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, 1999
Commission File Number 1-3880
National Fuel Gas Company
(Exact name of registrant as specified in its charter)
New Jersey 13-1086010
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
10 Lafayette Square 14203
Buffalo, New York (Zip Code)
(Address of principal executive offices)
(716) 857-6980
Registrant's telephone number, including area code
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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 $1,907,786,000 as of November 30, 1999.
Common Stock, $1 Par Value, outstanding as of November 30, 1999:
38,966,378 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Annual Report to Shareholders for 1999 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 17, 2000 are incorporated by reference into Part III of this
report.
For the Fiscal Year Ended September 30, 1999
Contents
Part I Page
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ITEM 1 Business
THE COMPANY AND ITS SUBSIDIARIES.......................................19
RATES AND REGULATION...................................................21
THE UTILITY SEGMENT....................................................22
THE PIPELINE AND STORAGE SEGMENT.......................................22
THE EXPLORATION AND PRODUCTION SEGMENT.................................22
THE INTERNATIONAL SEGMENT..............................................22
THE ENERGY MARKETING SEGMENT...........................................23
THE TIMBER SEGMENT.....................................................23
SOURCES AND AVAILABILITY OF RAW MATERIALS..............................23
COMPETITION............................................................24
SEASONALITY............................................................25
CAPITAL EXPENDITURES...................................................26
ENVIRONMENTAL MATTERS..................................................26
MISCELLANEOUS..........................................................26
EXECUTIVE OFFICERS OF THE COMPANY......................................26
ITEM 2 PROPERTIES
GENERAL INFORMATION ON FACILITIES......................................27
EXPLORATION AND PRODUCTION ACTIVITIES..................................28
ITEM 3 Legal Proceedings..................................................29
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................29
Part II
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ITEM 5 Market for the Registrant's Common Stock and Related
Shareholder Matters................................................29
ITEM 6 Selected Financial Data............................................30
ITEM 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations................................31
ITEM 7A Quantitative and Qualitative Disclosures About Market Risk........57
ITEM 8 Financial Statements and Supplementary Data........................57
ITEM 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................89
Part III
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ITEM 10 Directors and Executive Officers of the Registrant................89
ITEM 11 Executive Compensation............................................89
ITEM 12 Security Ownership of Certain Beneficial Owners and Management....89
ITEM 13 Certain Relationships and Related Transactions....................89
Part IV
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ITEM 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K..90
Signatures................................................................93
This combined Annual Report to Shareholders/Form 10-K contains "forward-looking
statements" as defined by the Private Securities Litigation Reform Act of 1995.
Forward-looking statements should be read with the cautionary statements
included in this combined Annual Report to Shareholders/Form 10-K at Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations (MD&A), under the heading "Safe Harbor for Forward-Looking
Statements." Forward-looking statements are all statements other than statements
of historical fact, including, without limitation, those statements that are
designated with a "*" 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
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ITEM 1 Business
The Company and its Subsidiaries
National Fuel Gas Company (the Company or Registrant), a registered holding
company under the Public Utility Holding Company Act of 1935, as amended (the
Holding Company Act), was organized under the laws of the State of New Jersey on
December 8, 1902. The Company is engaged in the business of owning and holding
securities issued by its subsidiary companies. Except as otherwise indicated
below, the Company owns all of the outstanding securities of its subsidiaries.
Reference to "the Company" in this report means the Registrant or the Registrant
and its subsidiaries collectively, as appropriate in the context of the
disclosure.
The Company is a diversified energy company consisting of the six
reportable business segments. This report includes two newly-reported segments -
Energy Marketing and Timber - and no longer includes the previously reported
"Other Nonregulated" segment. As a result of these refinements in the Company's
reportable segments, where appropriate in this report the information for 1998
and 1997 has been restated from the prior year's presentation to conform to the
1999 presentation.
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 and provides natural gas
transportation services through a local distribution system located in western
New York and northwestern Pennsylvania (principal metropolitan areas: Buffalo,
Niagara Falls and Jamestown, New York; Erie and Sharon, Pennsylvania).
2. The Pipeline and Storage segment 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) 29 underground natural gas
storage fields owned and operated by Supply Corporation and four other
underground natural gas storage fields operated jointly with various major
interstate gas pipeline companies. SIP holds a one-third general partnership
interest in Independence Pipeline Company (Independence), a Delaware general
partnership. Independence, after receipt of regulatory approvals and upon
securing sufficient customer interest, plans to construct and operate the
Independence Pipeline, a 370-mile interstate pipeline system which would
transport about 900,000 dekatherms per day (Dth/day) of natural gas from
Defiance, Ohio to Leidy, Pennsylvania.*
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, and in California,
Wyoming and in the Appalachian region of the United States.
4. The International segment operations are carried out by Horizon Energy
Development, Inc. (Horizon), a New York corporation. Horizon engages in foreign
energy projects through the investments of its indirect subsidiaries as the sole
or substantial owner of various business entities. Horizon is the sole
shareholder of Horizon Energy Holdings, Inc., a New York corporation which in
turn, owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V.
is a Dutch company whose principal assets consist of a majority ownership in (i)
Severoeeske teplarny, a.s. (SCT), a company with district heating and power
generation operations located in the northern part of the Czech Republic; (ii)
Prvni severozapadni teplarenska, a.s. (PSZT), a wholesale power and district
heating company that is located in the Czech Republic in close proximity to SCT;
and (iii) Teplarna Kromeriz, 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 electricity and the performance of energy
management services for industrial, commercial, public authority and residential
end-users throughout the northeast United States.
6. The Timber segment operations are carried out by Highland Land & Minerals,
Inc. (Highland), a Pennsylvania corporation, and by a division of Seneca known
as its Northeast Division. Highland owns four sawmill operations in northwestern
Pennsylvania and processes timber consisting primarily of high quality
hardwoods. The Northeast Division of Seneca markets timber from its New York and
Pennsylvania land holdings.
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 discussion of the Company's business segments as contained in
the business segment discussion on pages 7 to 16 of the paper copy of the
Company's combined Annual Report to Shareholders/Form 10-K, is included in this
electronic filing as Exhibit 13 and is incorporated herein by reference.
The Company's other wholly-owned subsidiaries are not included in any
of the six reportable business segments and consist of the following:
o Upstate Energy Inc. (Upstate) (formerly known as Niagara Energy
Trading Inc.), a New York corporation engaged in wholesale natural
gas marketing and other energy-related activities;
o Niagara Independence Marketing Company (NIM), a Delaware
corporation which owns a one-third general partnership interest in
DirectLink Gas Marketing Company (DirectLink), a Delaware general
partnership. DirectLink was formed to engage in natural gas
marketing and related businesses, in part by subscribing for firm
transportation capacity on the Independence Pipeline;
o Leidy Hub, Inc. (Leidy), a New York corporation formed to provide
various natural gas hub services to customers in the eastern
United States through a 50% ownership of Ellisburg-Leidy Northeast
Hub Company (a Pennsylvania general partnership);
o Data-Track Account Services, Inc. (Data-Track), a New York
corporation which provides collection services principally for the
Company's subsidiaries; and
o NFR Power, Inc. (NFR Power), a New York corporation capitalized by
the Company in 1999 which, while not actively generating
electricity at this time, is designated as an "exempt wholesale
generator" under the Holding Company Act.
No single customer, or group of customers under common control,
accounted for more than 10% of the Company's consolidated revenues in 1999.
Any reference to a year in this report is to the Company's fiscal year
ended September 30 of that year unless otherwise noted.
Rates and Regulation
The Company is subject to regulation by the Securities and Exchange Commission
(SEC) under the broad regulatory provisions of the Holding Company Act,
including provisions relating to issuance of securities, sales and acquisitions
of securities and utility assets, intra-Company transactions and limitations on
diversification. The SEC 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. The proposed
legislation currently under consideration 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.
Such legislation could actually increase regulation of the Company, especially
at the state level. Previous SEC rule changes, however, 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 current or future
legislative and/or regulatory initiatives 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 rates, services
and other matters 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
The Utility segment contributed approximately 49.4% of the Company's net income
available for common stock in 1999.
Additional discussion of the Utility segment appears in the business
segment discussion contained in this combined Annual Report to Shareholders/Form
10-K, below in this Item 1 under the headings "Sources and Availability of Raw
Materials" and "Competition," in Item 7, MD&A and in Item 8 at Notes
B-Regulatory Matters, H-Commitments and Contingencies and I-Business Segment
Information.
The Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 34.6% of the
Company's net income available for common stock in 1999.
Supply Corporation currently has service agreements for substantially
all of its firm transportation capacity, which totals approximately 1,943
million cubic feet (MMcf) per day. The Utility segment has contracted for
approximately 1,126 MMcf per day or 58% of that capacity until 2003 and
continuing year-to-year thereafter. An additional 25% of Supply Corporation's
firm transportation capacity is subject to firm contracts with nonaffiliated
customers until 2003 or later.
Supply Corporation has available for sale to customers approximately
62.8 billion cubic feet (Bcf) of firm storage capacity. The Utility segment has
contracted for 26.0 Bcf or 41% of that capacity, in service agreements with
remaining initial terms of approximately 4 to 7 years and continuing
year-to-year thereafter: 23.3 Bcf - 4 years; 2.0 Bcf - 7 years and 0.7 Bcf - 5
years. Nonaffiliated customers have contracted for the remaining 36.8 Bcf or 59%
of firm storage capacity; 12.1 Bcf or 19% of total storage capacity is
contracted by nonaffiliated customers until 2003 or later. 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.*
Independence has filed with the FERC signed precedent agreements
providing for firm transportation service totaling about 629,000 Dth/day for ten
years, out of total proposed transportation capacity of about 900,000 Dth/day.
The customer for 500,000 Dth/day of that total is DirectLink, which is owned by
the sponsors of the Independence Pipeline, including NIM.
Additional discussion of the Pipeline and Storage segment appears in
the business segment discussion contained in this combined Annual Report to
Shareholders/Form 10-K, below under the headings "Sources and Availability of
Raw Materials" and "Competition," Item 7, MD&A and Item 8 at Notes B-Regulatory
Matters, H-Commitments and Contingencies and I-Business Segment Information.
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 6.2% of the
Company's net income available for common stock in 1999.
Additional discussion of the Exploration and Production segment appears
in the business segment discussion contained in this combined Annual Report to
Shareholders/Form 10-K, below under the headings "Sources and Availability of
Raw Materials" and "Competition," Item 7, MD&A and Item 8 at Notes A-Summary of
Significant Accounting Policies, F-Financial Instruments, I-Business Segment
Information, J-Stock Acquisitions and M-Supplementary Information for Oil and
Gas Producing Activities.
The International Segment
The International segment contributed approximately 2.0% of the Company's net
income available for common stock in 1999.
Additional discussion of the International segment appears in the
business segment discussion contained in this combined Annual Report to
Shareholders/Form 10-K, below under the headings "Sources and Availability of
Raw Materials" and "Competition," Item 7, MD&A and Item 8 at Notes F-Financial
Instruments, I-Business Segment Information and J-Stock Acquisitions.
The Energy Marketing Segment
The Energy Marketing segment contributed approximately 1.8% of the Company's net
income available for common stock in 1999.
Additional discussion of the Energy Marketing segment appears in the
business segment discussion contained in this combined Annual Report to
Shareholders/Form 10-K, below under the headings "Sources and Availability of
Raw Materials" and "Competition," Item 7, MD&A and Item 8 at Notes F-Financial
Instruments and I-Business Segment Information.
The Timber Segment
The Timber segment contributed approximately 4.1% of the Company's net income
available for common stock in 1999.
Additional discussion of the Timber segment appears in the business
segment discussion contained in this combined Annual Report to Shareholders/Form
10-K, below under the headings "Sources and Availability of Raw Materials" and
"Competition," Item 7, MD&A and Item 8 at Note I-Business Segment Information.
Sources and Availability of Raw Materials
Natural gas is the principal raw material for the Utility segment. In 1999, the
Utility segment purchased 112.4 Bcf of gas. Gas purchases from various producers
and marketers in the southwestern United States under long-term (two years or
longer) contracts accounted for 66% of these purchases. Purchases of gas in
Canada and the United States on the spot market (contracts of less than a year)
accounted for 29% of the Utility segment's 1999 gas purchases. Gas purchases
from Southern Company Energy Marketing L.P. and Dynegy Marketing and Trade
represented 17% and 13%, respectively, of total 1999 gas purchases by the
Utility segment. No other producer or marketer provided the Utility segment with
10% or more of its gas requirements in 1999.
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 midwestern United States.
The Exploration and Production segment seeks to discover and produce
raw materials (natural gas, oil and hydrocarbon liquids) as described in the
business segment discussion contained in this combined Annual Report to
Shareholders/Form 10-K, Item 7, MD&A and Item 8 at Notes I-Business Segment
Information and M - Supplementary Information for Oil and Gas Producing
Activities.
Coal is the principal raw material for the International segment,
constituting 45% of the cost of raw materials needed to operate the boilers
which produce steam or hot water. Natural gas, fuel oil, limestone and water
combined account for the remaining 55% of such materials. Coal is purchased and
delivered directly from the Mostecka Uhelna Spoleenost, a.s. mine for Horizon's
largest coal-fired plant under a contract where price and quantity are the
subject of negotiation each year. Natural gas is imported by the Czech Republic
government from Russia and the North Sea and is transported through the Transgas
pipeline system which is majority owned by the Czech Republic government and
purchased by the International segment from two of the eight regional gas
distribution companies. Fuel oil used to fire certain of the boilers is
purchased from both domestic Czech Republic and foreign refineries.
The Energy Marketing segment depends on an adequate supply of natural
gas and electricity. In 1999, this segment purchased approximately 34.5 Bcf of
natural gas and approximately 73,000 megawatt hours of electricity.
With respect to the Timber segment, Highland requires an adequate
supply of timber to process. Highland, however, mainly processes timber which is
located on land owned by Seneca, and therefore, the source and availability of
this segment's primary raw material are generally known in advance.
Competition
Competition in the natural gas industry exists among providers of natural gas,
as well as between natural gas and other sources of energy. The continuing
deregulation of the natural gas industry should enhance the competitive position
of natural gas relative to other energy sources by removing some of the
regulatory impediments to adding customers and responding to market forces.* In
addition, the environmental advantages of natural gas compared with other fuels
should increase the role of natural gas as an energy source.* Moreover, natural
gas is abundantly available in North America, which makes it a dependable
alternative to imported oil.
The electric industry is moving toward a more competitive environment
as a result of the Federal Energy Policy Act of 1992 and initiatives undertaken
by the FERC and various states. It is unclear at this point what impact this
restructuring will have on the Company.*
The Company competes on the basis of price, service and reliability,
product performance and other factors.
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. State restructuring initiatives are under way, with
regulators in both New York and Pennsylvania adopting 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 and/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 midwestern
regions of the United States. This location offers the opportunity for increased
transportation and storage services in the future.*
SIP, through Independence, is competing for customers with other
proposed pipeline projects which would bring natural gas from the Chicago area
to the growing Northeast and Mid-Atlantic United States markets. In combination
with expansion projects of Transcontinental Gas Pipe Line Corporation and ANR
Pipeline Company, Independence intends to provide the least-cost path for this
service and 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.*
Independence is attempting to be the first of the proposed projects approved by
the FERC and the first built.* If completed, the Independence pipeline would
likely create opportunities for increased transportation and storage services by
Supply Corporation.*
Competition: The Exploration and Production Segment
The Exploration and Production segment competes with other gas and oil producers
and marketers with respect to its sales of oil and gas. The Exploration and
Production segment also competes, by competitive bidding and otherwise, with
other oil and 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 originates and acts as operator
on most prospects, minimizes risk of exploratory efforts through
partnership-type arrangements, applies the latest technology for both
exploratory studies and drilling operations and focuses on market niches that
suit its size, operating expertise and financial criteria.
Competition: The International Segment
Horizon competes with other entities seeking to develop foreign and domestic
energy projects. Horizon, through SCT and PSZT, faces competition in the sales
of thermal energy to large industrial customers. Currently, electric energy
sales are made to the regional electric distribution companies. The Czech
Ministry of Finance has announced plans to privatize these distribution
companies. While it is expected that these plans will increase competition at
the retail level of the electric energy market, it is unclear at this point what
impact this privatization will have on the wholesale electric energy market.*
Both SCT and PSZT sell electricity at the wholesale level.
Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of electricity and
natural gas and with other providers of energy management services. Although the
deregulation of electric and natural gas utilities is a relatively new
occurrence, the competition in this area is well developed with regard to price
and services and derives primarily from both local and regional marketers.
Competition: The Timber Segment
Highland competes with other sawmill operations and Seneca competes with other
suppliers of timber. This competition may be local, regional, national or
international in scope. These competitors, however, are primarily limited to
those entities which either process or supply high quality hardwoods species,
such as cherry, oak and maple as veneer, or 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
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. In the International segment, district
heating operations in the Czech Republic are also subject to the seasonality of
weather.
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 all fixed costs in fixed monthly reservation charges.
Variable charges based on volumes are designed only to reimburse the variable
costs caused by actual transportation or storage of gas.
Variations in weather conditions can materially affect the volume of
gas and electricity consumed by customers of the Energy Marketing 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
A discussion of capital expenditures by business segment is included in Item 7,
MD&A under the heading "Investing Cash Flow" and subheading "Expenditures for
Long-Lived Assets."
Environmental Matters
A discussion of material environmental matters involving the Company is included
in Item 7, MD&A under the heading "Other Matters" and in Item 8, Note
H-Commitments and Contingencies.
Miscellaneous
The Company had a total of 3,807 full-time employees at September 30, 1999,
2,401 employees in all of its U.S. operations and 1,406 employees in its
International segment. This represents a decrease of 3.47% from the 3,944 total
employed at September 30, 1998.
Agreements covering employees in collective bargaining units in New
York were renegotiated in November 1997, effective December 1997, and are
scheduled to expire in February 2001. Agreements covering most employees in
collective bargaining units in Pennsylvania have been 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(1)
- ---------------------------- ---------------------------------------------------
Name and Age Current Company Positions and Other Material
Business Experience During Past 5 Years(2)
- ---------------------------- ---------------------------------------------------
Bernard J. Kennedy Chairman of the Board of Directors since March
(68) 1989, Chief Executive Officer since August 1988
and Director since March 1978. Mr. Kennedy
previously served as President from January 1987
to July 1999.
- ---------------------------- ---------------------------------------------------
Philip C. Ackerman President since July 1999 and Director since March
(55) 1994. Mr. Ackerman has served as Executive Vice
President of Supply Corporation since October 1994
and President of Horizon since September 1995.
He previously served as Senior Vice President from
June 1989 to July 1999 and as President of
Distribution Corporation from October 1995 to
July 1999.
- ---------------------------- ---------------------------------------------------
Richard Hare President of Supply Corporation since June 1989.
(61) Mr. Hare previously served as Senior Vice President
of Penn-York Energy Corporation from June 1989
until its merger into Supply Corporation in July
1994.
- ---------------------------- ---------------------------------------------------
David F. Smith President of Distribution Corporation since July
(46) 1999. Mr. Smith previously served as Senior Vice
President of Distribution Corporation from January
1993 to July 1999.
- ---------------------------- ---------------------------------------------------
James A. Beck President of Seneca since October 1996 and
(52) President of Highland since March 1998. Mr. Beck
previously served as Vice President of Seneca from
January 1994 to April 1995 and as Executive Vice
President of Seneca from May 1995 to September
1996.
- ---------------------------- ---------------------------------------------------
Joseph P. Pawlowski Treasurer since December 1980. Mr. Pawlowski has
(58) served as Senior Vice President of Distribution
Corporation since February 1992, Treasurer of
Distribution Corporation since January 1981,
Treasurer of Supply Corporation since June 1985 and
Secretary of Supply Corporation since October 1995.
- ---------------------------- ---------------------------------------------------
Gerald T. Wehrlin Controller since December 1980. Mr. Wehrlin has
(61) served as Senior Vic President of Distribution
Corporation since April 1991, Controller of Seneca
since September 1981 and Vice President of Horizon
since February 1997. He previously served as
Secretary and Treasurer of Horizon from September
1995 to February 1997.
- ---------------------------- ---------------------------------------------------
- -------------------------- -----------------------------------------------------
Name and Age Current Company Positions and Other Material
Business Experience During Past 5 Years(2)
- ---------------------------- ---------------------------------------------------
Walter E. DeForest Senior Vice President of Distribution Corporation
(58) since August 1993.
- ---------------------------- ---------------------------------------------------
Bruce H. Hale Senior Vice President of Supply Corporation since
(50) February 1997 a nd Vice President of Horizon since
September 1995. Mr. Hale previously served as
Senior Vice President of Distribution Corporation
from January 1993 to February 1997.
- ---------------------------- ---------------------------------------------------
Dennis J. Seeley Senior Vice President of Distribution Corporation
(56) since February 1997. Mr. Seeley previously served
as Senior Vice President of Supply Corporation from
January 1993 to February 1997.
- ---------------------------- ---------------------------------------------------
Robert J. Kreppel President of NFR since March 1995. Mr. Kreppel
(42) previously served as Vice President of NFR from
February 1992 to March 1995.
- ---------------------------- ---------------------------------------------------
(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 was elected as an officer. The executive officers serve at the
pleasure of the Board of Directors.
(2) The information provided relates to positions within the Company and,
where identified, the principal subsidiaries of the Company. Many of the
executive officers have in the past served or currently serve as
officers for other subsidiaries of the Company.
ITEM 2 Properties
General Information on Facilities
The investment of the Company in net property, plant and equipment was $2.4
billion at September 30, 1999. Approximately 59% of this investment is in the
Utility and Pipeline and Storage segments, which are primarily located in
western New York and western Pennsylvania. The remaining investment in property,
plant and equipment is mainly in the Exploration and Production segment (29%),
which is primarily located in the Gulf Coast, southwestern, western and
Appalachian regions of the United States, the International segment (9%) which
is located in the Czech Republic, and the Timber segment (3%) which is located
primarily in northwestern Pennsylvania. During the past five years, the Company
has made significant additions to property, plant and equipment in order to
expand and improve transmission and distribution facilities for both retail and
transportation customers, to augment the reserve base of oil and gas, and to
purchase district heating and power generation facilities in the Czech Republic.
Net property, plant and equipment has increased $808.3 million, or 52%, since
1994.
The Utility segment has the largest net investment in property, plant
and equipment, compared with the Company's other business segments. The net
investment in its gas distribution network (including 14,773 miles of
distribution pipeline) and its services represent approximately 58% and 29%,
respectively, of the Utility segment's net investment of $919.6 million at
September 30, 1999.
The Pipeline and Storage segment represents a net investment of $466.5
million in property, plant and equipment at September 30, 1999. Transmission
pipeline, with a net cost of $145.3 million, represents 31% of this segment's
total net investment and includes 2,583 miles of pipeline required to move large
volumes of gas throughout its service area. Storage facilities consist of 33
storage fields, 4 of which are jointly operated with certain pipeline suppliers,
and 482 miles of pipeline. Net investment in storage facilities includes $85.1
million of gas stored underground-noncurrent, representing the cost of the gas
required to maintain pressure levels for normal operating purposes as well as
gas maintained for system balancing and other purposes, including that needed
for no-notice transportation service. The Pipeline and Storage segment has 29
compressor stations with 74,646 installed compressor horsepower.
The Exploration and Production segment had a net investment in
property, plant and equipment amounting to $674.8 million at September 30, 1999.
