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, 2001
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. [ X ]
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $1,759,487,000 as of November 30, 2001.
Common Stock, $1 Par Value, outstanding as of November 30, 2001: 79,480,675 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Annual Report to Shareholders for 2001 are incorporated by reference into Part I of this report. Portions of the registrant's definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 21, 2002 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 Company is engaged in the business of owning and holding securities issued by its twelve directly owned subsidiary companies. Except as otherwise indicated below, the Company owns all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, 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, and by Seneca Independence Pipeline Company (SIP), a Delaware 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) 27 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. SIP holds a one-third general partnership interest in Independence Pipeline Company (Independence), a Delaware general partnership proposing to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania (the Independence Pipeline).
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 the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, and in the Appalachian region of the United States. Also, exploration and production operations are conducted in the provinces of Manitoba, Alberta and Saskatchewan in Canada by Seneca’s wholly-owned subsidiary, National Fuel Exploration Corp. (NFE), 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 assets are majority ownership of (i) United Energy, a.s. (UE), a wholesale power and district heating company located in the northern part of the Czech Republic, and (ii) Teplárna Kromìøíž, a.s. (TK), a district heating company located in the southeast region of the Czech Republic.
5. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation engaged in the marketing and brokerage of natural gas and the performance of energy management services for industrial, commercial, public authority and residential end-users in the northeastern United States.
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 four 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:
No single customer, or group of customers under common control, accounted for more than 10% of the Company's consolidated revenues in 2001.
Rates and Regulation
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The Company is subject to
regulation by the Securities and Exchange Commission (SEC) under the broad
regulatory provisions of the Holding Company Act, including provisions relating
to issuance of securities, sales and acquisitions of securities and utility
assets, intra-Company transactions and limitations on diversification. The SEC
and some members of Congress have advocated, on either a stand-alone basis or in
conjunction with legislation which would deregulate the electric industry, the
repeal of the Holding Company Act. Thus far, the proposed legislation would
transfer certain oversight responsibilities to the various state public utility
regulatory commissions and the Federal Energy Regulatory Commission (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 the FERC. SIP is not itself regulated by the FERC, but its sole business is the ownership of an interest in Independence, whose construction, rates, services and other matters are or will be regulated by the 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 regulations on various subjects as other companies doing similar business in the same locations.
The Utility
Segment
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The Utility segment
contributed approximately 35.8% of the Company’s 2001 net income available
for common stock, exclusive of the Exploration and Production segment’s
non-cash asset impairment.
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
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The Pipeline and Storage segment
contributed approximately 23.8% of the Company’s 2001 net income available
for common stock, exclusive of the Exploration and Production segment’s
non-cash asset impairment.
Supply Corporation currently has service agreements for substantially all of its firm transportation capacity, which totals approximately 2,036 thousand dekatherms (MDth) per day. The Utility segment accounts for approximately 1,179 MDth per day or 57.9% of the total capacity, and the Energy Marketing segment represents another 70 MDth per day or 3.5% of the total capacity. The remaining 787 MDth or 38.6% of Supply Corporation's firm transportation capacity is subject to firm contracts with nonaffiliated customers.
Supply Corporation has available for sale approximately 67,843 MDth of firm storage capacity. The Utility segment has contracted for 31,395 MDth or 46.3% of the total capacity and the Energy Marketing segment accounts for another 4,305 MDth or 6.3% of the total capacity. Nonaffiliated customers have contracted for the remaining 32,143 MDth or 47.4% 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
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The Exploration and
Production segment contributed approximately 42.3% of the Company’s 2001
net income available for common stock, exclusive of this segment’s non-cash
asset impairment.
In June 2001, Seneca, through its wholly-owned subsidiary, NFE, acquired the stock of Player Petroleum Corporation (Player), an oil and gas exploration and development company, with operations based primarily in the Province of Alberta, Canada.
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
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The International segment
incurred a net loss in 2001. The impact of this segment’s net loss in
relation to the Company’s 2001 net income available for common stock,
exclusive of the Exploration and Production segment’s non-cash asset
impairment, was negative 1.8%.
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
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The Energy Marketing
segment incurred a net loss in 2001. The impact of this segment’s net loss
in relation to the Company’s 2001 net income available for common stock,
exclusive of the Exploration and Production segment’s non-cash asset
impairment, was negative 2.0%.
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
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The Timber segment
contributed approximately 4.6% of the Company’s 2001 net income available
for common stock, exclusive of the Exploration and Production segment’s
non-cash asset impairment.
Additional discussion of the Timber segment appears below under the headings "Sources and Availability of Raw Materials," "Competition" and "Seasonality," in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
All Other
Category and Corporate Operations
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The All Other category and
Corporate operations incurred a net loss in 2001. The impact of this net loss in
relation to the Company’s 2001 net income available for common stock,
exclusive of the Exploration and Production segment’s non-cash asset
impairment, was 2.7%.
Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A.
Sources and
Availability of Raw Materials
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Natural gas is the
principal raw material for the Utility segment. In 2001, the Utility segment
purchased 117.3 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 63% of these purchases.
Purchases of gas on the spot market (contracts of less than a year) accounted
for 34% of the Utility segment’s 2001 gas purchases. Gas purchases from
Dynegy Marketing and Trade and BP Energy Co. (both providing gas from the
southwestern United States under long-term contracts) represented 23% and
13%, respectively, of total 2001 gas purchases by the Utility segment. No
other producer or marketer provided the Utility segment with 10% or more of its
gas requirements in 2001.
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. SIP, through Independence, proposes to transport natural gas produced in Canada and in the continental United States. Additional discussion of proposed pipeline projects appears below in Item 7, MD&A.
The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Notes I-Business Segment Information and M - Supplementary Information for Oil and Gas Producing Activities.
Coal is the principal raw material for the International segment, constituting 50% of the cost of raw materials needed in 2001 to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined accounted for the remaining 50% of such materials. Coal is purchased and delivered directly from the Mostecka Uhelna Spolecnost, a.s. mine for Horizon's largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. Based on the current extraction rate, 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 its majority-owned Transgas pipeline system. The International segment purchases natural gas from two 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 2001, this segment purchased 39.7 Bcf of natural gas.
Competition
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Competition in the natural
gas industry exists among providers of natural gas, as well as between natural
gas and other sources of energy. The continuing deregulation of the natural gas
industry should enhance the competitive position of natural gas relative to
other energy sources, 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.* Moreover, while
demand for natural gas is increasing, the production of natural gas also
continues to increase making it a dependable alternative to imported oil.*
The electric industry is moving toward a more competitive environment as a result of the Federal Energy Policy Act of 1992 and initiatives undertaken by the FERC and various states. It is unclear at this point what impact this restructuring will have on the Company.*
The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this "Competition" heading, do not compete with the Company to any significant extent.*
Competition:
The Utility Segment
The changes precipitated by
the FERC’s restructuring of the gas industry in Order No. 636 are
redefining the roles of the gas utility industry and the state regulatory
commissions. Regulators in both New York and Pennsylvania have adopted retail
competition 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.*
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 growing markets in the northeast and mid-Atlantic regions of the United States. Similarly, SIP, through Independence, is competing for customers with other proposed pipeline projects that would bring natural gas from the Chicago area to the northeast and mid-Atlantic regions of the United States. In combination with expansion projects of Transcontinental Gas Pipe Line Corporation and ANR Pipeline Company, Independence intends to provide a service that will access the storage and market hub at Leidy, Pennsylvania.* 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 Independence Pipeline and the Northwinds Pipeline would likely create opportunities for increased transportation and storage services by Supply Corporation.* For further discussion of the Independence Pipeline and 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 subsidiary, NFE, 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 and/or acquire foreign and domestic energy projects.
Horizon, through UE, faces competition in the sale of thermal energy to large
industrial customers. In addition, UE faces competition in the sale of
electricity to the regional electric distribution company. A large percentage of
the electricity purchased by the regional electric distribution companies is
produced by the Czech Republic’s dominant state-owned energy producer. The
Czech cabinet approved a plan put forward by the Ministry of Industry and Trade
to privatize this producer and six regional electricity distributors. It is
unclear at this point what impact this privatization will have on the wholesale
electric energy market.* 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 and derives 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, saw logs or export logs
ultimately used in the production of high-end furniture, cabinetry and flooring.
The Timber segment markets its products both nationally and internationally.
Seasonality
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Variations in weather
conditions can materially affect the volume of gas delivered by the Utility
segment, as virtually all of its residential and commercial customers use gas
for space heating. The effect on the Utility segment in New York is mitigated by
a weather normalization clause which is designed to adjust the rates of retail
customers to reflect the impact of deviations from normal weather. Weather that
is more than 2.2% warmer than normal results in a surcharge being added to
customers’ current bills, while weather that is more than 2.2% colder than
normal results in a refund being credited to customers’ current bills.
Volumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its earnings. 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.
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.
Capital
Expenditures
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A discussion of capital
expenditures by business segment is included in Item 7, MD&A under the
heading “Investing Cash Flow.”
Environmental
Matters
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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.
Miscellaneous
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The Company and its
wholly-owned subsidiaries had a total of 3,235 full-time employees at September
30, 2001, with 2,244 employees in all of its U.S. operations and 991 employees
in its international operations. This is a decrease of 10% from the 3,597
total employed at September 30, 2000.
Agreements covering employees in collective bargaining units in New York were renegotiated in November 2000, effective beginning November 26, 2000, and are scheduled to expire in February 2006. Agreements covering most employees in collective bargaining units in Pennsylvania were renegotiated, effective November 1998, and are scheduled to expire in April and May 2003.
The Company 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 Company renews such franchises.
Executive Officers of the Company as of November 15, 2001(1)
Back to Table of ContentsOn September 19, 2001, the Board of Directors elected Philip C. Ackerman as Chief Executive Officer of the Company, effective October 1, 2001. Mr. Ackerman joined the Company in 1968 and has served as President since July 1999, as a Director since 1994 and as Chief Financial Officer since 1981. Mr. Ackerman succeeds Bernard J. Kennedy as Chief Executive Officer. Mr. Kennedy will continue to serve as Chairman of the Board of Directors through January 2, 2002 and as a Director thereafter. Mr. Kennedy has also agreed to serve as a consultant to the Company for 30 months commencing January 2, 2002. On December 13, 2001, the Board of Directors elected Philip C. Ackerman as Chairman of the Board effective January 3, 2002.
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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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Bernard J. Kennedy Chairman of the Board of Directors since March 1989. Mr. Kennedy has served
(70) as a Director since March 1978 and previously served as Chief Executive
Officer from August 1988 to October 2001 and as President from January 1987
to July 1999.
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Philip C. Ackerman Chief Executive Officer since October 2001; President since July 1999;
(57) Executive Vice President of Supply Corporation since October 1994; 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. Mr. Seeley has served as
(58) Vice President of the Company from January 2000 to April 2000, Senior Vice
President of Distribution Corporation from February 1997 to March 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. Mr. Smith served as
(48) 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
(54) 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;
(63) 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
(52) 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
(60) Corporation 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
(60) Senior 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
(48) 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;
(49) Controller of Distribution Corporation since February 1997; Secretary and
Treasurer of Horizon since February 1997; and Vice President of Distribution
Corporation from April 1993 to July 2001.
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John R. Pustulka Senior Vice President of Supply Corporation since July 2001; and Vice
(49) President of Supply Corporation from April 1993 to July 2001.
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James D. Ramsdell Senior Vice President of Distribution Corporation since July 2001; and Vice
(46) 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, 2001.
(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.
Back to Table of ContentsGeneral
Information on Facilities
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The investment of the
Company in net property, plant and equipment was $2.8 billion at September 30,
2001. 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 (39%), is primarily
located in the Gulf Coast region of Texas and Louisiana, in California, in
Wyoming, in the Appalachian region of the United States and in the provinces of
Manitoba, Alberta and Saskatchewan in Canada. The remaining investment in net
property, plant and equipment consisted primarily of the International segment
(6%) 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 expand and improve transmission and distribution facilities for both retail
and transportation customers, to augment the reserve base of oil and gas in the
United States and Canada, and to purchase district heating and power generation
facilities in the Czech Republic. Net property, plant and equipment has
increased $1.071 billion, or 63%, since 1996.
The Utility segment had a net investment in property, plant and equipment of $945.7 million at September 30, 2001. The net investment in its gas distribution network (including 14,778 miles of distribution pipeline) and its services represent approximately 57% and 29%, respectively, of the Utility segment's net investment in property, plant and equipment at September 30, 2001.
The Pipeline and Storage segment had a net investment of $483.2 million in property, plant and equipment at September 30, 2001. Transmission pipeline, with a net cost of $138.1 million, represents 29% of this segment's total net investment and includes 2,543 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 31 storage fields, four of which are jointly operated with certain pipeline suppliers, and 446 miles of pipeline. Net investment in storage facilities includes $87.2 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 75,006 installed compressor horsepower.
The Exploration and Production segment had a net investment in property, plant and equipment of $1.082 billion at September 30, 2001. Of this amount, $828.3 million relates to properties located in the United States. The remaining net investment of $253.4 million relates to properties located in Canada.
The International segment had a net investment in property, plant and equipment of $178.2 million at September 30, 2001. 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 $90.5 million at September 30, 2001. Located primarily in northwestern Pennsylvania, the net investment includes four sawmills and approximately 150,000 acres of timber.
The Utility and Pipeline and Storage segments' facilities provided the capacity to meet its 2001 peak day sendout, including transportation service, of 1,659 million cubic feet (MMcf), which occurred on December 22, 2000. Withdrawals from storage of 749.4 MMcf provided approximately 45.2% of the requirements on that day.
Company maps are included on the back of the front cover and page 1 of the Annual Report to Shareholders and are incorporated herein by reference.
Exploration
and Production Activities
Back to Table of Contents
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 M-Supplementary Information
for Oil and Gas Producing Activities. Note M sets forth proved developed and
undeveloped reserve information for Seneca. Seneca’s oil and gas reserves
reported in Note M as of September 30, 2001 were estimated by Seneca’s
qualified 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 M.
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.
- ---------------------------------------------------------------- ----------------- ---------------- ----------------- For the Year Ended September 30 2001 2000 1999 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- United States Average Sales Price per Mcf of Gas(1) $5.53 $3.31 $2.20 Average Sales Price per Barrel of Oil(1) $25.43 $25.34 $12.85 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.55 $0.51 $0.46 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Canada Average Sales Price per Mcf of Gas(1) $2.41 $2.52 - Average Sales Price per Barrel of Oil(1) $24.29 $29.28 - Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.34 $1.41 - - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Average Sales Price per Mcf of Gas(1) $5.39 $3.31 $2.20 Average Sales Price per Barrel of Oil(1) $24.99 $26.03 $12.85 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.73 $0.58 $0.46 - ---------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Prices do not reflect gains or losses from hedging activities.
- --------------------------------------- ------------------------ -------------------------- -------------------------
At September 30, 2001 United States Canada Total
- --------------------------------------- ------------------------ -------------------------- -------------------------
Gas Oil Gas Oil Gas Oil
Productive Wells - gross 1,964 950 188 979 2,152 1,929
- net 1,815 875 121 833 1,936 1,708
- --------------------------- ----------- ----------- ------------ ------------ ------------- ------------ ------------
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------
At September 30, 2001 United States Canada Total
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------
Developed Acreage - gross 646,957 152,491 799,448
- net 568,652 104,206 672,858
Undeveloped Acreage - gross 926,022 981,065 1,907,087
- net 669,250 929,460 1,598,710
- ----------------------------------------------- ---------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------------------------------------------------------------
Productive Dry
--------------------------------------------------------------
For the Year Ended September 30 2001 2000 1999 2001 2000 1999
--------------------------------------------------------------
United States
Net Wells Completed - Exploratory 11.83 13.89 12.95 4.93 6.53 5.64
- Development 108.60 82.82 95.26 1.00 1.00 4.75
- ----------------------------------------------------------------------------------------------------------------------
Canada
Net Wells Completed - Exploratory 10.00 1.00 - 11.00 - -
- Development 61.14 21.50 - 2.75 4.00 -
- ----------------------------------------------------------------------------------------------------------------------
Total
Net Wells Completed - Exploratory 21.83 14.89 12.95 15.93 6.53 5.64
- Development 169.74 104.32 95.26 3.75 5.00 4.75
- ----------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
At September 30, 2001 United States Canada Total
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
Wells in Process of Drilling - gross 61.00 46.00 107.00
- net 56.90 42.15 99.05
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
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 19 injection wells and 89 production wells in the
program. The total injection and production from this waterflood project are
2,400 barrels of water per day and 260 barrels of oil per day, respectively.
