are generated by the
unbundling of services in the Utility segment’s service territory, such
costs will be recoverable from customers.
In October 2002, the Company announced its intention to buy the Empire State Pipeline (Empire) from Duke Energy Corporation for $180.0 million in cash plus assumed debt of $60.0 million. Empire is a 157-mile, 24-inch pipeline that begins at the United States/Canadian border at the Chippawa Channel of 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 is regulated by the NYPSC. Empire can transport 525 million cubic feet of gas per day and currently 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. Empire would better position 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 Company notified the Department of Justice and Federal Trade Commission of the proposed acquisition as required under the antitrust laws, and the Company's request for early termination of the antitrust waiting period has been granted. The Company has also made a filing seeking approval of the transaction from the NYPSC. Subject to NYPSC approval, it is anticipated that the purchase will be completed in the beginning of calendar 2003.
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 I - 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 by the Federal Energy Regulatory Commission (FERC) and are carried out by Supply Corporation. 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. SIP, although not regulated itself by FERC, holds a one-third partnership interest in the Independence Pipeline Company (Independence), whose rates, services and other matters were anticipated to be regulated by FERC. As discussed in Note J - Investments in Unconsolidated Subsidiaries, SIP wrote off its investment in Independence in June 2002. As shown in the table below, this impairment amounted to $15.2 million. On September 30, 2002, Independence was dissolved.
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 Wyoming, in the Gulf Coast region of Texas and Louisiana and in the provinces of Manitoba, 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.
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.
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.
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
- -----------------------------------------------------------------------------------------------------------------------------------------
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 3,186 174,794 119 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
- -----------------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30, 2000 (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 $827,231 $ 81,434 $222,611 $104,736 $133,929 $41,545 $1,411,486 $930 $ - $1,412,416
Intersegment
Revenues 19,228 88,225 225 - - - 107,678 4,415 (112,093) -
Interest Expense 31,655 13,311 42,034 12,353 774 4,750 104,877 262 (5,054) 100,085
Depreciation,
Depletion and
Amortization 35,842 23,379 69,583 11,110 209 1,948 142,071 97 2 142,170
Income Tax
Expense 38,362 22,172 19,413 (1,783) (4,372) 3,816 77,608 (205) (335) 77,068
Segment Profit
(Loss): Net
Income 57,662 31,614 34,877 3,282 (7,790) 6,133 125,778 (371) 1,800 127,207
Expenditures for
Additions to
Long-Lived Assets 55,799 35,806(1) 280,049 9,767 89 13,542 395,052 3,725 - 398,777
At September 30, 2000 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
Segment Assets $1,233,639 $552,059 $1,088,066 $202,622 $ 47,121 $107,402 $3,230,909 $21,930 $(1,808) $3,251,031
- -----------------------------------------------------------------------------------------------------------------------------------------
(1)Amount includes $1.2 million in a stock-for-asset swap.
-------------------------------------------------------- ------------------ -------------------- --------------------
Geographic Information 2002 2001 2000
-------------------------------------------------------- ------------------ -------------------- --------------------
For the Year Ended September 30 (Thousands)
Revenues from External Customers (1):
United States $1,293,239 $1,887,958 $1,279,329
Czech Republic 95,315 97,910 104,736
Canada 75,942 73,968 28,351
-------------------------------------------------------- ------------------ -------------------- --------------------
$1,464,496 $2,059,836 $1,412,416
At September 30 (Thousands)
-------------------------------------------------------- ------------------ -------------------- --------------------
Long-Lived Assets:
United States $2,624,810 $2,645,429 $2,488,180
Czech Republic 216,044 187,961 183,274
Canada 258,196 257,939 248,937
-------------------------------------------------------- ------------------ -------------------- --------------------
$3,099,050 $3,091,329 $2,920,391
-------------------------------------------------------- ------------------ -------------------- --------------------
(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.