The International segment had a net investment in property, plant and
equipment amounting to $203.5 million at September 30, 1999. PSZT's net
investment in district heating and electric generation facilities was $147.5
million; SCT's net investment in district heating and electric generation
facilities was $55.0 million; and TK's net investment in district heating
facilities was approximately $1.0 million.
The Timber segment had a net investment in property, plant and
equipment of $88.9 million at September 30, 1999. Located primarily in
northwestern Pennsylvania, the net investment includes 4 sawmills and
approximately 140,000 acres of timber.
The Utility and Pipeline and Storage segments' facilities provided the
capacity to meet its 1999 peak day sendout, including transportation service, of
1,909 MMcf, which occurred on January 5, 1999. Withdrawals from storage of 687
MMcf provided approximately 36% of the requirements on that day.
Company maps are included on pages 2 and 3 of the paper copy of the
Company's combined Annual Report to Shareholders/Form 10-K, and are narratively
described in the Appendix to this electronic filing and are incorporated herein
by reference.
Exploration and Production Activities
The information that follows is disclosed in accordance with SEC regulations,
and relates to the Company's oil and gas producing activities. A further
discussion of oil and gas producing activities is included in Item 8, Note
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, 1999 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:
Production
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
For the Year Ended September 30 1999 1998 1997
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Average Sales Price per Mcf of Gas(1) $2.20 $2.45 $2.60
Average Sales Price per Barrel of Oil(1) $12.85 $12.15 $20.63
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $0.46 $0.45 $0.35
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Prices do not reflect gains or losses from hedging activities.
Productive Wells
- --------------------------------------------------------------------------------------------
At September 30, 1999 Gas Oil
- --------------------------------------------------------------------------------------------
Productive Wells - gross 1,934 895
- net 1,801 845
- --------------------------------------------------------------------------------------------
Developed and Undeveloped Acreage
- --------------------------------------------------------------------------------
At September 30, 1999
- --------------------------------------------------------------------------------
Developed Acreage - gross 636,221
- net 558,651
Undeveloped Acreage - gross 1,043,757
- net 753,106
- -------------------------------------- ---------------- ------------------------
Drilling Activity
- ---------------------------------------------------------------------------------------------------------------------
Productive Dry
--------------------------------------------------------------
For the Year Ended September 30 1999 1998 1997 1999 1998 1997
--------------------------------------------------------------
Net Wells Completed - Exploratory 12.95 10.72 4.21 5.64 4.97 3.49
- Development 95.26 14.11 1.84 4.75 2.00 1.60
- ---------------------------------------------------------------------------------------------------------------------
Present Activities
- --------------------------------------------------------------------------------
At September 30, 1999
- --------------------------------------------------------------------------------
Wells in Process of Drilling - gross 13.00
- net 10.01
- --------------------------------------------------------------------------------
South Lost Hills Waterflood Program
In Seneca's South Lost Hills Field (acquired in 1998 as part of the HarCor
Energy, Inc. and Bakersfield Energy Resources, Inc. acquisitions) a waterflood
project was initiated in 1996 on the Ellis lease in the Diatomite reservior for
pressure maintenance and recovery enhancement purposes. Currently there are 27
injection wells and 88 production wells in the program. The total injection and
production from this waterflood project are 7,000 barrels of water per day and
400 barrels of oil per day, respectively.
ITEM 3 Legal Proceedings
For a discussion of various environmental matters, refer to Item 7, MD&A of this
report under the heading "Other Matters" and to Item 8 at Note H-Commitments and
Contingencies.
ITEM 4 Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter
of 1999.
PART II
-------
ITEM 5 Market for the Registrant's Common Stock and Related Shareholder Matters
Information regarding the market for the Registrant's common stock and related
shareholder matters appears in Note D-Capitalization and Note L-Market for
Common Stock and Related Shareholder Matters (unaudited) under Item 8 of this
combined Annual Report to Shareholders/Form 10-K, and reference is made thereto.
On July 1, 1999, the Company issued 700 unregistered shares of Company
common stock to the seven non-employee directors of the Company, 100 shares to
each such director. These shares were issued as partial consideration for the
directors' service as directors during the quarter ended September 30, 1999,
pursuant to the Company's Retainer Policy for Non-Employee Directors. These
transactions were exempt from registration by Section 4(2) of the Securities Act
of 1933, as amended, as transactions not involving any public offering.
ITEM 6 Selected Financial Data
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30 1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Summary of Operations (Thousands)
Operating Revenues $1,263,274 $1,248,000 $1,265,812 $1,208,017 $975,496
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Purchased Gas 405,925 441,746 528,610 477,357 351,094
Fuel Used in Heat and
Electric Generation 55,788 37,837 1,489 - -
Operation and Maintenance 323,888 319,769 286,537 309,206 292,505
Property, Franchise and Other Taxes 91,146 92,817 100,549 99,456 91,837
Depreciation, Depletion and
Amortization 129,690 118,880 111,650 98,231 71,782
Impairment of Oil and Gas
Producing Properties - 128,996 - - -
Income Taxes 64,829 24,024 68,674 66,321 43,879
- ----------------------------------------------------------------------------------------------------------------------------------
1,071,266 1,164,069 1,097,509 1,050,571 851,097
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 192,008 83,931 168,303 157,446 124,399
Other Income 12,343 35,870 3,196 3,869 5,378
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 204,351 119,801 171,499 161,315 129,777
Interest Charges 87,698 85,284 56,811 56,644 53,883
- ----------------------------------------------------------------------------------------------------------------------------------
Minority Interest in Foreign Subsidiaries (1,616) (2,213)
- - -
- ----------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect 115,037 32,304 114,688 104,671 75,894
Cumulative Effect of Change in
Accounting - (9,116) - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income Available for Common
Stock $115,037 $ 23,188 $114,688 $104,671 $ 75,894
- ----------------------------------------------------------------------------------------------------------------------------------
Per Common Share Data
Basic Earnings per Common Share $2.98 $0.61(1) $3.01 $2.78 $2.03
Diluted Earnings per Common Share $2.95 $0.60(1) $2.98 $2.77 $2.03
Dividends Declared $1.83 $1.77 $1.71 $1.65 $1.60
Dividends Paid $1.82 $1.76 $1.70 $1.64 $1.59
Dividend Rate at Year-End $1.86 $1.80 $1.74 $1.68 $1.62
At September 30:
Number of Common Shareholders 22,336 23,743 20,267 21,640 21,429
- ----------------------------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment (Thousands)
Utility $919,642 $906,754 $889,216 $855,161 $822,764
Pipeline and Storage 466,524 460,952 450,865 452,305 463,647
Exploration and Production 674,813 638,886 443,164 375,958 339,950
International 203,452 202,590 942 1,274 70
Energy Marketing 489 353 123 41 54
Timber 88,904 38,593 34,872 24,680 22,146
All Other 63 - 173 172 420
Corporate 7 9 11 15 131
- ----------------------------------------------------------------------------------------------------------------------------------
Total Net Plant $2,353,894 $2,248,137 $1,819,366 $1,709,606 $1,649,182
- ----------------------------------------------------------------------------------------------------------------------------------
Total Assets (Thousands) $2,842,586 $2,684,459 $2,267,331 $2,149,772 $2,036,823
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (Thousands)
Common Stock Equity $ 939,293 $ 890,085 $ 913,704 $ 855,998 $ 800,588
Long-Term Debt, Net of Current Portion 822,743 693,021 581,640 574,000 474,000
Total Capitalization $1,762,036 $1,583,106 $1,495,344 $1,429,998 $1,274,588
- ----------------------------------------------------------------------------------------------------------------------------------
(1) 1998 includes oil and gas asset impairment of ($2.06) basic, ($2.04)
diluted and cumulative effect of a change in depletion methods of ($0.24)
basic and diluted. Refer to further discussion of these items in Notes to
Financial Statements, Note A - Summary of Significant Accounting Policies.
ITEM 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
1999 Compared with 1998
The Company's earnings were $115.0 million, or $2.98 per common share ($2.95 per
common share on a diluted basis), in 1999. This compares with 1998 earnings of
$23.2 million, or $0.61 per common share ($0.60 per common share on a diluted
basis). Earnings for 1998 included a $79.1 million (after tax) non-cash
impairment of the Exploration and Production segment's oil and gas assets and
the non-cash cumulative effect of a change in accounting. The 1998 accounting
change, which was a change in depletion methods for the Exploration and
Production segment's oil and gas assets, had a negative $9.1 million (after
tax), or $0.24 per common share, non-cash cumulative effect through fiscal 1997,
which was recorded in the first quarter of fiscal 1998. Excluding these two
non-cash special items, earnings for 1998 would have been $111.4 million, or
$2.91 per common share ($2.88 per common share on a diluted basis).
The increase in 1999 earnings of $3.6 million (exclusive of the two
non-cash special items in 1998) is the result of higher earnings in the Utility,
Timber, Energy Marketing and International segments and in Corporate operations.
These higher earnings were offset in part by reduced earnings in the Exploration
and Production segment. The Pipeline and Storage segment's earnings remained
level with the prior year. Additional discussion of earnings in each of the
business segments can be found in the business segment information that follows.
1998 Compared with 1997
The Company's earnings were $23.2 million, or $0.61 per common share ($0.60 per
common share on a diluted basis), in 1998. These earnings include the two
non-cash special items discussed above. Without these two non-cash items,
earnings for 1998 would have been $111.4 million, or $2.91 per common share
($2.88 per common share on a diluted basis). This compares with earnings of
$114.7 million, or $3.01 per common share ($2.98 per common share on a diluted
basis), in 1997.
The earnings decrease in 1998 was attributable to lower earnings of the
Company's Utility, Exploration and Production and Energy Marketing segments,
offset in part by higher earnings in the Pipeline and Storage segment and in the
International and Timber segments (both of which incurred a loss in 1997).
Additional discussion of earnings in each of the business segments can be found
in the business segment information that follows.
Discussion of Asset Impairment and Cumulative Effect of a Change in Depletion
Method
Seneca follows the full-cost method of accounting for its oil and gas
operations. Under this method, all costs directly associated with property
acquisitions, exploration and development are capitalized, up to certain
specified limits. Due to significant declines in oil prices in 1998, Seneca's
capitalized costs under the full-cost method of accounting exceeded these limits
at March 31, 1998. Seneca was required to recognize an impairment of its oil and
gas producing properties in the quarter ended March 31, 1998. This charge
amounted to $129.0 million (pretax) and reduced net income for 1998 by $79.1
million.
Effective October 1, 1997, Seneca changed its method of depletion for
oil and gas properties from the gross revenue method to the units of production
method. The units of production method was applied retroactively to prior years
to determine the cumulative effect through October 1, 1997. This cumulative
effect reduced earnings for 1998 by $9.1 million, net of income tax. Depletion
of oil and gas properties for 1999 and 1998 has been computed under the units of
production method.
Earnings (Loss) by Segment
- ---------------------------------------------------------------------------------------------------------------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Utility $56,875 $51,788 $57,220
Pipeline and Storage 39,765 39,852 36,760
Exploration and Production (1) (2) 7,127 (64,110) 20,359
International 2,276 1,279 (3,348)
Energy Marketing 2,054 787 1,567
Timber 4,769 1,904 (609)
- ---------------------------------------------------------------------------------------------------------------------
Total Reportable Segments 112,866 31,500 111,949
All Other (162) 143 171
Corporate 2,333 661 2,568
- ---------------------------------------------------------------------------------------------------------------------
Total Consolidated (1) (2) $115,037 $32,304 $114,688
- ---------------------------------------------------------------------------------------------------------------------
(1) Before Cumulative Effect of a Change in Accounting in 1998
(2) Exclusive of the non-cash asset impairment, 1998 earnings for the
Exploration and Production segment and Total Consolidated would have been
$15,004 and $111,418, respectively.
Utility
Revenues
Utility Operating Revenues
- ---------------------------------------------------------------------------------------------------------------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Retail Revenues:
Residential $581,022 $612,647 $709,968
Commercial 101,482 123,807 167,338
Industrial 15,903 18,068 22,412
- ---------------------------------------------------------------------------------------------------------------------
698,407 754,522 899,718
- ---------------------------------------------------------------------------------------------------------------------
Off-System Sales 29,214 44,479 43,857
Transportation 77,600 62,844 49,285
Other 2,134 9,335 (1,494)
- ---------------------------------------------------------------------------------------------------------------------
$807,355 $871,180 $991,366
- ---------------------------------------------------------------------------------------------------------------------
Utility Throughput - (MMcf)
- ---------------------------------------------------------------------------------------------------------------------
Year Ended September 30 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Retail Sales:
Residential 71,177 71,704 85,676
Commercial 13,885 16,405 22,640
Industrial 4,144 4,298 5,134
- ---------------------------------------------------------------------------------------------------------------------
89,206 92,407 113,450
- ---------------------------------------------------------------------------------------------------------------------
Off-System Sales 12,469 16,192 14,051
Transportation 64,284 60,386 57,875
- ---------------------------------------------------------------------------------------------------------------------
165,959 168,985 185,376
Intrasegment Throughput (198) (306) (565)
- ---------------------------------------------------------------------------------------------------------------------
165,761 168,679 184,811
- ---------------------------------------------------------------------------------------------------------------------
1999 Compared with 1998
Operating revenues for the Utility segment decreased $63.8 million in 1999
compared with 1998. This resulted from a reduction in retail and off-system gas
sales revenue of $56.1 million and $15.3 million, respectively, and a reduction
in other operating revenue of $7.2 million. These decreases were partly offset
by an increase in transportation revenue of $14.8 million.
The recovery of lower gas costs (gas costs are recovered dollar for
dollar in revenues) and the general base rate decrease in the New York
jurisdiction effective October 1, 1998 caused the decrease in retail gas
revenue. The recovery of lower gas costs resulted from both lower retail volumes
sold of 3.2 billion cubic feet (Bcf) and a lower average cost of purchased gas
(see discussion of purchased gas below under the heading "Purchased Gas").
Despite weather that was colder than the prior year, retail volumes sold
decreased, mainly due to the migration of residential and small commercial
retail customers to transportation service. This is the result of customers
turning to marketers for their gas supplies while using Distribution Corporation
for gas transportation service. (Restructuring in the Utility segment's service
territory is further discussed in the "Rate Matters" section that follows).
Transportation revenue increased and volumes are up 3.9 Bcf as a result of the
migration noted above and because of colder weather. Off-system revenue is down
due to lower volumes sold of 3.7 Bcf. Off-system sales are a function of demand
in the northeast markets. Record storage levels at the beginning of the 1998-99
heating season and a warmer than normal winter in 1998-99 reduced demand for
off-system sales. The margins resulting from off-system sales are minimal.
The decrease in other operating revenue of $7.2 million is due
primarily to a $7.2 million gas restructuring reserve reducing revenue in the
current year, $6.0 million of revenue recorded in 1998 as a result of Internal
Revenue Service (IRS) audits and $0.5 million of a revenue reduction in the
current year due to a final IRS audit settlement. These items are offset in part
by a $7.1 million lower refund provision recorded in 1999 as compared with the
1998 refund provision. The gas restructuring reserve is to be applied against
incremental costs resulting from the New York Public Service Commission's
(NYPSC) gas restructuring efforts (the NYPSC's gas restructuring efforts are
further discussed in the "Rate Matters" section that follows). The revenue
related to the IRS audits represents the rate recovery of interest expense as
allowed by the New York rate settlement of 1996. The refund provision represents
the 50% sharing with customers of earnings over a predetermined amount in
accordance with the New York rate settlements of 1996 and 1998. All of these
items are included in the "Other" category of the Utility Operating Revenue
table above.
1998 Compared with 1997
Operating revenues for the Utility segment decreased $120.2 million in 1998
compared with 1997. This resulted from a reduction in retail sales revenue of
$145.2 million offset in part by higher off-system sales revenue, transportation
revenue and other revenue of $0.6 million, $13.6 million and $10.8 million,
respectively.
The decrease in retail gas revenue was caused by the recovery of
lower gas costs offset in part by a general base rate increase in the New York
jurisdiction effective October 1, 1997. The recovery of lower gas costs resulted
from a decrease in retail gas sales of 21.0 Bcf and a decrease in the average
cost of purchased gas (see discussion of purchased gas below under the heading
"Purchased Gas"). While the decrease in gas sales also reflects, in part, the
migration of residential and small commercial retail customers to transportation
service, the major reason for the decrease stems from warmer weather which was
on average 13.8% warmer in 1998 than in 1997 (see Degree Days table below).
The increase in other operating revenue of $10.8 million is due
primarily to $6.0 million of revenue recorded in 1998 as a result of IRS audits,
as discussed above, and $7.9 million of refund pool revenue, as discussed below,
offset in part by a $4.7 million higher refund provision recorded in 1998 as
compared with 1997. The refund provision represents the 50% sharing with
customers of earnings over a predetermined amount in accordance with the New
York rate settlement of 1996.
As part of the 1996 rate settlement with the NYPSC, Distribution
Corporation was allowed to utilize certain refunds from upstream pipeline
companies and certain credits (referred to as the "refund pool") to offset
certain specific expense items. In September 1998, Distribution Corporation
recognized $7.9 million of the refund pool as other operating revenue and
recorded an equal amount of Operation and Maintenance (O&M) expense in
accordance with the settlement agreement.
Earnings
1999 Compared with 1998
In the Utility segment, 1999 earnings were $56.9 million, up $5.1 million from
the prior year. This was largely because the settlement of the primary issues of
IRS audits of years 1977-1994 had a negative impact on earnings in 1998. In
addition, adjustments made relating to the final settlement of these audits had
a positive impact to earnings in the current year. Absent the IRS audit items,
earnings of the Utility segment were up $0.6 million from the prior year.
Lower O&M and interest expenses, a lower refund provision in the
current year (as noted in the revenue discussion above), positive adjustments
for lost and unaccounted-for gas related to 1998 and 1999 and slightly colder
weather (which mainly benefits the Pennsylvania jurisdiction), were the positive
contributors to earnings this year. These items offset the costs associated with
the current year's early retirement offers (which totaled $5.6 million, pretax,
for this segment), as well as the effects of a rate settlement that included a
$7.2 million rate reduction in New York that became effective October 1, 1998
and a special $7.2 million (pretax) reserve to be applied against incremental
costs resulting from the NYPSC gas restructuring efforts, as discussed above.
The impact of weather on Distribution Corporation's New York rate
jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New
York, which covers the eight-month period from October through May, has had a
stabilizing effect on earnings for the New York rate jurisdiction. In addition,
in periods of colder than normal weather, the WNC benefits Distribution
Corporation's New York customers. In 1999, the WNC in New York preserved
earnings of approximately $0.6 million (after tax) as weather, overall, was
warmer than normal for the period of October 1998 through May 1999. Since the
Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather
variations directly impact earnings. In the Pennsylvania service territory,
weather was 4.0% colder than 1998 and 9.9% warmer than normal. The Pennsylvania
jurisdiction's colder weather in 1999 compared with 1998 increased earnings by
approximately $0.5 million (after tax).
1998 Compared with 1997
Utility segment 1998 earnings were $51.8 million, down $5.4 million from 1997.
This decrease was largely the result of the Utility segment incurring interest
expense in 1998, net of related rate recovery, in connection with the settlement
of the primary issues relating to the previously referred to settlement of the
IRS audits. Absent this interest expense, the Utility segment's earnings were
down $1.6 million as compared to 1997. Warmer weather in 1998 compared with 1997
was the primary cause of the decrease.
Partly offsetting the earnings decrease caused by warmer weather, the
Utility segment experienced a decrease in O&M expense as a result of
management's continued emphasis on controlling costs. Also contributing to this
decrease, 1997 O&M expense included $0.9 million of pretax expenses associated
with an early retirement offer to certain Pennsylvania operating union employees
in 1997.
In 1998, the WNC in New York preserved earnings of approximately $7.9
million (after tax) as weather, overall, was warmer than normal for the period
of October 1997 through May 1998. In the Pennsylvania service territory, weather
was 15.7% warmer than 1997 and 13.4% warmer than normal. The Pennsylvania
jurisdiction's warmer weather in 1998 compared with 1997 lowered earnings by
approximately $4.0 million (after tax).
Degree Days
- ----------------------------------------------------------------------------------------------------------------------
Percent (Warmer)
Colder Than
--------------------------------
Year Ended September 30 Normal Actual Normal Prior Year
- ----------------------------------------------------------------------------------------------------------------------
1999: Buffalo 6,848 6,179 (9.8%) 4.5%
Erie 6,223 5,607 (9.9%) 4.0%
- ----------------------------------------------------------------------------------------------------------------------
1998: Buffalo 6,689 5,914 (11.6%) (12.9%)
Erie 6,223 5,389 (13.4%) (15.7%)
- ----------------------------------------------------------------------------------------------------------------------
1997: Buffalo 6,690 6,793 1.5% (5.7%)
Erie 6,223 6,395 2.8% (5.5%)
- ----------------------------------------------------------------------------------------------------------------------
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 $3.82 per thousand cubic feet (Mcf) in 1999, a
decrease of 7.5% from the average cost of $4.13 per Mcf in 1998. The average
cost of purchased gas in 1998 was 3% lower than the $4.26 per Mcf in 1997.
Pipeline and Storage
Revenues
Pipeline and Storage Operating Revenues
- ---------------------------------------------------------------------------------------------------------------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation $91,659 $93,362 $92,027
Interruptible Transportation 476 985 831
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
92,135 94,347 92,858
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Storage Service 63,655 62,850 64,147
Interruptible Storage Service 173 655 74
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
63,828 63,505 64,221
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Other 12,820 13,131 15,615
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$168,783 $170,983 $172,694
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Pipeline and Storage Throughput - (MMcf)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 1999 1998 1997
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Firm Transportation 300,242 298,738 291,164
Interruptible Transportation 8,061 14,310 9,138
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
308,303 313,048 300,302
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
1999 Compared with 1998
Operating revenues decreased $2.2 million in 1999 compared with 1998. The
decrease resulted primarily from lower firm transportation revenue of $1.7
million, lower interruptible transportation and storage service revenue of $1.0
million, lower net revenues from unbundled pipeline sales and open access
transportation of $0.8 million and an accrual for a gas imbalance payable of
$1.0 million. These items were offset in part by higher firm storage service
revenue of $0.8 million and higher cashout revenue of $1.3 million.
Approximately $1.0 million of the decrease in the firm transportation
revenue related to "pass through" type items (i.e., surcharges and refunds) that
correspondingly reduced O&M expense, thus having no bottom line earnings impact.
Interruptible transportation and storage service revenue decreased (and
interruptible volumes transported decreased 6.2 Bcf) as a result of full
storages at the beginning of the 1998-99 heating season and a warmer than normal
winter in 1998-99; thus Supply Corporation lacked available storage space to
service interruptible customers. Lower interruptible storage service generally
results in lower interruptible transportation. The higher cashout revenue (a
cash resolution of a gas imbalance whereby a customer pays Supply Corporation
for gas it receives in excess of amounts delivered into Supply Corporation's
system by the customer's shipper) is offset by an equal amount of purchased gas
expense, thus there is no bottom line earnings impact.
Transportation volumes in this segment decreased 4.7 Bcf. Generally,
volume fluctuations do not have a significant impact on revenues as a result of
Supply Corporation's straight fixed-variable (SFV) rate design. However, as
mentioned above, lower interruptible transportation volumes did negatively
impact revenue for 1999.