No matter was submitted to a vote of security holders during the fourth quarter of 2001.
PART II
Information regarding the market for the Company’s common stock and related shareholder matters appears under Item 8 at Note D-Capitalization and Note L-Market for Common Stock and Related Shareholder Matters (unaudited).
On July 2, 2001, the Company issued 1,680 unregistered shares of Company common stock to the seven non-employee directors of the Company, 240 shares to each such director. These shares were issued as partial consideration for the directors' service as directors during the quarter ended September 30, 2001, 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 any public offering.
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30 2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
Summary of Operations (Thousands)
Operating Revenues $2,100,352 $1,425,277 $1,263,274 $1,248,000 $1,265,812
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Purchased Gas 1,045,805 503,617 405,925 441,746 528,610
Fuel Used in Heat and
Electric Generation 54,968 54,893 55,788 37,837 1,489
Operation and Maintenance 364,318 350,383 328,800 321,411 286,537
Property, Franchise and Other Taxes 83,730 78,878 91,146 92,817 100,549
Depreciation, Depletion and
Amortization 174,914 142,170 124,778 117,238 111,650
Impairment of Oil and Gas
Producing Properties 180,781 - - 128,996 -
Income Taxes 37,106 77,068 64,829 24,024 68,674
- ----------------------------------------------------------------------------------------------------------------------------------
1,941,622 1,207,009 1,071,266 1,164,069 1,097,509
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 158,730 218,268 192,008 83,931 168,303
Other Income 15,256 10,408 12,343 35,870 3,196
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 173,986 228,676 204,351 119,801 171,499
Interest Charges 107,145 100,085 87,698 85,284 56,811
- ----------------------------------------------------------------------------------------------------------------------------------
Minority Interest in Foreign Subsidiaries (1,342) (1,384) (1,616) (2,213) -
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect 65,499 127,207 115,037 32,304 114,688
Cumulative Effect of Change in
Accounting - - - (9,116) -
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income Available for Common
Stock $65,499 $127,207 $115,037 $23,188 $114,688
- ----------------------------------------------------------------------------------------------------------------------------------
Per Common Share Data(3)
Basic Earnings per Common Share $0.83(1) $1.63 $1.49 $0.30(2) $1.51
Diluted Earnings per Common Share $0.82(1) $1.61 $1.47 $0.30(2) $1.49
Dividends Declared $0.99 $0.95 $0.92 $0.89 $0.86
Dividends Paid $0.97 $0.94 $0.91 $0.88 $0.85
Dividend Rate at Year-End $1.01 $0.96 $0.93 $0.90 $0.87
At September 30:
Number of Common Shareholders 20,345 21,164 22,336 23,743 20,267
- ----------------------------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment (Thousands)
Utility $945,693 $939,753 $919,642 $906,754 $889,216
Pipeline and Storage 483,222 474,972 466,524 460,952 450,865
Exploration and Production 1,081,622 998,852 674,813 638,886 443,164
International 178,250 172,602 210,920 202,590 942
Energy Marketing 262 360 489 353 123
Timber 90,453 95,607 88,623 38,593 34,872
All Other 1,209 1,241 214 - 173
Corporate 2 4 7 9 11
- ----------------------------------------------------------------------------------------------------------------------------------
Total Net Plant $2,780,713 $2,683,391 $2,361,232 $2,248,137 $1,819,366
- ----------------------------------------------------------------------------------------------------------------------------------
Total Assets (Thousands) $3,445,566 $3,251,031 $2,842,586 $2,684,459 $2,267,331
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (Thousands)
Comprehensive Shareholders' Equity $1,002,655 $ 987,437 $ 939,293 $ 890,085 $ 913,704
Long-Term Debt, Net of Current Portion 1,046,694 953,622 822,743 693,021 581,640
Total Capitalization $2,049,349 $1,941,059 $1,762,036 $1,583,106 $1,495,344
- ----------------------------------------------------------------------------------------------------------------------------------
(1)
2001 includes oil and gas asset impairment of ($1.32) basic, ($1.29) diluted.
Refer to further discussion of these items in Notes to Financial Statements,
Note A - Summary of Significant Accounting Policies.
(2) 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.
(3) Per Common Share Data reflects two-for-one stock split on September 7, 2001.
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. These 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), which is discussed below. Without this non-cash asset
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). This compares with
2000 earnings of $127.2 million, or $1.63 per common share ($1.61 per common
share on a diluted basis). The increase in earnings of $42.3 million (exclusive
of the non-cash impairment) was the result of higher earnings in the Exploration
and Production, Utility, Pipeline and Storage, and Timber segments. Earnings
were also positively impacted by a lower loss in the Energy Marketing segment.
These higher earnings were offset by losses in 2001 in the International segment
and Corporate operations compared to net income for this segment and these
operations in 2000. Furthermore, the All Other category experienced an increased
loss in 2001 compared to 2000. The higher loss in the All Other category
resulted primarily from a natural gas inventory write-down by Upstate Energy
Inc. (Upstate), the Company’s wholly-owned subsidiary which is primarily
engaged in wholesale natural gas marketing. Additional discussion of earnings in
each of the business segments can be found in the business segment information
that follows.
Discussion of
Asset Impairment
Seneca, which follows the full-cost
method of accounting for its oil and gas operations, is required to perform a
quarterly “ceiling test.” Under the ceiling test, the present value of
future revenues from Seneca’s oil and gas reserves is compared (on a
country by country basis) with the book value of those reserves at the balance
sheet date. If the book value of the reserves in any country exceeds the present
value of the associated future revenues, a non-cash charge must be recorded to
write down the book value of the reserves to their present value. As a result of
low oil and gas prices at September 30, 2001, Seneca was required to recognize a
non-cash impairment relating to its Canadian properties of $180.8 million (pre
tax) or $104.0 million (after tax) for the quarter ended September 30, 2001.
2000 Compared
with 1999
The Company’s earnings
were $127.2 million, or $1.63 per common share ($1.61 per common share on a
diluted basis) in 2000. This compares with 1999 earnings of $115.0 million, or
$1.49 per common share ($1.47 per common share on a diluted basis). The increase
in earnings of $12.2 million was the result of higher earnings in the
Exploration and Production, Utility, Timber and International segments. These
higher earnings were offset in part by lower earnings in the Pipeline and
Storage segment, the Energy Marketing segment (which had a loss for the year)
and in Corporate operations. Additional discussion of earnings in each of the
business segments can be found in the business segment information that follows.
- ---------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 (Thousands) 2001 2000 1999 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Utility $60,707 $57,662 $56,875 Pipeline and Storage 40,377 31,614 39,765 Exploration and Production (1) (32,284) 34,877 7,127 International (3,042) 3,282 2,276 Energy Marketing (3,432) (7,790) 2,054 Timber 7,715 6,133 4,769 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Reportable Segments 70,041 125,778 112,866 All Other (4,277) (371) (162) Corporate (265) 1,800 2,333 - ---------------------------------------------------------------- ----------------- ---------------- ----------------- Total Consolidated (1) $65,499 $127,207 $115,037 - ---------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Exclusive of the non-cash asset impairment, 2001 earnings for the Exploration and Production segment and Total Consolidated would have been $71,756 and $169,539, respectively.
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Retail Revenues:
Residential $ 875,050 $ 584,618 $ 581,022
Commercial 154,266 93,914 101,482
Industrial 29,110 21,543 15,903
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
1,058,426 700,075 698,407
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Off-System Sales 84,078 47,962 29,214
Transportation 89,037 104,534 77,600
Other 3,106 (6,112) 2,134
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$1,234,647 $ 846,459 $ 807,355
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2001 2000 1999
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Retail Sales:
Residential 73,530 68,196 71,177
Commercial 13,831 12,312 13,885
Industrial 4,089 4,276 4,144
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
91,450 84,784 89,206
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Off-System Sales 12,736 12,833 12,469
Transportation 66,283 71,862 64,086
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
170,469 169,479 165,761
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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 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 (gas costs are recovered dollar for dollar in revenues) 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. However, due to profit sharing with retail customers, the margins resulting from off-system sales were minimal. The decrease in transportation revenues and volumes was primarily due to residential transportation customers switching back to retail sales customers and the fact that certain commercial and industrial customers were reducing usage due to a slowing economy and/or 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 (O&M) expense in 2000). These revenue reductions related to the September 30, 2000 conclusion of the 1998 two-year rate settlement approved by the State of New York Public Service Commission (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 relates to the current three-year rate settlement approved by the NYPSC in October 2000. The final refund for the current settlement will not be known until 2003.
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 current three-year rate settlement approved by the NYPSC. 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.
2000 Compared
with 1999
Operating revenues for the
Utility segment increased $39.1 million in 2000 compared with 1999. This
resulted from an increase in retail, off-system, and transportation gas sales
revenues of $1.7 million, $18.7 million, and $26.9 million, respectively. These
increases were partly offset by a decrease in other operating revenues of $8.2
million.
The increase in retail gas revenues for the Utility segment was primarily due to the recovery of higher gas costs, offset by a decrease in the volumes sold. 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 decrease in retail sales volumes was primarily the result of the migration of residential and small commercial customers to transportation service in both the New York and Pennsylvania jurisdictions, offset slightly by the impact of colder weather. Transportation revenues increased and volumes were up 7.8 billion cubic feet (Bcf) as a result of the migration noted above as well as the slightly colder weather. Off-system sales revenues increased largely due to increased gas prices and slightly higher volumes.
The decrease in other operating revenues of $8.2 million was largely due to $18.2 million of various revenue reductions ($9.7 million of which was offset by lower O&M expense) related to the September 30, 2000 conclusion of the 1998 two-year rate settlement approved by the NYPSC. Partly offsetting these decreases was the gas restructuring reserve which reduced revenues by $7.2 million in 1999. This special reserve, which did not recur in 2000, put aside dollars to be applied against incremental costs that could result from the NYPSC's gas restructuring efforts and was required in 1999 by the terms of the rate settlement with the NYPSC. The NYPSC's gas restructuring efforts are further discussed in the "Rate Matters" section that follows.
2001 Compared
with 2000
In the Utility segment,
2001 earnings were $60.7 million, up $3.0 million from the prior year. Items
increasing earnings from the prior year include a $6.1 million (after tax)
reduction in O&M expense representing the Utility segment’s portion of
the year-to-year change in the Company’s stock appreciation right (SAR)
expense, as discussed below, and the non-recurrence of $2.2 million (after tax)
of revenue adjustments recorded in 2000 related to the conclusion of the 1998
two-year rate settlement, as discussed in the revenue section above. Colder
weather in the Utility segment’s Pennsylvania jurisdiction also increased
earnings by $3.1 million (after tax), as discussed below. Furthermore, the lower
provision for refund in 2001 as compared to 2000, as discussed in the revenue
section above, had a positive contribution to earnings of $2.3 million (after
tax). These items were offset by a $10.0 million rate decrease ($6.5 million
after tax) in the Utility segment’s New York jurisdiction, as previously
discussed. Also, the Utility segment recorded an early retirement expense in its
Pennsylvania jurisdiction ($0.6 million after tax) during the first quarter of
2001 and an early retirement expense in its New York jurisdiction ($3.6 million
after tax) during the second quarter of 2001.
The decrease in the market price of the Company's common stock during 2001 carried with it a reduction in the Company's SAR liability. This reduction is spread across all segments, with the greatest impact on the Pipeline and Storage, Utility and Exploration and Production segments. For 2001, the Company experienced a reduction in its SAR liability (reflected through lower total Company O&M expense of $8.9 million after tax) as the market price of the Company's common stock decreased from September 30, 2000 ($28.03 per common share) to September 30, 2001 ($23.03 per common share). For 2000, the Company experienced an increase in its SAR liability (reflected through higher total Company O&M expense of $9.2 million after tax) as the market price of the Company's common stock increased from September 30, 1999 ($23.59 per common share) to September 30, 2000 ($28.03 per common share).
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 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. Since the Pennsylvania jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, weather during 2001 was 12.3% colder than 2000 and 2.8% colder than normal.
2000 Compared
with 1999
In the Utility segment,
2000 earnings were $57.7 million, up $0.8 million from 1999. The increase in
earnings resulted primarily from two items in 1999 (expenses related to an early
retirement offer of $3.7 million (after tax) and a special reserve for gas
restructuring of $4.7 million (after tax) which did not recur in 2000). These
items were offset by an increase in the Utility segment’s portion of the
Company’s SAR expense, reflected through higher O&M expense of $2.9
million (after tax), as discussed above, and revenue adjustments of $5.5 million
(after tax), as discussed in the revenue section above.
In 2000, the WNC in New York preserved earnings of approximately $8.1 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 1999 through May 2000. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, since weather in 2000 was only 0.9% colder than 1999, no significant earnings variances occurred.
- ---------------------------------- -------------- -------------- -------------------- --------------------------------
Percent (Warmer)
Colder Than
--------------------------------
Year Ended September 30 Normal Actual Normal Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
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%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
1999: Buffalo 6,848 6,179 (9.8%) 4.5%
Erie 6,223 5,607 (9.9%) 4.0%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Purchased Gas
The cost of purchased gas
is currently 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 $7.35 per thousand cubic feet (Mcf) in 2001, an increase of 49% from the average cost of $4.93 per Mcf in 2000. The average cost of purchased gas in 2000 was 29% higher than the $3.82 per Mcf in 1999.
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation $91,611 $92,305 $91,279
Interruptible Transportation 1,917 1,578 856
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
93,528 93,883 92,135
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Storage Service 61,559 62,899 63,655
Interruptible Storage Service 670 287 173
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
62,229 63,186 63,828
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Other 15,334 12,590 12,820
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$171,091 $169,659 $168,783
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2001 2000 1999
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation 304,183 291,818 300,242
Interruptible Transportation 17,372 21,730 8,061
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
321,555 313,548 308,303
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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 (SFV)
rate design.
2000 Compared
with 1999
Operating revenues
increased $0.9 million in 2000 compared with 1999. The increase resulted
primarily from higher firm transportation revenue of $1.0 million and higher
interruptible transportation and interruptible storage service revenues of $0.8
million, offset by lower firm storage service revenue of $0.8 million. The
increase in firm transportation revenues resulted primarily from a $1.3 million
“pass-through” type item (which did not recur in 2000) that reduced
revenues in the prior year and correspondingly reduced O&M expense in the
prior year, thus having no earnings impact. The increase in interruptible
transportation and interruptible storage service revenues is principally the
result of higher throughput volumes. The decrease in firm storage service
revenue was the result of discounted storage service rates, as well as the loss
of certain storage service customers. Transportation volumes in this segment
increased 5.2 Bcf. Generally, volume fluctuations do not have a significant
impact on revenues as a result of Supply Corporation’s SFV rate design.
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. This increase in earnings is attributable
to an $8.8 million (after tax) reduction in O&M expenses associated with the
Pipeline and Storage segment’s portion of the year-to-year change in the
Company’s SAR expense, as previously discussed. Also, there was a $1.3
million (after tax) increase in revenues from unbundled pipeline sales and open
access transportation. The increase in earnings is also attributable to the
buy-out by a customer of a long-term transportation contract ($2.6 million after
tax) during the first quarter of 2001. The resulting gain from this buy-out was
recorded in other income. As a partial offset to these earnings increases, this
segment recorded early retirement expenses of $1.2 million (after tax) in the
first and second quarters of 2001. This segment also recorded additional
executive retirement benefit expenses of $2.1 million (after tax) in 2001.
2000 Compared
with 1999
Earnings in the Pipeline
and Storage segment decreased $8.2 million in 2000 compared with 1999. In 2000,
increased O&M expenses of $4.6 million (after tax) associated with the
Pipeline and Storage segment’s portion of the year-to-year change in the
Company’s SAR expense, as previously discussed, and the addition of $1.1
million of New York State income tax, resulting from a change in the tax laws in
New York State, contributed to the decrease in earnings. The Federal Energy
Regulatory Commission (FERC), which regulates this segment, has not provided for
the recovery of additional taxes as has the New York Department of Public
Service. Several items in 1999, which did not recur in 2000, also contributed to
2000 earnings being less than 1999 earnings. The 1999 earnings included interest
income of $1.2 million (after tax) and a reduction in income tax of $1.7 million
related to the final settlement of IRS audits of years 1977-1994. In addition,
1999 included the recovery of $0.5 million (after tax) of costs related to a
gathering project that had been previously reserved for and the recovery,
through insurance, of $0.4 million (after tax) of a previously expensed base gas
loss. These items were offset in part by a charge in 1999 for an early
retirement of $0.9 million (after tax).