In June 2002, the Company wrote off its 33-1/3% equity method investment in Independence, a partnership that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania. In June 2002, Independence submitted a motion to FERC requesting that FERC vacate the certificate issued to Independence to construct, own and operate the pipeline. Independence took this action because it had been unable to obtain sufficient customer contracts to proceed with the project. In connection with this filing, the Company wrote off its $15.2 million investment in Independence. FERC formally vacated the certificate in an order issued in July 2002.
A summary of the Company's investments in unconsolidated subsidiaries at September 30, 2002 and 2001 is as follows:
---------------------------------------------------------------- --------------------- ---------------------
At September 30 (Thousands)
2002 2001
---------------------------------------------------------------- --------------------- ---------------------
ESNE $12,522 $12,950
Independence - 14,632
Seneca Energy 3,625 3,735
Model City 606 451
---------------------------------------------------------------- --------------------- ---------------------
$16,753 $31,768
---------------------------------------------------------------- --------------------- ---------------------
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.
In June 2000, the Company acquired the outstanding shares of Tri Link Resources, Ltd. (Tri Link), a Calgary, Alberta-based oil and gas exploration and production company. The cost of acquiring the outstanding shares of Tri Link was approximately $123.8 million and the acquisition was accounted for in accordance with the purchase method. Tri Link'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 15, 2000.
Details of the stock acquisitions made by the Company during 2001 and 2000 are as follows:
---------------------------------------------------------------- --------------------- ---------------------
Year Ended September 30 (Millions)
2001 2000
---------------------------------------------------------------- --------------------- ---------------------
Assets acquired $175.1 $259.9
Liabilities assumed (84.5) (136.1)
---------------------------------------------------------------- --------------------- ---------------------
Cash paid $90.6 $123.8
---------------------------------------------------------------- --------------------- ---------------------
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 (Loss)
Available
for Earnings (Loss) Per
Quarter Operating Operating Common Common Share
----------------------------------
Ended Revenues Income (Loss) Stock Basic Diluted
- --------------------- ------------------- ------------------ -------------------- ---------------- -----------------
2002 (Thousands, except per common share amounts)
- --------------------- ----------------------------------------------------------- ----------------------------------
12/31/2001 $392,327 $58,798 $33,207 $0.42 $0.41
3/31/2002 $477,436 $89,328 $61,924 $0.78 $0.77
6/30/2002 $350,123 $57,357 $17,676 (1) $0.22 $0.22
9/30/2002 $244,610 $26,507 $4,875 $0.06 $0.06
- --------------------- ----------------------------------------------------------------- ----------------------------
2001 (Thousands, except per common share amounts)
- --------------------- ----------------------------------------------------------------- ----------------------------
12/31/2000 $552,212 $ 77,335 $52 984(2) $0.67 $0.66
3/31/2001 $864,715 $103,572 $75,275(3) $0.95 $0.94
6/30/2001 $393,007 $ 60,212 $36,618 $0.46 $0.45
9/30/2001 $249,902 $(79,566) $(99,378)(4) $(1.25) $(1.24)
- --------------------- ------------------- ------------------ -------------------- ---------------- -----------------
(1) Includes expense of $9.9 million related to the impairment of investment in partnership.
(2) Includes expense of $7.5 million related to Stock Appreciation Rights (SARs), expense of $1.2 million related to early retirement offers and income of $2.6 million related to the termination of a long-term transportation contract.
(3) Includes income of $9.7 million related to SARs and expense of $4.2 million related to early retirement offers.
(4) Includes income of $5.3 million related to SARs and expense of $104.0 million related to the impairment of oil and gas assets.