1998 Compared with 1997
Operating revenues decreased $1.7 million in 1998 compared with 1997. The
decrease resulted primarily from lower net revenues from unbundled pipeline
sales and open access transportation of $1.8 million, lower firm storage service
revenues of $1.3 million and lower cashout revenue of $1.1 million. These
decreases were partially offset by an increase in firm transportation revenue of
$1.3 million (resulting from demand charges related to the incremental expansion
of this segment's Niagara import facilities) and higher interruptible
transportation and storage service revenues of $0.7 million.
Transportation volumes in this segment increased 12.8 Bcf. As noted
above, generally, volume fluctuations do not have a significant impact on
revenues as a result of Supply Corporation's SFV rate design. However, the
increase in capacity stemming from the above noted incremental expansion
contributed to higher demand charge revenue. Higher interruptible transportation
volumes also increased revenues.
Earnings
1999 Compared with 1998
Earnings in the Pipeline and Storage segment remained at $39.8 million for 1999
and 1998. Lower revenues, as discussed above, and nonrecurring income in 1998
from a buyout of a firm transportation agreement by a customer in the amount of
$2.5 million (pretax), were offset by lower O&M and interest expenses. Items
causing lower O&M expense in 1999 when compared to 1998 include the
establishment of reserves, in 1998, for preliminary survey and investigation
costs associated with a proposed incremental expansion project and a natural gas
gathering project (mainly due to lack of interest in furthering these projects).
In addition, Supply Corporation recognized a base gas loss at its Zoar Storage
Field in 1998. In total, these three items amounted to $3.7 million of pretax
expense in 1998. In 1999, Supply Corporation reversed $0.8 million (pretax) of
the gathering project reserve as it recovered that amount from its former
project partner. Also in 1999, Supply recovered, through insurance, $0.7 million
(pretax) related to the Zoar base gas loss. Several significant items also
increased O&M expense in 1999 when compared to 1998, including early retirement
offers in 1999 (which totaled $1.4 million, pretax, for this segment) and the
1998 reversal of a portion of a reserve set up in a prior period for a storage
project. Supply Corporation was able to recover approximately $1.0 million
(pretax) by selling preliminary engineering, survey, environmental and
archeological information from this storage project to the Independence Pipeline
Company (the Independence Pipeline project is discussed further under "Investing
Cash Flow," subheading "Pipeline and Storage").
1998 Compared with 1997
In the Pipeline and Storage segment, earnings for 1998 of $39.8 million
increased $3.1 million when compared with 1997. This was mainly due to Supply
Corporation's portion of interest income from the previously mentioned
settlement of IRS audits. Additional income tax expense related to certain
unsettled issues was also recorded. Absent these IRS audit items, earnings would
have been down $0.3 million when compared with 1997. This decrease reflects the
lower revenues, as discussed above, and an increase in O&M expense. These items
were offset in part by lower interest expense and a buyout of a firm
transportation agreement by a customer in the amount of $2.5 million (pretax).
The higher O&M expenses resulted primarily from the above noted establishment of
reserves associated with a proposed incremental expansion project and a natural
gas gathering project and the base gas loss at Zoar Storage Field. Partially
offsetting these increases in O&M expense was the reversal of a portion of a
reserve set up in a prior period for a storage project and the fact that 1997
O&M expense included $1.0 million of pretax expenses associated with an early
retirement offer.
Exploration and Production
Revenues
Exploration and Production Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Year Ended September 30 (Thousands) 1999 1998 1997
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Gas (after Hedging) $83,229 $82,910 $84,024
Oil (after Hedging) 52,050 34,069 34,147
Gas Processing Plant 11,751 4,937 -
Other (36) 2,356 1,089
- --------------------------------------------------------------- ----------------- ---------------- ------------------
$146,994 $124,272 $119,260
- --------------------------------------------------------------- ----------------- ---------------- ------------------
1999 Compared with 1998
Operating revenues increased $22.7 million in 1999 compared with 1998. Oil
production revenues, net of hedging activities, increased $18.0 million as
production increased 54% (mainly the result of West Coast production from the
properties acquired in 1998). Gas production revenue, net of hedging activities,
increased $0.3 million due to higher production (also mainly the result of West
Coast production from the properties acquired in 1998). Refer to the tables
below for production and price information. Revenue from Seneca's gas processing
plant, acquired as part of the HarCor Energy, Inc. (HarCor) and Bakersfield
Energy Resources (BER) acquisitions in May and June 1998, was up $6.8 million.
These items were partly offset by a negative mark-to-market revenue adjustment
related to written options of $1.3 million. Refer to further discussion of
written options in the "Market Risk Sensitive Instruments" section that follows
and in Note F - Financial Instruments in Item 8 of this report.
1998 Compared with 1997
Operating revenues increased $5.0 million in 1998 compared with 1997. The main
reason for the increase was the $4.9 million in revenues related to the gas
processing plant acquired in 1998, as noted above. While this gas processing
plant contributed a large amount of revenue, this revenue was basically offset
by an equal amount of expense.
Gas production revenues, net of hedging activities, decreased $1.1
million as a result of decreased production, offset in part by higher gas prices
(after hedging). Refer to the tables below for production and price information.
The gas production declines were mainly due to the shut-in of production during
the Gulf hurricane season and tropical storms, as well as the expected decline
in production of West Cameron 552 and delays in drilling due to lack of rig
availability in the first half of the year. Oil production revenues, net of
hedging activities, were basically even with 1997 as increased production was
offset by lower oil prices (after hedging). The increase in oil production was
mainly the result of West Coast production from the properties acquired in the
Whittier Trust Company, HarCor and BER acquisitions.
Production Volumes
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Year Ended September 30 1999 1998 1997
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Gas Production (million cubic feet)
Gulf Coast 28,758 29,461 32,377
West Coast 3,977 2,146 1,135
Appalachia 4,431 4,867 5,074
- --------------------------------------------------------------- ----------------- ---------------- ------------------
37,166 36,474 38,586
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Oil Production (thousands of barrels)
Gulf Coast 1,373 1,228 1,404
West Coast 2,633 1,376 490
Appalachia 10 10 8
- --------------------------------------------------------------- ----------------- ---------------- ------------------
4,016 2,614 1,902
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Average Prices
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Year Ended September 30 1999 1998 1997
- --------------------------------------------------------------- ----------------- ---------------- ------------------
Average Gas Price/Mcf
Gulf Coast $2.15 $2.40 $2.60
West Coast $2.28 $2.14 $1.79
Appalachia $2.44 $2.88 $2.79
Weighted Average $2.20 $2.45 $2.60
Weighted Average After Hedging $2.24 $2.27 $2.18
Average Oil Price/bbl
Gulf Coast $15.18 $14.69 $21.37
West Coast(1) $11.62 $9.85 $18.49
Appalachia $14.73 $16.80 $21.28
Weighted Average $12.85 $12.15 $20.63
Weighted Average After Hedging $12.96 $13.03 $17.95
- --------------------------------------------------------------- ----------------- ---------------- ------------------
(1) 1999 and 1998 includes low gravity oil which generally sells for a lower
price.
Seneca utilizes price swap agreements and options to manage a portion
of the market risk associated with fluctuations in the price of natural gas and
crude oil. Refer to further discussion of these hedging activities below under
"Market Risk Sensitive Instruments" and in Note F - Financial Instruments in
Item 8 of this report.
Earnings
1999 Compared with 1998
In the Exploration and Production segment, 1999 earnings of $7.1 million are
down $7.9 million (exclusive of the two non-cash special items in 1998) when
compared with 1998. This is largely because the settlement of the primary issues
of IRS audits of years 1977-1994 had a positive impact on earnings in the prior
year. Absent the IRS audit items, earnings of the Exploration and Production
segment were down $1.4 million from the prior year. Depressed oil and gas prices
for much of 1999 were the main reason for these lower earnings. Higher oil and
gas production revenue, as noted in the revenue section above, was offset by
increases in lease operating, depletion and interest expense related mainly to
Seneca's acquisition activity in 1998. The increase in the gas processing plant
revenue of $6.8 million was largely offset by an increase in related expenses of
$6.2 million.
1998 Compared with 1997
Earnings in the Exploration and Production segment were $15.0 million in 1998
(exclusive of the two non-cash special items), down $5.4 million from 1997. This
segment's 1998 earnings include interest income related to the previously
mentioned settlement of IRS audits. Without the positive contribution from this
interest income, earnings would be down $12.1 million when compared with 1997.
This decrease was mainly because of low oil prices, decreased gas production
(for reasons discussed in the revenue section above) and higher lease operating
and interest costs related to Seneca's acquisition activities in 1998. These
circumstances more than offset the positive contribution to earnings that
resulted from higher oil production and higher gas prices (after hedging).
International
Revenues
International Operating Revenues
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Heating $71,974 $49,560 $1,887
Electricity 34,158 22,774 -
Other 913 3,925 23
- --------------------------------------------------------------- ----------------- ---------------- -----------------
$107,045 $76,259 $1,910
- --------------------------------------------------------------- ----------------- ---------------- -----------------
International Heating and Electric Volumes
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 1999 1998 1997
- --------------------------------------------------------------- ----------------- ---------------- -----------------
Heating Sales (Gigajoules) (1) 10,047,042 7,116,776 262,615
Electricity Sales (megawatt hours) 1,138,980 763,848 -
- --------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Gigajoules = one billion joules. A joule is a unit of energy.
1999 Compared with 1998
Operating revenues increased $30.8 million in 1999 compared with 1998. The
increase in revenues as well as the increase in heat and electric volumes, as
shown in the tables above, reflects the fact that 1999 was the first year in
which a full twelve months of sales and revenues are included for PSZT. Sales
and revenues for 1998 include only eight months of activity as PSZT was acquired
in February 1998.
1998 Compared with 1997
Operating revenues increased $74.3 million in 1998 compared with 1997. The
increase primarily reflects 100% of the revenues of SCT and PSZT for 1998.
Horizon acquired a 34% equity interest in SCT in April 1997, subsequently
increasing that interest to 36.8% by September 30, 1997 (and thus accounted for
its investment in SCT under the equity method in 1997). During 1998, Horizon
increased its ownership in SCT to 82.7% as of September 30, 1998. In February
1998, Horizon acquired a 75.3% equity interest in PSZT and subsequently
increased its ownership interest to 86.2% as of September 30, 1998. The
consolidation method was used to account for the investments in SCT and PSZT
during 1998.
Earnings
1999 Compared with 1998
The International segment's 1999 earnings were $2.3 million, or $1.0 million
higher than 1998 earnings. The current year's earnings reflect a full twelve
months of results from PSZT, while the prior year only included eight months of
earnings. The contribution from these additional months in 1999 was offset in
part by higher interest expense during 1999. In addition, 1998 earnings included
a $5.1 million pretax net gain associated with U.S. dollar denominated debt,
which did not recur in the current year. This debt was converted to a Czech
koruna denominated loan in December 1998.
1998 Compared with 1997
The International segment's earnings of $1.3 million in 1998 were up $4.6
million when compared to the loss recognized in 1997. This segment realized
increases from Horizon's share of earnings from its two main investments in
district heating and power generation operations located in the Czech Republic.
Because of the change in the nature of operations of the International
segment over the past three years, earnings comparisons between 1999, 1998 and
1997 may not be meaningful. Future revenues from district heating operations are
expected to fluctuate with changes in weather.*
Energy Marketing
Revenues
Energy Marketing Operating Revenues
- --------------------------------------------------------------- ------------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- --------------------------------------------------------------- ------------------- ---------------- -----------------
Natural Gas (after Hedging) $97,514 $86,877 $70,054
Electricity 1,551 253 -
Other 23 57 44
- --------------------------------------------------------------- ------------------- ---------------- -----------------
$99,088 $87,187 $70,098
- --------------------------------------------------------------- ------------------- ---------------- -----------------
Energy Marketing Volumes
- --------------------------------------------------------------- ------------------- ---------------- -----------------
Year Ended September 30 1999 1998 1997
- --------------------------------------------------------------- ------------------- ---------------- -----------------
Natural Gas - (MMcf) 34,454 26,453 21,024
- --------------------------------------------------------------- ------------------- ---------------- -----------------
1999 Compared with 1998
Operating revenues increased $11.9 million in 1999 compared with 1998. This
increase reflects higher marketing volumes as NFR customers increased from 5,476
at September 30, 1998 to 17,480 at September 30, 1999. Over 75% of the increase
in customers was residential.
1998 Compared with 1997
Operating revenues increased $17.1 million in 1998 compared with 1997. This
increase reflects higher marketing volumes as NFR customers increased from 1,307
at September 30, 1997 to 5,476 at September 30, 1998.
NFR utilizes exchange-traded futures and exchange-traded options to
manage a portion of the market risk associated with fluctuations in the price of
natural gas. Refer to further discussion of these hedging activities below under
"Market Risk Sensitive Instruments" and in Note F-Financial Instruments in Item
8 of this report.
Earnings
1999 Compared with 1998
The Energy Marketing segment's 1999 earnings were $2.1 million, an increase of
$1.3 million over 1998 earnings. Volumes of natural gas marketed have increased
30% to 34.5 Bcf in 1999 from 26.5 Bcf in 1998 and margins were up from the prior
year. These positive contributions to earnings were partly offset by higher
expenses for labor, office expense and advertising.
1998 Compared with 1997
The Energy Marketing segment's earnings for 1998 of $0.8 million were $0.8
million below 1997 earnings. Although volumes of natural gas marketed were up
5.4 Bcf, lower earnings reflect lower margins and higher O&M expense in 1998.
The increase in O&M expense mainly resulted from expansion of NFR's customer
base into new market areas.
Timber
Revenues
Timber Operating Revenues
- --------------------------------------------------------------- ------------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- --------------------------------------------------------------- ------------------- ---------------- -----------------
Operating Revenues $31,117 $17,805 $11,536
- --------------------------------------------------------------- ------------------- ---------------- -----------------
1999 Compared with 1998
Operating revenues for the Timber segment increased $13.3 million. This increase
was primarily the result of higher timber sales by Seneca of $3.6 million and
increased log sales and kiln dry lumber sales of $4.9 million and $4.2 million,
respectively, by Highland. Revenue growth reflects the increased investment by
this segment in timber and sawmills.
1998 Compared with 1997
Operating revenues for the Timber segment increased $6.3 million as a result of
higher timber sales by Seneca and increased lumber sales resulting from
Highland's purchase in 1998 of two new lumber mills. Highland also had a full
year of production from the mill it purchased in January 1997.
Earnings
1999 Compared with 1998
Timber segment earnings of $4.8 million in 1999 were up $2.9 million when
compared with 1998. As noted above, timber revenues increased by 75%. These
higher revenues were partly offset by higher O&M, depletion and interest
expenses. Earnings growth reflects the increased investment by this segment in
timber and sawmills.
1998 Compared with 1997
Timber segment earnings of $1.9 million in 1998 were up $2.5 million when
compared to the loss recognized in 1997. Higher revenues from the operations of
two new sawmills purchased in 1998 helped drive the earnings increase.
Other Income and Interest Charges
Although variances in Other Income items and Interest Charges are discussed in
the earnings discussion by segment above, following is a recap on a consolidated
basis:
Other Income
Other income decreased $23.5 million in 1999 and increased $32.7 million in
1998. The 1999 decrease is primarily due to a decrease in interest income
related to the settlement of IRS audits. In 1999 and 1998, $3.1 million and
$18.5 million, respectively, of interest income was recognized related to these
audits. Lower other income in 1999 also reflects two items recorded in 1998: a
net gain of $5.1 million associated with U.S. dollar denominated debt carried on
the balance sheet of PSZT and a buyout of a firm transportation agreement by a
Pipeline and Storage segment customer in the amount of $2.5 million. Partly
offsetting these items is a $2.4 million gain recorded in 1999 resulting 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.
The 1998 increase in other income is primarily due to the above noted
$18.5 million of interest income related to the settlement of IRS audits, the
$5.1 million net gain associated with U.S. dollar denominated debt, the $2.5
million buyout of a firm transportation agreement by a Pipeline and Storage
segment customer, as well as $1.3 million of interest income on temporary cash
investments of SCT and PSZT.
Interest Charges
Interest on long-term debt increased $12.2 million in 1999 and $11.0 million in
1998. 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 several years primarily as a result of acquisition
activity in the Exploration and Production and International segments.
Other interest charges decreased $9.8 million in 1999 and increased
$17.5 million in 1998. The decrease in 1999 compared to 1998, as well as the
increase in 1998 compared with 1997, resulted primarily from the $11.7 million
of interest expense recorded in 1998 related to the settlement of IRS audits. In
addition, in 1999 and 1998, interest on short-term debt increased mainly as a
result of higher average amounts of debt outstanding.
Capital Resources and Liquidity
The primary sources and uses of cash during the last three years are summarized
in the following condensed statement of cash flows:
Sources (Uses) of Cash
- -------------------------------------------------------------- -------------------- ---------------- -----------------
Year Ended September 30 (Millions) 1999 1998 1997
- -------------------------------------------------------------- -------------------- ---------------- -----------------
Provided by Operating Activities $271.9 $253.0 $294.7
Capital Expenditures (260.5) (393.2) (214.0)
Investment in Subsidiaries,
Net of Cash Acquired (5.8) (112.0) (21.1)
Investment in Partnerships (3.6) (5.5) -
Other Investing Activities 6.7 7.6 1.4
Short-Term Debt, Net Change 67.2 229.4 (107.3)
Long-Term Debt, Net Change (15.6) 94.9 98.2
Issuance of Common Stock 10.7 7.9 7.1
Dividends Paid on Common Stock (69.9) (67.0) (64.3)
Dividends Paid to Minority
Interest (0.2) (0.3) -
Effect of Exchange Rates on Cash (2.1) 1.6 -
- -------------------------------------------------------------- -------------------- ---------------- -----------------
Net Increase (Decrease) in Cash
and Temporary Cash Investments $(1.2) $16.4 $(5.3)
- -------------------------------------------------------------- -------------------- ---------------- -----------------
Operating Cash Flow
Internally generated cash from operating activities consists of net income
available for common stock, adjusted for noncash expenses, noncash income and
changes in operating assets and liabilities. Noncash items include depreciation,
depletion and amortization, deferred income taxes, minority interest in foreign
subsidiaries, the cumulative effect of a change in accounting for depletion
(1998) and the impairment of oil and gas producing properties (1998).
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 $271.9 million in
1999, an increase of $18.9 million compared with the $253.0 million provided by
operating activities in 1998. The increase is attributed primarily to the
Utility segment's contribution offset partly by a decrease in cash provided by
operations in the Exploration and Production segment. The increase in the
Utility segment is mainly the result of lower O&M expenditures combined with
lower cash disbursements for taxes and interest. While cash receipts from gas
sales and transportation service were down, this decrease was substantially
offset by lower gas purchase expenditures. The decrease to cash provided by
operations in the Exploration and Production segment is primarily because of an
increase in interest payments stemming from higher debt related to the
acquisitions made in 1998.
Investing Cash Flow
Expenditures for Long-Lived Assets
Expenditures for long-lived assets include additions to property, plant and
equipment (capital expenditures) and investments in corporations (stock
acquisitions) or partnerships, net of any cash acquired.
The Company's expenditures for long-lived assets totaled $269.9 million
in 1999. The table below presents these expenditures by business segment:
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Total
Investments Expenditures
Capital in Corporations For Long-
Year Ended September 30, 1999 (Millions) Expenditures or Partnerships Lived Assets
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Utility $47.0 $ - $47.0
Pipeline and Storage 31.2 3.6 34.8
Exploration and Production 97.6 - 97.6
International 27.6 5.8 33.4
Energy Marketing 0.3 - 0.3
Timber 56.7 - 56.7
All Other 0.1 - 0.1
- ----------------------------------------------------------- ------------------- ------------------- -----------------
$260.5 $9.4 $269.9
- ----------------------------------------------------------- ------------------- ------------------- -----------------
Utility
The majority of the Utility capital expenditures were made for replacement of
mains and main extensions, as well as for the replacement of service lines.
Pipeline and Storage
The majority of the Pipeline and Storage capital expenditures were made for
additions, improvements and replacements to this segment's transmission and
storage systems.
SIP made a $3.6 million investment in 1999 in Independence and had an
aggregate investment balance of $10.4 million at September 30, 1999.
Independence is a Delaware general partnership in which SIP owns a one-third
general partnership interest. SIP's cash investments were financed with
short-term borrowings. Independence intends to build a 370 mile natural gas
pipeline (Independence Pipeline) from Defiance, Ohio to Leidy, Pennsylvania at
an estimated cost of $680 million.* If the Independence Pipeline is not
constructed, SIP's share of the development costs (including SIP's investment in
Independence Pipeline Company) is estimated not to exceed $13.0 million.*
Exploration and Production
Exploration and Production segment capital expenditures included approximately
$57.4 million on the offshore program in the Gulf of Mexico, including offshore
drilling expenditures, offshore construction and lease acquisition costs. The
remaining $40.2 million of capital expenditures included onshore drilling and
construction costs for wells located in Louisiana, Texas and California as well
as onshore geological and geophysical costs, including the purchase of certain
3-D seismic data. Of this amount, approximately $20.4 million was spent on
development drilling, workover, recompletion and facility construction costs on
the leases acquired last year in the Midway Sunset, Lost Hills area of
California.
International
The majority of the International segment capital expenditures were made by PSZT
for the construction of new fluidized-bed boilers at its district heating and
power generation plant to comply with stricter clean air standards. Short-term
borrowings and cash from operations were used to finance these capital
expenditures.
In fiscal 1999, Horizon, through a wholly-owned subsidiary, increased
its ownership interest in SCT to 82.87% for a minimal cost. SCT in turn
increased its ownership interest in Jablonecka teplarenska a realitni, a.s.
(JTR), a district heating plant in the northern Bohemia region of the Czech
Republic, from 34% to 65.78%. The cost of acquiring these additional shares was
approximately $5.8 million ($5.7 million, net of cash acquired) and was financed
with short-term borrowings and cash from operations.
Energy Marketing
The capital expenditures consisted primarily of the purchase of furniture,
equipment and computer hardware and software for NFR's gas marketing operations.
Timber
The majority of the Timber segment's capital expenditures consisted of the
purchase of 36,300 acres of land and timber from PennzEnergy Company for
approximately $47 million. The acquisition was financed with short-term
borrowings. The remaining $9.7 million of capital expenditures in this segment
were for other land, timber and equipment purchases.
Other Investing Activities
Other cash provided by or used in investing activities primarily reflects cash
received on the sale of various subsidiaries investments in property, plant and
equipment, and cash used for investments in a mutual fund.