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Gas (after Hedging) $171,045 $108,832 $83,229
Oil (after Hedging) 169,613 117,606 52,050
Gas Processing Plant 39,986 17,666 11,751
Other 17,700 (6,034) (36)
- --------------------------------------------------------------- ----------------- ---------------- -----------------
$398,344 $238,070 $146,994
- --------------------------------------------------------------- ----------------- ---------------- -----------------
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 2001 2000 1999
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Gas Production (MMcf)
Gulf Coast 30,663 32,760 28,758
West Coast 4,383 4,374 3,977
Appalachia 4,142 4,344 4,431
Canada 1,816 192 -
- --------------------------------------------------------------- ----------------- ---------------- -----------------
41,004 41,670 37,166
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Oil Production (thousands of barrels)(Mbbl)
Gulf Coast 1,914 1,415 1,373
West Coast 2,875 2,824 2,633
Appalachia 7 9 10
Canada 3,061 899 -
- --------------------------------------------------------------- ----------------- ---------------- -----------------
7,857 5,147 4,016
- --------------------------------------------------------------- ----------------- ---------------- -----------------
- --------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 2001 2000 1999 - --------------------------------------------------------------- ----------------- ---------------- ----------------- Average Gas Price/Mcf Gulf Coast $4.93 $3.29 $2.15 West Coast $10.18 $3.62 $2.28 Appalachia $5.03 $3.16 $2.44 Canada $2.41 $2.52 - Weighted Average $5.39 $3.31 $2.20 Weighted Average After Hedging(1) $4.17 $2.61 $2.24 Average Oil Price/barrel (bbl) Gulf Coast $27.47 $28.27 $15.18 West Coast(2) $24.06 $23.87 $11.62 Appalachia $28.51 $25.12 $14.73 Canada $24.29 $29.28 - Weighted Average $24.99 $26.03 $12.85 Weighted Average After Hedging(1) $21.59 $22.85 $12.96 - --------------------------------------------------------------- ----------------- ---------------- -----------------
(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.
2001 Compared
with 2000
Operating revenues for the
Exploration and Production segment increased $160.3 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 Canadian properties
acquired in June 2001 (i.e., the Player Petroleum Corp. acquisition) (Player)
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 in June 2000. 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 and other revenue adjustments related to derivative financial
instruments. Refer to further discussion of derivative financial instruments
under the heading “Market Risk Sensitive Instruments” that follows.
2000 Compared
with 1999
Operating revenues
increased $91.1 million in 2000 compared with 1999. Oil production revenues
after hedging increased $65.6 million as the weighted average price of oil after
hedging increased 76% and oil production increased 28% from 1999 compared to
2000. Oil production from Canadian wells acquired as part of the June 2000
acquisition of Tri Link Resources, Ltd. (Tri Link) added $26.3 million to oil
revenues. Gas production revenues after hedging increased $25.6 million as gas
production increased 12% and the weighted average price of gas after hedging
increased 17%. Revenue from Seneca’s gas processing plant was up $5.9
million. These items were partly offset by a $6.0 million decrease in other
revenues resulting primarily from mark-to-market and other revenue adjustments
related to written options.
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 of this segment’s Canadian oil
and gas assets, as previously discussed, 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 Canadian properties acquired 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 (G&A) increased
in total, largely due to the Player and Tri Link acquisitions, offset by the
impact of the Exploration and Production segment’s portion of the
year-to-year change in the Company’s SAR expense, as previously discussed.
Greater interest expense due to higher borrowings related to the Player and Tri
Link acquisitions also partially offset the positive impact of higher revenues.
2000 Compared
with 1999
In the Exploration and
Production segment, 2000 earnings of $34.9 million were up $27.8 million when
compared with 1999. The Canadian properties acquired in June 2000 added $6.4
million to 2000 earnings. As discussed above, significant improvement in oil and
gas pricing, combined with an increase in production, were the main reasons for
higher earnings. Partly offsetting higher revenues was an increase in
production-related expenses, including higher depletion, an increase in lease
operating costs, and higher production taxes. In addition, G&A was up as a
result of higher costs associated with labor and benefits (including SAR
expense), and interest expense increased due to higher borrowings related to the
acquisition of Tri Link. The increase in the gas processing plant revenue of
$5.9 million was offset by an equal amount of related expense.
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Heating $69,072 $69,387 $71,974
Electricity 26,398 31,426 34,158
Other 2,440 3,923 913
- --------------------------------------------------------------- ----------------- ---------------- -----------------
$97,910 $104,736 $107,045
- --------------------------------------------------------------- ----------------- ---------------- -----------------
- --------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 2001 2000 1999 - --------------------------------------------------------------- ----------------- ---------------- ----------------- Heating Sales (Gigajoules) (1) 9,978,118 10,222,024 10,047,042 Electricity Sales (megawatt hours) 1,019,901 1,147,303 1,138,980 - --------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Gigajoules = one billion joules. A joule is a unit of energy.
2001 Compared
with 2000
Operating revenues
decreased $6.8 million in 2001 compared with 2000. The revenue decrease largely
reflects a decrease in the average value of the Czech koruna (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 are actually up
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.
2000 Compared
with 1999
Operating revenues
decreased $2.3 million in 2000 compared with 1999. The decrease in revenues is
largely due to the decrease in value of the CZK as compared to the U.S. dollar.
While higher heating and electricity sales contributed to higher operating
revenues (in CZK), the decrease in value of the CZK caused an overall decrease
in revenues when translated into U.S. dollars.
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, are 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.
2000 Compared
with 1999
The International
segment’s 2000 earnings were $3.3 million, or $1.0 million higher than 1999
earnings. This increase can be attributed to lower O&M expense, an income
tax adjustment that benefited earnings in 2000, and additional consideration
received in 2000 on the sale of a previously written-off project. These were
partly offset by a decrease in margin and the negative impact of the decline in
the exchange rate, as discussed above.
- ------------------------------------------------------------- ------------------- ------------------ -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ------------------------------------------------------------- ------------------- ------------------ -----------------
Natural Gas (after Hedging) $257,005 $139,614 $97,514
Electricity 1,362 1,941 1,551
Other 839 (7,626) 23
- ------------------------------------------------------------- ------------------- ------------------ -----------------
$259,206 $133,929 $99,088
- ------------------------------------------------------------- ------------------- ------------------ -----------------
- ------------------------------------------------------------- ------------------- ------------------ ----------------- Year Ended September 30 2001 2000 1999 - ------------------------------------------------------------- ------------------- ------------------ ----------------- Natural Gas - (MMcf) 37,427 35,465 34,454 - ------------------------------------------------------------- ------------------- ------------------ -----------------
2001 Compared
with 2000
Operating revenues
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 customers
from September 30, 2000 to September 30, 2001. In addition, NFR recognized a
negative $8.6 million mark-to-market adjustment related to certain derivative
financial instruments (included in “Other” on the table above) during
2000. NFR experienced positive mark-to-market adjustments in 2001 of $0.5
million. See further discussion of NFR’s use of derivatives in the
“Market Risk Sensitive Instruments” section that follows and in Note F
– Financial Instruments in Item 8 of this report.
2000 Compared
with 1999
Operating revenues
increased $34.8 million in 2000 compared with 1999. The primary reason for this
increase was higher gas costs that are reflected in the natural gas marketing
revenues. In addition, higher marketing volumes reflect an increase in NFR
customers from 17,480 at September 30, 1999 to 33,115 at September 30, 2000.
Almost 89% of the increase in customers were residential customers. These higher
revenues were offset in part by a negative $8.6 million mark-to-market
adjustment discussed above.
2001 Compared
with 2000
The Energy Marketing
segment incurred a loss for 2001 of $3.4 million, a decrease of approximately
$4.4 million compared with the loss of $7.8 million 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. Lower margins, higher O&M expense, mainly attributable to
higher bad debt expense, and higher interest expense in 2001 compared to 2000
partially offset the effect of these adjustments.
2000 Compared
with 1999
The Energy Marketing
segment incurred a loss for 2000 of $7.8 million, a decrease of approximately
$9.9 million over 1999 earnings of $2.1 million. The most significant reasons
for the decrease were mark-to-market losses related to certain derivative
financial instruments of $5.6 million (after tax), the accrual of a $1.6 million
(after tax) loss contingency on the unhedged portion of this segment’s
fixed price sales contracts for sale of natural gas to customers in 2001, and
higher expenses including interest.
- ------------------------------------------------------------- ------------------- ------------------ -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ------------------------------------------------------------- ------------------- ------------------ -----------------
Log Sales $23,460 $24,091 $18,276
Green Lumber Sales 5,597 4,397 4,018
Kiln Dry Lumber Sales 12,320 10,152 8,197
Other 714 532 626
- ------------------------------------------------------------- ------------------- ------------------ -----------------
$42,091 $39,172 $31,117
- ------------------------------------------------------------- ------------------- ------------------ -----------------
- ------------------------------------------------------------- ------------------- ------------------ -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ------------------------------------------------------------- ------------------- ------------------ -----------------
Log Sales 8,839 9,370 6,902
Green Lumber Sales 10,332 8,193 8,541
Kiln Dry Lumber Sales 8,804 6,987 5,711
- ------------------------------------------------------------- ------------------- ------------------ -----------------
27,975 24,550 21,154
- ------------------------------------------------------------- ------------------- ------------------ -----------------
2001 Compared
with 2000
Operating revenues for the
Timber segment increased $2.9 million. Green lumber sales were up due to an
increase in board feet sold at slightly higher prices. The increase in kiln dry
lumber sales is 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.
2000 Compared
with 1999
Operating revenues for the
Timber segment increased $8.1 million. This increase was primarily the result of
higher log sales and kiln dry lumber sales. Log sales were up due mainly to
higher board feet of cherry veneer and export logs sold and higher average
prices. The increase in kiln dry lumber sales is due to the operation of
additional kilns brought on line in 1999 that were operational for a full 12
months in 2000 and the addition of two more kilns brought on line in August
2000.
2001 Compared
with 2000
Timber segment earnings of
$7.7 million in 2001 were up $1.6 million compared with 2000. The increase is
primarily due to higher operating revenues, as mentioned above, and lower
interest expense.
2000 Compared
with 1999
Timber segment earnings of
$6.1 million in 2000 were up $1.4 million compared with 1999. The increase was
due to higher operating revenues, as mentioned above, and an after tax gain on
the sale of land and standing timber of $1.5 million. These items were partly
offset by higher interest expense resulting from higher debt related to an
acquisition in July 1999 and by higher operating expenses.
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 increased $4.8
million in 2001 compared with 2000. This increase resulted primarily from a $4.0
million buyout of a long-term transportation contract by a customer in the
Pipeline and Storage segment during the first quarter of 2001.
Other income decreased $1.9 million in 2000 compared with 1999. This decrease resulted from $3.2 million of interest income related to the final settlement of IRS audits of years 1977-1994 which was recorded during 1999, as well as a $2.4 million gain recorded in 1999 which resulted from the demutualization of an insurance company. As a policyholder, the Company received stock of the insurance company as part of its initial public offering. Neither of these items recurred in 2000. Partly offsetting this decrease was a $2.6 million gain on the sale of land and standing timber in 2000, as well as $0.5 million of additional consideration received in 2000 on the sale of a previously written-off project in the International segment.
Interest
Charges
Interest on long-term debt
increased $14.7 million in 2001 and $1.8 million in 2000. The increase in both
years can be attributed mainly to 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.
Other interest charges decreased $7.6 million in 2001 and increased $10.6 million in 2000. The decrease in 2001 was primarily the result of lower weighted average interest rates on short-term debt. The increase in 2000 resulted primarily from higher weighted average interest rates and higher average amounts of short-term debt outstanding.
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
- ----------------------------------------------------------- -------------------- ------------------- ----------------- Year Ended September 30 (Millions) 2001 2000 1999 - ----------------------------------------------------------- -------------------- ------------------- ----------------- Provided by Operating Activities $414.1 $238.2 $267.5 Capital Expenditures (292.7) (269.4) (256.1) Investment in Subsidiaries, Net of Cash Acquired (90.6) (123.8) (5.8) Investment in Partnerships (1.8) (4.4) (3.6) Other Investing Activities (2.9) 13.3 6.7 Short-Term Debt, Net Change (143.4) 226.5 67.2 Long-Term Debt, Net Change 187.2 (18.1) (15.6) Issuance of Common Stock 11.5 14.3 10.7 Dividends Paid on Common Stock (76.7) (73.0) (69.9) Dividends Paid to Minority Interest - (0.2) (0.2) Effect of Exchange Rates on Cash (0.6) (0.5) (2.1) - ----------------------------------------------------------- -------------------- ------------------- ----------------- Net Increase (Decrease) in Cash and Temporary Cash Investments $4.1 $2.9 $(1.2) - ----------------------------------------------------------- -------------------- ------------------- -----------------
Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, deferred income taxes, minority interest in foreign subsidiaries and the impairment of oil and gas producing properties (2001).
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 SFV rate design.
Net cash provided by operating activities totaled $414.1 million in 2001, an increase of $175.9 million compared with the $238.2 million provided by operating activities in 2000. The increase is attributable primarily to higher cash receipts from the sale of oil and gas in the Exploration and Production segment. Gas prices were up significantly for most of 2001 and oil production increased significantly due to this segment's Canadian properties acquired in June 2000, offsetting a slight overall decrease in oil prices. The increase in cash provided by operating activities also reflects the over-recovery of purchased gas costs in the Utility segment during 2001.
Expenditures
for Long-Lived Assets
Expenditures for long-lived
assets include additions to property, plant and equipment (capital expenditures)
and investments in corporations (stock acquisitions) or partnerships, net of any
cash acquired.
The Company's expenditures for long-lived assets totaled $385.1 million in 2001. The table below presents these expenditures:
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Total
Investments Expenditures
Capital in Corporations For Long-
Year Ended September 30, 2001 (Millions) Expenditures or Partnerships Lived Assets
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Utility $42.4 $ - $42.4
Pipeline and Storage 25.0 1.0 26.0
Exploration and Production 205.8 90.6 296.4
International 15.6 - 15.6
Energy Marketing 0.1 - 0.1
Timber 3.7 - 3.7
All Other 0.1 0.8 0.9
- ----------------------------------------------------------- ------------------- ------------------- -----------------
$292.7 $92.4 $385.1
- ----------------------------------------------------------- ------------------- ------------------- -----------------
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 Pipeline and Storage segment’s
capital expenditures made during 2001 included $8.1 million for the construction
of a transmission line from Lamont, Pennsylvania to Roystone, Pennsylvania. The
remaining capital expenditures were made for additions, improvements and
replacements to this segment’s transmission and gas storage systems.
During 2001, SIP made an additional $980,000 investment in Independence. SIP's total investment through September 30, 2001 was $14.6 million. The investment represents a one-third partnership interest in Independence. The investment has been financed with short-term borrowings. Independence intends to build the Independence Pipeline, a 400-mile natural gas pipeline from Defiance, Ohio to Leidy, Pennsylvania at an estimated cost of about $700 million.* If the Independence Pipeline project is not constructed, SIP's share of the developmental costs (including SIP's investment in Independence) is estimated not to exceed $15.5 million.* This amount represents the estimated maximum charge to earnings that would be recorded if the project is not constructed.
On July 12, 2000, the Federal Energy Regulatory Commission (FERC) issued a Certificate of Public Convenience and Necessity (the Certificate) authorizing, among other things, the construction and operation of the Independence Pipeline, subject to satisfaction of various conditions spelled out in the Certificate and in previous FERC orders. Independence accepted the Certificate on August 14, 2000. Among the conditions to the construction and operation of the pipeline is the requirement that the pipeline be in service by July 12, 2003. Another condition is that, before construction may commence, Independence must file at FERC executed, firm transportation agreements with "no out" clauses for at least 68.2% of its capacity. (Independence already filed, on June 26 and July 6, 2000, precedent agreements for firm transportation amounting to about 38% of the capacity of the Independence Pipeline, thereby satisfying a FERC requirement previously imposed as a precondition to FERC's issuance of the Certificate.) The Independence Pipeline partners are working on obtaining the required additional customer commitments, and had extended the planned in-service date from November 1, 2002 to July 1, 2003 to allow additional time to obtain those commitments.