At September 30, 2002, there were 20,004 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. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 2002 and 2001, are shown below:
- --------------------------------------------------------------- ------------------------------------ -----------------
Price Range Dividends
------------------------------------
Quarter Ended High Low Declared
- --------------------------------------------------------------- ------------------- ---------------- -----------------
2002
- --------------------------------------------------------------- ------------------- ---------------- -----------------
12/31/2001 $24.95 $21.95 $.2525
3/31/2002 $25.70 $22.00 $.2525
6/30/2002 $24.98 $21.38 $.260
9/30/2002 $22.84 $15.61 $.260
- --------------------------------------------------------------- ------------------- ---------------- -----------------
2001
- --------------------------------------------------------------- ------------------- ---------------- -----------------
12/31/2000 $32.25 $25.57 $.240
3/31/2001 $31.60 $25.01 $.240
6/30/2001 $28.99 $25.90 $.2525
9/30/2001 $26.38 $21.96 $.2525
- --------------------------------------------------------------- ------------------- ---------------- -----------------
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)
2002 2001
- ----------------------------------------------------------------------------------- ---------------- -----------------
Proved Properties $1,779,962 $1,586,889
Unproved Properties 50,925 152,326
- ----------------------------------------------------------------------------------- ---------------- -----------------
1,830,887 1,739,215
Less - Accumulated Depreciation, Depletion
and Amortization 776,477 675,256
- ----------------------------------------------------------------------------------- ---------------- -----------------
$1,054,410 $1,063,959
- ----------------------------------------------------------------------------------- ---------------- -----------------
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, 2002:
- ---------------------------- -------------------------- --------------------------------------------------------------
Total as of Year Costs Incurred
--------------------------------------------------------------
(Thousands) September 30, 2002 2002 2001 2000 Prior
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
Acquisition Costs $50,925 $21,170 $7,831 $10,895 $11,029
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
Proved $ 9,316 $ 1,713 $ 2,848
Unproved 698 15,296 19,066
Exploration Costs 25,583 42,338 50,163
Development Costs 51,792 88,987 72,039
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
87,389 148,334 144,116
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
Proved (536) 115,643 159,268
Unproved 2,804 2,612 77,198
Exploration Costs 8,779 8,523 573
Development Costs 15,332 36,554 11,013
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
26,379 163,332 248,052
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs: (1)
Proved 8,780 117,356 162,116
Unproved 3,502 17,908 96,264
Exploration Costs 34,362 50,861 50,736
Development Costs 67,124 125,541 83,052
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
$113,768 $311,666 $392,168
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Total proved and unproved property acquisition costs for 2001 of $135.3 million include $107.6 million related to the Player acquisition. Total proved and unproved property acquisition costs for 2000 of $258.4 million include $236.5 million related to the Tri Link acquisition.
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands, Except Per Mcfe Amounts) 2002 2001 2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates
of $43, $4 and $237, respectively) $104,954 $216,729 $137,336
Oil, Condensate and Other Liquids 101,549 121,973 107,645
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 206,503 338,702 244,981
Production/Lifting Costs 42,956 37,068 33,979
Depreciation, Depletion and Amortization
($1.25, $1.13 and $0.97 per Mcfe of production) 80,142 76,686 64,624
Income Tax Expense 30,253 83,649 52,656
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) 53,152 141,299 93,722
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas 14,621 4,379 485
Oil, Condensate and Other Liquids 56,511 74,349 26,320
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 71,132 78,728 26,805
Production/Lifting Costs 30,109 27,089 7,858
Depreciation, Depletion and Amortization
($0.93, $0.93 and $0.77 per Mcfe of production) 21,707 18,719 4,321
Impairment of Oil and Gas Producing Properties(2) - 180,781 -
Income Tax Expense (Benefit) 4,672 (63,795) 6,121
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) 14,644 (84,066) 8,505
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates
of $43, $4 and $237, respectively) 119,575 221,108 137,821
Oil, Condensate and Other Liquids 158,060 196,322 133,965
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 277,635 417,430 271,786
Production/Lifting Costs 73,065 64,157 41,837
Depreciation, Depletion and Amortization
($1.16, $1.08 and $0.95 per Mcfe of production) 101,849 95,405 68,945
Impairment of Oil and Gas Producing Properties(2) - 180,781 -
Income Tax Expense 34,925 19,854 58,777
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) $ 67,796 $ 57,233 $102,227
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Exclusive of hedging gains and losses. See further discussion in Note F - 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.