Estimated Capital Expenditures
The Company's estimated capital expenditures for the next three years are:*
- -------------------------------------------------------------- ------------------- ---------------- -----------------
Year Ended September 30 (Millions) 2000 2001 2002
- -------------------------------------------------------------- ------------------- ---------------- -----------------
Utility $ 50.5 $ 49.5 $ 48.5
Pipeline and Storage 38.9 20.5 20.5
Exploration and Production 112.2 139.7 139.9
International 8.6 8.6 8.6
Timber 0.8 0.8 0.8
- -------------------------------------------------------------- ------------------- ---------------- -----------------
$211.0 $219.1 $218.3
- -------------------------------------------------------------- ------------------- ---------------- -----------------
Estimated capital expenditures for the Utility segment in 2000 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
2000 will be concentrated in the reconditioning of storage wells and the
replacement of storage and transmission lines. The estimated capital
expenditures also include approximately $9.4 million for the purchase of an
additional interest in both the Niagara Spur Loop Line (a 49.2 mile, 30-inch
pipeline extending from Lewiston, New York to East Aurora, New York) and the
Ellisburg Leidy Line (pipelines and facilities extending from Ellisburg,
Pennsylvania to Leidy, Pennsylvania).*
Estimated capital expenditures in 2000 for the Exploration and
Production segment includes approximately $78.3 million for the offshore program
in the Gulf of Mexico. Of this amount, approximately $53.3 million is intended
to be spent on exploratory and development drilling. The estimated expenditures
also includes approximately $33.9 million for the onshore program. Of this
amount, approximately $29.7 million is intended to be spent on exploratory and
development drilling.*
Estimated capital expenditures for the International segment will be
concentrated in the areas of improvements and replacements within the district
heating and power generation plants in the Czech Republic.*
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 order to meet the Company's capital requirements, cash from external sources
must periodically be obtained through short-term bank loans and commercial
paper, as well as through issuances of long-term debt and equity securities. The
Company expects these traditional sources of cash to continue to supplement its
internally generated cash during the next several years.*
In February 1999, the Company issued $100.0 million of 6.0% medium-term
notes due in March 2009. After deducting underwriting discounts and commissions,
the net proceeds to the Company amounted to $98.7 million. The proceeds of this
debt issuance, together with other funds, were used to redeem $100.0 million of
5.58% medium-term notes which matured in March 1999.
In July 1999, the Company issued $100.0 million of 6.82% medium-term
notes due to mature in August 2004. After deducting underwriting discounts and
commissions, the net proceeds to the Company amounted to $99.5 million. The
proceeds of this debt issuance, together with other funds, were used to redeem
$50.0 million of 7.25% medium-term notes which matured in July 1999 and to
complete the redemption of HarCor's 14.875% senior secured notes, discussed
below.
In March and July of 1999, the Company redeemed HarCor's 14.875% senior
secured notes. The Company redeemed the notes at a redemption price of 110% of
face value, which amounted to $59.1 million. The senior secured notes were
recorded at fair market value on the opening balance sheet in 1998 to reflect an
effective interest rate of 5.875% and the projected redemption of this debt in
1999.
The Company's embedded cost of long-term debt was 7.0% and 6.9% at
September 30, 1999 and 1998, respectively.
Consolidated short-term debt increased $67.2 million during 1999. The
Company continues to consider short-term bank loans and commercial paper
important sources 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.
In March 1998, the Company obtained authorization from the SEC, under
the Holding Company Act, to issue long-term debt securities and equity
securities in amounts not exceeding $2.0 billion during the order's
authorization period, which extends to December 31, 2002. In August 1999, the
Company obtained authorization from the SEC under the Securities Act of 1933 to
issue up to $625 million of debt and equity securities.
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, 1999, the Company would have been permitted to issue up to a
maximum of $485.0 million in additional long-term unsecured indebtedness at
projected market interest rates. In addition, at September 30, 1999, the Company
had regulatory authorizations and unused short-term credit lines that would have
permitted it to borrow an additional $356.5 million of short-term debt.
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
its business. In addition to the regulatory matters discussed in Note B -
Regulatory Matters, in Item 8 of this report, the Company is involved in other
regulatory matters arising in the normal course of business that involve rate
base, cost of service and purchased gas cost issues. While the resolution of
such litigation or other regulatory matters could have a material effect on
earnings and cash flows in the year of resolution, neither such litigation nor
these other regulatory matters are expected to materially change the Company's
present liquidity position nor have a material adverse effect on the financial
condition of the Company at this time.*
Market Risk Sensitive Instruments
Energy Commodity Price Risk
Certain of the Company's subsidiaries (primarily Seneca and NFR) utilize various
derivative financial instruments (derivatives), including price swap agreements,
options, exchange-traded futures and exchange-traded options, 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 providing more
stability to operating results. The derivatives entered into by these
subsidiaries are not held for trading purposes. These subsidiaries have
operating procedures in place that are administered by experienced management to
monitor compliance with their risk management policies.
The following tables disclose natural gas and crude oil price swap
information by expected maturity dates for agreements in which Seneca 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
tables do not reflect the earnings impact of the physical transactions that are
expected to offset the financial gains and losses arising from the use of the
price swap agreements. The weighted average variable prices represent the prices
as of September 30, 1999. At September 30, 1999, Seneca had not entered into any
natural gas or crude oil price swap agreements extending beyond 2002.
Natural Gas Price Swap Agreements
- ---------------------------------
- ------------------------------------------------------ -------------------------------------------------------------
Expected Maturity Dates
-------------------------------------------------------------
2000 2001 2002 Total
- ------------------------------------------------------ --------------- -------------- -------------- ---------------
Notional Quantities (Equivalent Bcf) 28.0 11.1 1.1 40.2
Weighted Average Fixed Rate (per Mcf) $2.70 $2.66 $2.61 $2.69
Weighted Average Variable Rate (per Mcf) $3.01 $3.00 $2.35 $2.99
- ------------------------------------------------------ --------------- -------------- -------------- ---------------
Crude Oil Price Swap Agreements
- -------------------------------
- ------------------------------------------------------ --------------- ---------------------------------------------
Expected Maturity Dates
---------------------------------------------
2000 2001 Total
- ------------------------------------------------------ --------------- -------------- -------------- ---------------
Notional Quantities (Equivalent bbls) 2,112,000 184,000 2,296,000
Weighted Average Fixed Rate (per bbl) $19.09 $18.00 $19.00
Weighted Average Variable Rate (per bbl) $23.79 $23.79 $23.79
- ------------------------------------------------------ --------------- -------------- -------------- ---------------
At September 30, 1999, Seneca would have had to pay the respective
counterparties to its natural gas price swap agreements an aggregate of
approximately $2.4 million to terminate the natural gas price swap agreements
outstanding at that date. Seneca would have had to pay an aggregate of
approximately $7.4 million to the counterparties to its crude oil price swap
agreements to terminate the crude oil price swap agreements outstanding at
September 30, 1999.
The following tables disclose the notional quantities and weighted
average strike prices for options utilized by Seneca to manage natural gas and
crude oil price risk. The tables do not reflect the earnings impact of the
physical transactions that are expected to offset any financial gains or losses
that might arise if an option were to be exercised.
Written Call Options
- --------------------
- ------------------------------------------------------------ --------------------------------------
Expected Maturity Date - 2000
- ------------------------------------------------------------ --------------------------------------
Crude Oil
Notional Quantities (Equivalent bbls) 184,000
Weighted Average Strike Price (per bbl) $18.00
Natural Gas
Notional Quantities (Equivalent Bcf) 2.6
Weighted Average Strike Price (per Mcf) $2.86
- ------------------------------------------------------------ --------- --------------
Written Call Options(1)
- -----------------------
- ---------------------------------------------------------------------- ---------------------------------------------
Expected Maturity Dates
---------------------------------------------
2000 2001 Total
- ---------------------------------------------------------------------- -------------- -------------- ---------------
Crude Oil
Notional Quantities (Equivalent bbls) 548,000 184,000 732,000
Weighted Average Strike Price (per bbl) $18.00 $18.00 $18.00
Natural Gas
Notional Quantities (Equivalent Bcf) 10.4 3.5 13.9
Weighted Average Strike Price (per Mcf) $2.58 $2.74 $2.62
- ---------------------------------------------------------------------- -------------- -------------- ---------------
(1) The counterparty has a choice between a natural gas call option and a
crude oil call option, depending on whichever option has greater value
to the counterparty.
Written Put Options
- -------------------
- ---------------------------------------------------------------------- ---------------------------------------------
Expected Maturity Dates
---------------------------------------------
2000 2001 Total
- ---------------------------------------------------------------------- -------------- -------------- ---------------
Crude Oil
Notional Quantities (Equivalent bbls) 732,000 184,000 916,000
Weighted Average Strike Price (per bbl) $12.50 $12.50 $12.50
- ---------------------------------------------------------------------- -------------- -------------- ---------------
Purchased Call Option
- ---------------------
- ---------------------------------------------------------- -----------------------------------------
Expected Maturity Date - 2000
- ---------------------------------------------------------- -----------------------------------------
Crude Oil
Notional Quantities (Equivalent bbls) 1,464,000
Weighted Average Strike Price (per bbl) $20.00
- ---------------------------------------------------------- -------------- --------------------------
At September 30, 1999, Seneca would have had to pay the counterparty to
its call options $3.6 million on a net basis to terminate its call options.
Seneca would have paid the counterparty $8.2 million related to the exercise of
the written call and put options but would have received $4.6 million related to
Seneca's exercise of its purchased call option.
The Company is exposed to credit risk on the price swap agreements that
Seneca has entered into as well as on the call options that Seneca has
purchased. 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.
The Company does not anticipate any material impact to its financial position,
results of operations, or cash flows as a result of nonperformance by
counterparties.*
The following table discloses the net notional quantities, weighted
average contract prices and weighted average settlement prices by expected
maturity date for exchange-traded futures contracts utilized by NFR to manage
natural gas price risk. The table does not reflect the earnings impact of the
physical transactions that are expected to offset the financial gains and losses
arising from the use of the futures contracts. At September 30, 1999, NFR held
no futures contracts with maturity dates extending beyond 2001.
Exchange-Traded Futures Contracts
- --------------------------------------------------------------- ----------------- ------------------ -----------------
Expected Maturity Dates
------------------------------------------------------
2000 2001 Total
- --------------------------------------------------------------- ----------------- ------------------ -----------------
Contract Volumes Purchased (Equivalent Bcf) 2.0 0.1 2.1
Weighted Average Contract Price (per Mcf) $2.75 $2.82 $2.75
Weighted Average Settlement Price (per Mcf) $2.89 $2.98 $2.89
- --------------------------------------------------------------- ----------------- ------------------ -----------------
The following table discloses the notional quantities and weighted
average strike prices by expected maturity dates for exchange-traded options
utilized by NFR to manage natural gas price risk. The table does not reflect the
earnings impact of the physical transactions that would offset any financial
gains or losses that might arise if an option were to be exercised. At September
30, 1999, NFR held no options with maturity dates extending beyond 2000.
Exchange-Traded Options Purchased
- ---------------------------------
- ------------------------------------------------------------- -------------------------------------
Expected Maturity Date - 2000
- ------------------------------------------------------------- -------------------------------------
Notional Quantities (Equivalent Bcf) 9.0
Weighted Average Strike Price (per Mcf) $2.72
- ------------------------------------------------------------- -------------------------------------
Exchange-Traded Options Sold
- ----------------------------
- ------------------------------------------------------------- -------------------------------------
Expected Maturity Date - 2000
- ------------------------------------------------------------- -------------------------------------
Notional Quantities (Equivalent Bcf) 17.1
Weighted Average Strike Price (per Mcf) $3.01
- ------------------------------------------------------------- -------------------------------------
At September 30, 1999, NFR would have received approximately $2.3
million to settle the exchange-traded futures outstanding at that date. NFR
would have paid approximately $1.2 million to settle its exchange-traded options
outstanding at September 30, 1999.
Exchange Rate Risk
Horizon'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. During 1999, the Czech koruna
decreased in value in relation to the U.S. dollar resulting in a $11.7 million
negative adjustment to the Cumulative Foreign Currency Translation Adjustment (a
component of Accumulated Other Comprehensive Income). Further valuation changes
to the Czech koruna would result in corresponding positive or negative
adjustments to the Cumulative Foreign Currency Translation Adjustment.
Management cannot predict whether the Czech koruna 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, 1999, these instruments included short-term
bank loans and commercial paper totaling $392.3 million (domestically). The
interest rate on these short-term bank loans and commercial paper approximated
5.5%. These instruments also included $1.2 million of short-term bank loans held
by SCT in the Czech Republic at September 30, 1999. The interest rate on the
Czech Republic loans approximated 6.4%.
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 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, 1999:
- ------------------------------------ ------------------------------------------------------------------------ ----------
Principal Amounts by Expected Maturity Dates
------------------------------------------------------------------------
(Millions of Dollars) 2000 2001 2002 2003 2004 Thereafter Total
- ------------------------------------ ---------- ----------- ----------- ----------- ----------- ------------- ----------
National Fuel Gas Company
Long-Term Fixed Rate Debt $50 $- $- $- $225 $549 $824
Weighted Average Interest
Rate Paid 6.6% -% -% -% 7.3% 6.6% 6.8%
Fair Value = $798.7 million
- ------------------------------------ ---------- ----------- ----------- ----------- ----------- ------------- ----------
PSZT
Long-Term Variable Rate
Debt $7.2 $9.5 $9.5 $9.5 $9.5 $2.5 $47.7
Weighted Average Interest
Rate Paid 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5%
Fair Value = $47.7 million
- ------------------------------------ ---------- ----------- ----------- ----------- ----------- ------------- ----------
Other Notes
Long-Term Debt(1) $12.4 $3.1 $1.2 $0.9 $0.9 $2.2 $20.7
Weighted Average Interest
Rate Paid 11.3% 6.7% 6.7% 7.3% 7.3% 6.8% 9.5%
Fair Value = $20.7 million
- ------------------------------------ ---------- ----------- ----------- ----------- ----------- ------------- ----------
(1) $5.8 million is variable rate debt; $14.9 million is fixed rate debt.
PSZT utilizes an interest rate swap to eliminate interest rate
fluctuations on its CZK 1,595,924,000 term loan ($47.7 million at September 30,
1999), 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 2001, PSZT pays a fixed rate of 8.31% and receives a
floating rate of six month PRIBOR. PSZT would have paid approximately $1.0
million to settle the interest rate swap at September 30, 1999.
Rate Matters
Utility Operation
New York Jurisdiction
On October 21, 1998, the NYPSC approved a rate plan for Distribution Corporation
for the period beginning October 1, 1998 and ending September 30, 2000. The plan
was the result of a settlement agreement entered into by Distribution
Corporation, Staff for the NYPSC (Staff), Multiple Intervenors (an advocate for
large industrial customers) and the State Consumer Protection Board. Under the
plan, Distribution Corporation's rates were reduced by $7.2 million, or 1.1%. In
addition, customers are receiving up to $6.0 million in bill credits, disbursed
volumetrically over the two year term, reflecting a predetermined share of
excess earnings under a 1996 settlement. An allowed return on equity of 12%,
above which additional earnings will be shared equally with the customers, was
maintained from a 1996 settlement. Finally, as provided by the rate plan, $7.2
million of 1999 revenues were set aside in a special reserve to be applied
against Distribution Corporation's incremental costs resulting from the NYPSC's
gas restructuring effort further described below.
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." That vision includes the following goals:
(1) Effective competition in the gas supply market for retail
customers;
(2) Downward pressure on customer gas prices;
(3) Increased customer choice of gas suppliers and service options;
(4) A provider of last resort (not necessarily the utility);
(5) Continuation of reliable service and maintenance of operations
procedures that treat all participants fairly;
(6) Sufficient and accurate information for customers to use in
making informed decisions;
(7) The availability of information that permits adequate oversight
of the market to ensure fair competition; and
(8) Coordination of Federal and State policies affecting gas supply
and distribution in New York State.
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 hopes to accomplish that objective over a three-to-seven
year transition period, 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.
Distribution Corporation was recently advised, on an informal basis,
that its "individualized plan" for restructuring to "effectuate [the NYPSC's]
vision" may be included in discussions anticipated in connection with the
current rate settlement, which expires on its own terms on September 30, 2000.
On June 7, 1999, the NYPSC issued a notice requesting comments on
Staff's proposal for a "single retailer" billing environment. The proposal
recommends that electric and gas utilities exit the billing function at an
undetermined future date. The retail billing function would then be performed
solely by unregulated marketers. Included in the billing proposal is a
recommendation that utilities design a "back-out" credit equal to the long run
costs avoided by each utility when billing is provided by another party.
Distribution Corporation filed comments opposing much of the proposal but
supporting a suggested interim regime where multiple billing arrangements,
including utility billing, would be permitted. This proceeding remains pending.
In anticipation of a NYPSC order partially adopting Staff's recommendation,
Distribution Corporation is exploring the development of a retail billing
service for sale to marketers serving aggregated customers. There is a market
for retail billing services in Distribution Corporation's service territory, and
Distribution Corporation believes that a service can be designed that will meet
the approval of the regulators.*
Pennsylvania Jurisdiction
Distribution Corporation currently does not have a rate case on file with the
Pennsylvania Public Utility Commission (PaPUC). Management will continue to
monitor its financial position in the Pennsylvania jurisdiction to determine the
necessity of filing a rate case in the future.
Effective October 1, 1997, Distribution Corporation commenced a PaPUC
approved customer choice pilot program called Energy Select. Energy Select,
which lasted until April 1, 1999, allowed approximately 19,000 small commercial
and residential customers of Distribution Corporation in the greater Sharon,
Pennsylvania area to purchase gas supplies from qualified, participating
non-utility suppliers (or marketers) of gas. Distribution Corporation was not a
supplier of gas in this pilot. Under Energy Select, Distribution Corporation
delivered the gas to the customer's home or business and remained responsible
for reading customer meters, the safety and maintenance of its pipeline system
and responding to gas emergencies. NFR was a participating supplier in Energy
Select.
Effective February 11, 1999, Distribution Corporation's System Wide
Energy Select tariff was approved by the PaPUC. This program is intended to
expand the Energy Select pilot program described above to apply across
Distribution Corporation's entire Pennsylvania service territory. The plan
borrows many features of the Energy Select pilot, but several important changes
were adopted. Most significantly, the new program includes Distribution
Corporation as a choice for retail consumers, in furtherance of Distribution
Corporation's objective to remain a merchant. Also departing from the pilot
scheme, Distribution Corporation resumes its role as provider of last resort and
maintains customer contact by providing a billing service on its own behalf and,
as an option, for participating marketers.
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 mirrors the Energy Select program currently in effect,
which substantially complies with the Act's requirements. Currently the parties
to the proceeding are engaged in routine discovery and settlement discussions
have begun. Distribution Corporation is unable to predict the outcome of the
proceeding at this time.
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.
Pipeline and Storage
Supply Corporation currently does not have a rate case on file with the Federal
Energy Regulatory Commission (FERC). Its last case was settled with the FERC in
February 1996. As part of that settlement, Supply Corporation agreed not to seek
recovery of revenues related to certain terminated service from storage
customers until April 1, 2000, as long as the terminations were not greater than
approximately 30% of the terminable service. Supply Corporation has been
successful in marketing and obtaining executed contracts for such terminated
storage service (at discounted rates) and expects to continue obtaining executed
contracts for additional terminated storage service as it arises.*
Other Matters
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.
Distribution Corporation and Supply Corporation have estimated their clean-up
costs related to former manufactured gas plant and former gasoline plant sites
and third party waste disposal sites will be in the range of $9.4 million to
$10.4 million.* The minimum liability of $9.4 million has been recorded on the
Consolidated Balance Sheet at September 30, 1999. 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 June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). In June 1999, the FASB issued
SFAS 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of SFAS 133." For a discussion of SFAS 133 and
SFAS 137 and their impact on the Company, see disclosure in Note A - Summary of
Significant Accounting Policies in Item 8 of this report.
Year 2000
Numerous media reports have heightened concern that information technology
computer systems, software programs and semiconductors may not be capable of
recognizing dates after the Year 2000 because such systems use only two digits
to refer to a particular year. Such systems may read dates in the Year 2000 and
thereafter as if those dates represent the year 1900 or thereafter and, in
certain instances, such systems may fail to function properly.
State of Readiness
The Company believes that all necessary work has been completed in order to make
its internal computer system Year 2000 ready.* Following the completion of an
early-impact analysis study, a formal project manager at the Company was
designated to spearhead the Year 2000 remediation effort. The methodology
adopted by the Company to address the Year 2000 issue is a combination of
methods recommended by respected industry consultants and efforts tailored to
meet the Company's specific needs. The Company's Year 2000 plan addresses five
primary areas.
A. Mainframe Corporate Business Applications Developed and Maintained by the
Company: A detailed plan and impact analysis was conducted in 1996-1997 to
determine the extent of Year 2000 implications on the Company's mainframe-based
computer systems. The remediation and testing in this area have been completed.*
B. Personal Computer Business Applications Software Developed and Supported by
the Company: Distribution Corporation and Supply Corporation have retained a
consulting firm to perform a detailed impact analysis of the personal computer
business application systems supported by the Company's Information Services
Department. Seneca has similarly retained a consulting firm to review its Year
2000 issues. These firms have either corrected Year 2000 problems identified by
their analysis or advised the respective subsidiaries of the potentially
problematic computer applications. Certain applications identified by the
consulting firms as potentially problematic have been retired and replaced with
Year 2000 compliant applications. The required changes and testing for these
applications are complete.*
C. Vendor-Supplied Software, Hardware, and Services for Corporate Business
Applications Supported by the Company: This category includes all mainframe
infrastructure products as well as all PC client/server software and hardware.
The Company has sent letters to its vendors asking if their products and
services will continue to perform as expected after January 1, 2000. These
vendors are responsible for approximately 200 products and services associated
with corporate computer applications. The Company has received responses from
all vendors which the Company believes supply critical hardware, software,
date-sensitive embedded chips and related computer services. The Company has
completed testing and implementation of the vendor-supplied Year 2000 ready
products and services.*
D. Vendor-Supplied Products and Services Used on a Corporate Wide Basis: This
category includes the critical products and services that are used by multiple
departments within the Company including all products containing embedded chips
which might be date sensitive. The Company has sent letters to the primary
vendors who provide these products and services to the Company, requesting Year
2000 compliance plans. The Company is monitoring their responses and has
incorporated them into the Company's overall Year 2000 project and contingency
plans. The Company has completed testing and implementation of the products and
services of these vendors (reference is made to the "Risks" section below).*
E. User-Department Maintained Business Applications: The Company uses certain
business software applications that were either built in-house or
vendor-supplied and subsequently maintained by individual departments of the
Company. The scope of such applications includes, but is not limited to,
spreadsheets, databases, vendor provided products and services and embedded
process controls. A corporate wide Year 2000 task force is in place and has
established a process to identify and resolve Year 2000 problems in this area.
This task force meets on a monthly basis to coordinate ongoing activities and
report on the project status. Providers of critical products and services have
been identified and the Company has sent letters requesting their Year 2000
compliance plans. Responses are being monitored and incorporated into the Year
2000 planning of the various departments. Based on responses received to date
along with internal testing, the Company believes that all applications and
services under this category are Year 2000 ready.*
Cost
The cost of upgrading both vendor supplied and internally developed systems and
services is expensed as incurred and has amounted to approximately $2.3 million
in total. Minimal additional expenses related to Year 2000 administration are
expected to be incurred.*
Risks
The Company's main concern is to ensure the safe, reliable and uninterrupted
production and delivery of natural gas and Company-provided services to its
customers. Based on the efforts discussed above, the Company expects to be able
to operate its own facilities without interruption and continue normal operation
in Year 2000 and beyond.* However, the Company has no control over the systems
and services used by third parties with whom it interfaces. While the Company
has placed its major third parties on notice that the Company expects their
products and services to perform as expected after January 1, 2000, the Company
cannot predict with accuracy the actual adverse consequences to the Company that
could result if such third parties are not Year 2000 compliant.* The widespread
failure of electric, telecommunication, and upstream gas supply could
potentially affect gas service to utility customers, and the Company is pursuing
contingency plans to avoid such disruptions.*
The majority of the devices which control the Company's physical
delivery system are not believed to be susceptible to Year 2000 problems because
they do not contain micro-processors. The Company has conducted an extensive
review of its existing micro-processors (embedded technology) and has replaced
non-Year 2000 compliant hardware.