The Certificate also includes an environmental condition that Independence file an "implementation plan" within 60 days after Independence accepts the Certificate. FERC extended the due date for submission of that implementation plan to November 1, 2001. On November 1, 2001, Independence filed a partial implementation plan with FERC seeking to extend the due date for a complete implementation plan to November 2003 and to extend the in service date to November 2004. As of the date the Company filed this Form 10-K with the SEC, FERC had placed the Independence Pipeline project on the agenda for its December 19, 2001 meeting but had not decided upon Independence's requests for extensions. If FERC does not grant these extensions, it may revoke the Certificate. If the certificate is revoked and the Independence partners decide to proceed with the project, they would file a new application at FERC after obtaining additional customer commitments.
The Company also continues to explore various opportunities to participate in transporting gas to the Northeast, either through Supply's system or in partnership with others. This includes the proposed Northwinds Pipeline that the Company and TransCanada PipeLines Limited are pursuing. This project would be 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. 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 - $400 million. At September 30, 2001, the Company had not incurred any material costs associated with this project. The Company would be interested in building the Independence Pipeline and/or the Northwinds Pipeline if there are sufficient customer commitments.
Exploration
and Production
The Exploration and
Production segment’s capital expenditures included approximately $116.6
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 $116.6
million discussed above, $56.8 million was spent on the Exploration and
Production segment’s Canadian properties. The Exploration and Production
segment’s capital expenditures also included approximately $89.2 million
for Seneca’s offshore program in the Gulf of Mexico, including offshore
drilling expenditures, offshore construction, lease acquisition costs and
geological and geophysical expenditures.
In June 2001, the Company acquired the issued and outstanding shares of Player, an oil and gas exploration and development company with operations based primarily in the Province of Alberta, Canada. The cost of acquiring the shares of Player was approximately $90.6 million. The acquisition was financed with short-term borrowings.
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. In June 2001, the Company sold its ownership interest in
Jablonecká teplárenská a realitní, a.s. (JTR). JTR is a
district heating plant in the northern part of the Czech Republic. The proceeds
from this sale, net of cash sold, were $5.6 million. There was a loss of less
than $0.1 million on the sale.
Timber
The majority of the Timber
segment’s capital expenditures were made for purchases of land and timber,
as well as equipment for this segment’s sawmill and kiln operations. In
November 2000, this segment sold timber properties with a book value of $5.2
million for $7.3 million. In April 2001, this segment sold land having a minimal
book value for $0.6 million.
All Other
Expenditures for Long-Lived
Assets for all other subsidiaries consisted of the purchase of a 50% partnership
interest in Model City Energy, LLC (Model City) ($0.3 million) and the purchase
of a 50% partnership interest in Energy Systems North East, LLC (ESNE) ($0.5
million). The Company also financed ESNE with a long-term note in the principal
amount of $11.5 million. Model City generates electricity by using methane gas
obtained from a landfill in Model City, New York, which is owned by an outside
party. ESNE is an 80-megawatt power plant located in North East, Pennsylvania.
The plant provides thermal energy to an adjacent, industrial facility, as well
as electric power to the New York power pool.
Estimated
Capital Expenditures
The Company's estimated capital expenditures for the next three years are:*
------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Millions) 2002 2003 2004
------------------------------------------------------------- ----------------- ---------------- -----------------
Utility $49.6 $49.6 $50.1
Pipeline and Storage 30.8 26.2 27.5
Exploration and Production 141.0 117.2 108.8
International 5.5 1.7 1.7
Timber 1.5 1.5 1.5
------------------------------------------------------------- ----------------- ---------------- -----------------
$228.4 $196.2 $189.6
------------------------------------------------------------- ----------------- ---------------- -----------------
Estimated capital expenditures for the Utility segment in 2002 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 2002 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines.* The estimated capital expenditures also include $6.3 million for an increase in horsepower at the Ellisburg, Pennsylvania compressor station.* The estimated capital expenditures do not include any partnership investments for Independence or the Northwinds Pipeline.
Estimated capital expenditures in 2002 for the Exploration and Production segment include approximately $88.0 million for the onshore program ($47.0 million in Canada).* Of this amount, approximately $59.0 million ($26.0 million in Canada) is intended to be spent on exploratory and development drilling.* The estimated expenditures also include approximately $53.0 million for the offshore program in the Gulf of Mexico.* Of this amount, approximately $27.0 million is intended to be spent on exploratory and development drilling.*
The estimated capital expenditures for the International segment in 2002 will be concentrated on improvements and replacements within the district heating and power generation plants in the Czech Republic.*
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 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
Flow
In November 2000, the
Company issued $200.0 million of 7.50% medium-term notes due in November 2010.
After deducting underwriting discounts and commissions, the net proceeds to the
Company amounted to $197.3 million. The proceeds of this debt issuance were used
to reduce short-term debt.
Consolidated short-term debt decreased $143.4 million during 2001. The Company continues to consider short-term debt an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, exploration and development expenditures and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt.
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, 2001, the Company would have been permitted to issue up to a maximum of $322.0 million in additional long-term unsecured indebtedness at projected market interest rates. Excluding the unrealized gain for derivative financial instruments reflected in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet, the Company would have been permitted to issue up to a maximum of $296.0 million in additional long-term unsecured indebtedness at projected market interest rates. In addition, at September 30, 2001, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $260.3 million of short-term debt.
The Company's embedded cost of long-term debt was 7.0% at both September 30, 2001 and 2000, respectively.
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.
In March 1998, the Company obtained authorization from the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935, to issue long-term debt securities and equity securities in amounts not exceeding $2.0 billion at any one time outstanding during the order's authorization period, which extends to December 31, 2002. In August 1999, the Company registered $625.0 million of debt and equity securities under the Securities Act of 1933. After the November 2001 medium-term note issuance discussed above, the Company currently has $125.0 million of securities registered under the Securities Act of 1933.
The amounts and timing of the issuance and sale of debt and/or equity securities will depend on market conditions, regulatory authorizations, and the requirements of the Company.
The Company is involved in litigation arising in the normal course of business. The Company is involved in regulatory matters arising in the normal course of business that involve 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 year of resolution, none of this litigation, and none of these regulatory matters are currently expected to change materially the Company's present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
Energy
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, 2001 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 prices as of September 30, 2001. At September 30, 2001, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2003.
----------------------------------------------------- ----------------------------------------------------------
Expected Maturity Dates
----------------------------------------------------------
2002 2003 Total
----------------------------------------------------- ------------------- ------------------- ------------------
Notional Quantities (Equivalent Bcf) 26.4 1.1 27.5
Weighted Average Fixed Rate (per Mcf) $3.82 $2.80 $3.77
Weighted Average Variable Rate (per Mcf) $2.40 $2.35 $2.39
----------------------------------------------------- ------------------- ------------------- ------------------
- ------------------------------------------------------ -----------------------------------------------------------
Expected Maturity Dates
-----------------------------------------------------------
2002 2003 Total
- ------------------------------------------------------ ------------------- ------------------ --------------------
Notional Quantities (Equivalent bbls) 4,840,980 1,803,000 6,643,980
Weighted Average Fixed Rate (per bbl) $22.98 $19.93 $22.15
Weighted Average Variable Rate (per bbl) $26.49 $26.50 $26.49
- ------------------------------------------------------ ------------------- ------------------ --------------------
At September 30, 2001, the Company would have received from the respective counterparties an aggregate of approximately $25.7 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $7.5 million to the counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2001.
At September 30, 2000, the Company had natural gas price swap agreements covering 44.9 Bcf at a weighted average fixed rate of $3.34 per Mcf. The Company also had crude oil price swap agreements covering 10,361,895 bbls at a weighted average fixed rate of $21.75 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 the pricing environment during the latter part of 2000 compared to 2001. In the latter part of 2000, prices were on the rise, allowing the Company to lock in favorable prices. In the latter part of 2001, prices were falling providing less opportunities for the Company to lock in favorable prices. Furthermore, the Company has changed its hedging strategy by using more natural gas no cost collars and options (puts) to allow the Company to share in more of the upside potential of commodity prices while limiting the downside risk.
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, 2001, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2004.
- ---------------------------------------------------- --------------------------------------------------------
Expected Maturity Dates
--------------------------------------------------------
2002 2003 2004 Total
- ---------------------------------------------------- ------------- -------------- ------------- -------------
Crude Oil
Notional Quantities (Equivalent bbls) 1,335,000 1,125,000 270,000 2,730,000
Weighted Average Ceiling Price (per bbl) $28.26 $26.41 $25.80 $27.25
Weighted Average Floor Price (per bbl) $21.91 $21.96 $22.00 $21.94
Natural Gas
Notional Quantities (Equivalent Bcf) 2.8 6.2 0.2 9.2
Weighted Average Ceiling Price (per Mcf) $5.61 $5.28 $4.40 $5.36
Weighted Average Floor Price (per Mcf) $4.11 $4.05 $3.71 $4.06
- ---------------------------------------------------- ------------- -------------- ------------- -------------
At September 30, 2001, the Company would have received from the respective counterparties an aggregate of approximately $11.2 million to terminate the natural gas no cost collars outstanding at that date. The Company would have received an aggregate of approximately $2.3 million to terminate the crude oil no cost collars outstanding at that date.
At September 30, 2000, the Company had crude oil no cost collars covering 4,725,000 bbls at a weighted average floor price of $22.49 per bbl and a weighted average ceiling price of $28.44 per bbl. The Company also had natural gas no cost collars covering 6.6 Bcf at a weighted average floor price of $3.83 per Mcf and a weighted average ceiling price of $5.75 per Mcf.
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. These options provide for the Company to receive monthly payments from other parties when a variable price falls below an established floor or "strike" price. At September 30, 2001, the Company held no options with maturity dates extending beyond 2003.
- ---------------------------------------------------------- ----------------------------------------- --------------------
Expected Maturity Date
- ---------------------------------------------------------- ----------------------------------------- --------------------
2002 2003 Total
- ---------------------------------------------------------- --------------------- ------------------- --------------------
Natural Gas
Notional Quantities (Equivalent Bcf) 2.5 0.2 2.7
Weighted Average Strike Price (per Mcf) $4.12 $3.98 $4.11
- ---------------------------------------------------------- --------------------- ------------------- --------------------
At September 30, 2001, the Company would have received from the respective counterparties an aggregate of approximately $4.7 million to terminate these options.
At September 30, 2000, the Company had purchased natural gas options covering 31.1 Bcf at a weighted average strike price of $4.76 per Mcf. The Company had also sold natural gas options covering 37.9 Bcf at a weighted average strike price of $4.76 per Mcf and sold crude oil options covering 368,000 bbls at a weighted average strike price of $15.25 per bbl. The significant decrease in the amount of options outstanding at September 30, 2001 compared to September 30, 2000 primarily reflects a change in hedging strategy by the Company's Energy Marketing segment, which eliminated its use of options in 2001. At September 30, 2001, the Energy Marketing segment was using only futures contracts to manage the market risk associated with fluctuations in the price of natural gas. The options outstanding at September 30, 2001 were purchased by the Company's Exploration and Production segment.
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, 2001, the Company held no futures contracts with maturity dates extending beyond 2003.
- ---------------------------------------------------------------------- ---------------------------------------------
Expected Maturity Dates
---------------------------------------------
2002 2003 Total
- ---------------------------------------------------------------------- -------------- -------------- ---------------
Net Contract Volumes Purchased (Equivalent Bcf) 11.4 1.8 13.2
Weighted Average Contract Price (per Mcf) $4.16 $4.32 $4.17
Weighted Average Settlement Price (per Mcf) $2.83 $3.41 $2.89
- ---------------------------------------------------------------------- -------------- -------------- ---------------
At September 30, 2001, the Company would have had to pay $15.3 million to terminate these futures contracts.
At September 30, 2000, the Company had futures contracts covering 3.9 Bcf (net short position) at a weighted average contract price of $4.20 per Mcf.
The Company may be exposed to credit risk on some of the derivatives disclosed above. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check and then, on an ongoing basis, monitors counterparty credit exposure. Management has obtained guarantees from the parent companies of the respective counterparties to its derivative financial instruments. At September 30, 2001, the Company's credit risk amounted to $36.4 million of net fair value that was owed to the Company for its price swap agreements, no cost collars and puts. There are five counterparties that comprise this credit risk, with the minimum and maximum credit risk from any of the counterparties being 9% and 45%, respectively, of the total fair value at September 30, 2001. One of the counterparties, Enron, representing 29% of the total fair value at September 30, 2001, filed for bankruptcy protection subsequent to September 30, 2001. The bankruptcy filing effectively terminated the natural gas and crude oil price swap agreements as well as the crude oil no cost collars that the Company had entered into with Enron. The natural gas price swap agreements that were terminated covered 8.7 Bcf of production at a weighted average fixed rate of $4.19 per Mcf through the end of 2002. The crude oil price swap agreements that were terminated covered 645,000 bbls of production in 2002 at a weighted average fixed rate of $19.13 per bbl and 135,000 bbls of production in 2003 at a weighted average fixed rate of $19.10 per bbl. The crude oil no cost collars covered 80,000 bbls of production in 2002 at a weighted average ceiling price of $28.10 per bbl and a weighted average floor price of $21.00 per bbl. The Company replaced the Enron natural gas price swap agreements with natural gas no cost collars with another counterparty. The new natural gas no cost collars cover 7.5 Bcf of production in 2002 at a weighted average ceiling price of $4.21 per Mcf and a weighted average floor price of $2.15 per Mcf. In the first quarter of 2002, the Company expects to establish a reserve for up to a maximum amount of $10.7 million for what Enron owed the Company at the time of the termination of the derivative financial instruments (December 3, 2001).* In accordance with SFAS 133, the amount of Accumulated Other Comprehensive Income associated with these cash flow hedges will be reclassified to the Consolidated Statement of Income when the hedged physical transactions occur, the majority of which will occur in 2002, as disclosed above.
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, 2001 compared to September
30, 2000, the Czech koruna was higher in value in relation to the U.S. dollar,
resulting in a $7.7 million positive adjustment to the Cumulative Foreign
Currency Translation Adjustment (CTA) (a component of Accumulated Other
Comprehensive Income/Loss). At September 30, 2001 compared to September 30,
2000, the Canadian dollar was lower in value in relation to the U.S. dollar,
resulting in a $14.9 million negative 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 primarily consists of short-term debt instruments. At
September 30, 2001, these instruments included short-term bank loans and
commercial paper totaling $459.9 million (domestically). The interest rate on
these short-term bank loans and commercial paper approximated 3.3% at September
30, 2001. The Company’s short-term debt instruments also included $29.8
million of short-term bank loans in Canada and the Czech Republic at
September 30, 2001. The weighted average interest rates on the Canadian and
Czech Republic loans approximated 3.9% and 5.5%, respectively, at September 30,
2001.
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, 2001:
- --------------------------------------- ------------------------------------------------------------------- ----------
Principal Amounts by Expected Maturity Dates
-------------------------------------------------------------------
(Millions of Dollars) 2002 2003 2004 2005 2006 Thereafter Total
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------
National Fuel Gas Company
Long-Term Fixed Rate Debt $100 $150 $225 $- $- $649 $1,124
Weighted Average Interest
Rate Paid 6.2% 7.3% 7.3% -% -% 7.0% 7.0%
Fair Value = $1,154.7 million
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------
Other Notes
Long-Term Debt(1) $9.4 $11.1 $3.9 $3.9 $3.6 $0.2 $32.1
Weighted Average Interest
Rate Paid 5.5% 5.8% 6.3% 6.3% 6.3% 6.2% 5.9%
Fair Value = $32.1 million
- --------------------------------------- --------- ---------- ---------- ---------- ---------- ------------- ----------
(1)$18.7 million is variable rate debt; $13.4 million is fixed rate debt.
The Company utilizes an interest rate swap to eliminate interest rate fluctuations on its CZK 586,993,000 term loan ($15.8 million at September 30, 2001), which carries a variable interest rate of six month Prague Interbank Offered Rate (PRIBOR) plus 0.475%. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month PRIBOR. The Company would have paid approximately $0.6 million to settle the interest rate swap at September 30, 2001.
On October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) that establishes rates for a three-year period beginning October 1, 2000. The Agreement provides that customers will receive a bill credit of $17.6 million in the first year, of which $7.6 million relates to customers’ share of earnings accumulated under previous settlements. The credit will be reduced to $5.0 million in the second year, and in the third and subsequent years the credit will remain at $5.0 million 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 ratepayers. 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,” are continuing. The Joint Proposal makes no changes in Distribution Corporation’s revenue requirement or other such matters addressed in the above-described settlement agreement.
On November 3, 1998, the NYPSC issued its Policy Statement Concerning the Future of the Natural Gas Industry in New York State and Order Terminating Capacity Assignment (Policy Statement). The Policy Statement sets forth the NYPSC's "vision" on "how best to ensure a competitive market for natural gas in New York." The Policy Statement, which sets forth numerous achievement goals, has been regarded as the Commission's template for restructuring of the gas industry.