- -------------------------------------- ----------------------------------------- -----------------------------------------
Gas MMcf Oil Mbbl
----------------------------------------- -----------------------------------------
U.S. Canada Total U.S. Canada Total
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
Proved Developed and
Undeveloped Reserves:
September 30, 1999 320,792 - 320,792 75,819 - 75,819
Extensions and Discoveries 34,641 - 34,641 2,167 1,765 3,932
Revisions of
Previous Estimates (8,001) - (8,001) 4,000 - 4,000
Production (41,478) (192) (41,670) (4,248) (899) (5,147)
Sales of Minerals in Place (7,444) - (7,444) (227) - (227)
Purchases of Minerals
in Place and Other - 3,349 3,349 - 41,320 41,320
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
September 30, 2000 298,510 3,157 301,667 77,511 42,186 119,697
Extensions and Discoveries 35,960 15,681 51,641 924 3,625 4,549
Revisions of
Previous Estimates (22,813) (34) (22,847) 1,737 (5,396) (3,659)
Production (39,188) (1,816) (41,004) (4,796) (3,061) (7,857)
Sales of Minerals in Place (6,066) (280) (6,346) (685) (80) (765)
Purchases of Minerals
in Place and Other 410 38,859 39,269 104 3,259 3,363
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
September 30, 2001 266,813 55,567 322,380 74,795 40,533 115,328
Extensions and Discoveries 16,542 20,263 36,805 1,437 586 2,023
Revisions of
Previous Estimates (24,108) (20,676) (44,784) 916 (10,278) (9,362)
Production (35,067) (6,387) (41,454) (4,828) (2,834) (7,662)
Sales of Minerals in Place (14,726) - (14,726) (200) (410) (610)
Purchases of Minerals
in Place and Other - - - - - -
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
September 30, 2002 209,454 48,767 258,221 72,120 27,597 99,717
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
Proved Developed Reserves:
September 30, 1999 222,929 - 222,929 57,333 - 57,333
September 30, 2000 227,250 3,157 230,407 66,074 35,130 101,204
September 30, 2001 213,792 53,463 267,255 50,640 33,676 84,316
September 30, 2002 192,833 39,253 232,086 46,940 24,100 71,040
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)
The Company cautions that the following presentation of the standardized measure of discounted future net
cash flows is intended to be neither a measure of the fair market value of the
Company’s oil and gas properties, nor an estimate of the present value of
actual future cash flows to be obtained as a result of their development and
production. It is based upon subjective estimates of proved reserves only and
attributes no value to categories of reserves other than proved reserves, such
as probable or possible reserves, or to unproved acreage. Furthermore, it is
based on year-end prices and costs adjusted only for existing contractual
changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no
effect to future price and cost changes certain to occur under the widely
fluctuating political and economic conditions of today’s world.