Distribution Corporation is subject to regulatory review by both the
NYPSC and the PaPUC. Both of these regulatory bodies have issued orders
concerning the Year 2000 issue, and both have established dates in 1999 by which
jurisdictional utilities must have taken the necessary steps to ensure that its
critical systems are Year 2000 ready. Distribution Corporation has, to date, met
the requirements of those orders and will continue to comply with such orders
for the pertinent time periods specified in such orders.*
Contingency Planning
The Company formed its Corporate Year 2000 task force in mid-1997. The primary
function of this group was, and continues to be, to: (1) raise awareness of the
Year 2000 issue within the Company, (2) facilitate identification and
remediation of Year 2000 potential problems within the Company, and (3)
facilitate and develop corporate contingency plans. The group is comprised of
middle to senior level managers and Company executives. The Company has
developed Year 2000 strategic contingency plans which have been prioritized in
relation to the overall corporation in the order of human safety,
reliability/delivery of Company services and administrative services. The
Company has added the operational specifics to these plans and is continuing to
hone them through operational drills. During September through November 1999,
Distribution Corporation and Supply Corporation conducted Year 2000 Readiness
Drills at critical Company owned operating facilities (e.g. compressor stations,
pipeline interconnect locations, and gas dispatching control centers) to
simulate operation under the low probability occurrence of loss of local
electricity or communications (primarily telephone). These drills tested backup
generation equipment, alternative communication functionality (radios), and our
employees' preparedness to manually operate the physical gas delivery system
should these low probability events occur. These drills also tested and
sharpened the Company's readiness to dispatch and make safe any customer
emergencies, which might occur during a loss of electrical supply or
communications functionality. The Company will have a very significant
incremental workforce in the field during the critical Year 2000 rollover period
New Year's Eve. The pertinent portions of these plans have been filed with the
NYPSC whose review is ongoing. Distribution Corporation and Supply Corporation
are currently working with other utilities in their service areas and regional
Emergency Management Services to establish communication channels and procedures
in the low probability event of a serious Year 2000 disruption. The Company has
always had disaster/contingency plans to deal with operational gas supply or
delivery problems, loss of the corporate data center, and loss of the corporate
customer telephone centers. These plans, in conjunction with the Year 2000
drills, enable the Company to verify its readiness and ability to operate in the
event of failures resulting from Year 2000 problems arising outside of the
Company (i.e., loss of electricity, telephone service, etc.). All critical Year
2000 contingency plans have been completed.*
All of the above Year 2000 information is a YEAR 2000 READINESS
DISCLOSURE made pursuant to the Year 2000 Information and Readiness Disclosure
Act of 1998.
Effects of Inflation
Although the rate of inflation has been relatively low over the past few years,
and thus has benefited both the Company and its customers, the Company's
operations remain sensitive to increases in the rate of inflation because of its
capital spending and the regulated nature of a significant portion of its
business.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this combined
Annual Report to Shareholders/Form 10-K to make applicable and take advantage of
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995 for any forward-looking statements made by, or on behalf of, the Company.
Forward-looking statements include statements concerning plans, objectives,
goals, strategies, future events or performance, and underlying assumptions and
other statements which are other than statements of historical facts. From time
to time, the Company may publish or otherwise make available forward-looking
statements of this nature. All such subsequent forward-looking statements,
whether written or oral and whether made by or on behalf of the Company, are
also expressly qualified by these cautionary statements. Certain statements
contained herein, including those which are designated with a "*", are
forward-looking statements and accordingly involve risks and uncertainties which
could cause actual results or outcomes to differ materially from those expressed
in the forward-looking statements. The forward-looking statements contained
herein are based on various assumptions, many of which are based, in turn, upon
further assumptions. The Company's expectations, beliefs and projections are
expressed in good faith and are believed by the Company to have a reasonable
basis, including without limitation, management's examination of historical
operating trends, data contained in the Company's records and other data
available from third parties, but there can be no assurance that management's
expectations, beliefs or projections will result or be achieved or accomplished.
In addition to other factors and matters discussed elsewhere herein, the
following are important factors that, in the view of the Company, could cause
actual results to differ materially from those discussed in the forward-looking
statement:
1. Changes in economic conditions, demographic patterns and weather
conditions;
2. Changes in the availability and/or price of natural gas and oil;
3. Inability to obtain new customers or retain existing ones;
4. Significant changes in competitive factors affecting the Company;
5. Governmental/regulatory actions and initiatives, including those
affecting financings, allowed rates of return, industry and rate
structure, franchise renewal, and environmental/safety requirements;
6. Unanticipated impacts of restructuring initiatives in the natural gas
and electric industries;
7. Significant changes from expectations in actual capital expenditures
and operating expenses and unanticipated project delays;
8. The nature and projected profitability of pending and potential
projects and other investments;
9. Occurrences affecting the Company's ability to obtain funds from
operations, debt or equity to finance needed capital expenditures and
other investments;
10. Uncertainty of oil and gas reserve estimates;
11. Ability to successfully identify and finance oil and gas property
acquisitions and ability to operate existing and any subsequently
acquired properties;
12. Ability to successfully identify, drill for and produce economically
viable natural gas and oil reserves;
13. Changes in the availability and/or price of derivative financial
instruments;
14. Inability of the various counterparties to meet their obligations with
respect to the Company's financial instruments;
15. Regarding foreign operations - changes in foreign trade and monetary
policies, laws and regulations related to foreign operations, political
and governmental changes, inflation and exchange rates, taxes and
operating conditions;
16. Significant changes in tax rates or policies or in rates of inflation
or interest;
17. Significant changes in the Company's relationship with its employees
and the potential adverse effects if labor disputes or grievances were
to occur;
18. Changes in accounting principles and/or the application of such
principles to the Company; and/or
19. Unanticipated problems related to the Company's internal Year 2000
initiative as well as potential adverse consequences related to third
party Year 2000 compliance.
The Company disclaims any obligation to update any forward-looking
statements to reflect events or circumstances after the date hereof.
ITEM 7A Quantitative and Qualitative Disclosures About Market Risk
Refer to the "Market Risk Sensitive Instruments" section in Item 7, MD&A.
ITEM 8 Financial Statements and Supplementary Data
Index to Financial Statements
- -----------------------------
Page
----
Financial Statements:
Report of Independent Accountants 58
Consolidated Statements of Income and Earnings Reinvested
in the Business, three years ended September 30, 1999 59
Consolidated Balance Sheets at September 30, 1999 and 1998 60
Consolidated Statement of Cash Flows, three years ended
September 30, 1999 62
Consolidated Statement of Comprehensive Income,
three years ended September 30, 1999 63
Notes to Consolidated Financial Statements 64
Financial Statement Schedules:
For the three years ended September 30, 1999
II-Valuation and Qualifying Accounts 88
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 generally accepted accounting principles 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 generally
accepted auditing standards.
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.
Report of Independent Accountants
- ---------------------------------
To the Board of Directors
and Shareholders of
National Fuel Gas Company
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of
National Fuel Gas Company and its subsidiaries at September 30, 1999 and 1998,
and the results of their operations and their cash flows for each of the three
years in the period ended September 30, 1999, in conformity with accounting
principles generally accepted in the United States. In addition, in our opinion,
the financial statement schedules listed in the accompanying index present
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 schedules are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and financial statement schedules based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note A to the consolidated financial statements, the
Company changed its method of depletion for oil and gas properties in 1998.
PricewaterhouseCoopers LLP
Buffalo, New York
October 25, 1999
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) 1999 1998 1997
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Income
Operating Revenues $1,263,274 $1,248,000 $1,265,812
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Operating Expenses
Purchased Gas 405,925 441,746 528,610
Fuel Used in Heat and Electric Generation 55,788 37,837 1,489
Operation 300,007 293,976 260,839
Maintenance 23,881 25,793 25,698
Property, Franchise and Other Taxes 91,146 92,817 100,549
Depreciation, Depletion and Amortization 129,690 118,880 111,650
Impairment of Oil and Gas Producing
Properties - 128,996 -
Income Taxes 64,829 24,024 68,674
- -------------------------------------------------------------- ----------------- ----------------- ------------------
1,071,266 1,164,069 1,097,509
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Operating Income 192,008 83,931 168,303
Other Income 12,343 35,870 3,196
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 204,351 119,801 171,499
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Interest Charges
Interest on Long-Term Debt 65,402 53,154 42,131
Other Interest 22,296 32,130 14,680
- -------------------------------------------------------------- ----------------- ----------------- ------------------
87,698 85,284 56,811
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Minority Interest in Foreign Subsidiaries (1,616) (2,213) -
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Income Before Cumulative Effect 115,037 32,304 114,688
Cumulative Effect of Change in
Accounting for Depletion - (9,116) -
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Net Income Available for Common Stock 115,037 23,188 114,688
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Earnings Reinvested in the Business
Balance at Beginning of Year 428,112 472,595 422,874
- -------------------------------------------------------------- ----------------- ----------------- ------------------
543,149 495,783 537,562
Dividends on Common Stock 70,632 67,671 64,967
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Balance at End of Year $472,517 $428,112 $472,595
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Basic Earnings Per Common Share:
Income Before Cumulative Effect $2.98 $0.85 $3.01
Cumulative Effect of Change in Accounting
For Depletion - (0.24) -
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Net Income Available for Common Stock $2.98 $0.61 $3.01
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Diluted Earnings Per Common Share:
Income Before Cumulative Effect $2.95 $0.84 $2.98
Cumulative Effect of Change in Accounting
For Depletion - (0.24) -
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Net Income Available for Common Stock $2.95 $0.60 $2.98
- -------------------------------------------------------------- ----------------- ----------------- ------------------
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 38,663,981 38,316,397 38,083,514
Used in Diluted Calculation 39,041,728 38,703,526 38,440,018
- -------------------------------------------------------------- ----------------- ----------------- ------------------
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
- ---------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands of Dollars) 1999 1998
- ---------------------------------------------------------------------------- ------------------- -------------------
Assets
Property, Plant and Equipment $3,383,537 $3,186,853
Less - Accumulated Depreciation,
Depletion and Amortization 1,029,643 938,716
- ---------------------------------------------------------------------------- ------------------- -------------------
2,353,894 2,248,137
- ---------------------------------------------------------------------------- ------------------- -------------------
Current Assets
Cash and Temporary Cash Investments 29,222 30,437
Receivables - Net 105,296 82,336
Unbilled Utility Revenue 18,674 15,403
Gas Stored Underground 41,099 31,661
Materials and Supplies - at average cost 23,350 24,609
Unrecovered Purchased Gas Costs 4,576 6,316
Prepayments 35,072 19,755
- ---------------------------------------------------------------------------- ------------------- -------------------
257,289 210,517
- ---------------------------------------------------------------------------- ------------------- -------------------
Other Assets
Recoverable Future Taxes 87,724 88,303
Unamortized Debt Expense 21,717 22,295
Other Regulatory Assets 25,214 41,735
Deferred Charges 14,266 8,619
Other 82,482 64,853
- ---------------------------------------------------------------------------- ------------------- -------------------
231,403 225,805
- ---------------------------------------------------------------------------- ------------------- -------------------
$2,842,586 $2,684,459
- ---------------------------------------------------------------------------- ------------------- -------------------
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
- ---------------------------------------------------------------------------- ----------------- ----------------
At September 30 (Thousands of Dollars) 1999 1998
- ---------------------------------------------------------------------------- ----------------- ----------------
Capitalization and Liabilities
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued and
Outstanding - 38,837,499 Shares and 38,468,795
Shares, Respectively $ 38,837 $ 38,469
Paid In Capital 431,952 416,239
Earnings Reinvested in the Business 472,517 428,112
Accumulated Other Comprehensive Income (4,013) 7,265
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Common Stock Equity 939,293 890,085
Long-Term Debt, Net of Current Portion 822,743 693,021
- ---------------------------------------------------------------------------- ----------------- ----------------
Total Capitalization 1,762,036 1,583,106
- ---------------------------------------------------------------------------- ----------------- ----------------
Minority Interest in Foreign Subsidiaries 27,589 25,479
- ---------------------------------------------------------------------------- ----------------- ----------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 393,495 326,300
Current Portion of Long-Term Debt 69,608 216,929
Accounts Payable 82,747 59,933
Amounts Payable to Customers 5,934 5,781
Other Accruals and Current Liabilities 87,310 80,480
- ---------------------------------------------------------------------------- ----------------- ----------------
639,094 689,423
- ---------------------------------------------------------------------------- ----------------- ----------------
Deferred Credits
Accumulated Deferred Income Taxes 275,008 258,222
Taxes Refundable to Customers 14,814 18,404
Unamortized Investment Tax Credit 11,007 11,372
Other Deferred Credits 113,038 98,453
- ---------------------------------------------------------------------------- ----------------- ----------------
413,867 386,451
- ---------------------------------------------------------------------------- ----------------- ----------------
Commitments and Contingencies - -
- ---------------------------------------------------------------------------- ----------------- ----------------
$2,842,586 $2,684,459
- ---------------------------------------------------------------------------- ----------------- ----------------
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Statement of Cash Flows
------------------------------------
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Year Ended September 30 (Thousands of Dollars) 1999 1998 1997
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Operating Activities
Net Income Available for Common Stock $115,037 $ 23,188 $114,688
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Cumulative Effect of a Change in Accounting
for Depletion - 9,116 -
Impairment of Oil and Gas Producing Properties - 128,996 -
Depreciation, Depletion and Amortization 129,690 118,880 111,650
Deferred Income Taxes 14,030 (26,237) 3,800
Minority Interest in Foreign Subsidiaries 1,616 2,213 -
Other 7,018 (6,378) 8,030
Change in:
Receivables and Unbilled Utility Revenue (18,161) 45,200 (10,332)
Gas Stored Underground and Materials and
Supplies (7,806) (1,271) 7,300
Unrecovered Purchased Gas Costs 1,740 (6,316) -
Prepayments (15,322) 829 10,065
Accounts Payable 22,871 (24,975) 9,495
Amounts Payable to Customers 153 (4,735) 5,898
Other Accruals and Current Liabilities 10,931 (15,481) 4,113
Other Assets (906) 36 (2,856)
Other Liabilities 10,999 9,913 32,811
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Provided by Operating Activities 271,890 252,978 294,662
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Investing Activities
Capital Expenditures (260,506) (393,233) (214,001)
Investment in Subsidiaries, Net of Cash Acquired (5,774) (111,966) (21,075)
Investment in Partnerships (3,633) (5,453) -
Other 6,687 7,583 1,429
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Used in Investing Activities (263,226) (503,069) (233,647)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper 67,195 229,387 (107,300)
Net Proceeds from Issuance of Long-Term Debt 198,217 198,750 99,500
Reduction of Long-Term Debt (213,849) (103,867) (1,310)
Proceeds from Issuance of Common Stock 10,735 7,853 7,074
Dividends Paid on Common Stock (69,878) (66,959) (64,260)
Dividends Paid to Minority Interest (246) (253) -
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Cash Provided by (Used in) Financing Activities (7,826) 264,911 (66,296)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Effect of Exchange Rates on Cash (2,053) 1,578 -
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Increase (Decrease) in Cash and
Temporary Cash Investments (1,215) 16,398 (5,281)
Cash and Temporary Cash Investments
at Beginning of Year 30,437 14,039 19,320
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Cash and Temporary Cash Investments
at End of Year $ 29,222 $ 30,437 $ 14,039
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Statement of Comprehensive Income
----------------------------------------------
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Year Ended September 30 (Thousands of Dollars) 1999 1998 1997
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Net Income Available for Common Stock $115,037 $ 23,188 $114,688
----------------- ---------------- -----------------
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment (11,737) 9,350 (2,085)
Unrealized Gain on Securities Available for
Sale 706 - -
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Other Comprehensive Income (Loss), Before Tax (11,031) 9,350 (2,085)
Income Tax Expense Related to Unrealized Gain
on Securities Available for Sale 247 - -
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Other Comprehensive Income (Loss), Net of Tax (11,278) 9,350 (2,085)
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
Comprehensive Income $103,759 $32,538 $112,603
- ------------------------------------------------------------------ ----------------- ---------------- -----------------
See Notes to Consolidated Financial Statements
National Fuel Gas Company
Notes to Consolidated Financial Statements
Note A - Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
its majority owned subsidiaries. The equity method is used to account for the
Company's investment in any minority owned entities. All significant
intercompany balances and transactions have been eliminated where appropriate.
The preparation of the consolidated financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current year
presentation.
Regulation
Two of the Company's principal subsidiaries, Distribution Corporation and Supply
Corporation, are subject to regulation by certain state and federal authorities.
Distribution Corporation and Supply Corporation have accounting policies which
conform to generally accepted accounting principles, as applied to regulated
enterprises, and are in accordance with the accounting requirements and
ratemaking practices of the regulatory authorities. Reference is made to Note B
- - 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
Distribution Corporation's rate schedules contain clauses that permit adjustment
of revenues to reflect price changes from the cost of purchased gas included in
base rates. Differences between amounts currently recoverable and actual
adjustment clause revenues, as well as other price changes and pipeline and
storage company refunds not yet includable in adjustment clause rates, are
deferred and accounted for as either unrecovered purchased gas costs or amounts
payable to customers.
Distribution Corporation's rate settlements with the State of New York
Public Service Commission (NYPSC) include provisions for a sharing of earnings
over a specified rate of return on equity. Estimated refund liabilities are
recorded over the term of the settlements which reflect 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, 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.
Maintenance and repairs of property and replacements of minor items of
property are charged directly to maintenance expense. The original cost of the
regulated subsidiaries' property, plant and equipment retired, and the cost of
removal less salvage, are charged to accumulated depreciation.
Oil and gas 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. Due to significant declines in oil prices
in 1998, Seneca's capitalized costs under the full-cost method of accounting
exceeded these limits at March 31, 1998. Seneca was required to recognize an
impairment of its oil and gas producing properties in the quarter ended March
31, 1998. This charge amounted to $129.0 million (pretax) and reduced net income
for 1998 by $79.1 million.
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 (see discussion of change in method of depletion for
oil and gas properties below). 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 4.3% in 1999, 4.4% in 1998 and 4.6% in 1997.
Cumulative Effect of Change in Accounting
Effective October 1, 1997, Seneca changed its method of depletion for oil and
gas properties from the gross revenue method to the units of production method.
The units of production method was applied retroactively to prior years to
determine the cumulative effect through October 1, 1997. This cumulative effect
reduced earnings for 1998 by $9.1 million, net of income tax. Depletion of oil
and gas properties for 1999 and 1998 was computed under the units of production
method.
Pro forma amounts for 1998 and 1997 shown below, assume the retroactive
application of the new depletion method.
- --------------------------------------------------------------------------------------------------------------------
Year Ended September 30 1998 1997
- --------------------------------------------------------------------------------------------------------------------
Net Income (Thousands):
As reported $ 23,188 $114,688
Pro forma $ 32,304 $113,022
Earnings Per Common Share:
Basic - As reported $0.61 $3.01
Basic - Pro forma $0.85 $2.97
Diluted - As reported $0.60 $2.98
Diluted - Pro forma $0.84 $2.94
- --------------------------------------------------------------------------------------------------------------------
Gas Stored Underground - Current
Gas stored underground - current 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 1999, including transportation costs, the current
cost of replacing the inventory of gas stored underground-current exceeded the
amount stated on a LIFO basis by approximately $51.4 million at September 30,
1999.
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. The translation from the local currency to U. S. dollars is performed
for balance sheet accounts by using current exchange ratios in effect at the
balance sheet date and, for revenue and expense accounts, by using an average
exchange rate during the period. The resultant cumulative foreign currency
translation adjustment is recorded as a component of Accumulated Other
Comprehensive Income in the Common Stock Equity section of the Consolidated
Balance Sheet.
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 U.S.
Financial Instruments
Unrealized gains or losses from "available-for-sale securities" (i.e., the
Company's investments in marketable equity securities) are recorded as a
component of Accumulated Other Comprehensive Income in the Common Stock Equity
section of the Consolidated Balance Sheet. Reference is made to Note F -
Financial Instruments for further discussion.
Seneca utilizes price swap agreements and options (primarily written
options) to manage a portion of the market risk associated with fluctuations in
the price of natural gas and crude oil. NFR utilizes exchange-traded futures and
exchange-traded options to manage a portion of the market risk that it faces due
to fluctuations in the price of natural gas. Gains or losses from Seneca's price
swap agreements are accrued in operating revenues on the Consolidated Statement
of Income at the contract settlement dates. Seneca's options are
marked-to-market on a quarterly basis with gains or losses recorded in Operating
Revenues on the Consolidated Statement of Income. Gains or losses from NFR's
exchange-traded futures and exchange-traded options are recorded in Other
Deferred Credits on the Consolidated Balance Sheet until the hedged commodity
transaction occurs, at which point they are reflected in operating revenues on
the Consolidated Statement of Income. Reference is made to Note F - Financial
Instruments for further discussion.
In the International segment, PSZT utilizes an interest rate swap to
eliminate interest rate fluctuations on its variable rate debt. Gains or losses
are accrued in interest charges on the Consolidated Statement of Income at the
contract settlement dates.
Consolidated Statement of Cash Flows
For purposes of the Consolidated Statement of Cash Flows, the Company considers
all highly liquid debt instruments purchased with a maturity of generally three
months or less to be cash equivalents. Interest paid in 1999, 1998 and 1997 was
$75.8 million, $46.2 million and $52.4 million, respectively. Income taxes paid
in 1999, 1998 and 1997 were $35.0 million, $64.5 million and $69.2 million,
respectively.
Details of the stock acquisitions made by the Company during 1999 and
1998 are as follows:
- ----------------------------------------- --------------- ------------------------------------------------------------
Year Ended September 30 (Millions)
1999 1998
- ----------------------------------------- --------------- -------------- -------------- --------------- --------------
JTR(1) SCT PSZT HarCor(2) Total
- ----------------------------------------- --------------- |-------------- -------------- --------------- --------------
|
|
Assets acquired $13.5 | $66.1 $141.8 $105.6 $313.5
Liabilities assumed (7.3) | (22.3) (77.3) (73.0) (172.6)
Existing investment at acquisition (0.4) | (18.9) - - (18.9)
Cash acquired at acquisition (0.1) | (6.3) (0.9) (2.8) (10.0)
- ----------------------------------------- --------------- |-------------- -------------- --------------- --------------
Cash paid, net of cash acquired $5.7 | $18.6 $63.6 $29.8 $112.0
- ----------------------------------------- --------------- |-------------- -------------- --------------- --------------
(1) Jablonecka teplarenska a realitni, a.s. (JTR) is a majority owned subsidiary
of SCT.
(2) HarCor Energy, Inc. (HarCor).
Further discussion of these acquisitions can be found at Note J - Stock
Acquisitions.
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
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. This
statement requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. The intended use of the derivatives and their designation as
either a fair value hedge, a cash flow hedge, or a foreign currency hedge will
determine when the gains or losses on the derivatives are to be reported in
earnings and when they are to be reported as a component of other comprehensive
income.
Management has evaluated the derivatives used by Seneca, NFR and
Horizon and believes that the adoption of SFAS 133 will not have a material
impact on the financial condition or results of operations of the Company.