The Policy Statement provides that the most effective way to establish a competitive market in gas supply is "for local distribution companies to cease selling gas." The NYPSC indicated in its order that it hopes to accomplish that objective over a three-to-seven year transition period from the date the Policy Statement was issued, taking into account "statutory requirements" and the individual needs of each local distribution company (LDC).* The Policy Statement directs Staff to schedule "discussions" with each LDC on an "individualized plan that would effectuate our vision." In preparation for negotiations, LDCs will be required to address issues such as a strategy to hold new capacity contracts to a minimum, a long-term rate plan with a goal of reducing or freezing rates, and a plan for further unbundling. In addition, Staff was instructed to hold collaborative sessions with multiple parties to discuss generic issues including reliability and market power regulation. Distribution Corporation has participated in the collaborative sessions. These collaborative sessions have not yet produced a consensus document on all issues before the NYPSC. Distribution Corporation will continue to participate in all future collaborative sessions.*
As an outgrowth of the Policy Statement, the NYPSC issued an Order Directing Expedited Consideration of Rate Unbundling on March 29, 2001 (Unbundling Order). The Unbundling Order directs the state's electric and gas utilities, including Distribution Corporation, to submit cost studies for "bottom-up" unbundling, which as described by the NYPSC, "begins with the total costs of the utility's business and then assigns those costs to the various functions, some of which are expected to become competitively available." This is in contrast to methods used for establishing "back-out" credits, although the result is essentially the same: competitive functions are identified and priced in order to subsidize market entry for marketers. Numerous parties met for several collaborative sessions and were unable to reach consensus on the methodology for the studies. Accordingly, briefs were filed and a decision on the appropriate methodology to use will be issued by the NYPSC at a later date. Distribution Corporation has no objection to the NYPSC's authority to order unbundling cost studies, but to the extent any legally-mandated utility functions are identified as "competitive," there is a possibility that stranded costs may be incurred. While at this juncture the NYPSC has not indicated that stranded cost recovery would be denied, in whole or in part, the issue remains open for consideration in individual utility proceedings. At this time, Distribution Corporation is unable to ascertain the outcome of this proceeding.*
On July 23, 2001, the NYPSC ordered implementation of an initial set of electronic data interchange (EDI) datasets for electronic exchange of retail access data in New York (EDI Order). As described by the NYPSC, EDI is the computer-to-computer exchange of routine business information in a standard form. The NYPSC believes that EDI is necessary to develop uniform data exchange protocol for the state's customer choice initiatives. The EDI Order adopts modified enrollment and historical usage datasets initially prepared by an EDI working group involving utilities, marketers and other interests. The Order identifies required changes to uniform business practices and also adopts Web Site Design Principles and EDI testing plans. Initial EDI implementation is ordered for calendar year-end 2001 following completion of EDI testing. Phased testing of EDI began during the fourth quarter of calendar 2001. The NYPSC also directs development of datasets governing billing and payment processing based upon the recommendations of a national group of stakeholders. EDI datasets governing billing are now under development and will be completed in the first quarter of calendar 2002 and implemented thereafter.
The NYPSC continues to address, through various proceedings and "collaboratives," upstream pipeline capacity issues arising from the restructuring. Currently Distribution Corporation remains authorized to release upstream intermediate capacity to marketers serving former sales customers. Costs relating to retained upstream transmission capacity are recovered through a transition cost surcharge. At this time, Distribution Corporation does not foresee any material changes to upstream capacity requirements in the near term.*
On May 15, 2000, the New York State tax law was amended to phase out the long-running tax on utility gross revenues beginning January 1, 2001. Offsetting the scheduled reductions, however, is the imposition of a net income based tax on the same utilities. In an order issued on December 21, 2000, the NYPSC adopted a recommendation providing that utilities be kept whole for any tax increases resulting from implementation of the changes. Toward that end, the report proposed that the mechanism in rates currently used for recovery of the gross revenue tax would be utilized to collect the new income tax. To the extent a utility's income tax liability exceeded the amount collectible through the existing gross revenue tax recovery mechanism, deferral accounting would be authorized.
Distribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission (PaPUC). Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future.
A natural gas restructuring bill was signed into law on June 22, 1999. Entitled the Natural Gas Choice and Competition Act (Act), the new law requires all Pennsylvania LDCs to file tariffs designed to provide retail customers with direct access to competitive gas markets. Distribution Corporation submitted its compliance filing on October 1, 1999 for an effective date on or about July 1, 2000. The filing largely mirrored Distribution Corporation's System Wide Energy Select program previously in effect, which substantially complied with the Act's requirements. After negotiations with PaPUC Staff and intervenors, a settlement was reached with all parties except for the Pennsylvania Office of Consumer Advocate (OCA). The settlement parties generally agreed that Distribution Corporation's proposal needed only modest changes to meet the requirements of the Act. Hearings were held and briefs filed on OCA's open issues. In a Recommended Decision issued on March 31, 2000, the Administrative Law Judge rejected the OCA's arguments and recommended approval of the settlement agreement. On June 29, 2000, the PaPUC entered an Opinion and Order adopting the settlement, with immaterial changes. Distribution Corporation's restructured rates and services became effective on July 1, 2000.
Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
Supply 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.
Environmental
Matters
It is the Company’s
policy to accrue estimated environmental clean-up costs (investigation and
remediation) when such amounts can reasonably be estimated and it is probable
that the Company will be required to incur such costs. The Company has estimated
its clean-up costs related to former manufactured gas plant sites and third
party waste disposal sites will be in the range of $5.4 million to $6.4
million.* The minimum liability of $5.4 million has been recorded on the
Consolidated Balance Sheet at September 30, 2001. 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
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 Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of this report.
New Accounting
Pronouncements
In 2001, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards (SFAS) No. 141, “Business Combinations” (SFAS 141), 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 141, SFAS 142 and SFAS 143 and their impact on the Company,
see disclosure in Note A – Summary of Significant Accounting Policies in
Item 8 of this report.
Effects of
Inflation
Although the rate of
inflation has been relatively low over the past few years, the Company’s
operations remain sensitive to increases in the rate of inflation because of its
capital spending and the regulated nature of a significant portion of its
business.
Safe Harbor
for Forward-Looking Statements
The Company is including
the following cautionary statement in this Form 10-K to make applicable and take
advantage of the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995 for any forward-looking statements made by, or on behalf of,
the Company. Forward-looking statements include statements concerning plans,
objectives, goals, projections, strategies, future events or performance, and
underlying assumptions and other statements which are other than statements of
historical facts. From time to time, the Company may publish or otherwise make
available forward-looking statements of this nature. All such subsequent
forward-looking statements, whether written or oral and whether made by or on
behalf of the Company, are also expressly qualified by these cautionary
statements. Certain statements contained in this report, including 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, 2001 and 2000
Consolidated Statement of Cash Flows, three years ended September 30, 2001
Consolidated Statement of Comprehensive Income, three years ended September 30, 2001
Notes to Consolidated Financial Statements
Financial Statement Schedules:
For the three years ended September 30, 2001
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 Data
Supplementary data that is included in Note K - Quarterly Financial Data (unaudited) and Note M - Supplementary Information for Oil and Gas Producing Activities, appears under this Item, and reference is made thereto.
Report of Management
Management is responsible for the preparation and integrity of the Company’s financial statements. The financial statements have been prepared in accordance with 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2001, 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 24, 2001, except for
Note F, as to which the date
is December 3, 2001
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) 2001 2000 1999
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Income
Operating Revenues $2,100,352 $1,425,277 $1,263,274
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Operating Expenses
Purchased Gas 1,045,805 503,617 405,925
Fuel Used in Heat and Electric Generation 54,968 54,893 55,788
Operation 343,693 326,933 304,919
Maintenance 20,625 23,450 23,881
Property, Franchise and Other Taxes 83,730 78,878 91,146
Depreciation, Depletion and Amortization 174,914 142,170 124,778
Impairment of Oil and Gas Producing
Properties 180,781 - -
Income Taxes 37,106 77,068 64,829
- -------------------------------------------------------------- ----------------- ---------------- ------------------
1,941,622 1,207,009 1,071,266
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Operating Income 158,730 218,268 192,008
Other Income 15,256 10,408 12,343
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 173,986 228,676 204,351
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Interest Charges
Interest on Long-Term Debt 81,851 67,195 65,402
Other Interest 25,294 32,890 22,296
- -------------------------------------------------------------- ----------------- ---------------- ------------------
107,145 100,085 87,698
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Minority Interest in Foreign Subsidiaries (1,342) (1,384) (1,616)
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Net Income Available for Common Stock 65,499 127,207 115,037
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Earnings Reinvested in the Business
Balance at Beginning of Year 525,847 472,517 428,112
- -------------------------------------------------------------- ----------------- ---------------- ------------------
591,346 599,724 543,149
Dividends on Common Stock 77,858 73,877 70,632
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Balance at End of Year $513,488 $525,847 $472,517
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Earnings Per Common Share:
Basic $0.83 $1.63 $1.49
Diluted $0.82 $1.61 $1.47
- -------------------------------------------------------------- ----------------- ---------------- ------------------
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 79,053,444 78,233,842 77,327,962
Used in Diluted Calculation 80,361,258 79,166,200 78,083,456
- -------------------------------------------------------------- ----------------- ---------------- ------------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Balance Sheets
- ---------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands of Dollars) 2001 2000
- ---------------------------------------------------------------------------- ------------------- -------------------
Assets
Property, Plant and Equipment $4,273,716 $3,829,637
Less - Accumulated Depreciation,
Depletion and Amortization 1,493,003 1,146,246
- ---------------------------------------------------------------------------- ------------------- -------------------
2,780,713 2,683,391
- ---------------------------------------------------------------------------- ------------------- -------------------
Current Assets
Cash and Temporary Cash Investments 36,227 32,125
Receivables - Net 131,726 121,639
Unbilled Utility Revenue 25,375 27,105
Gas Stored Underground 83,231 55,795
Materials and Supplies - at average cost 33,710 25,145
Unrecovered Purchased Gas Costs 4,113 29,681
Prepayments 39,520 39,150
- ---------------------------------------------------------------------------- ------------------- -------------------
353,902 330,640
- ---------------------------------------------------------------------------- ------------------- -------------------
Other Assets
Recoverable Future Taxes 86,586 84,199
Unamortized Debt Expense 19,796 19,841
Other Regulatory Assets 23,253 24,804
Deferred Charges 9,136 12,985
Fair Value of Derivative Financial Instruments 37,585 -
Other 134,595 95,171
- ---------------------------------------------------------------------------- ------------------- -------------------
310,951 237,000
- ---------------------------------------------------------------------------- ------------------- -------------------
$3,445,566 $3,251,031
- ---------------------------------------------------------------------------- ------------------- -------------------
See Notes to Consolidated Financial Statements
Back to Index of Financial StatementsNational Fuel Gas Company
Consolidated Balance Sheets
- ---------------------------------------------------------------------------- ----------------- ----------------
At September 30 (Thousands of Dollars) 2001 2000
- ---------------------------------------------------------------------------- ----------------- ----------------
Capitalization and Liabilities
Capitalization:
Comprehensive Shareholders' Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued and
Outstanding - 79,406,105 Shares and 78,659,606
Shares, Respectively $ 79,406 $ 78,660
Paid In Capital 430,618 412,887
Earnings Reinvested in the Business 513,488 525,847
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Common Shareholder Equity Before Items
Of Other Comprehensive Loss 1,023,512 1,017,394
Accumulated Other Comprehensive Loss (20,857) (29,957)
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Comprehensive Shareholders' Equity 1,002,655 987,437
Long-Term Debt, Net of Current Portion 1,046,694 953,622
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Capitalization 2,049,349 1,941,059
- ---------------------------------------------------------------------------- ----------------- ----------------
Minority Interest in Foreign Subsidiaries 22,324 23,031
- ---------------------------------------------------------------------------- ----------------- ----------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 489,673 619,502
Current Portion of Long-Term Debt 109,435 11,262
Accounts Payable 118,505 88,853
Amounts Payable to Customers 51,223 9,583
Other Accruals and Current Liabilities 94,634 79,370
- ---------------------------------------------------------------------------- ----------------- ----------------
863,470 808,570
- ---------------------------------------------------------------------------- ----------------- ----------------
Deferred Credits
Accumulated Deferred Income Taxes 340,559 326,994
Taxes Refundable to Customers 16,865 14,410
Unamortized Investment Tax Credit 9,599 9,951
Other Deferred Credits 126,319 114,451
Fair Value of Derivative Financial Instruments 17,081 12,565
- ---------------------------------------------------------------------------- ----------------- ----------------
510,423 478,371
- ---------------------------------------------------------------------------- ----------------- ----------------
Commitments and Contingencies - -
- ---------------------------------------------------------------------------- ----------------- ----------------
$3,445,566 $3,251,031
- ---------------------------------------------------------------------------- ----------------- ----------------
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) 2001 2000 1999
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Operating Activities
Net Income Available for Common Stock $65,499 $127,207 $115,037
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 174,914 142,170 124,778
Deferred Income Taxes (55,849) 41,858 14,030
Minority Interest in Foreign Subsidiaries 1,342 1,384 1,616
Other 6,553 4,540 7,018
Change in:
Receivables and Unbilled Utility Revenue (2,299) (26,336) (18,161)
Gas Stored Underground and Materials and
Supplies (37,054) (13,707) (7,280)
Unrecovered Purchased Gas Costs 25,568 (25,105) 1,740
Prepayments (399) (3,420) (15,322)
Accounts Payable 20,419 (16,489) 22,871
Amounts Payable to Customers 41,640 3,649 153
Other Accruals and Current Liabilities 13,969 (10,233) 10,931
Other Assets (34,229) 763 (906)
Other Liabilities 13,289 11,965 10,999
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Provided by Operating Activities 414,144 238,246 267,504
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Investing Activities
Capital Expenditures (292,706) (269,371) (256,120)
Investment in Subsidiaries, Net of Cash Acquired (90,567) (123,809) (5,774)
Investment in Partnerships (1,830) (4,442) (3,633)
Other (2,940) 13,283 6,687
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Used in Investing Activities (388,043) (384,339) (258,840)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper (143,397) 226,477 67,195
Net Proceeds from Issuance of Long-Term Debt 210,221 149,334 198,217
Reduction of Long-Term Debt (23,052) (167,426) (213,849)
Proceeds from Issuance of Common Stock 11,545 14,278 10,735
Dividends Paid on Common Stock (76,671) (73,046) (69,878)
Dividends Paid to Minority Interest - (152) (246)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Provided by (Used in) Financing Activities (21,354) 149,465 (7,826)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Effect of Exchange Rates on Cash (645) (469) (2,053)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Increase (Decrease) in Cash and
Temporary Cash Investments 4,102 2,903 (1,215)
Cash and Temporary Cash Investments
at Beginning of Year 32,125 29,222 30,437
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Cash and Temporary Cash Investments
at End of Year $36,227 $ 32,125 $ 29,222
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Supplemental Disclosure of Cash Flow Information
Cash Paid For:
Interest $97,259 $97,042 $75,813
Income Taxes 77,662 41,928 48,995
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
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) 2001 2000 1999
- ------------------------------------------------------- -------------------------- ------------------------- -----------------------
Net Income Available for Common Stock $65,499 $127,207 $115,037
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
Other Comprehensive Income, Before Tax:
Foreign Currency Translation Adjustment (7,158) (27,463) (11,737)
Unrealized Gain (Loss) on Securities Available
for Sale Arising During the Period (712) 2,441 706
Unrealized Gain on Derivative Financial
Instruments Arising During the Period 58,355 - -
Reclassification Adjustment for Realized
Losses on Derivative Financial Instruments
in Net Income 83,218 - -
Reclassification Adjustment for Realized Gains
on Securities Available for Sale in Net
Income - (103) -
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
Other Comprehensive Income (Loss), Before
Tax: 133,703 (25,125) (11,031)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
Income Tax Expense (Benefit) Related to
Unrealized Gain (Loss) on Securities
Available for Sale Arising During the Period (249) 855 247
Income Tax Expense Related to Unrealized
Gain on Derivative Financial Instruments
Arising During the Period 23,053 - -
Reclassification Adjustment for Income Tax
Benefit on Realized Losses on Derivative
Financial Instruments in Net Income 32,032 - -
Reclassification Adjustment for Income Tax
Expense on Realized Gains on Securities
Available for Sale in Net Income - (36) -
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
Income Taxes - Net 54,836 819 247
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
Other Comprehensive Income (Loss), Before
Cumulative Effect, Net of Tax 78,867 (25,944) (11,278)
Cumulative Effect of Change in Accounting,
Net of Tax (69,767) - -
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
Other Comprehensive Income (Loss), After
Cumulative Effect, Net of Tax 9,100 (25,944) (11,278)
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
Comprehensive Income $74,599 $101,263 $103,759
- ------------------------------------------------------- ---------- --------------- --------- -------------- -------- ---------------
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
The Company consolidates
its majority owned subsidiaries. The equity method is used to account for
minority owned entities. All significant intercompany balances and transactions
are eliminated.
