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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, 1997
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
-----------------------------------------------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each
exchange
Title of each class 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 $1,707,884,000 as of November 30, 1997.
Common Stock, $1 Par Value, outstanding as of November 30, 1997:
38,216,910 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Annual Report to Shareholders for 1997 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 26, 1998 are incorporated by reference into Part III of this
report.
National Fuel Gas Company
Form 10-K Annual Report
For the Fiscal Year Ended September 30, 1997
Table of Contents
Page
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Part I
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Item 1. Business
The Company and its Subsidiaries 19
Rates and Regulation 21
The Utility Segment 21
The Pipeline and Storage Segment 22
The Exploration and Production Segment 22
The Other Nonregulated Segment 23
Sources and Availability of Raw Materials 23
Competition 23
Seasonality 25
Capital Expenditures 25
Environmental Matters 25
Miscellaneous 25
Executive Officers of the Company 26
Item 2. Properties
General Information on Facilities 27
Exploration and Production Activities 27
Item 3. Legal Proceedings 28
Item 4. Submission of Matters to a Vote of Security Holders 28
Part II
- -------
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 49
Item 8. Financial Statements and Supplementary Data 49
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 78
Part III
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Item 10. Directors and Executive Officers of the Registrant 78
Item 11. Executive Compensation 78
Item 12. Security Ownership of Certain Beneficial Owners and
Management 78
Item 13. Certain Relationships and Related Transactions 78
Part IV
- -------
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 79
Signatures 82
- ----------
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 "1" following the statement, as well as those statements that
are identified by the use of the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts," "projects," and similar expressions.
PART I
------
ITEM 1 Business
The Company and its Subsidiaries
National Fuel Gas Company (the 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 in
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 an integrated natural gas operation consisting of three
major business segments:
1. The Utility segment is 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 is 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) 30 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 has agreed to purchase, upon receipt of regulatory approval, a
one-third general partnership interest in Independence Pipeline Company
(Independence), a Delaware general partnership. Independence, after receipt of
regulatory approvals, 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 is 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 of Texas, Louisiana, and Alabama, in California, in
Wyoming, and in the Appalachian region of the United States.
The Other Nonregulated segment is carried out by the following
subsidiaries:
* Horizon Energy Development, Inc. (Horizon), a New York corporation formed in
1995 to engage in foreign and domestic energy projects through investment as a
sole or partial owner in various business entities including Beheer-en-
Beleggingsmaatschappij Bruwabel B.V. (Bruwabel), a Dutch company whose principal
asset is an equity investment in Severoceske Teplarny, a.s. (SCT), a company
with district heating and power generation operations located in the northern
part of the Czech Republic. Bruwabel also owns and operates an additional
district heating plant and a power development group in the Czech Republic.
* 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 utilities and end-users located in the
northeastern and midwestern United States;
* Niagara Energy Trading Inc. (NET), a New York corporation formed in July 1997
to engage in wholesale natural gas trading and other energy-related activities;
* Niagara Independence Marketing Company (NIM), a Delaware corporation formed in
September 1997 to own a one-third general partnership interest in DirectLink Gas
Marketing Company (DirectLink), a Delaware general partnership which will engage
in natural gas marketing and related businesses, in part by subscribing for firm
transportation capacity on the Independence Pipeline (see Pipeline and Storage
segment discussion below);
* Leidy Hub, Inc. (Leidy), a New York corporation engaged in providing various
natural gas hub services to customers in the northeastern, mid-Atlantic, Chicago
and Los Angeles areas of the United States and Ontario, Canada, through (i)
Leidy's 50% ownership of Ellisburg-Leidy Northeast Hub Company (a Pennsylvania
general partnership) and (ii) Leidy's 14.5% ownership of Enerchange, L.L.C.
(Enerchange) (a Delaware limited liability company which in turn owns
QuickTrade, L.L.C., another Delaware limited liability company);
* Seneca is also engaged in the marketing of timber from its Pennsylvania land
holdings;
* Highland Land & Minerals, Inc. (Highland), a Pennsylvania corporation which
operates a sawmill and kiln in Kane, Pennsylvania and a sawmill in Kersey,
Pennsylvania;
* Data-Track Account Services, Inc. (Data-Track), a New York corporation which
provides collection services (principally issuing collection notices) for the
Company's subsidiaries (principally Distribution Corporation); and
* Utility Constructors, Inc. (UCI), a Pennsylvania corporation which
discontinued its operations (primarily pipeline construction) in 1995 and whose
affairs are being wound down.
Financial information about each of the Company's business segments can
be found in Item 8 at Note I Business Segment Information. No single customer,
or group of customers under common control, accounted for more than 10% of the
Company's consolidated revenues in 1997. All references to years in this report
are to the Company's fiscal year ended September 30 unless otherwise noted.