Management is continuing to evaluate other financial instruments and contracts
which may have embedded derivatives that could be impacted by the adoption of
SFAS 133. SFAS 133 required the Company to adopt the standard in the first
quarter of fiscal 2000. However, in June 1999, the FASB issued SFAS 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133." SFAS 137 delays, by one year, the
effective date of SFAS 133. Accordingly, the Company will adopt SFAS 133 by the
first quarter of fiscal 2001.
Note B - Regulatory Matters
Regulatory Assets and Liabilities
Distribution Corporation and Supply Corporation have recorded the following
regulatory assets and liabilities:
- --------------------------------------------------------------------------------- ------------------- -------------------
At September 30 (Thousands) 1999 1998
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Assets:
Recoverable Future Taxes (Note C) $87,724 $ 88,303
Unamortized Debt Expense (Note A) 15,223 16,886
Pension and Post-Retirement Benefit Costs (Note G) 21,217 22,483
Environmental Clean-up (Note H) - 12,394
Other 3,997 6,858
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Assets 128,161 146,924
- --------------------------------------------------------------------------------- ------------------- -------------------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) 5,934 5,781
New York Rate Settlements 18,913 19,341
Taxes Refundable to Customers (Note C) 14,814 18,404
Pension and Post-Retirement Benefit Costs(1) (Note G) 26,087 20,222
Other(1) 3,226 1,741
- --------------------------------------------------------------------------------- ------------------- -------------------
Total Regulatory Liabilities 68,974 65,489
- --------------------------------------------------------------------------------- ------------------- -------------------
Net Regulatory Position $59,187 $ 81,435
- --------------------------------------------------------------------------------- ------------------- -------------------
(1) Included in Other Deferred Credits on the Consolidated Balance Sheets.
If for any reason Distribution Corporation and/or Supply Corporation
ceases to meet the criteria for application of regulatory accounting treatment
for all or part of their operations, the regulatory assets and liabilities
related to those portions ceasing to meet such criteria would be eliminated from
the balance sheet and included in income of the period in which the
discontinuance of regulatory accounting treatment occurs. Such amounts would be
classified as an extraordinary item.
New York Rate Settlements
With respect to services provided in New York, Distribution Corporation has
entered into rate settlements with the NYPSC. The rate settlements provide for a
sharing mechanism, whereby earnings above a 12% return on equity are to be
shared equally between shareholders and ratepayers. As a result of this sharing
mechanism, Distribution Corporation had liabilities of $8.6 million and $10.7
million at September 30, 1999 and 1998, respectively. Of these amounts, $3.0
million was reclassified to Amounts Payable to Customers at September 30, 1999
and 1998 to reflect the amounts estimated to be passed back to customers in the
following year. Other aspects of the settlements include a special reserve of
$7.4 million (including interest of $0.2 million) recorded during 1999 to be
applied against Distribution Corporation's incremental costs resulting from the
NYPSC's gas restructuring effort and a "refund pool" of $3.5 million and $5.0
million at September 30, 1999 and 1998, 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 $2.5 million and $6.6 million at September 30, 1999
and 1998, respectively.
Note C - Income Taxes
The components of federal, state and foreign income taxes included in the
Consolidated Statement of Income are as follows:
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Expenses:
Current Income Taxes -
Federal $ 43,467 $ 40,740 $ 57,807
State 6,215 6,635 7,067
Deferred Income Taxes -
Federal 11,149 (21,687) 2,895
State 1,244 (5,997) 905
Foreign Income Taxes 2,754 4,333 -
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
64,829 24,024 68,674
Other Income:
Deferred Investment Tax Credit (729) (665) (665)
Minority Interest in Foreign Subsidiaries (642) (1,218) -
Cumulative Effect of Change in Accounting
for Depletion - (5,737) -
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Total Income Taxes $ 63,458 $ 16,404 $ 68,009
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
The U.S. and foreign components of income (loss) before income taxes are as follows:
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
U.S. $169,037 $ 31,127 $184,257
Foreign 9,457 8,465 (1,560)
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
$178,494 $ 39,592 $182,697
- ---------------------------------------------------------------- ----------------- ---------------- -----------------
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) 1999 1998 1997
- --------------------------------------------------------------- ------------------- --------------- ----------------
Net Income Available for Common Stock $115,037 $ 23,188 $114,688
Income Tax Expense 63,458 16,404 68,009
- --------------------------------------------------------------- ------------------- --------------- ----------------
Income Before Income Taxes 178,495 39,592 182,697
- --------------------------------------------------------------- ------------------- --------------- ----------------
Income Tax Expense, Computed at Federal
Statutory Rate of 35% 62,473 13,857 63,944
Increase (Reduction) in Taxes Resulting from:
State Income Taxes 4,848 986 5,182
Depreciation 1,872 2,186 2,560
Property Retirements (833) (1,609) (1,320)
Keyman Life Insurance (502) (774) (695)
Prior Years Tax Adjustment (1,362) 2,846 -
Miscellaneous (3,038) (1,088) (1,662)
- --------------------------------------------------------------- ------------------- --------------- ----------------
Total Income Taxes $ 63,458 $ 16,404 $ 68,009
- --------------------------------------------------------------- ------------------- --------------- ----------------
Significant components of the Company's deferred tax liabilities and
assets were as follows:
- ----------------------------------------------------------------------------------- --------------- ----------------
At September 30 (Thousands) 1999 1998
- ----------------------------------------------------------------------------------- --------------- ----------------
Deferred Tax Liabilities:
Abandonments $21,192 $15,545
Accelerated Tax Depreciation 132,732 132,138
Exploration and Intangible Well
Drilling Costs 165,798 147,795
Other 62,565 42,109
- ----------------------------------------------------------------------------------- --------------- ----------------
Total Deferred Tax Liabilities 382,287 337,587
- ----------------------------------------------------------------------------------- --------------- ----------------
Deferred Tax Assets:
Capitalized Overheads (25,587) (22,484)
Other (81,692) (56,881)
- ----------------------------------------------------------------------------------- --------------- ----------------
Total Deferred Tax Assets (107,279) (79,365)
- ----------------------------------------------------------------------------------- --------------- ----------------
Total Net Deferred Income Taxes $275,008 $258,222
- ----------------------------------------------------------------------------------- --------------- ----------------
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 $14.8 million and $18.4
million at September 30, 1999 and 1998, 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 $87.7 million and $88.3 million at September
30, 1999 and 1998, respectively.
The primary issues related to Internal Revenue Service audits of the
Company for the years 1977-1994 were settled during March 1998 and the remaining
issues were settled in December 1998. Net income for the years ended September
30, 1999 and 1998 was increased by approximately $3.9 million and $5.0 million,
respectively, as a result of interest, net of tax and other adjustments, related
to these settlements.
Note D - Capitalization
Summary of Changes in Common Stock Equity
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Earnings Accumulated
Paid Reinvested Other
(Thousands, Except Per Share Common Stock In in the Comprehensive
Amounts) Shares Amount Capital Business Income
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 1996 37,852 $37,852 $395,272 $422,874 $ -
Net Income Available
for Common Stock 114,688
Dividends Declared
on Common Stock
($1.71 Per Share) (64,967)
Other Comprehensive
Income, Net of Tax (2,085)
Common Stock Issued
Under Stock and
Benefit Plans 314 314 9,756
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 1997 38,166 38,166 405,028 472,595 (2,085)
Net Income Available
for Common Stock 23,188
Dividends Declared on
Common Stock
($1.77 Per Share) (67,671)
Other Comprehensive
Income, Net of Tax 9,350
Common Stock Issued
Under Stock and
Benefit Plans 303 303 11,211
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 1998 38,469 38,469 416,239 428,112 7,265
Net Income Available
for Common Stock 115,037
Dividends Declared on
Common Stock
($1.83 Per Share) (70,632)
Other Comprehensive
Income, Net of Tax (11,278)
Common Stock Issued
Under Stock and
Benefit Plans 368 368 15,713
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
Balance at
September 30, 1999 38,837 $38,837 $431,952 $472,517(1) $(4,013)
- ----------------------------------- -------------- ----------------- ---------------- ----------------- --------------------
(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, 1999, $398.1 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 Dividend Reinvestment and Stock
Purchase Plan allows shareholders to reinvest cash dividends and/or make cash
investments in the Company's common stock. The Customer Stock Purchase Plan
provides residential customers the opportunity to acquire shares of Company
common stock without the payment of any brokerage commissions or service charges
in connection with such acquisitions. Effective November 1, 1999, these two
plans were combined into a new plan, known as the National Fuel Direct Stock
Purchase and Dividend Reinvestment Plan. 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.
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 $130 per share, being $65 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 $.01 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, 1999, 1998 and 1997, no compensation
expense was recognized for options granted under these plans. Compensation
expense related to stock appreciation rights and restricted stock under these
stock plans was $1.0 million, $4.1 million and $8.1 million for the years ended
September 30, 1999, 1998 and 1997, respectively. 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 1999 1998 1997
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Net Income (Thousands):
As reported $115,037 $23,188 $114,688
Pro forma $111,385 $18,859 $110,506
Earnings Per Common Share:
Basic - As reported $2.98 $0.61 $3.01
Basic - Pro forma $2.88 $0.49 $2.90
Diluted - As reported $2.95 $0.60 $2.98
Diluted - Pro forma $2.85 $0.49 $2.87
- ---------------------------------------------------------- ------------------- ------------------- -------------------
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, 1996 1,773,251 $29.62
Granted in 1997 678,750 $39.61
Exercised in 1997(1) (274,655) $25.80
Forfeited in 1997 (3,000) $36.81
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 1997 2,174,346 $33.21
Granted in 1998 770,000 $44.44
Exercised in 1998(1) (205,200) $27.41
Forfeited in 1998 (7,250) $41.68
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 1998 2,731,896 $36.79
Granted in 1999 753,400 $46.70
Exercised in 1999(1) (111,504) $28.41
Forfeited in 1999 (9,700) $37.41
- ------------------------------------------------------------- ---------------------------- ---------------------------
Outstanding at September 30, 1999 3,364,092 $39.29
- ------------------------------------------------------------- ---------------------------- ---------------------------
Option shares exercisable at September 30, 1999 2,537,360 $37.01
Option shares available for future
grant at September 30, 1999(2) 76,338
- ------------------------------------------------------------- ---------------------------- ---------------------------
(1) In connection with exercising these options, 16,531, 44,580 and 117,326
shares were surrendered and canceled during 1999, 1998 and 1997,
respectively.
(2) Including shares available for restricted stock grants.
The weighted average fair value per share of options granted in 1999,
1998 and 1997 was $7.43, $7.91 and $7.66, 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 1999 1998 1997
- ---------------------------------------------------------- ------------------- ------------------- -------------------
Quarterly Dividend Yield 0.97% 0.98% 1.06%
Annual Standard Deviation (Volatility) 18.86% 16.48% 16.76%
Risk Free Rate 4.74% 5.77% 6.58%
Expected Term - in Years 5.0 5.5 5.0
- ---------------------------------------------------------- ------------------- ------------------- -------------------
The following table summarizes information about options outstanding at
September 30, 1999:
- --------------------------------------------------------------------------------- -------------------------------------
Options Outstanding Options Exercisable
- --------------------------------------------------------------------------------- -------------------------------------
Number Weighted Average Weighted Number Weighted
Range of Outstanding Remaining Average Exercisable Average
Exercise Price at 9/30/99 Contractual Life Exercise Price at 9/30/99 Exercise Price
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
$23.81 - $35.72 846,817 4.5 years $28.77 846,817 $28.77
$35.73 - $49.57 2,517,275 8.2 years $42.83 1,690,543 $41.14
- ------------------------- ---------------- -------------------- ----------------- ----------------- -------------------
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 1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Shares of Restricted Stock Awarded 6,580 7,609 6,300
Weighted Average Market Price of
Stock on Award Date $46.06 $44.88 $40.88
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
As of September 30, 1999, 96,319 shares of non-vested restricted stock
were outstanding. Vesting restrictions will lapse as follows: 2000 - 28,216
shares; 2001 - 35,103 shares; 2002 - 8,000 shares; 2003 - 8,000 shares; 2004 -
7,000 shares; 2005 - 6,000 shares; and 2006 - 4,000 shares.
Redeemable Preferred Stock
As of September 30, 1999, 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) 1999 1998
- ----------------------------------------------------------------------------------- ---------------- -----------------
National Fuel Gas Company:
Debentures:
7-3/4% due February 2004 $125,000 $125,000
Medium-Term Notes:
5.58% to 8.48% due March 1999 to August 2027(1) 699,000 649,000
- ----------------------------------------------------------------------------------- ---------------- -----------------
824,000 774,000
- ----------------------------------------------------------------------------------- ---------------- -----------------
HarCor:
14.875% Senior Secured Notes - 62,571
- ----------------------------------------------------------------------------------- ---------------- -----------------
PSZT:
8.04% U.S. Dollar Denominated
Debt due March 2000 - December 2004(2) - 50,596
7.505% Term Loan due March 2000 - December 2004(2) 47,671 -
- ----------------------------------------------------------------------------------- ---------------- -----------------
47,671 50,596
- ----------------------------------------------------------------------------------- ---------------- -----------------
Other Notes 20,680 22,783
- ----------------------------------------------------------------------------------- ---------------- -----------------
Total Long-Term Debt 892,351 909,950
Less Current Portion 69,608 216,929
- ----------------------------------------------------------------------------------- ---------------- -----------------
$822,743 $693,021
- ----------------------------------------------------------------------------------- ---------------- -----------------
(1) Includes $50 million of 8.48% medium-term notes due July 2024 which are
callable at a redemption price of 106.36% through July 2000. The redemption
price will decline in subsequent years. It 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.
(2) In December 1998, PSZT converted its U.S. Dollar denominated debt to a
Czech koruna denominated term loan. The interest rate on the new term loan
is six month Prague Interbank Offered Rate (PRIBOR) plus 0.475%. Refer to
Note F - Financial Instruments for discussion of PSZT's interest rate swap.
The aggregate principal amounts of long-term debt maturing for the next
five years and thereafter are as follows: $69.6 million in 2000, $12.6 million
in 2001, $10.7 million in 2002, $10.4 million in 2003, $235.4 million in 2004
and $553.7 million thereafter.
Note E - Short-Term Borrowings
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, 1999, the Company had outstanding short-term notes
payable to banks and commercial paper of $246.0 million (domestic = $244.8
million; foreign = $1.2 million) and $147.5 million, respectively. At September
30, 1998, the Company had outstanding notes payable to banks and commercial
paper of $196.3 million and $130.0 million, respectively.
The weighted average interest rate on domestic notes payable to banks
was 5.55% and 5.67% at September 30, 1999 and 1998, respectively. The interest
rate on the foreign notes payable to banks was 6.35% at September 30, 1999.
There were not any foreign notes payable to banks at September 30, 1998. The
weighted average interest rate on commercial paper was 5.49% and 5.60% at
September 30, 1999 and 1998, respectively.
Note F - Financial Instruments
Fair Values
The fair market value of the Company's long-term debt is estimated based on
quoted market prices of similar issues having the same remaining maturities,
redemption terms and credit ratings. Based on these criteria, the fair market
value of long-term debt, including current portion, was as follows:
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
1999 1999 1998 1998
Carrying Fair Carrying Fair
At September 30 (Thousands) Amount Value Amount Value
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
Long-Term Debt $892,351 $867,056 $909,950 $966,437
- ------------------------------------------------ ---------------- ----------------- ---------------- -----------------
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, as discussed below, are
stated at fair value based on quoted market prices.
Investments
Other assets includes cash surrender values of insurance contracts and a mutual
fund (accounted for as an "available-for-sale security"). The insurance
contracts and mutual fund were established as an informal funding mechanism for
various benefit obligations the Company has to certain employees. The cash
surrender values of the insurance contracts amounted to $44.2 million and $40.1
million at September 30, 1999 and 1998, respectively. The mutual fund amounted
to $5.0 million and $2.2 million at September 30, 1999 and 1998, respectively.
Other assets also includes shares of stock in an insurance company
which the Company received as part of the insurance company's initial public
offering in 1999. This "demutualization" of the insurance company resulted in a
gain to the Company of $2.4 million. At September 30, 1999, the value of the
stock was $2.3 million. The stock is accounted for as an "available-for-sale
security."
Derivative Financial Instruments
Seneca has entered into certain price swap agreements and options to manage a
portion of the market risk associated with fluctuations in the price of natural
gas and crude oil in an effort to provide more stability to its operating
results. These agreements and options are not held for trading purposes. The
price swap agreements call for Seneca to receive monthly payments from (or make
payment to) other parties based upon the difference between a fixed and a
variable price as specified by the agreement. The variable price is either a
crude oil price quoted on the New York Mercantile Exchange or a quoted natural
gas price in "Inside FERC." These variable prices are highly correlated with the
market prices received by Seneca for its natural gas and crude oil production.
The fair value of outstanding natural gas and crude oil price swap agreements
and options discussed below reflect the estimated amounts Seneca would pay or
receive to terminate its derivative financial instruments at September 30, 1999.
At September 30, 1999, Seneca had natural gas price swap agreements
covering a notional amount of 40.2 Bcf extending through 2002 at a weighted
average fixed rate of $2.69 per Mcf. Seneca also had crude oil price swap
agreements covering a notional amount of 2,296,000 bbls extending through 2001
at a weighted average fixed rate of $19.00 per bbl. The fair value of Seneca's
outstanding natural gas and crude oil price swap agreements at September 30,
1999 was a net loss of approximately $9.8 million. This loss was offset by
corresponding unrecognized gains from Seneca's anticipated natural gas and crude
oil production over the terms of the price swap agreements.
Seneca recognized net gains (losses) of $2.6 million, $(4.1) million
and $(21.5) million related to settlements of its price swap agreements during
1999, 1998 and 1997, respectively. As the price swap agreements have been
designated as hedges, these gains (losses) were offset by corresponding gains
(losses) from Seneca's natural gas and crude oil production.
At September 30, 1999, Seneca had the following options outstanding:
Type of Option Notional Amount Weighted Average Strike Price
- -------------- --------------- -----------------------------
Written Call Option 184,000 bbls $18.00/bbl
Written Call Option 2.6Bcf $2.86/Mcf
Written Call Options(1) 13.9 Bcf or 732,000 bbls $2.62/Mcf or $18.00/bbl
Written Put Option 916,000 bbls $12.50/bbl
Purchased Call Option 1,464,000 bbls $20.00/bbl
(1)The counterparty has a choice between a natural gas call option and a crude
oil call option, depending on whichever option has greater value to the
counterparty.
As disclosed in Note A-Summary of Significant Accounting Policies,
Seneca's call and put options are being marked-to-market. The mark-to-market
adjustment for 1999 was a loss of $1.3 million, the recording of which leaves
the fair value of the call and put options at September 30, 1999 at a net loss
of $3.6 million. During 1999, Seneca paid the counterparty $28,000 and $1.2
million related to the exercise of a portion of the written put options and the
written call options, respectively. Seneca received $0.6 million from the
counterparty related to Seneca's exercise of a portion of the $20.00 per bbl
call options that it had purchased.
The Company is exposed to credit risk on the price swap agreements that
Seneca has entered into as well as on the call options that Seneca has
purchased. 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.
NFR utilizes exchange-traded futures and exchange-traded options to
manage a portion of the market risk associated with fluctuations in the price of
natural gas. Such futures and options are not held for trading purposes. At
September 30, 1999, NFR had natural gas futures contracts covering 2.1 Bcf of
gas on a net basis extending through 2001 at a weighted average contract price
of $2.75 per Mcf. NFR had sold natural gas options covering 17.1 Bcf of gas at a
weighted average strike price of $3.01 per Mcf. NFR also had purchased natural
gas options covering 9.0 Bcf of gas at a weighted average strike price of $2.72
per Mcf. The exchange-traded futures and exchange-traded options are used to
hedge NFR's purchase and sale commitments and storage gas inventory. The fair
value of NFR's outstanding exchange-traded futures and exchange-traded options
at September 30, 1999 was a net gain of approximately $1.1 million. This fair
value reflects the estimated net amount that NFR would receive to terminate its
exchange-traded futures and exchange-traded options at September 30, 1999. Since
these exchange-traded futures contracts and exchange-traded options qualify and
have been designated as hedges, any gains or losses resulting from market price
changes would be substantially offset by the related commodity transaction.
NFR recognized net gains (losses) of $(5.4) million, $1.3 million and
$1.7 million related to futures contracts and options during 1999, 1998 and
1997, respectively. Since these futures contracts and options qualify and have
been designated as hedges, these net gains (losses) were substantially offset by
the related commodity transactions.
PSZT utilizes an interest rate swap to eliminate interest rate
fluctuations on its CZK 1,595,924,000 term loan ($47.7 million at September 30,
1999), which carries a variable interest rate of six month PRIBOR plus 0.475%.
Under the terms of the interest rate swap, which extends until 2001, PSZT pays a
fixed rate of 8.31% and receives a floating rate of six month PRIBOR. PSZT
recognized a loss of $0.1 million related to this interest rate swap during
1999. The fair value of PSZT's interest rate swap at September 30, 1999 was a
loss of approximately $1.0 million.
Note G - Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement
plan (Retirement Plan) that covers substantially all domestic employees of the
Company. The Company provides health care and life insurance benefits for
substantially all domestic retired employees under a post-retirement benefit
plan (Post-Retirement Plan).
The 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 and/or units in commingled funds or money market funds.
Distribution Corporation and Supply Corporation are fully recovering
their net periodic pension and post-retirement benefit costs in accordance with
the applicable regulatory commission authorization. For financial reporting
purposes, Distribution Corporation and Supply Corporation record 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 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,
Distribution Corporation 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) 1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period $532,250 $462,377 $432,753
Service Cost 12,676 10,655 9,988
Interest Cost 36,299 35,485 33,532
Amendments 1,691 - 1,479
Actuarial (Gain) Loss (13,598) 52,446 10,336
Benefits Paid (30,522) (28,713) (25,711)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Benefit Obligation at End of Period $538,796 $532,250 $462,377
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Plan Assets
Fair Value of Assets at Beginning of Period $509,393 $473,205 $431,828
Actual Return on Plan Assets 47,888 59,415 65,790
Employer Contribution 11,199 5,486 1,298
Benefits Paid (30,522) (28,713) (25,711)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Fair Value of Assets at End of Period $537,958 $509,393 $473,205
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Reconciliation of Funded Status
Funded Status $(838) $(22,857) $10,828
Unrecognized Net Actuarial Gain (45,853) (12,659) (38,687)
Unrecognized Transition Asset (14,864) (18,580) (22,296)
Unrecognized Prior Service Cost 12,048 11,369 12,435
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Accrued Benefit Cost $(49,507) $(42,727) $(37,720)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate 7.25% 7.00% 7.75%
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 $ 12,676 $ 10,655 $9,988
Interest Cost 36,299 35,485 33,532
Expected Return on Plan Assets (38,158) (35,724) (34,011)
Amortization of Prior Service Cost 1,012 1,065 991
Amortization of Transition Asset (3,716) (3,716) (3,754)
Recognition of Actuarial Loss 2,833 981 -
Early Retirement Window 7,032 - 1,904
Net Amortization and Deferral for
Regulatory Purposes 2,721 4,829 (374)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Net Periodic Benefit Cost $ 20,699 $ 13,575 $8,276
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The effect of the discount rate change in 1999 was to decrease the
Benefit Obligation by $15.9 million as of the end of the period. The effect of
the discount rate change in 1998 was to increase the Benefit Obligation as of
the end of the period by $45.0 million.