The standardized measure is intended instead to provide a somewhat better means for comparing the value of the Company's proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
2002 2001 2000
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows $2,764,556 $2,127,601 $3,886,499
Less:
Future Production Costs 546,182 602,479 600,243
Future Development Costs 117,999 121,240 179,565
Future Income Tax Expense at
Applicable Statutory Rate 653,347 376,667 1,006,366
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 1,447,028 1,027,215 2,100,325
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 665,941 421,865 859,950
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows 781,087 605,350 1,240,375
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows 888,515 890,381 1,083,598
Less:
Future Production Costs 413,006 533,848 277,067
Future Development Costs 25,398 19,608 21,399
Future Income Tax Expense at
Applicable Statutory Rate 101,919 76,191 286,148
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 348,192 260,734 498,984
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 103,097 79,295 221,227
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows 245,095 181,439 277,757
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows 3,653,071 3,017,982 4,970,097
Less:
Future Production Costs 959,188 1,136,327 877,310
Future Development Costs 143,397 140,848 200,964
Future Income Tax Expense at
Applicable Statutory Rate 755,266 452,858 1,292,514
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 1,795,220 1,287,949 2,599,309
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 769,038 501,160 1,081,177
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows $1,026,182 $ 786,789 $1,518,132
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2002 2001 2000
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $605,350 $1,240,375 $707,259
Sales, Net of Production Costs (163,548) (301,634) (211,002)
Net Changes in Prices, Net of Production Costs 441,085 (921,719) 795,408
Purchases of Minerals in Place - 1,191 -
Sales of Minerals in Place (27,197) (17,552) (11,914)
Extensions and Discoveries 42,970 52,062 186,818
Changes in Estimated Future Development Costs (42,069) (3,157) (82,270)
Previously Estimated Development Costs Incurred 45,310 61,482 88,322
Net Change in Income Taxes at
Applicable Statutory Rate (126,263) 363,425 (292,371)
Revisions of Previous Quantity Estimates (32,646) (29,841) 20,736
Accretion of Discount and Other 38,095 160,718 39,389
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 781,087 605,350 1,240,375
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year 181,439 277,757 -
Sales, Net of Production Costs (41,023) (51,638) (18,948)
Net Changes in Prices, Net of Production Costs 111,148 (161,461) -
Purchases of Minerals in Place - 30,575 424,072
Sales of Minerals in Place (3,084) (761) -
Extensions and Discoveries 29,813 39,752 2,979
Changes in Estimated Future Development Costs 18,151 (31,009) -
Previously Estimated Development Costs Incurred 12,361 12,176 -
Net Change in Income Taxes at
Applicable Statutory Rate (6,910) 73,865 (150,057)
Revisions of Previous Quantity Estimates (88,571) (64,368) -
Accretion of Discount and Other 31,771 56,551 19,711
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 245,095 181,439 277,757
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year 786,789 1,518,132 707,259
Sales, Net of Production Costs (204,571) (353,272) (229,950)
Net Changes in Prices, Net of Production Costs 552,233 (1,083,180) 795,408
Purchases of Minerals in Place - 31,766 424,072
Sales of Minerals in Place (30,281) (18,313) (11,914)
Extensions and Discoveries 72,783 91,814 189,797
Changes in Estimated Future Development Costs (23,918) (34,166) (82,270)
Previously Estimated Development Costs Incurred 57,671 73,658 88,322
Net Change in Income Taxes at
Applicable Statutory Rate (133,173) 437,290 (442,428)
Revisions of Previous Quantity Estimates (121,217) (94,209) 20,736
Accretion of Discount and Other 69,866 217,269 59,100
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $1,026,182 $ 786,789 $1,518,132
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
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, 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
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 2000
Reserve for Doubtful Accounts $7,842 $15,177 $ - $11,006 $12,013
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
(1) Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate settlements.
(2) Amounts represent net accounts receivable written-off.
None
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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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 2005,” “Directors Whose Terms Expire in 2004,” “Directors Whose Terms Expire in 2003,” 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 information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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 Weighte 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 14,629,504 $22.12 942,669
security holders
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Equity compensation
plans not approved by
security holders 0 0 0
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
Total
14,629,504 $22.12 942,669
- ------------------------------ ----------------------------- ---------------------------- ----------------------------
(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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. The information concerning security ownership of certain beneficial owners is set forth in the definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
(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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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 20, 2003 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2002. 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.
PART IV
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 proceduresThe term "disclosure controls and procedures" is defined in Rules 13a-14(c) and 15d-14(c) 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 Chief Executive Officer and Treasurer have evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days before the filing of this Annual Report on Form 10-K (Evaluation Date), and, they have concluded that, as of the Evaluation Date, such controls and procedures were effective to accomplish those tasks.