The discussion of the Company's business segments as contained in the
Letter to Shareholders, which is included on pages 4 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.
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 has recommended legislation to repeal conditionally the
Holding Company Act, in conjunction with legislation which would allow the
various state regulatory commissions to have access to such books and records of
companies in a holding company system as would be necessary for effective
regulation, and allow for federal audit authority and oversight of affiliate
transactions. However, the additional proposed access
to Company books and records by state regulatory commissions would
correspondingly increase the amount of regulatory burden at the state level. In
addition, recent SEC rule changes have reduced the number of applications
required to be filed under the Holding Company Act, exempted some routine
financings and expanded diversification opportunities. The Company is unable to
predict at this time what the ultimate outcome of legislative and/or regulatory
changes will be, and therefore what the impact on the Company might be.1
The Utility segment's rates, services and other matters are regulated
by the Public Service Commission of the State of New York (PSC) 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
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 Federal Energy Regulatory Commission (FERC). SIP is not
itself regulated by the FERC, but its sole business will be 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 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 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.
This report occasionally refers collectively to the Utility segment and
the Pipeline and Storage segment as the Regulated Operations.
The Company's current operations other than the Utility segment and the
Pipeline and Storage segment are not regulated as to prices or rates for
services. Accordingly, this report occasionally refers collectively to the
Exploration and Production segment and the Other Nonregulated segment as the
Nonregulated Operations.
The Utility Segment
The Utility segment contributed approximately 52% of the Company's operating
income before income taxes in 1997.
Additional discussion of the Utility segment appears in the Letter to
Shareholders contained in this combined Annual Report to Shareholders/Form 10-K,
below 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 31% of the Company's
operating income before income taxes in 1997.
Supply Corporation currently has service agreements for substantially
all of its firm transportation capacity, which totals approximately 1,893
million cubic feet (MMcf) per day. The Utility segment has contracted for
approximately 1,126 MMcf per day or 59% of that capacity until 2003 and
continuing year-to-year thereafter. An additional 25% of that capacity is
subject to firm contracts with nonaffiliated customers until 2003 or later.
Supply Corporation has available for sale to customers approximately
60.9 billion cubic feet (Bcf) of firm storage capacity. The Utility segment has
contracted for 26.0 Bcf or 43% of that capacity, in service agreements with
remaining initial terms of approximately 6 to 9 years and continuing
year-to-year thereafter: 23.3 Bcf - 6 years; 2.0 Bcf - 9 years and 0.7 Bcf - 7
years. Nonaffiliated customers have contracted for the remaining 34.9 Bcf or 57%
of firm storage capacity; 12.1 Bcf or 20% of total storage capacity is
contracted by nonaffiliated customers until 2003 or later.
The primary terms of current firm storage service agreements
representing 23.3 Bcf of Supply Corporation's firm storage capacity contracted
for by nonaffiliated customers expired in 1995. Service continues year-to-year
and can be terminated or reduced by the customer on one year's notice. When such
terminations or reductions occur, Supply Corporation has been able to remarket
the storage service under firm contracts, at discounted rates. Currently, the
Pipeline and Storage segment is actively marketing 3.3 Bcf of available storage
capacity.
Independence has filed with the FERC signed precedent agreements
providing for firm transportation service totalling about 530,000 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.
Additional discussion of the Pipeline and Storage segment appears in
the Letter to Shareholders 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 and I-Business Segment Information.
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 18% of the
Company's operating income before income taxes in 1997.
Additional discussion of the Exploration and Production segment appears
in the Letter to Shareholders contained in this combined Annual Report to
Shareholders/Form 10-K, below under the heading "Competition," Item 7 "MD&A,"
and Item 8 at Notes F-Financial Instruments, I-Business Segment Information and
L-Supplementary Information for Oil and Gas Producing Activities.
The Other Nonregulated Segment
The Other Nonregulated segment reduced the Company's operating income before
income taxes slightly (less than 1%) in 1997. Corporate operations reduced the
Company's operating income before income taxes by approximately 1%.
Additional discussion of the Other Nonregulated segment appears in the
Letter to Shareholders 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.
Sources and Availability of Raw Materials
Natural gas is the principal raw material for the Utility segment and some of
the subsidiaries in the Other Nonregulated segment, as discussed below. Supply
Corporation transports and stores gas owned by its customers, whose gas
originates in the southwestern United States, Canada and Appalachia. SIP,
through Independence, proposes to transport natural gas produced in Canada and
in the midwestern United States. Highland and Seneca's timber operations rely to
a large degree upon timber located on Seneca's lands, so that source and
availability are not issues. The Exploration and Production segment seeks to
discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as
described in the Letter to Shareholders 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 L Supplementary Information for Oil and Gas Producing
Activities.
In 1997, the Utility segment purchased 138.8 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 74% of these purchases.