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) 1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Period $ 256,983 $218,370 $ 212,047
Service Cost 4,493 4,022 4,056
Interest Cost 17,635 17,122 16,594
Plan Participants' Contributions 673 867 417
Actuarial (Gain) Loss (13,542) 27,014 (6,653)
Benefits Paid (10,627) (10,412) (8,091)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Benefit Obligation at End of Period $ 255,615 $256,983 $ 218,370
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Change in Plan Assets
Fair Value of Assets at Beginning of Period $ 122,870 $ 98,639 $73,059
Actual Return on Plan Assets 17,345 14,602 13,618
Employer Contribution 19,623 19,174 19,636
Plan Participants' Contributions 673 867 417
Benefits Paid (10,627) (10,412) (8,091)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Fair Value of Assets at End of Period $ 149,884 $122,870 $98,639
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Reconciliation of Funded Status
Funded Status $(105,731) $(134,113) $(119,731)
Unrecognized Net Actuarial Loss (2,396) 19,660 505
Unrecognized Transition Obligation 99,780 106,907 114,034
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Accrued Benefit Cost $ (8,347) $ (7,546) $ (5,192)
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
- ----------------------------------------------------------------- ----------------- ----------------- -----------------
1999 1998 1997
- ----------------------------------------------------------------- ----------------- ----------------- -----------------
Weighted Average Assumptions as of September 30
Discount Rate 7.25% 7.00% 7.75%
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 $4,493 $4,022 $4,056
Interest Cost 17,635 17,122 16,594
Expected Return on Plan Assets (10,134) (8,099) (6,014)
Amortization of Transition Obligation 7,127 7,127 7,768
Amortization of Loss 1,304 683 -
Net Amortization and Deferral for
Regulatory Purposes 1,774 915 (1,257)
- ----------------------------------------------------------------- ----------------- ----------------- -----------------
Net Periodic Benefit Cost $ 22,199 $ 21,770 $ 21,147
- ----------------------------------------------------------------- ----------------- ----------------- -----------------
The effect of the discount rate change in 1999 was to decrease the
Benefit Obligation by $9.1 million. The effect of the discount rate change in
1998 was to increase the Benefit Obligation by $25.3 million.
The annual rate of increase in the per capita cost of covered medical
care benefits was assumed to be 10% for 1997, 9% for 1998 and 8% for 1999 and
gradually decline to 5.5% by the year 2003 and remain level thereafter. The
annual rate of increase for medical care benefits provided by healthcare
maintenance organizations was assumed to be 7.5% in 1998, 7.0% in 1999 and
gradually decline to 5.5% by the year 2002 and remain level thereafter. The
annual rate of increase in the per capita cost of covered prescription drug
benefits was assumed to be 8.5% for 1997, 9.0% for 1998 and 8.0% for 1999 and
gradually decline to 5.5% by the year 2003 and remain level thereafter. The
annual rate of increase in the per capita Medicare Part B Reimbursement was
assumed to be 3.1% for 1997, 9.0% for 1998 and 8.0% for 1999 and gradually
decline to 5.5% by the year 2003 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, 1999 would be increased by
$38.9 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 1999 by $4.0 million. If the health care cost trend rates were
decreased by 1% in each year, the Benefit Obligation as of October 1, 1999 would
be decreased by $34.0 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 1999 by $3.4 million.
Note H - Commitments and Contingencies
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.
Distribution Corporation and Supply Corporation have estimated their clean-up
costs related to the sites described below in (i) and (ii) will be in the range
of $9.4 million to $10.4 million. The minimum liability of $9.4 million has been
recorded on the Consolidated Balance Sheet at September 30, 1999. Other than
discussed 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 has been recovering site investigation and remediation
costs in rates. Accordingly, the Consolidated Balance Sheet at September 30,
1998 included related regulatory assets of $12.4 million. Over the past several
years, the Company has been negotiating settlements with its insurance carriers
related to environmental investigation and remediation costs. The Company
received net proceeds of approximately $9.8 million in 1999 and approximately
$3.5 million in 1998 related to these settlements. In addition, the Company
reached a settlement with one of its insurance carriers for reimbursement of
covered costs to remediate certain sites. A portion of the net proceeds received
and future proceeds accrued have been applied to reduce the Company's
environmental related regulatory assets to zero at September 30, 1999.
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.
(i) Former Manufactured Gas Plant and Former Gasoline Plant Sites
Distribution Corporation has incurred or is incurring clean-up costs at
five former manufactured gas plant sites in New York and Pennsylvania.
Remediation is complete at one site and substantially complete at a second site.
With respect to the second site, Distribution Corporation has been designated by
the New York Department of Environmental Conservation (DEC) as a potentially
responsible party (PRP) and is also engaged in litigation with the DEC and the
party who bought that site from Distribution Corporation's predecessor. At a
third site, the remedial plan has been approved by the DEC and remediation is
expected to begin in 2000. A fourth site is in an ongoing investigation stage
with remediation being designed. The fifth is a site allegedly containing, among
other things, manufactured gas plant waste and is in the investigation stage.
Supply Corporation is in the final stages of remediation of a former gasoline
plant site.
(ii) Third Party Waste Disposal Sites
Distribution Corporation and Supply Corporation are each currently
identified by the DEC or the Federal Environmental Protection Agency as one of a
number of companies considered to be PRPs with respect to certain waste disposal
sites in New York which were operated by unrelated third parties. The PRPs are
alleged to have contributed to the materials that may have been collected at
such waste disposal sites by the site operators. The ultimate cost to
Distribution Corporation or Supply Corporation 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 Distribution Corporation or
Supply Corporation. Distribution Corporation is a PRP at two waste disposal
sites. The remediation has been completed at one site and the remedial design
selected at the second site. Supply Corporation is a PRP at one waste disposal
site, which is at the investigation stage.
Without being named a PRP, Distribution Corporation has also signed a
consent decree (court approval pending) by which it would share the costs of
remediating another waste disposal site in New York. Also without being named a
PRP, Supply Corporation expects that it will participate in the cost of a site
that is currently being remediated by a third party.
(iii) Other Sites
Distribution Corporation received, in 1998 and again in October 1999,
notice that the DEC believes Distribution Corporation is responsible for
contamination discovered at an additional former manufactured gas plant site in
New York (without naming Distribution Corporation as a PRP). Distribution
Corporation responded that other companies operated that site before
Distribution Corporation's predecessor did, that liability could be imposed upon
Distribution Corporation only if hazardous substances were disposed of at the
site during a period when the site was operated by Distribution Corporation's
predecessor, and that Distribution Corporation was unaware of any such disposal.
Distribution Corporation 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.
Distribution Corporation understands that PRPs at another third party
waste disposal site have obtained records from the operator (a waste oil
collector) indicating that the site received used oil from Distribution
Corporation (among others). A contribution claim could, therefore, be asserted
against Distribution Corporation, which has not incurred any clean-up costs at
this site nor been able to reasonably estimate the probability or extent of
potential liability.
Supply Corporation believes that there is the possibility that it may
incur costs related to certain of its measuring and regulator stations in New
York. No costs have been incurred or accrued to date. Supply Corporation has
estimated its exposure at approximately $0.2 million.
(iv) Clean Air Standards
The Company, in its international operations in the Czech Republic has
substantially completed the construction of new fluidized-bed boilers at the
district heating and power generation plant of PSZT in order to comply with
certain clean air standards mandated by the Czech Republic government. Capital
expenditures related to this reconstruction incurred by PSZT in 1999 were
approximately $23.0 million.
Other
The Company has entered into contractual commitments in the ordinary course of
business including commitments by Distribution Corporation to purchase capacity
on nonaffiliated pipelines to meet customer gas supply needs. The majority of
these contracts (representing 88% of current 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 through inclusion in Distribution Corporation's rate schedules.
Management believes, to the extent any stranded pipeline costs are generated by
the unbundling of services in Distribution Corporation'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 expected to have a material adverse effect on the
financial condition of the Company at this time.
Note I - Business Segment Information
The Company has adopted SFAS 131, "Disclosures About Segments of an Enterprise
and Related Information" (SFAS 131), which changes the way the Company reports
information about its business segments. SFAS 131 requires disclosure of certain
financial information based upon how management evaluates the performance of its
business segments. The information for 1998 and 1997 has been restated from the
prior year's presentation to conform to the 1999 presentation.
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 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 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 will 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 of Texas and Louisiana, in California, in Wyoming and in the
Appalachian region of the United States. 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 of the Czech
Republic.
The Energy Marketing segment is comprised of NFR's operations. NFR is
engaged in the retail marketing of natural gas, the marketing of electricity,
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) and/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, 1999 (Thousands)
- ------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total
and and Energy Reportable
Utility Storage Production International Marketing Timber Segments All Other
- ------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers $801,053 $82,994 $140,212 $107,045 $99,088 $31,117 $1,261,509 $1,765
Intersegment
Revenues 6,302 85,789 6,782 - - - 98,873 -
Interest Expense 29,659 13,147 34,409 11,451 234 2,208 91,108 100
Depreciation,
Depletion and
Amortization 34,215 22,690 55,750 10,473 165 6,388 129,681 7
Income Tax
Expense 34,741 22,439 2,992 15 1,138 2,788 64,113 55
Segment Profit
(Loss): Net
Income 56,875 39,765 7,127 2,276 2,054 4,769 112,866 (162)
Expenditures for
Additions to
Long-Lived Assets 46,974 34,873 97,586 33,412 302 56,700 269,847 66
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
- ------------------------------------------------------------------------------------------------------------
Year Ended September 30, 1999 (Thousands)
- ------------------------------
Corporate and
Intersegment Total
Eliminations Consolidated
- ------------------------------
$ - $1,263,274
(98,873) -
(3,510) 87,698
2 129,690
661 64,829
2,333 115,037
- 269,913
- ------------------------------
$13,983 $2,842,586
- ------------------------------
Year Ended September 30, 1998 (Thousands)
- -------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total
and and Energy Reportable
Utility Storage Production International Marketing Timber Segments All Other
- -------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers $ 867,802 $84,218 $113,194 $76,259 $87,187 $17,805 $1,246,465 $1,535
Intersegment
Revenues 3,378 86,765 11,078 - - - 101,221 -
Interest Expense 44,639 15,232 21,454 7,188 31 1,580 90,124 33
Depreciation,
Depletion and
Amortization 33,459 21,816 50,937 7,309 91 5,169 118,781 97
Income Tax
Expense (Benefit) 30,076 29,644 (39,478) 2,158 471 1,445 24,316 119
Significant
Noncash Item:
Impairment of Oil
and Gas Producing
Properties - - 128,996 - - - 128,996 -
Segment Profit
(Loss): Income
Before Cumulative
Effect of Change
in Accounting 51,788 39,852 (64,110) 1,279 787 1,904 31,500 143
Expenditures for
Additions to
Long-Lived Assets 50,680 29,145 323,627 96,987 320 9,893 510,652 -
At September 30, 1998 (Thousands)
- -------------------------------------------------------------------------------------------------------------
Segment Assets $1,171,645 $526,738 $673,706 $242,339 $16,944 $45,507 $2,676,879 $5,216
- -------------------------------------------------------------------------------------------------------------
Year Ended September 30, 1998 (Thousands)
- ------------------------------
Corporate and
Intersegment Total
Eliminations Consolidated
- ------------------------------
$ - $1,248,000
(101,221) -
(4,873) 85,284
2 118,880
(411) 24,024
- 128,996
661 32,304
- 510,652
- ------------------------------
$2,364 $2,684,459
- ------------------------------
Year Ended September 30, 1997 (Thousands)
- -----------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total
and and Energy Reportable
Utility Storage Production International Marketing Timber Segments All Other
- -----------------------------------------------------------------------------------------------------------------
Revenue from
External
Customers $991,281 $82,883 $107,733 $1,910 $70,098 $11,536 $1,265,441 $ 371
Intersegment
Revenues 85 89,811 11,527 - - - 101,423 -
Interest Expense 32,608 16,068 11,103 1,230 33 1,410 62,452 18
Depreciation,
Depletion and
Amortization 32,972 21,459 51,117 107 14 5,960 111,629 18
Income Tax
Expense (Benefit) 35,510 21,026 11,592 (954) 931 (193) 67,912 55
Segment Profit
(Loss): Net
Income 57,220 36,760 20,359 (3,348) 1,567 (609) 111,949 171
Expenditures for
Additions to
Long-Lived Assets 66,908 22,562 120,282 22,293 96 16,151(1) 248,292 19
At September 30, 1997 (Thousands)
- -----------------------------------------------------------------------------------------------------------------
Segment Assets $1,175,885 $522,191 $469,795 $24,031 $17,083 $42,260 $2,251,245 $5,207
- -----------------------------------------------------------------------------------------------------------------
(1)Amount includes non-cash acquisition of $12.3 million in exchange for
long-term debt obligations.
Year Ended September 30, 1997 (Thousands)
- -------------------------------
Corporate and
Intersegment Total
Eliminations Consolidated
- -------------------------------
$ - $1,265,812
(101,423) -
(5,659) 56,811
3 111,650
707 68,674
2,568 114,688
- 248,311
- -------------------------------
$10,879 $2,267,331
- -------------------------------
- ---------------------------------------------------------------------------------------------------------------
Geographic Information: 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Year Ended September 30 (Thousands)
Revenues from External Customers:
United States $1,156,229 $1,171,741 $1,263,902
Czech Republic 107,045 76,259 1,910
---------- ---------- ----------
$1,263,274 $1,248,000 $1,265,812
- ---------------------------------------------------------------------------------------------------------------
At September 30 (Thousands)
Long-Lived Assets:
United States $2,369,840 $2,258,817 $2,036,525
Czech Republic 215,457 215,125 22,139
---------- ---------- ----------
$2,585,297 $2,473,942 $2,058,664
- ---------------------------------------------------------------------------------------------------------------
Note J - Stock Acquisitions
Exploration and Production
In May 1998, Seneca acquired the outstanding shares of HarCor for approximately
$32.6 million. The acquisition of HarCor was accounted for in accordance with
the purchase method. HarCor's results of operations were incorporated into the
Company's consolidated financial statements for the period subsequent to the
completion of the tender offer in May 1998. Effective August 31, 1999, HarCor
was merged into Seneca.
International
During 1998, Horizon, through a wholly-owned subsidiary, increased its ownership
interest in SCT from 36.8% at September 30, 1997 to 82.7% at September 30, 1998.
The cost of acquiring these additional shares was approximately $24.9 million.
Also in 1998, Horizon invested in PSZT, and owned an 86.2% interest at September
30, 1998. The cost of acquiring the shares of PSZT was approximately $64.5
million.
During 1999, Horizon, through a wholly-owned subsidiary, increased its
ownership interest in SCT to 82.87% for a minimal cost. SCT in turn increased
its ownership in JTR, a district heating plant in the northern Bohemia region of
the Czech Republic, from 34% to 65.78%. The cost of acquiring these additional
shares was approximately $5.8 million.
The acquisitions made in the International segment have been accounted
for in accordance with the purchase method. The goodwill resulting from these
acquisitions is being amortized over a twenty-year period. The goodwill is
recorded in Other Assets in the Company's Consolidated Balance Sheet. This
goodwill amounted to $9.5 million and $10.1 million at September 30, 1999 and
1998, respectively.
Note K - Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all
adjustments necessary for a fair statement of the results of operations for such
periods. Per common share amounts are calculated using the weighted average
number of shares outstanding during each quarter. The total of all quarters may
differ from the per common share amounts shown on the Consolidated Statement of
Income. Those per common share amounts are based on the weighted average number
of shares outstanding for the entire fiscal 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
Income Income (Loss) (Loss)
(Loss) Per Common Available Earnings
Operating Before Share Before for (Loss) Per
Quarter Operating Income Cumulative Cumulative Effect Common Common Share
----------------------- --------------------------
Ended Revenues (Loss) Effect Basic Diluted Stock Basic Diluted
- ----------------- -------------- -------------- ------------- ----------- ----------- --------------- ------------- ------------
1999 (Thousands, except per common share amounts)
- ----------------- ------------------------------------------------------------------- --------------- ------------- ------------
12/31/98 $340,422 $56,835 $ 37,619 $ 0.98 $0.97 $ 37,619(1) $ 0.98 $0.97
3/31/99 $483,404 $83,475 $ 61,145 $ 1.58 $1.57 $ 61,145 $ 1.58 $1.57
6/30/99 $248,658 $31,319 $ 11,840 $ 0.31 $0.30 $ 11,840(2) $ 0.31 $0.30
9/30/99 $190,790 $20,379 $ 4,433 $ 0.11 $0.11 $ 4,433(3) $ 0.11 $0.11
- ----------------- ------------------------------------------------------------------- --------------- ------------- ------------
1998 (Thousands, except per common share amounts)
- ----------------- ------------------------------------------------------------------- --------------- ------------- ------------
12/31/97 $371,021 $ 52,280 $ 37,534 $ 0.98 $0.97 $ 28,418(4) $ 0.74 $0.73
3/31/98 $462,648 $(16,228) $(21,262) $(0.56) N/A $(21,262)(5) $ (0.56) N/A
6/30/98 $242,447 $ 33,726 $ 19,107 $ 0.50 $0.49 $ 19,107 $ 0.50 $0.49
9/30/98 $171,884 $ 14,153 $ (3,075) $(0.08) N/A $ (3,075)(6) $ (0.08) N/A
- ----------------- -------------- -------------- ------------- ----------- ----------- --------------- ------------- ------------
N/A - Not applicable due to antidilution.
(1) Includes income of $3.9 million related to IRS audit settlement and expense
of $3.5 million related to an early retirement offer.
(2) Includes expense of $3.8 million related to stock appreciation rights
(SAR), expense of $1.1 million related to an early retirement offer and
income of $1.0 million for lost and unaccounted for (LAUF) gas adjustment
related to 1998.
(3) Includes income of $1.6 million for LAUF gas adjustment related to 1999 and
income of $1.6 million related to a gain on stock received from the
demutualization of an insurance company.
(4) Includes $9.1 million negative non-cash cumulative effect of a change in
accounting for depletion.
(5) Includes expense of $79.1 million for impairment of oil and gas producing
properties and income of $5.0 million related to IRS audit settlement.
(6) Includes expense of $1.8 million for Distribution Corporation refund
provision and income of $1.0 million for a net gain associated with U.S.
dollar denominated debt.
Note L - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 1999, there were 22,336 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, 1999 and 1998, are
shown below:
- --------------------------------------------------------------- ------------------------------------ -----------------
Price Range Dividends
------------------------------------
Quarter Ended High Low Declared
- --------------------------------------------------------------- ------------------- ---------------- -----------------
1999
- --------------------------------------------------------------- ------------------- ---------------- -----------------
12/31/98 $49-5/8 $44-7/8 $.450
3/31/99 $46-1/2 $39-1/4 $.450
6/30/99 $50 $37-1/2 $.465
9/30/99 $49-3/4 $44-5/8 $.465
- --------------------------------------------------------------- ------------------- ---------------- -----------------
1998
- --------------------------------------------------------------- ------------------- ---------------- -----------------
12/31/97 $48-15/16 $42-11/16 $.435
3/31/98 $48-13/16 $45-3/8 $.435
6/30/98 $49-1/8 $39-5/8 $.450
9/30/98 $47 $39-13/16 $.450
- --------------------------------------------------------------- ------------------ ---------------- -----------------
Note M - Supplementary Information for Oil and Gas Producing Activities
The following supplementary information is presented in accordance with SFAS 69,
"Disclosures about Oil and Gas Producing Activities," and related SEC accounting
rules.
Capitalized Costs Relating to Oil and Gas Producing Activities
- ----------------------------------------------------------------------------------- ---------------- -----------------
At September 30 (Thousands)
1999 1998
- ----------------------------------------------------------------------------------- ---------------- -----------------
Proved Properties $880,470 $739,684
Unproved Properties 92,097 141,873
- ----------------------------------------------------------------------------------- ---------------- -----------------
972,567 881,557
Less - Accumulated Depreciation, Depletion
and Amortization 315,675 261,236
- ----------------------------------------------------------------------------------- ---------------- -----------------
$656,892 $620,321
- ----------------------------------------------------------------------------------- ---------------- -----------------
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, 1999:
- ---------------------------- -------------------------- --------------------------------------------------------------
Total as of Year Costs Incurred
--------------------------------------------------------------
(Thousands) September 30, 1999 1999 1998 1997 Prior
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
Acquisition Costs $82,994 $12,077 $51,226 $8,525 $11,166
Exploration Costs 9,103 9,103 - - -
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
$92,097 $21,180 $51,226 $8,525 $11,166
- ---------------------------- -------------------------- ---------------- --------------- -------------- --------------
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Property Acquisition Costs: (1)
Proved $ 2,798 $189,201 $ 4,154
Unproved 11,530 88,369 23,120
Exploration Costs 52,141 74,421 76,703
Development Costs 30,985 23,887 15,583
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
$ 97,454 $375,878 $119,560
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Total proved and unproved property acquisition costs for 1998 of $277.6
million include amounts related to the HarCor, Bakersfield Energy and
Whittier Trust properties acquired in 1998 of $87.0 million, $25.3 million
and $141.1 million, respectively.
Results of Operations for Producing Activities
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Operating Revenues:
Natural Gas (includes revenues from sales to affiliates
of $6,365, $11,065 and $10,682, respectively) $ 81,734 $ 89,284 $100,411
Oil, Condensate and Other Liquids 51,592 31,770 39,237
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Total Operating Revenues(1) 133,326 121,054 139,648
Production/Lifting Costs 28,119 23,622 17,335
Depreciation, Depletion and Amortization
($0.89 and $0.96 per Mcfe of production, and $0.36 per
dollar of operating revenues, respectively) (2) 54,439 50,221 50,687
Impairment of Oil and Gas Producing Properties(3) - 128,996 -
Income Tax Expense (Benefit) 16,255 (28,949) 24,699
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Results of Operations for Producing Activities
(excluding corporate overheads and interest charges) $ 34,513 $(52,836) $ 46,927
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
(1) Exclusive of hedging gains and losses. See further discussion in Note F -
Financial Instruments.
(2) In 1998, Seneca changed its method of depletion for oil and gas producing
properties from the gross revenue method to the units of production method.
See further discussion in Note A - Summary of Significant Accounting
Policies.