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Stock Split
Effective September 7,
2001, the Company’s common stock was split two-for-one. All references in
the consolidated financial statements referring to shares, share prices, per
share amounts and stock plans have been adjusted retroactively to give effect to
the two-for-one common stock split.
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 an impairment of its oil and gas producing properties in the quarter ended September 30, 2001. This charge amounted to $180.8 million (pre tax) and reduced net income for 2001 by $104.0 million ($1.32 per common share; basic, $1.29 per common share, diluted).
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 4.7% in 2001, 4.2% in 2000 and 4.1% in 1999 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 marketable equity securities 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 can be categorized as price swap agreements, no cost collars, options and futures contracts. The Company also uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. 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 2001. The gain or loss recorded in Accumulated Other Comprehensive Income (Loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues or interest expense, as applicable, 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 2001.
In the case of the no cost collars and options used by the Company, the fair value of these instruments consisted of time value and intrinsic value. The exclusion of time value from the Company's effectiveness tests during 2001 resulted in a $4.4 million gain that was recorded in operating revenues on the Consolidated Statement of Income.
Prior to October 1, 2000, gains or losses from price swap agreements and no cost collars were accrued in operating revenues on the Consolidated Statement of Income at the contract settlement dates. Gains or losses from futures contracts that were designated as hedges were recorded in other deferred credits or deferred debits until the hedged commodity transaction occurred, at which point they were reflected in operating revenues on the Consolidated Statement of Income. For options that were designated as hedges, premiums were amortized on a straight-line basis over the life of the option. Gains or losses resulting from the exercise of options that were designated as hedges were reflected in operating revenues on the Consolidated Statement of Income when the hedged commodity transaction occurred. Options and futures that were not designated as hedges were marked-to-market on a quarterly basis with gains or losses recorded in operating revenues on the Consolidated Statement of Income. In the case of the interest rate swap, gains and losses were accrued in interest charges at the contract settlement dates.
While the accounting standards for derivative financial instruments in 2001 are different from those used in 2000, the liabilities that were recorded for derivative financial instruments at September 30, 2000 have been reclassified to "Fair Value of Derivative Financial Instruments" on the September 30, 2000 Consolidated Balance Sheet. Reference is made to Note F - Financial Instruments for further discussion of derivative financial instruments.
Accumulated Other Comprehensive
Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
---------------------------------------------------------------- -------------------- -------------------- Year Ended September 30 (Thousands) 2001 2000 ---------------------------------------------------------------- -------------------- -------------------- Cumulative Foreign Currency Translation Adjustment $(39,093) $(31,935) Net Unrealized Gain on Derivative Financial Instruments 16,721 - Net Unrealized Gain on Securities Available for Sale 1,515 1,978 ---------------------------------------------------------------- -------------------- -------------------- Accumulated Other Comprehensive Loss $(20,857) $(29,957) ---------------------------------------------------------------- -------------------- --------------------
At September 30, 2001, it is estimated that $16.1 million of the net unrealized gain on derivative financial instruments shown in the table above will be reclassified into the Consolidated Statement of Income during 2002.
Gas Stored
Underground - Current
In the Utility segment, gas
stored underground - current in the amount of $69.5 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 2001, 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
$4.0 million at September 30, 2001. 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. 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 undistributed earnings of foreign
subsidiaries as the 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.
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.
New Accounting
Pronouncements
In 2001, the FASB issued
SFAS No. 141, “Business Combinations” (SFAS 141), SFAS No. 142,
“Goodwill and Other Intangible Assets” (SFAS 142) and SFAS No. 143,
“Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 141
requires that all business combinations initiated after June 30, 2001 be
accounted for by the purchase method. It also requires disclosure of the primary
reasons for a business combination and the allocation of the purchase price paid
to the assets acquired and liabilities assumed by major balance sheet caption.
Additional disclosure would be required when goodwill and intangible assets
represent a significant portion of the purchase price paid. 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. SFAS 142 requires that the Company adopt
this standard by October 1, 2002. However, goodwill and intangible assets
acquired after June 30, 2001 will be subject immediately to the provisions of
SFAS 142. 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. SFAS 143 requires that the Company adopt
this standard by October 1, 2002, with earlier application encouraged.
Management is currently evaluating the impact of SFAS 142 and SFAS 143 on the
financial condition and results of operations of the Company.
Regulatory
Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
- --------------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands) 2001 2000
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Assets:
Recoverable Future Taxes (Note C) $86,586 $84,199
Unrecovered Purchased Gas Costs (Note A) 4,113 29,681
Unamortized Debt Expense (Note A) 11,738 13,454
Pension and Post-Retirement Benefit Costs (Note G) 21,065 23,656
Other 2,188 1,148
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Assets 125,690 152,138
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) 51,223 9,583
New York Rate Settlements(1) 27,630 21,315
Taxes Refundable to Customers (Note C) 16,865 14,410
Pension and Post-Retirement Benefit Costs(1) (Note G) 33,829 24,725
Other(1) 7,498 2,975
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Liabilities 137,045 73,008
- --------------------------------------------------------------------------------- ------------------- -------------------
Net Regulatory Position $(11,355) $79,130
- --------------------------------------------------------------------------------- ------------------- -------------------
(1) Included in Other Deferred Credits 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 a specified
return on equity (11.5% and 12% for 2001 and 2000, respectively) are to be
shared equally between shareholders and ratepayers. As a result of this sharing
mechanism, the Company had liabilities of $5.8 million and $11.2 million at
September 30, 2001 and 2000, respectively. At September 30, 2000, $7.6 million
of the earnings sharing liability was included in Amounts Payable to Customers,
to reflect the amounts that were passed back to customers in 2001. Other aspects
of the settlements include a special reserve of $8.2 million and $7.8 million at
September 30, 2001 and 2000, respectively, to be applied against the
Company’s incremental costs resulting from the NYPSC’s gas
restructuring effort and a “refund pool” of $6.0 million and $5.6
million at September 30, 2001 and 2000, 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 $7.7 million and $4.2 million at September 30, 2001
and 2000, respectively.
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Expenses:
Current Income Taxes -
Federal $ 67,429 $ 26,352 $ 43,467
State 21,330 13,067 6,215
Foreign 4,196 (4,209) 1,116
Deferred Income Taxes -
Federal 18,444 29,604 11,149
State 431 2,495 1,244
Foreign (74,724) 9,759 1,638
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
37,106 77,068 64,829
Other Income:
Deferred Investment Tax Credit (348) (1,051) (729)
Minority Interest in Foreign Subsidiaries (614) (259) (642)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Total Income Taxes $ 36,144 $ 75,758 $ 63,458
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
The U.S. and foreign components of income (loss) before income taxes are as follows:
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
U.S. $267,270 $182,813 $169,038
Foreign (165,627) 20,152 9,457
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$101,643 $202,965 $178,495
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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) 2001 2000 1999 - --------------------------------------------------------------- ------------------- --------------- ---------------- Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $35,575 $71,038 $62,473 Increase (Reduction) in Taxes Resulting from: State Income Taxes 14,145 10,115 4,848 Foreign Tax Rate Differential (13,172) (1,762) (1,198) Depreciation 1,790 1,925 1,872 Miscellaneous (2,194) (5,558) (4,537) - --------------------------------------------------------------- ------------------- --------------- ---------------- Total Income Taxes $36,144 $75,758 $63,458 - --------------------------------------------------------------- ------------------- --------------- ----------------
Significant components of the Company's deferred tax liabilities and assets are as follows:
- --------------------------------------------------------------- ------------------- --------------- At September 30 (Thousands) 2001 2000 - --------------------------------------------------------------- ------------------- --------------- Deferred Tax Liabilities: Property, Plant and Equipment $389,879 $375,660 Other 27,047 13,322 - --------------------------------------------------------------- ------------------- --------------- Total Deferred Tax Liabilities 416,926 388,982 - --------------------------------------------------------------- ------------------- --------------- Deferred Tax Assets: Deferred Gas Costs (20,178) 10,454 Other (56,189) (72,442) - --------------------------------------------------------------- ------------------- --------------- Total Deferred Tax Assets (76,367) (61,988) - --------------------------------------------------------------- ------------------- --------------- Total Net Deferred Income Taxes $340,559 $326,994 - --------------------------------------------------------------- ------------------- ---------------
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 $16.9 million and $14.4 million at September 30, 2001 and 2000, 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 $86.6 million and $84.2 million at September 30, 2001 and 2000, respectively.
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
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, 1998 76,938 $76,938 $377,770 $428,112 $7,265
Net Income Available
for Common Stock 115,037
Dividends Declared on
Common Stock
($0.92 Per Share) (70,632)
Other Comprehensive
Loss, Net of Tax (11,278)
Common Stock Issued
Under Stock and
Benefit Plans 736 736 15,345
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
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(1) $(20,857)
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
(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, 2001, $439.1 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 residential
customers 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 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, 2001, 2000 and 1999, 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 2001 2000 1999
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Net Income (Thousands):
As reported $65,499 $127,207 $115,037
Pro forma $59,108 $123,107 $111,385
Earnings Per Common Share:
Basic - As reported $0.83 $1.63 $1.49
Basic - Pro forma $0.75 $1.58 $1.44
Diluted - As reported $0.82 $1.61 $1.47
Diluted - Pro forma $0.73 $1.56 $1.43
- ---------------------------------------------------------- ------------------- ------------------- -------------------
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, 1998 5,463,792 $18.40
Granted in 1999 1,506,800 $23.35
Exercised in 1999(1) (223,008) $14.21
Forfeited in 1999 (19,400) $18.71
- ------------------------------------------------------------- ---------------------------- ---------------------------
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
- ------------------------------------------------------------- ---------------------------- ---------------------------
Option shares exercisable at September 30, 2001 7,269,160 $20.43
Option shares available for future
grant at September 30, 2001(2) 540,450
- ------------------------------------------------------------- ---------------------------- ---------------------------
(1) In connection with exercising these options, 78,850, 116,916 and 33,062 shares were surrendered and canceled during 2001, 2000 and 1999, respectively.
(2) Including shares available for restricted stock grants. Subsequent to September 30, 2001, the shareholders approved an additional 6 million shares available for granting.
The weighted average fair value per share of options granted in 2001, 2000 and 1999 was $5.25, $4.17 and $3.72, 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 2001 2000 1999 - ---------------------------------------------------------- ------------------- ------------------- ------------------- Quarterly Dividend Yield 0.87% 1.07% 0.97% Annual Standard Deviation (Volatility) 20.51% 19.05% 18.86% Risk Free Rate 5.26% 6.74% 4.74% Expected Term - in Years 5.0 5.5 5.0 - ---------------------------------------------------------- ------------------- ------------------- -------------------
The following table summarizes information about options outstanding at September 30, 2001:
- --------------------------------------------------------------------------------- -------------------------------------
Options Outstanding Options Exercisable
- --------------------------------------------------------------------------------- -------------------------------------
Number Weighted Average Weighted Number Weighted
Range of Outstanding Remaining Average Exercisable Average
Exercise Price at 9/30/01 Contractual Life Exercise Price at 9/30/01 Exercise Price
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
$11.12 - $16.68 1,130,542 2.9 years $14.84 1,130,542 $14.84
$16.69 - $22.24 3,453,470 6.6 years $20.28 3,403,470 $20.28
$22.25 - $27.80 4,788,674 7.8 years $24.78 2,735,148 $22.92
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
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 options 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 2001 2000 1999 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Shares of Restricted Stock Awarded 4,000 15,178 13,160 Weighted Average Market Price of Stock on Award Date $27.80 $24.47 $23.03 - ----------------------------------------------------------------- ----------------- ---------------- -----------------
As of September 30, 2001, 84,738 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2002 - 16,000 shares; 2003 - 32,610 shares; 2004 - 11,600 shares; 2005 - 9,600 shares; 2006 - 9,600 shares; 2007 - 4,000 shares; and 2009 - 1,328 shares.
Stock Appreciation Rights (SARs) give the grantee the right to cash compensation equal to the appreciation in the market price of Company common stock from the grant date to the exercise date. SARs are marked-to-market each quarter with the related increase or decrease in expense recognized in the income statement. At September 30, 2001, 3,303,308 SARs were outstanding at a weighted average exercise price of $20.71.
Compensation (benefit) expense related to SARs and restricted stock under the Company's stock plans was ($13.4) million, $14.9 million and $1.0 million for the years ended September 30, 2001, 2000 and 1999, respectively. Subsequent to September 30, 2001, the Company canceled substantially all of the SARs, issued non-qualified stock options and eliminated all future awards of SARs under its stock option plans. As a result, future earnings will not be materially impacted by SARs expense.
Redeemable
Preferred Stock
As of September 30, 2001,
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) 2001 2000
- ----------------------------------------------------------------------------------- ---------------- -----------------
Debentures:
7-3/4% due February 2004 $ 125,000 $ 125,000
Medium-Term Notes:
6.00% to 8.48% due February 2000 to August 2027(1) 999,000 799,000
- ----------------------------------------------------------------------------------- ---------------- -----------------
1,124,000 924,000
- ----------------------------------------------------------------------------------- ---------------- -----------------
Other Notes 32,129 40,884
- ----------------------------------------------------------------------------------- ---------------- -----------------
Total Long-Term Debt 1,156,129 964,884
Less Current Portion 109,435 11,262
- ----------------------------------------------------------------------------------- ---------------- -----------------
$1,046,694 $ 953,622
- ----------------------------------------------------------------------------------- ---------------- -----------------
(1) Includes $50 million of 8.48% medium-term notes due July 2024 which are callable at a redemption price of 105.51% through July 2002. The redemption price will decline in subsequent years. Also includes $100 million of 6.214% medium-term notes due August 2027 which are putable by debt holders only on August 12, 2002, at par. The $100 million of 6.214% medium-term notes are included in the current portion of long-term debt at September 30, 2001.
As of September 30, 2001, the aggregate principal amounts of long-term debt maturing for the next five years and thereafter are as follows: $109.4 million in 2002, $161.1 million in 2003, $228.9 million in 2004, $3.9 million in 2005, $3.6 million in 2006 and $649.2 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, 2002.
The Company historically has borrowed 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.
At September 30, 2001, the Company had outstanding short-term notes payable to banks and commercial paper of $289.7 million (domestic = $259.9 million; foreign = $29.8 million) and $200.0 million, respectively. At September 30, 2000, the Company had outstanding notes payable to banks and commercial paper of $419.5 million (domestic = $401.2 million; foreign = $18.3 million) and $200.0 million, respectively.
The weighted average interest rate on domestic notes payable to banks was 3.39% and 6.81% at September 30, 2001 and 2000, respectively. The interest rate on the foreign notes payable to banks was 4.65% and 5.73% at September 30, 2001 and 2000, respectively. The weighted average interest rate on commercial paper was 3.13% and 6.62% at September 30, 2001 and 2000, 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:
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
2001 2001 2000 2000
Carrying Fair Carrying Fair
At September 30 (Thousands) Amount Value Amount Value
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
Long-Term Debt $1,156,129 $1,186,795 $964,884 $928,066
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
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 a 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.
Investments
Other assets includes cash
surrender values of insurance contracts and marketable equity securities. The
cash surrender values of the insurance contracts amounted to $52.9 million and
$49.4 million at September 30, 2001 and 2000, respectively. The marketable
equity securities amounted to $10.0 million at both September 30, 2001 and 2000.
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 can be categorized as 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. They 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, 2001, the Company had natural gas price swap agreements covering a notional amount of 27.5 Bcf extending through 2003 at a weighted average fixed rate of $3.77 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 6,643,980 bbls extending through 2003 at a weighted average fixed rate of $22.15 per bbl. At September 30, 2001, the Company would have received a net $18.2 million to terminate the price swap agreements.