Changes in internal controlsThe Company maintains a system of internal accounting controls that are 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 generally accepted accounting principles in the United States. There were no significant changes in the Company's internal controls or in other factors that could significantly affect the Company's internal controls subsequent to the Evaluation Date, nor were there any significant deficiencies or material weaknesses in the Company's internal controls.
(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 statements 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 13, 2001 (Exhibit 3.1, Form
10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880)
(4) Instruments Defining the Rights of Security Holders, Including Indentures:
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)
(10) Material Contracts:
(ii) Contracts upon which the Company's business is substantially dependent:
10.1 Credit Agreement, dated as of September 30, 2002, among the Company, the Lenders Party Thereto and JP Morgan Chase Bank,
as Administrative Agent.
(iii) Compensatory plans for officers:
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 dated September 19, 2001 in File No. 1-3880)
o Employment Agreement, dated September 17, 1981, between the Company and Bernard J. Kennedy (Exhibit 10.4, Form 10-K for
fiscal year ended September 30, 1994 in File No. 1-3880)
o Tenth Amendment to Employment Agreement between the Company and Bernard J. Kennedy,
effective September 1, 1999 (Exhibit 10.1, Form 10-K for fiscal year ended September 30,
1999 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 Smith, Ronald J. Tanski and Gerald T. Werhrlin (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
National Fuel 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)
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)
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)
10.2 Split Dollar Insurance Agreement, dated March 6, 2001, between the Company and James A. Beck.
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)
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 2002
(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 National Fuel Exploration Corp.
23.3 Consent of Ralph E. Davis Associates, Inc. regarding Player Resources Ltd.
23.4 Consent of Independent Accountants
(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 National Fuel Exploration Corp.
99.3 Report of Ralph E. Davis Associates, Inc. regarding Player Resources Ltd.
99.4 Written statements of Chief Executive Officer and Principal Financial Officer pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.5 Company Maps
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 August 14, 2002 was filed on August 14, 2002, to report a sworn statement from the principal executive and financial officers, under Item 9, “Regulation FD Disclosure.” Related exhibits were reported under Item 7, “Financial Statements and Exhibits.
A report on Form 8-K dated July 25, 2002 was filed on July 29, 2002, to report earnings for the quarter ended June 30, 2002, the participation in the drilling of a natural gas discovery and to address certain matters from the Company’s public conference call, under Item 5, “Other Events.” Related exhibits were reported under Item 7, “Financial Statements and Exhibits.
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 12, 2002
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 12, 2002
/s/ R. T. Brady Director
R. T. Brady
Date: December 12, 2002
/s/ J. V. Glynn Director
J. V. Glynn
Date: December 12, 2002
/s/ W. J. Hill Director
W. J. Hill
Date: December 12, 2002
/s/ B. J. Kennedy Director
B. J. Kennedy
Date: December 12, 2002
/s/ R. E. Kidder Director
R. E. Kidder
Date: December 12, 2002
/s/ B. S. Lee Director
B. S. Lee
Date: December 12, 2002
/s/ E. T. Mann Director
E. T. Mann
Date: December 12, 2002
/s/ G. L. Mazanec Director
G. L. Mazanec
Date: December 12, 2002
/s/ J. F. Riordan Director
J. F. Riordan
Date: December 12, 2002
/s/ J. P. Pawlowski Treasurer, Principal Financial
J. P. Pawlowski Officer and Principal Accounting Officer
Date: December 12, 2002
I, Philip C. Ackerman, certify that:
1. I have reviewed this annual report on Form 10-K of National Fuel Gas Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: December 12, 2002
/s/ Philip C. Ackerman
Philip C. AckermanI, Joseph P. Pawlowski, certify that:
1. I have reviewed this annual report on Form 10-K of National Fuel Gas Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: December 12, 2002
/s/ Joseph P. Pawlowski
Joseph P. Pawlowski