(3) 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. 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
----------------------------------------- -----------------------------------------
Year Ended September 30 1999 1998 1997 1999 1998 1997
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
Proved Developed and
Undeveloped Reserves:
Beginning of Year 325,065 232,449 207,082 66,591 17,981 25,749
Extensions and Discoveries 46,423 40,293 47,951 3,716 640 359
Revisions of
Previous Estimates (13,091) (18,623) 20,820 9,808 (4,191) (6,224)
Production (37,166) (36,474) (38,586) (4,016) (2,614) (1,902)
Sales of Minerals in Place (439) - (5,464) (280) - (1)
Purchases of Minerals
in Place and Other - 107,420 646 - 54,775 -
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
End of Year 320,792 325,065 232,449 75,819 66,591 17,981
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
Proved Developed Reserves:
Beginning of Year 230,508 194,454 163,537 48,081 11,354 14,043
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
End of Year 222,929 230,508 194,454 57,333 48,081 11,354
- -------------------------------------- ------------ ------------- -------------- ------------- ------------- -------------
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)
1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Cash Inflows $2,402,308 $1,547,216 $1,072,375
Less:
Future Production Costs 560,459 413,753 166,989
Future Development Costs 185,617 160,884 85,216
Future Income Tax Expense at
Applicable Statutory Rate 477,205 245,120 257,172
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Future Net Cash Flows 1,179,027 727,459 562,998
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 471,768 260,688 179,798
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows $ 707,259 $ 466,771 $ 383,200
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Year Ended September 30 (Thousands) 1999 1998 1997
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $466,771 $383,200 $329,244
Sales, Net of Production Costs (53,615) (97,432) (122,313)
Net Changes in Prices, Net of Production Costs 317,356 (180,853) 78,499
Purchases of Minerals in Place - 364,102 1,138
Sales of Minerals in Place (2,706) - (9,632)
Extensions and Discoveries 122,894 36,844 88,228
Changes in Estimated Future Development Costs (97,082) (104,181) (20,785)
Previously Estimated Development Costs Incurred 72,349 28,514 43,731
Net Change in Income Taxes at
Applicable Statutory Rate (232,085) 57,190 (24,797)
Revisions of Previous Quantity Estimates 40,964 (75,136) (27,317)
Accretion of Discount and Other 72,413 54,523 47,204
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $707,259 $466,771 $383,200
- ----------------------------------------------------------------- ----------------- ---------------- -----------------
Schedule II - Valuation and Qualifying Accounts
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Additions Additions
Balance at Charged to Charged to Balance at
(Thousands) Beginning Costs and Other End of
Description of Period Expenses Accounts(1) Deductions(2) Period
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 1999
Reserve for Doubtful Accounts $6,232 $15,337 $ 1 $13,728 $7,842
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 1998
Reserve for Doubtful Accounts $8,291 $15,861 $746 $18,666 $6,232
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
Year Ended September 30, 1997
Reserve for Doubtful Accounts $7,672 $16,586 $ - $15,967 $8,291
- ----------------------------------------- --------------- -------------- -------------- ----------------- --------------
(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.
ITEM 9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
PART III
--------
ITEM 10 Directors and Executive Officers of the Registrant
The information required by this item concerning the directors of the Company is
omitted pursuant to Instruction G of Form 10-K since the Company's definitive
Proxy Statement for its February 17, 2000 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after September 30, 1999. The
information provided in such definitive Proxy Statement, excepting the "Report
of the Compensation Committee," and the "Corporate Performance Graph," is
incorporated herein by reference. Information concerning the Company's executive
officers can be found in Part I, Item 1, of this report.
ITEM 11 Executive Compensation
The information required by this item is omitted pursuant to Instruction G of
Form 10-K since the Company's definitive Proxy Statement for its February 17,
2000 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1999. The information provided in such definitive
Proxy Statement, excepting the "Report of the Compensation Committee," and the
"Corporate Performance Graph," is incorporated herein by reference.
ITEM 12 Security Ownership of Certain Beneficial Owners and Management
The information required by this item is omitted pursuant to Instruction G of
Form 10-K since the Company's definitive Proxy Statement for its February 17,
2000 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1999. The information provided in such definitive
Proxy Statement, excepting the "Report of the Compensation Committee," and the
"Corporate Performance Graph," is incorporated herein by reference.
ITEM 13 Certain Relationships and Related Transactions
At September 30, 1999, the Company knows of no relationships or transactions
required to be disclosed pursuant to Item 404 of Regulation S-K.
PART IV
-------
ITEM 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) Financial Statement Schedules
All financial statement schedules filed as part of this report
are included in Item 8 of this Form 10-K and reference is made
thereto.
(b) Reports on Form 8-K
None
(c) Exhibits
Exhibit
Number Description of Exhibits
------ -----------------------
3(i) Articles of Incorporation:
o Restated Certificate of Incorporation of National Fuel Gas
Company dated September 21, 1998 (Exhibit 3.1, Form 10-K for
fiscal year ended September 30, 1998 in File No. 1-3880)
3(ii) By-Laws:
3.1 National Fuel Gas Company By-Laws as amended on September
16, 1999
(4) Instruments Defining the Rights of Security Holders,
Including Indentures:
o Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company)
(Exhibit 2(b) in File No. 2-51796)
o Third Supplemental Indenture dated as of December 1, 1982,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(a)(4) in File No. 33-49401)
o Tenth Supplemental Indenture dated as of February 1, 1992,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(a), Form 8-K dated February 14, 1992 in
File No. 1-3880)
o Eleventh Supplemental Indenture dated as of May 1, 1992, to
Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company)
(Exhibit 4(b), Form 8-K dated February 14, 1992 in File No.
1-3880)
o Twelfth Supplemental Indenture dated as of June 1, 1992, to
Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company)
(Exhibit 4(c), Form 8-K dated June 18, 1992 in File No.
1-3880)
o Thirteenth Supplemental Indenture dated as of March 1, 1993,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(a)(14) in File No. 33-49401)
o Fourteenth Supplemental Indenture dated as of July 1, 1993,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4.1, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
o Fifteenth Supplemental Indenture dated as of September 1,
1996 to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4.1, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
4.1 Indenture dated as of October 1, 1999, between the Company
and The Bank of New York
4.2 Officer's Certificate Establishing Medium-Term Notes dated
October 14, 1999
o Amended and Restated Rights Agreement, dated as of April 30,
1999, between National Fuel Gas Company and HSBC Bank USA
(Exhibit 10.2, Form 10-Q for the quarterly period ended
March 31, 1999 in File No. 1-3880)
(10) Material Contracts:
(ii)(B) Contracts upon which Registrant's business is
substantially dependent:
o Service Agreement No. 830016 with Texas Eastern Transmission
Corporation, under Rate Schedule FT-1, dated November 2,
1995 (Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
o Service Agreement No. 830017 with Texas Eastern Transmission
Corporation, under Rate Schedule FT-1, dated November 2,
1995 (Exhibit 10.2, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
o Service Agreement with Texas Eastern Transmission
Corporation, under Rate Schedule CDS, dated November 2, 1995
(Exhibit 10.3, Form 10-K for fiscal year ended September 30,
1996 in File No. 1-3880)
o Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation, under
Rate Schedule FSS, dated April 3, 1996 [Portions of this
agreement are subject to confidential treatment under Rule
24b-2] (Exhibit 10.4, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
o Service Agreement with Engage Energy US, L.P. (formerly St.
Clair Pipelines Ltd.), dated January 29, 1996 [Portions of
this agreement are subject to confidential treatment under
Rule 24b-2] (Exhibit 10.5, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
o Service Agreement with Empire State Pipeline under Rate
Schedule FT, dated December 15, 1994 [Portions of this
agreement are subject to confidential treatment under Rule
24b-2] (Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1995, in File No. 1-3880)
o Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation under
Rate Schedule ESS dated August 1, 1993 (Exhibit 10.2, Form
10-K for fiscal year ended September 30, 1995, in File No.
1-3880)
o Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation under
Rate Schedule ESS dated September 19, 1995 (Exhibit 10.3,
Form 10-K for fiscal year ended September 30, 1995, in File
No. 1-3880)
o Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation under
Rate Schedule EFT dated August 1, 1993 (Exhibit 10.4, Form
10-K for fiscal year ended September 30, 1995, in File No.
1-3880)
o Amendment dated as of May 1, 1995 to Service Agreement
between National Fuel Gas Distribution Corporation and
National Fuel Gas Supply Corporation under Rate Schedule EFT
dated August 1, 1993 (Exhibit 10.5, Form 10-K for fiscal
year ended September 30, 1995, in File No. 1-3880)
o Service Agreement with Transcontinental Gas Pipe Line
Corporation under Rate Schedule FT dated August 1, 1993
(Exhibit 10.6, Form 10-K for fiscal year ended September 30,
1995, in File No. 1-3880)
o Service Agreement with Transcontinental Gas Pipe Line
Corporation under Rate Schedule FT dated October 1, 1993
(Exhibit 10.7, Form 10-K for fiscal year ended September 30,
1995, in File No. 1-3880)
o Service Agreement with Columbia Gas Transmission Corporation
under Rate Schedule FTS, dated November 1, 1993 and executed
February 13, 1994 (Exhibit 10.1, Form 10-K for fiscal year
ended September 30, 1994 in File No. 1-3880)
o Service Agreement with Columbia Gas Transmission Corporation
under Rate Schedule FSS, dated November 1, 1993 and executed
February 13, 1994 (Exhibit 10.2, Form 10-K for fiscal year
ended September 30, 1994 in File No. 1-3880)
o Service Agreement with Columbia Gas Transmission Corporation
under Rate Schedule SST, dated November 1, 1993 and executed
February 13, 1994 (Exhibit 10.3, Form 10-K for fiscal year
ended September 30, 1994 in File No. 1-3880)
o Gas Transportation Agreement with Tennessee Gas Pipeline
Company under Rate Schedule FT-A (Zone 4), dated September
1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
o Gas Transportation Agreement with Tennessee Gas Pipeline
Company under Rate Schedule FT-A (Zone 5), dated September
1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
o Service Agreement with CNG Transmission Corporation under
Rate Schedule FT, dated October 1, 1993 (Exhibit 10.5, Form
10-K for fiscal year ended September 30, 1993 in File No.
1-3880)
o Service Agreement with CNG Transmission Corporation under
Rate Schedule GSS, dated October 1, 1993 (Exhibit 10.6, Form
10-K for fiscal year ended September 30, 1993 in File No.
1-3880)
(iii) Compensatory plans for officers:
o Employment Agreement, dated September 17, 1981, with Bernard
J. Kennedy (Exhibit 10.4, Form 10-K for fiscal year ended
September 30, 1994 in File No. 1-3880)
10.1 Tenth Amendment to Employment Agreement with Bernard J.
Kennedy, effective September 1, 1999
o Agreement, dated August 1, 1989, with Richard Hare (Exhibit
10-Q, Form 10-K for fiscal year ended September 30, 1989 in
File No. 1-3880)
o Agreement dated August 1, 1986, with Joseph P. Pawlowski
(Exhibit 10.1, Form 10-K for fiscal year ended September
30,1997 in File No. 1-3880)
o Agreement dated August 1, 1986, with Gerald T. Wehrlin
(Exhibit 10.2, Form 10-K for fiscal year ended September 30,
1997, in File No. 1-3880)
o Form of Employment Continuation and Noncompetition
Agreements, dated as of December 11, 1998, with 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)
o Form of Employment Continuation and Noncompetition
Agreement, dated as of December 11, 1998, with Bruce H. Hale
and Richard Hare (Exhibit 10.2, Form 10-Q for the quarterly
period ended June 30, 1999 in File No. 1-3880)
o Form of Employment Continuation and Noncompetition
Agreement, dated as of December 11, 1998, with James A. Beck
(Exhibit 10.3, Form 10-Q for the quarterly period ended June
30, 1999 in File No. 1-3880)
o National Fuel Gas Company 1983 Incentive Stock Option Plan,
as amended and restated through February 18, 1993 (Exhibit
10.2, Form 10-Q for the quarterly period ended March 31,
1993 in File No. 1-3880)
o National Fuel Gas Company 1984 Stock Plan, as amended and
restated through February 18, 1993 (Exhibit 10.3, Form 10-Q
for the quarterly period ended March 31, 1993 in File No.
1-3880)
o Amendment to the National Fuel Gas Company 1984 Stock Plan,
dated December 11, 1996 (Exhibit 10.7, Form 10-K for fiscal
year ended September 30, 1996 in File No. 1-3880)
o National Fuel Gas Company 1993 Award and Option Plan, dated
February 18, 1993 (Exhibit 10.1, Form 10-Q for the quarterly
period ended March 31, 1993 in File No. 1-3880)
o Amendment to National Fuel Gas Company 1993 Award and Option
Plan, dated October 27, 1995 (Exhibit 10.8, Form 10-K for
fiscal year ended September 30, 1995 in File No. 1-3880)
o Amendment to National Fuel Gas Company 1993 Award and Option
Plan, dated December 11, 1996 (Exhibit 10.8, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
o Amendment to National Fuel Gas Company 1993 Award and Option
Plan, dated December 18, 1996 (Exhibit 10, Form 10-Q for the
quarterly period ended December 31, 1996 in File No. 1-3880)
o National Fuel Gas Company 1997 Award and Option Plan
(Exhibit 10.9, Form 10-K for fiscal year ended September 30,
1996 in File No. 1-3880)
10.2 Amended and Restated National Fuel Gas Company 1997 Award
and Option Plan, dated December 9, 1999 (being submitted to
Shareholder vote at the Annual Meeting in February 2000)
o National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through May 1, 1994 (Exhibit 10.7, Form
10-K for fiscal year ended September 30, 1994 in File No.
1-3880)
o Amendment to the National Fuel Gas Company Deferred
Compensation Plan, dated September 19, 1996 (Exhibit 10.10,
Form 10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
o Amendment to the National Fuel Gas Company Deferred
Compensation Plan, dated September 27, 1995 (Exhibit 10.9,
Form 10-K for fiscal year ended September 30, 1995 in File
No. 1-3880)
o National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through March 20, 1997 (Exhibit 10.3,
Form 10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
o Amendment to National Fuel Gas Company Deferred Compensation
Plan dated June 16, 1997 (Exhibit 10.4, Form 10-K for fiscal
year ended September 30, 1997 in File No. 1-3880)
o Amendment No. 2 to the National Fuel Gas Company Deferred
Compensation Plan, dated March 13, 1998 (Exhibit 10.1, Form
10-K for fiscal year ended September 30, 1998 in File No.
1-3880)
o Amendment to the National Fuel Gas Company Deferred
Compensation Plan, dated February 18, 1999 (Exhibit 10.1,
Form 10-Q for the quarterly period ended March 31, 1999 in
File No. 1-3880)
o National Fuel Gas Company Tophat Plan, effective March 20,
1997 (Exhibit 10, Form 10-Q for the quarterly period ended
June 30, 1997 in File No. 1-3880)
o Amendment No. 1 to the National Fuel Gas Company Tophat
Plan, dated April 6, 1998 (Exhibit 10.2, Form 10-K for
fiscal year ended September 30, 1998 in File No. 1-3880)
o Amendment No. 2 to the National Fuel Gas Company Tophat
Plan, dated December 10, 1998 (Exhibit 10.1, Form 10-Q for
the quarterly period ended December 31, 1998 in File No.
1-3880)
o Death Benefits Agreement, dated August 28, 1991, with
Bernard J. Kennedy (Exhibit 10-TT, Form 10-K for fiscal year
ended September 30, 1991 in File No. 1-3880)
o Amendment to Death Benefit Agreement of August 28, 1991,
with Bernard J. Kennedy, dated March 15, 1994 (Exhibit
10.11, Form 10-K for fiscal year ended September 30, 1995 in
File No. 1-3880)
o Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 17, 1997 with Philip C.
Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
10.3 Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Philip C. Ackerman, dated
March 23, 1999
10.4 Second Amended and Restated Split Dollar Insurance Agreement
dated August 9, 1999 with Richard Hare
o Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Joseph P.
Pawlowski (Exhibit 10.7, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
10.5 Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Joseph P. Pawlowski, dated
March 23, 1999
10.6 Second Amended and Restated Split Dollar Insurance Agreement
dated June 15, 1999 with Gerald T. Wehrlin
10.7 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Walter E.
DeForest
10.8 Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Walter E. DeForest, dated
March 29, 1999
10.9 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Dennis J.
Seeley
10.10 Amendment Number 1 to Amended and Restated Split Dollar
Insurance and Death Benefit Agreement by and Between
National Fuel Gas Company and Dennis J. Seeley, dated March
29, 1999
10.11 Split Dollar Insurance and Death Benefit Agreement dated
September 15, 1997 with Bruce H. Hale
10.12 Amendment Number 1 to Split Dollar Insurance and Death
Benefit Agreement by and Between National Fuel Gas Company
and Bruce H. Hale, dated March 29, 1999
10.13 Split Dollar Insurance and Death Benefit Agreement dated
September 15, 1997 with David F. Smith
10.14 Amendment Number 1 to Split Dollar Insurance and Death
Benefit Agreement by and Between National Fuel Gas Company
and David F. Smith, dated March 29, 1999
o National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan as amended and restated through
November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year
ended September 30, 1995 in File No. 1-3880)
o National Fuel Gas Company and Participating Subsidiaries
1996 Executive Retirement Plan Trust Agreement (II) dated
May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
o Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan dated September 18,
1997 (Exhibit 10.9, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
o Amendments to the 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)
10.15 Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan effective September
16, 1999
o Administrative Rules with Respect to at Risk Awards under
the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
o Administrative Rules of the Compensation Committee of the
Board of Directors of National Fuel Gas Company, as amended
and restated, effective December 10, 1998 (Exhibit 10.3,
Form 10-Q for the quarterly period ended December 31, 1998
in File No. 1-3880)
o Excerpts of Minutes from the National Fuel Gas Company Board
of Directors Meeting of February 20, 1997 regarding the
Retirement Benefits for Bernard J. Kennedy (Exhibit 10.10,
Form 10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
o Excerpts of Minutes from the National Fuel Gas Company Board
of Directors Meeting of March 20, 1997 regarding the
Retainer Policy for Non-Employee Directors (Exhibit 10.11,
Form 10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Business segment discussion as contained in the 1999 Annual
Report and incorporated by reference into this Form 10-K
(21) Subsidiaries of the Registrant:
See Item 1 of Part I of this Annual Report on
Form 10-K
(23) Consents of Experts:
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
(27) Financial Data Schedules:
27.1 Financial Data Schedule for the Twelve Months Ended
September 30, 1999
27.2 Restated Financial Data Schedule for the Twelve Months Ended
September 30, 1998
(99) Additional Exhibits:
99.1 Report of Ralph E. Davis Associates, Inc.
All other exhibits are omitted because they are not applicable or the
required information is shown elsewhere in this Annual Report on Form
10-K.
o Incorporated herein by reference as indicated.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
National Fuel Gas Company
(Registrant)
------------
By /s/ B. J. Kennedy
--------------------
B. J. Kennedy
Chairman of the Board
and Chief Executive Officer
Date: December 9, 1999
-------------------
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,
---------------------- Chief Executive Officer and Director
B. J. Kennedy
Date: December 9, 1999
----------------
/s/ P. C. Ackerman President, Principal Financial
--------------------- Officer and Director
P. C. Ackerman
Date: December 9, 1999
----------------
/s/ R. T. Brady Director
--------------------
R. T. Brady
Date: December 9, 1999
----------------
/s/ J. V. Glynn Director
---------------------
J. V. Glynn
Date: December 9, 1999
----------------
/s/ W. J. Hill Director
---------------------
W. J. Hill
Date: December 9, 1999
----------------
/s/ B. S. Lee Director
---------------------
B. S. Lee
Date: December 9, 1999
----------------
/s/ E. T. Mann Director
---------------------
E. T. Mann
Date: December 9, 1999
----------------
/s/ G. L. Mazanec Director
---------------------
G. L. Mazanec
Date: December 9, 1999
----------------
/s/ G. H. Schofield Director
---------------------
G. H. Schofield
Date: December 9, 1999
----------------
/s/ J. P. Pawlowski Treasurer and Principal
--------------------- Accounting Officer
J. P. Pawlowski
Date: December 9, 1999
----------------
APPENDIX TO ITEM 2 - PROPERTIES
Six maps outlining the Company's operating areas at September 30, 1999 are
included on pages 2 and 3 of the paper format version of the Company's
combined Annual Report to Shareholders/Form 10-K. 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 International operating area (i.e., Horizon's Czech Republic
operations). The fifth map identifies the Company's Energy Marketing
operating area (i.e., NFR's marketing service area). The sixth map
identifies the Company's Timber Operating area (i.e., Seneca's and
Highland's timber and sawmill operations).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 1999
Two pie graphs detailing the revenue dollar in 1999: where it came from
and where it went to, broken down as follows:
Where it came from:
$ .456 Residential Gas Sales
.115 Commercial, Industrial and Off-System Gas Sales
.100 Oil and Gas Production Revenues
.085 Gas Transportation Revenues
.078 Energy Marketing Revenues
.056 District Heating Revenues
.028 Gas Storage Service Revenues
.027 Electric Generation Revenues
.024 Timber and Sawmill Revenues
.031 Other Revenues
$1.000 Total
Where it went to:
$ .319 Gas Purchased
.151 Wages, Including Benefits
.122 Taxes
.103 Other Materials and Services
.102 Depreciation
.068 Interest
.055 Dividends - Common Stock
.044 Fuel Used in Heat and Electric Generation
.035 Reinvested in the Business
.001 Minority Interest in Foreign Subsidiaries
$1.000 Total
Exhibit Index
-------------
3.1 National Fuel Gas Company By-Laws as amended
on September 16, 1999
4.1 Indenture dated as of October 1, 1999,
between the Company and The Bank of New York
4.2 Officer's Certificate Establishing Medium-
Term Notes dated October 14, 1999
10.1 Tenth Amendment to Employment Agreement with
Bernard J. Kennedy, effective September 1,
1999
10.2 Amended and Restated National Fuel Gas
Company 1997 Award and Option Plan, dated
December 9, 1999 (being submitted to
Shareholder vote at the Annual Meeting in
February 2000)
10.3 Amendment Number 1 to Amended and Restated
Split Dollar Insurance and Death Benefit
Agreement by and Between National Fuel Gas
Company and Philip C. Ackerman, dated March
23, 1999
10.4 Second Amended and Restated Split Dollar
Insurance Agreement dated August 9, 1999
with Richard Hare
10.5 Amendment Number 1 to Amended and Restated
Split Dollar Insurance and Death Benefit
Agreement by and Between National Fuel Gas
Company and Joseph P. Pawlowski, dated March
23, 1999
10.6 Second Amended and Restated Split Dollar
Insurance Agreement dated June 15, 1999 with
Gerald T. Wehrlin
10.7 Amended and Restated Split Dollar Insurance
and Death Benefit Agreement dated September
15, 1997 with Walter E. DeForest
10.8 Amendment Number 1 to Amended and Restated
Split Dollar Insurance and Death Benefit
Agreement by and Between National Fuel Gas
Company and Walter E. DeForest, dated March
29, 1999
10.9 Amended and Restated Split Dollar Insurance
and Death Benefit Agreement dated September
15, 1997 with Dennis J. Seeley
10.10 Amendment Number 1 to Amended and Restated
Split Dollar Insurance and Death Benefit
Agreement by and Between National Fuel Gas
Company and Dennis J. Seeley, dated March
29, 1999
10.11 Split Dollar Insurance and Death Benefit
Agreement dated September 15, 1997 with
Bruce H. Hale
10.12 Amendment Number 1 to Split Dollar Insurance
and Death Benefit Agreement by and Between
National Fuel Gas Company and Bruce H. Hale,
dated March 29, 1999
10.13 Split Dollar Insurance and Death Benefit
Agreement dated September 15, 1997 with
David F. Smith
10.14 Amendment Number 1 to Split Dollar Insurance
and Death Benefit Agreement by and Between
National Fuel Gas Company and David F.
Smith, dated March 29, 1999
10.15 Amendments to National Fuel Gas Company and
Participating Subsidiaries Executive Retire-
ment Plan effective September 16, 1999
(12) Computation of Ratio of Earnings to Fixed
Charges
(13) Business segment discussion as contained in
the 1999 Annual Report and incorporated by
reference into this Form 10-K
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
27.1 Financial Data Schedule for the Twelve
Months Ended September 30, 1999
27.2 Restated Financial Data Schedule for the
Twelve Months Ended September 30, 1998
99.1 Report of Ralph E. Davis Associates, Inc.