Under the no cost collars, the Company receives monthly payments from (or makes payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). The variable price is either a crude oil price quoted on the NYMEX or a quoted natural gas price in "Inside FERC." These derivative financial instruments are accounted for as cash flow hedges. They 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, 2001, the Company had no cost collars on natural gas covering a notional amount of 9.2 Bcf extending through 2004 with 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 no cost collars on crude oil covering a notional amount of 2,730,000 bbls extending through 2004 with a weighted average floor price of $21.94 per bbl and a weighted average ceiling price of $27.25 per bbl. At September 30, 2001, the Company would have received $13.5 million to terminate the no cost collars.
At September 30, 2001, the Company had purchased options outstanding on natural gas covering a notional amount of 2.7 Bcf extending through 2003 at a weighted average strike price of $4.11 per Mcf. These derivative financial instruments are accounted for as cash flow hedges. They 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, 2001, the Company would have received $4.7 million to terminate these options.
At September 30, 2001, the Company had long (purchased) futures contracts covering 15.9 Bcf of gas extending through 2003 at a weighted average contract price of $4.14 per Mcf. These derivative financial instruments are accounted for as fair value hedges. They are used by the Company's Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with commercial and industrial customers. The Company would have had to pay $19.5 million to terminate these futures contracts at September 30, 2001.
At September 30, 2001, the Company had short (sold) futures contracts covering 2.7 Bcf of gas extending through 2003 at a weighted average contract price of $4.39 per Mcf. These derivative financial instruments are accounted for as fair value hedges. They are used by the Company's Energy Marketing segment and All Other category to hedge against falling prices, a risk to which they are exposed on their gas storage inventory and fixed price gas purchase commitments. The Company would have received $4.2 million to terminate these futures contracts at September 30, 2001.
The Company uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month Prague Interbank Offered Rate (PRIBOR). The interest rate swap is accounted for as a cash flow hedge. At September 30, 2001, the Company would have had to pay $0.6 million to terminate the interest rate swap.
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's credit risk amounted to $36.4 million of net fair value that was owed to the Company for its price swap agreements, no cost collars and puts. There are five counterparties that comprise this credit risk, with the minimum and maximum credit risk from any of the counterparties being 9% and 45%, respectively of the total fair value at September 30, 2001. One of the counterparties, Enron, representing 29% of the total fair value at September 30, 2001, filed for bankruptcy protection subsequent to September 30, 2001. The bankruptcy filing effectively terminated the natural gas and crude oil price swap agreements as well as the crude oil no cost collars that the Company had entered into with Enron. The natural gas price swap agreements that were terminated covered 8.7 Bcf of production at a weighted average fixed rate of $4.19 per Mcf through the end of 2002. The crude oil price swap agreements that were terminated covered 645,000 bbls of production in 2002 at a weighted average fixed rate of $19.13 per bbl and 135,000 bbls of production in 2003 at a weighted average fixed rate of $19.10 per bbl. The crude oil no cost collars covered 80,000 bbls of production in 2002 at a weighted average ceiling price of $28.10 per bbl and a weighted average floor price of $21.00 per bbl. The Company replaced the Enron natural gas price swap agreements with natural gas no cost collars with another counterparty. The new natural gas no cost collars cover 7.5 Bcf of production in 2002 at a weighted average ceiling price of $4.21 per Mcf and a weighted average floor price of $2.15 per Mcf. In the first quarter of 2002, the Company expects to establish a reserve for up to a maximum amount of $10.7 million for what Enron owed the Company at the time of the termination of the derivative financial instruments (December 3, 2001). In accordance with SFAS 133, the amount of Accumulated Other Comprehensive Income associated with these cash flow hedges will be reclassified to the Consolidated Statement of Income when the hedged physical transactions occur, the majority of which will occur in 2002, as disclosed above.
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 is fully recovering 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 by their actuary 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) 2001 2000 1999
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period $535,894 $538,796 $532,250
Service Cost 11,550 11,692 12,676
Interest Cost 39,061 37,954 36,299
Amendments 2,343 - 1,691
Actuarial (Gain) Loss 25,358 (20,216) (13,598)
Benefits Paid (34,160) (32,332) (30,522)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Benefit Obligation at End of Period $580,046 $535,894 $538,796
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Plan Assets
Fair Value of Assets at Beginning of Period $569,936 $537,958 $509,393
Actual Return on Plan Assets (19,248) 36,584 47,888
Employer Contribution 20,097 27,726 11,199
Benefits Paid (34,160) (32,332) (30,522)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Fair Value of Assets at End of Period $536,625 $569,936 $537,958
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Reconciliation of Funded Status
Funded Status $(43,421) $34,042 $(838)
Unrecognized Net Actuarial Gain 23,222 (62,008) (45,853)
Unrecognized Transition Asset (7,432) (11,148) (14,864)
Unrecognized Prior Service Cost 12,236 10,943 12,048
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Accrued Benefit Cost $(15,395) $(28,171) $(49,507)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
2001 2000 1999
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate 7.25% 7.50% 7.25%
Expected Return on Plan Assets 8.50% 8.50% 8.50%
Rate of Compensation Increase 5.00% 5.00% 5.00%
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost
Service Cost $11,550 $ 11,692 $ 12,676
Interest Cost 39,061 37,954 36,299
Expected Return on Plan Assets (45,703) (41,077) (38,158)
Amortization of Prior Service Cost 1,050 1,106 1,012
Amortization of Transition Amount (3,716) (3,716) (3,716)
Recognition of Actuarial (Gain) or Loss (2,256) 60 2,833
Early Retirement Window 7,337 - 7,032
Net Amortization and Deferral for
Regulatory Purposes 4,787 206 2,721
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Periodic Benefit Cost $12,110 $ 6,225 $ 20,699
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The effect of the discount rate change in 2001 was to increase the Benefit Obligation by $15.6 million as of the end of the period. The effect of the discount rate change in 2000 was to decrease the Benefit Obligation as of the end of the period by $15.3 million. A reduction in the salary increase assumption decreased the Benefit Obligation in 2001 by $1.5 million as of the end of the period. In 2000, there was no change in the salary increase assumption.
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) 2001 2000 1999 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 266,460 $ 255,615 $ 256,983 Service Cost 4,234 4,156 4,493 Interest Cost 19,557 18,142 17,635 Plan Participants' Contributions 524 414 673 Amendments 33 - - Actuarial (Gain) Loss 26,661 (355) (13,542) Benefits Paid (12,921) (11,512) (10,627) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Benefit Obligation at End of Period $ 304,548 $ 266,460 $ 255,615 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Change in Plan Assets Fair Value of Assets at Beginning of Period $ 176,357 $ 149,884 $ 122,870 Actual Return on Plan Assets (19,685) 18,527 17,345 Employer Contribution 17,684 19,044 19,623 Plan Participants' Contributions 524 414 673 Benefits Paid (12,921) (11,512) (10,627) - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Fair Value of Assets at End of Period $ 161,959 $ 176,357 $ 149,884 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Reconciliation of Funded Status Funded Status $(142,589) $(90,103) $(105,731) Unrecognized Net Actuarial (Gain) Loss 52,832 (8,676) (2,396) Unrecognized Transition Obligation 85,526 92,653 99,780 Unrecognized Prior Service Cost 33 - - - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Accrued Benefit Cost $ (4,198) $ (6,126) $ (8,347) - ----------------------------------------------------------------- ----------------- ---------------- ------------------ ----------------------------------------------------------------- ----------------- ---------------- ----------------- 2001 2000 1999 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Weighted Average Assumptions as of September 30 Discount Rate 7.25% 7.50% 7.25% Expected Return on Plan Assets 8.50% 8.50% 8.50% Rate of Compensation Increase 5.00% 5.00% 5.00% - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Year Ended September 30 (Thousands) Components of Net Periodic Benefit Cost Service Cost $4,234 $4,156 $4,493 Interest Cost 19,557 18,142 17,635 Expected Return on Plan Assets (14,787) (12,574) (10,134) Amortization of Transition Obligation 7,127 7,127 7,127 Amortization of (Gain) Loss (374) (24) 1,304 Net Amortization and Deferral for Regulatory Purposes 4,075 7,269 1,774 - ----------------------------------------------------------------- ----------------- ---------------- ----------------- Net Periodic Benefit Cost $19,832 $ 24,096 $ 22,199 - ----------------------------------------------------------------- ----------------- ---------------- -----------------
The effect of the discount rate change in 2001 was to increase the Benefit Obligation by $9.8 million. The effect of the discount rate change in 2000 was to decrease the Benefit Obligation by $8.9 million.
The health care trend assumptions were changed in 2000 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 $13.7 million. In 2001, there was no change in these assumptions.
The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 8.0% for 1999, 10.0% for 2000, 9.0% for 2001 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 7.0% in 1999, 10.0% in 2000, 9.0% in 2001 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 8.0% for 1999, 15.0% for 2000, 13.0% for 2001 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 8.0% for 1999, 10.0% for 2000, 9.0% for 2001 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, 2001 would be increased by $43.1 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 2001 by $3.8 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2001 would be decreased by $35.4 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2001 by $3.0 million.
Environmental
Matters
The Company is subject to various
federal, state and local laws and regulations relating to the protection of the
environment. The Company has established procedures for the 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 $5.4 million to $6.4 million. The minimum estimated liability of $5.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2001. 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 in progress. At a third site, the Company is negotiating with the DEC for clean-up under a voluntary program under which costs are expected to approximate $1.4 million. 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
88% of contracted demand capacity) expire within the next five years. Costs
incurred under these contracts are purchased gas costs, subject to state
commission review, and are being recovered in customer rates. Management
believes that, to the extent any stranded pipeline costs are generated by the
unbundling of services in the Utility segment’s service territory, such
costs will be recoverable from customers.
The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are currently expected to have a material adverse effect on the financial condition of the Company.
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 and SIP. 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 the FERC, holds a one-third partnership interest in the Independence Pipeline Company, whose rates, services and other matters are or are anticipated to be regulated by the FERC.
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, in the Appalachian region of the United States and in the provinces of Manitoba, Alberta and Saskatchewan 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 is engaged in the retail marketing of natural gas and the performance of energy management services for industrial, commercial, public authority and residential end-users located in the northeastern United States.
The Timber segment's operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings 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, 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 $ 398,344 $97,910 $259,206 $42,091 $2,093,222 $7,130 $ - $2,100,352
Intersegment
Revenues 20,033 90,034 - - - - 110,067 11,192 (121,259) -
Interest Expense 27,489 12,131 56,291 9,966 1,649 3,830 111,356 692 (4,903) 107,145
Depreciation,
Depletion and
Amortization 36,607 23,746 98,408 12,634 212 3,186 174,793 119 2 174,914
Income Tax
Expense 42,985 29,091 (36,075) 253 (1,660) 4,566 39,160 (2,281) 227 37,106
Significant
Non-cash Item:
Impairment of
Oil and Gas
Producing
Properties - - 180,781 - - - 180,781 - - 180,781
Segment Profit
(Loss): Net
Income 60,707 40,377 (32,284) (3,042) (3,432) 7,715 70,041 (4,277) (265) 65,499
Expenditures for
Additions to
Long-Lived Assets 42,374 25,978 296,419 15,585 116 3,694 384,166 937 - 385,103
At September 30, 2001 (Thousands)
- -----------------------------------------------------------------------------------------------------------------------------------------
Segment Assets $1,284,189 $549,991 $1,194,393 $206,361 $68,513 $113,294 $3,416,741 $26,858 $ 1,967 $3,445,566
- -----------------------------------------------------------------------------------------------------------------------------------------
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 $237,845 $104,736 $133,929 $39,172 $1,424,347 $930 $ - $1,425,277
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.
Year Ended September 30, 1999 (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
$ 801,053 $82,994 $140,212 $107,045 $99,088 $31,117 $1,261,509 $1,765 $ - $1,263,274
Intersegment
Revenues 6,302 85,789 6,782 - - - 98,873 - (98,873) -
Interest Expense 29,659 13,147 34,409 11,451 234 2,208 91,108 100 (3,510) 87,698
Depreciation,
Depletion and
Amortization 34,215 22,690 55,750 10,473 165 1,476 124,769 7 2 124,778
Income Tax
Expense 34,741 22,439 2,992 15 1,138 2,788 64,113 55 661 64,829
Segment Profit
(Loss): Net Income 56,875 39,765 7,127 2,276 2,054 4,769 112,866 (162) 2,333 115,037
Expenditures for
Additions to
Long-Lived Assets 46,974 34,873 97,586 33,412 302 52,314 265,461 66 - 265,527
At September 30, 1999 (Thousands)
- ------------------------------------------------------------------------------------------------------------------------------------------
Segment Assets $1,178,185 $542,962 $727,557 $255,042 $18,676 $98,830 $2,821,252 $7,351 $13,983 $2,842,586
- ------------------------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------- ------------------ -------------------- -------------------
Geographic Information 2001 2000 1999
-------------------------------------------------------- ------------------ -------------------- -------------------
For the Year Ended September 30 (Thousands)
Revenues from External Customers(1):
United States $1,928,474 $1,292,190 $1,156,229
Czech Republic 97,910 104,736 107,045
Canada 73,968 28,351 -
-------------------------------------------------------- ------------------ -------------------- -------------------
$2,100,352 $1,425,277 $1,263,274
At September 30 (Thousands)
-------------------------------------------------------- ------------------ -------------------- -------------------
Long-Lived Assets:
United States $2,645,764 $2,488,180 $2,369,840
Czech Republic 187,961 183,274 215,457
Canada 257,939 248,937 -
-------------------------------------------------------- ------------------ -------------------- -------------------
$3,091,664 $2,920,391 $2,585,297
-------------------------------------------------------- ------------------ -------------------- -------------------
(1) Revenue is based upon the country in which the sale originates.
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
---------------------------------------------------------------- --------------------- ---------------------
Total goodwill outstanding amounted to $11.1 million and $12.1 million at September 30, 2001 and 2000, respectively. This goodwill is recorded in Other Assets and is being amortized over a maximum period of twenty years.
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 - --------------------- ------------------- ------------------ -------------------- ---------------- ----------------- 2001 (Thousands, except per common share amounts) - --------------------- ----------------------------------------------------------- ---------------------------------- 12/31/2000 $559,504 $75,121 $52,984(1) $0.67 $0.66 3/31/2001 $879,869 $103,572 $75,275(2) $0.95 $0.94 6/30/2001 $406,494 $59,603 $36,618 $0.46 $0.45 9/30/2001 $254,485 $ (79,566) $(99,378)(3) $(1.25) $ (1.24) - --------------------- ----------------------------------------------------------------- ---------------------------- 2000 (Thousands, except per common share amounts) - --------------------- ----------------------------------------------------------------- ---------------------------- 12/31/1999 $377,031 $70,237 $ 44,868 $ 0.58 $0.57 3/31/2000 $517,767 $91,074 $ 71,051 $ 0.91 $0.90 6/30/2000 $281,201 $30,043 $ 9,070(4) $ 0.12 $0.11 9/30/2000 $249,278 $26,914 $ 2,218(5) $ 0.03 $0.03 - --------------------- ------------------- ------------------ -------------------- ---------------- -----------------
(1) 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.
(2) Includes income of $9.7 million related to SARs and expense of $4.2 million related to early retirement offers.
(3) Includes income of $5.3 million related to SARs and expense of $104.0 million related to the impairment of oil and gas assets.
(4) Includes expense of $14.2 million related to mark-to-market and other revenue adjustments related to derivative financial instruments and expense of $3.5 million related to SARs.
(5) Includes expense of $6.6 million related to SARs, expense of $3.7 million for adjustments related to the New York rate settlement, expense of $1.6 million related to the recording of a loss contingency on fixed price sales contracts and income of $3.9 million related to mark-to-market and other revenue adjustments related to derivative financial instruments.
At September 30, 2001, there were 20,345 holders of National Fuel Gas 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, 2001 and 2000, are shown below:
- --------------------------------------------------------------- ------------------------------------ -----------------
Price Range Dividends
------------------------------------
Quarter Ended High Low Declared
- --------------------------------------------------------------- ------------------- ---------------- -----------------
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
- --------------------------------------------------------------- ------------------- ---------------- -----------------
2000
- --------------------------------------------------------------- ------------------- ---------------- -----------------
12/31/1999 $26.47 $23.00 $.2325
3/31/2000 $23.38 $19.69 $.2325
6/30/2000 $25.97 $21.57 $.240
9/30/2000 $29.41 $24.07 $.240
- --------------------------------------------------------------- ------------------- ---------------- -----------------
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)
2001 2000
- ----------------------------------------------------------------------------------- ---------------- -----------------
Proved Properties $1,586,889 $1,218,871
Unproved Properties 152,326 152,360
- ----------------------------------------------------------------------------------- ---------------- -----------------
1,739,215 1,371,231
Less - Accumulated Depreciation, Depletion
and Amortization 675,256 390,267
- ----------------------------------------------------------------------------------- ---------------- -----------------
$1,063,959 $980,964
- ----------------------------------------------------------------------------------- ---------------- -----------------
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, 2001:
- ---------------------------- -------------------------- --------------------------------------------------------------
Total as of Year Costs Incurred
--------------------------------------------------------------
(Thousands) September 30, 2001 2001 2000 1999 Prior
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
Acquisition Costs $152,326 $35,272 $72,797 $4,675 $39,582
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
Proved $ 1,713 $ 2,848 $ 2,798
Unproved 15,296 19,066 11,530
Exploration Costs 42,338 50,163 52,141
Development Costs 88,987 72,039 30,985
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
148,334 144,116 97,454
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs:
Proved 115,643 159,268 -
Unproved 2,612 77,198 -
Exploration Costs 8,523 573 -
Development Costs 36,554 11,013 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
163,332 248,052 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs: (1)
Proved 117,356 162,116 2,798
Unproved 17,908 96,264 11,530
Exploration Costs 50,861 50,736 52,141
Development Costs 125,541 83,052 30,985
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
$311,666 $392,168 $97,454
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(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) 2001 2000 1999
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates
of $4, $237 and $6,365, respectively) $216,729 $137,336 $ 81,734
Oil, Condensate and Other Liquids 121,973 107,645 51,592
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 338,702 244,981 133,326
Production/Lifting Costs 37,068 33,979 28,119
Depreciation, Depletion and Amortization
($1.13, $0.97 and $0.89 per Mcfe of production) 76,686 64,624 54,439
Income Tax Expense 83,649 52,656 16,255
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) 141,299 93,722 34,513
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas 4,379 485 -
Oil, Condensate and Other Liquids 74,349 26,320 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 78,728 26,805 -
Production/Lifting Costs 27,089 7,858 -
Depreciation, Depletion and Amortization
($0.93, $0.77 and $ - per Mcfe of production) 18,719 4,321 -
Impairment of Oil and Gas Producing Properties(2) 180,781 - -
Income Tax Expense (Benefit) (63,795) 6,121 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) (84,066) 8,505 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates
of $4, $237 and $6,365, respectively) 221,108 137,821 81,734
Oil, Condensate and Other Liquids 196,322 133,965 51,592
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 417,430 271,786 133,326
Production/Lifting Costs 64,157 41,837 28,119
Depreciation, Depletion and Amortization
($1.08, $0.95 and $0.89 per Mcfe of production) 95,405 68,945 54,439
Impairment of Oil and Gas Producing Properties(2) 180,781 - -
Income Tax Expense 19,854 58,777 16,255
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) $ 57,233 $102,227 $ 34,513
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(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, 1998 325,065 - 325,065 66,591 - 66,591
Extensions and Discoveries 46,423 - 46,423 3,716 - 3,716
Revisions of
Previous Estimates (13,091) - (13,091) 9,808 - 9,808
Production (37,166) - (37,166) (4,016) - (4,016)
Sales of Minerals in Place (439) - (439) (280) - (280)
Purchases of Minerals
in Place and Other - - - - - -
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
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
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
Proved Developed Reserves:
September 30, 1998 230,508 - 230,508 48,081 - 48,081
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
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
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)
2001 2000 1999
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows $2,127,601 $3,886,499 $2,402,308
Less:
Future Production Costs 602,479 600,243 560,459
Future Development Costs 121,240 179,565 185,617
Future Income Tax Expense at
Applicable Statutory Rate 376,667 1,006,366 477,205
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 1,027,215 2,100,325 1,179,027
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 421,865 859,950 471,768
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows 605,350 1,240,375 707,259
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows 890,381 1,083,598 -
Less:
Future Production Costs 533,848 277,067 -
Future Development Costs 19,608 21,399 -
Future Income Tax Expense at
Applicable Statutory Rate 76,191 286,148 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 260,734 498,984 -
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 79,295 221,227 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows 181,439 277,757 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows 3,017,982 4,970,097 2,402,308
Less:
Future Production Costs 1,136,327 877,310 560,459
Future Development Costs 140,848 200,964 185,617
Future Income Tax Expense at
Applicable Statutory Rate 452,858 1,292,514 477,205
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 1,287,949 2,599,309 1,179,027
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 501,160 1,081,177 471,768
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows $ 786,789 $1,518,132 $707,259
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 2001 2000 1999
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
United States
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $1,240,375 $707,259 $466,771
Sales, Net of Production Costs (301,634) (211,002) (53,615)
Net Changes in Prices, Net of Production Costs (921,719) 795,408 317,356
Purchases of Minerals in Place 1,191 - -
Sales of Minerals in Place (17,552) (11,914) (2,706)
Extensions and Discoveries 52,062 186,818 122,894
Changes in Estimated Future Development Costs (3,157) (82,270) (97,082)
Previously Estimated Development Costs Incurred 61,482 88,322 72,349
Net Change in Income Taxes at
Applicable Statutory Rate 363,425 (292,371) (232,085)
Revisions of Previous Quantity Estimates (29,841) 20,736 40,964
Accretion of Discount and Other 160,718 39,389 72,413
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 605,350 1,240,375 707,259
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Canada
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year 277,757 - -
Sales, Net of Production Costs (51,638) (18,948) -
Net Changes in Prices, Net of Production Costs (161,461) - -
Purchases of Minerals in Place 30,575 424,072 -
Sales of Minerals in Place (761) - -
Extensions and Discoveries 39,752 2,979 -
Changes in Estimated Future Development Costs (31,009) - -
Previously Estimated Development Costs Incurred 12,176 - -
Net Change in Income Taxes at
Applicable Statutory Rate 73,865 (150,057) -
Revisions of Previous Quantity Estimates (64,368) - -
Accretion of Discount and Other 56,551 19,711 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year 181,439 277,757 -
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year 1,518,132 707,259 466,771
Sales, Net of Production Costs (353,272) (229,950) (53,615)
Net Changes in Prices, Net of Production Costs (1,083,180) 795,408 317,356
Purchases of Minerals in Place 31,766 424,072 -
Sales of Minerals in Place (18,313) (11,914) (2,706)
Extensions and Discoveries 91,814 189,797 122,894
Changes in Estimated Future Development Costs (34,166) (82,270) (97,082)
Previously Estimated Development Costs Incurred 73,658 88,322 72,349
Net Change in Income Taxes at
Applicable Statutory Rate 437,290 (442,428) (232,085)
Revisions of Previous Quantity Estimates (94,209) 20,736 40,964
Accretion of Discount and Other 217,269 59,100 72,413
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $ 786,789 $1,518,132 $707,259
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Schedule II - Valuation and Qualifying Accounts
Back to Index of Financial Statements
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
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, 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
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 1999
Reserve for Doubtful Accounts $6,232 $15,337 $ 1 $13,728 $7,842
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
(1) Represents opening balance sheet reserve plus exchange rate impact of translating the Czech koruna to the U.S. dollar for Horizon.
(2) Amounts represent net accounts receivable written-off.
PART III
PART IV
(a)1. Financial Statements
Financial statements filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and
reference is made thereto.
(a)2. Financial Statement Schedules
Financial 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:
• 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:
3.1 National Fuel Gas Company By-Laws as amended on September 20, 2001
(4) Instruments Defining the Rights of Security Holders, Including Indentures:
• Indenture, dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company)
(Exhibit 2(b) in File No. 2-51796)
• Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No. 33-49401)
• Tenth Supplemental Indenture, dated as of February 1, 1992, to Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a), Form 8-K dated February 14, 1992 in File No.
1-3880)
• Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and
The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992 in File No.
1-3880)
• Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and
The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992 in File No. 1-3880)
• Thirteenth Supplemental Indenture, dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401)
• Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30,
1993 in File No. 1-3880)
• Fifteenth Supplemental Indenture, dated as of September 1, 1996, to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
• Indenture, dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1, Form 10-K for fiscal year
ended September 30, 1999 in File No. 1-3880)
• Officer's Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2, Form 10-K for fiscal year ended
September 30, 1999 in File No. 1-3880)
• Amended and Restated Rights Agreement, dated as of April 30, 1999, between the Company and HSBC Bank USA (Exhibit 10.2,
Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880)
• Certificate of Adjustment, dated September 7, 2001, to the Amended and Restated Rights Agreement dated as of April 30, 1999,
between the Company and HSBC Bank USA (Exhibit 4, Form 8-K dated September 7, 2001 in File No. 1-3880)
(10) Material Contracts:
(iii) Compensatory plans for officers:
• 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)
• 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)
• 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)
• 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)
• 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)
• 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)
• Form of Employment Continuation and Noncompetition Agreements, dated as of December 11, 1998, between the Company and each
of Philip C. Ackerman, Walter E. DeForest, Joseph P. Pawlowski, Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin
(Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)
• Severance Agreement, Release and Waiver dated March 27, 2000, between National Fuel Gas Supply Corporation and Richard Hare
(Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 2000)
• Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, between the Company and James
A. Beck (Exhibit 10.3, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880)
• National Fuel Gas Company 1983 Incentive Stock Option Plan, as amended and restated through February 18, 1993 (Exhibit 10.2,
Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880)
• National Fuel Gas Company 1984 Stock Plan, as amended and restated through February 18, 1993 (Exhibit 10.3, Form 10-Q for
the quarterly period ended March 31, 1993 in File No. 1-3880)
• 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)
• National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1, Form 10-Q for the quarterly
period ended March 31, 1993 in File No. 1-3880)
• Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8, Form 10-K for
fiscal year ended September 30, 1995 in File No. 1-3880)
• Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
• Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10, Form 10-Q for the
quarterly period ended December 31, 1996 in File No. 1-3880)
10.1 National Fuel Gas Company 1993 Award and Option Plan, amended through June 14, 2001
10.2 National Fuel Gas Company 1997 Award and Option Plan, amended through June 14, 2001
10.3 Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001
• National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7, Form 10-K
for fiscal year ended September 30, 1994 in File No. 1-3880)
• Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
• Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9, Form 10-K for
fiscal year ended September 30, 1995 in File No. 1-3880)
• National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3, Form
10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
• Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4, Form 10-K for fiscal
year ended September 30, 1997 in File No. 1-3880)
• Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1, Form 10-K
for fiscal year ended September 30, 1998 in File No. 1-3880)
• Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit 10.1, Form 10-Q for
the quarterly period ended March 31, 1999 in File No. 1-3880)
• National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10, Form 10-Q for the quarterly period ended June
30, 1997 in File No. 1-3880)
• Amendment No. 1 to National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2, Form 10-K for fiscal year ended
September 30, 1998 in File No. 1-3880)
• Amendment No. 2 to National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1, Form 10-Q for the quarterly
period ended December 31, 1998 in File No. 1-3880)
• 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)
• 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)
• Amended and Restated Split Dollar Insurance Agreement, effective June 15, 2000, among the Company, Bernard J. Kennedy, and
Joseph B. Kennedy, as Trustee of the Trust under the Agreement dated January 9, 1998 (Exhibit 10.1, Form 10-Q for the
quarterly period ended June 30, 2000 in File No. 1-3880)
• Contingent Benefit Agreement, effective June 15, 2000 between the Company and Bernard J. Kennedy (Exhibit 10.2, Form 10-Q
for the quarterly period ended June 30, 2000 in File No. 1-3880)
• Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and
Philip C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
• Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and
Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1999 in File No.
1-3880)
• Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and
Joseph P. Pawlowski (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
• Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and
Joseph P. Pawlowski, dated March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1999 in File
No. 1-3880)
• 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)
• 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)
• 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)
• Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and
Dennis J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and
Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1999 in File No.
1-3880)
• Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997, between the Company and Bruce H. Hale (Exhibit
10.11, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and Bruce H. Hale, dated
March 29, 1999 (Exhibit 10.12, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith
(Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith,
dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• 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)
• National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10,
1996 (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880)
• Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997
(Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880)
• Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998
(Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880)
• Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16,
1999 (Exhibit 10.15, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880)
• Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 13, 2001
(Exhibit 10(iii)(c), Form 8-K dated September 19, 2001 in File No. 1-3880)
• Administrative Rules with Respect to at Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
• Administrative Rules with Respect to at Risk Awards under the 1997 Award and Option Plan (Exhibit A, Definitive Proxy
Statement, Schedule 14(A) filed January 14, 2000 in File No. 1-3880)
• 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)
• 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)
• 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, 1977 through 2001
(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.
• 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 September 19, 2001 was filed on September 21, 2001, to report the election of Philip C. Ackerman as Chief Executive Officer, under Item 5, “Other Events.” Related exhibits were reported under Item 7, “Financial Statements, Pro Forma Financial Information and Exhibits.” |
| A report on Form 8-K dated September 7, 2001 was filed on September 7, 2001, to report information related to the Company’s two-for-one stock split, under Item 5, “Other Events.” A related exhibit was reported under Item 7, “Financial Statements, Pro Forma Financial Information and Exhibits.” |
| A report on Form 8-K dated July 25, 2001 was filed on July 27, 2001, to report the release of revised earnings projections for fiscal year 2002 for the Company and its subsidiary, Seneca Resources Corporation, under Item 5, “Other Events.” Related exhibits were reported under Item 7, “Financial Statements, Pro Forma Financial Information 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/ B. J. Kennedy
B. J. Kennedy
Chairman of the Board
Date: December 13, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title
/s/ B. J. Kennedy Chairman of the Board
B. J. Kennedy
Date: December 13, 2001
/s/ P. C. Ackerman Chief Executive Officer,
P. C. Ackerman President, Principal Financial
Officer and Director
Date: December 13, 2001
/s/ R. T. Brady Director
R. T. Brady
Date: December 13, 2001
/s/ J. V. Glynn Director
J. V. Glynn
Date: December 13, 2001
/s/ W. J. Hill Director
W. J. Hill
Date: December 13, 2001
/s/ B. S. Lee Director
B. S. Lee
Date: December 13, 2001
/s/ E. T. Mann Director
E. T. Mann
Date: December 13, 2001
/s/ G. L. Mazanec Director
G. L. Mazanec
Date: December 13, 2001
/s/ J. F. Riordan Director
J. F. Riordan
Date: December 13, 2001
/s/ J. P. Pawlowski Treasurer and Principal
J. P. Pawlowski Accounting Officer
Date: December 13, 2001
APPENDIX TO ITEM 2 - PROPERTIES
Six maps outlining the Company’s operating areas at September 30, 2001 are included on the back of the front cover and page 1 of the paper format version of the Company’s Annual Report to Shareholders. The first map identifies the Company’s Exploration and Production operating area (i.e., Seneca’s operating area). The second map identifies the Company’s Pipeline and Storage operating area (i.e., Supply Corporation’s storage areas and pipelines). The third map identifies the Company’s Utility operating area (i.e., Distribution Corporation’s service area). The fourth map identifies the Company’s Energy Marketing operating area (i.e., NFR’s marketing service area). The fifth map identifies the Company’s Timber operating area (i.e., Seneca’s and Highland’s timber and sawmill operations). The sixth map identifies the Company’s International operating area (i.e., Horizon’s Czech Republic operations).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 2001
Two pie graphs detailing the revenue dollar in 2001: where it came from and where it went to, broken down as follows:
Where it came from:
$ .414 Residential Gas Sales
.161 Oil and Gas Production Revenues
.126 Commercial, Industrial and Off-System Gas Sales
.123 Energy Marketing Revenues
.051 Gas Transportation Revenues
.033 District Heating Revenues
.020 Timber and Sawmill Revenues
.014 Gas Storage Service Revenues
.012 Electric Generation Revenues
.046 Other Revenues
$1.000 Total
Where it went to:
$ .495 Gas Purchased
.089 Wages, Including Benefits
.085 Impairment of Oil and Gas Producing Properties
.083 Other Materials and Services
.083 Depreciation
.057 Taxes
.050 Interest
.031 Earnings
.026 Fuel Used in Heat and Electric Generation
.001 Minority Interest in Foreign Subsidiaries
$1.000 Total
Exhibit Index
-------------
3.1 National Fuel Gas Company By-Laws as amended on
September 20, 2001
10.1 National Fuel Gas Company 1997 Award and Option Plan,
amended through June 14, 2001
10.2 National Fuel Gas Company 1997 Award and Option Plan,
amended through June 14, 2001
10.3 Amendment to National Fuel Gas Company Deferred
Compensation Plan, dated June 15, 2001
(12) Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the fiscal years
ended September 30, 1977 through 2001
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
99.1 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.