Purchases of gas in Canada under long-term contracts, purchases of gas in Canada
and the United States on the spot market (contracts of less than a year) and
purchases from Appalachian producers accounted for 3%, 21% and 2%, respectively,
of the Utility segment's 1997 gas purchases. Gas purchases from Vastar
Resources, Inc. and Natural Gas Clearinghouse (both southwest gas under
long-term contracts) represented 14% and 21%, respectively, of total 1997 gas
purchases by the Utility segment. No other producer or marketer provided the
Utility segment with 10% or more of its gas requirements in 1997.
The Other Nonregulated segment needs natural gas for its marketing and
Leidy's hub services, but is relatively indifferent as to the source.
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.1 In
addition, the environmental advantages of natural gas compared with other fuels
should increase the role of natural gas as an energy source.1 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.1
The Company competes on the basis of price, service and reliability,
product performance and other factors. Sources and providers of energy, other
than those described under this "Competition" heading, do not compete with the
Company to any significant extent.
Competition: The Utility Segment
The changes precipitated by the FERC's restructuring of the gas industry in
Order No. 636 are redefining the roles of the gas utility industry and the state
regulatory commissions. The PSC issued an order in 1995 providing for the
Utility segment to implement unbundling of its services. The Utility segment has
implemented most of the provisions contained in the PSC's 1995 order, and now
offers unbundled, flexible services to its residential, commercial and
industrial customers. At present, these provisions are not advantageous to the
residential customers because of high cost and the resulting lack of interest by
gas marketers in offering residential gas sales. In large part, the high cost is
due to the significant customer protections required of utilities which are then
passed along in rates. Such protections include sufficient contracts to
purchase, transport and store natural gas in the event that it is needed by
residential customers.
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.1
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 Corporaton 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.1
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 U.S. 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.1 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.1
Independence is attempting to be the first of the proposed projects approved by
the FERC and the first built.1 Independence will also create opportunities for
increased transportation and storage services by Supply Corporation.1
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 gas exploration and production companies of various sizes for
leases and drilling rights for exploration and development prospects.
To compete in this environment, the Exploration and Production segment
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 Other Nonregulated Segment
In the Other Nonregulated segment, NFR, NET and NIM, through DirectLink, compete
with other marketers and energy management services providers. Leidy competes
with other natural gas hub service providers. Highland competes with other
sawmills in northwestern Pennsylvania. Horizon competes with other entities
seeking to develop foreign and domestic energy projects.
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.
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.
Capital Expenditures
A discussion of capital expenditures by business segment is included in Item 7
under the heading "Investing Cash Flow," subheading "Capital Expenditures."
Environmental Matters
A discussion of material environmental matters involving the Company is included
in Item 8, Note H-Commitments and Contingencies.
Miscellaneous
The Company had 2,524 full-time employees at September 30, 1997, a decrease of
11.2% from the 2,843 employed at September 30, 1996.
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 were renegotiated, effective April
and May 1996, and are scheduled to expire in April and May 1999.
The Company has numerous county and municipal franchises under which it
uses public roads and certain other rights-of-way and public property for the
location of facilities. The Company has regularly renewed such franchises at
expiration and expects no difficulty in continuing to renew them.1
Executive Officers of the Company*
Age as of Current Company Date Elected To
Name 9/30/97 Positions Current Positions
---- --------- --------------- -----------------
Bernard J. Kennedy 66 Chairman of the
Board of Directors. March 21, 1989
Chief Executive
Officer. August 1, 1988
President. January 1, 1987
Director. March 29, 1978
Philip C. Ackerman 53 Director. March 16, 1994
Senior Vice President. June 1, 1989
President of
Distribution Corporation. October 1, 1995
Executive Vice President
of Supply Corporation. October 1, 1994
President of Horizon. September 13, 1995
President of certain
other subsidiaries of
the Company from prior
to 1992.
Richard Hare 59 President of Supply
Corporation. June 1, 1989
Senior Vice President of
Penn-York Energy Corpor-
ation until its merger
into Supply Corporation
on July 1, 1994. June 1, 1989
President of SIP. September 22, 1997
James A. Beck 50 President of Seneca. October 1, 1996**
President of NET. July 18, 1997
President of NIM. September 22, 1997
Joseph P. Pawlowski 56 Treasurer. December 11, 1980
Senior Vice President of
Distribution Corporation. February 20, 1992
Treasurer of
Distribution Corporation. January 1, 1981
Treasurer of
Supply Corporation. June 1, 1985
Secretary of
Supply Corporation. October 1, 1995
Treasurer of SIP. September 22, 1997
Officer of certain other
subsidiaries of the
Company from prior
to 1992.
Gerald T. Wehrlin 59 Controller. December 11, 1980
Senior Vice President of
Distribution Corporation. April 1, 1991
Controller of Seneca. September 1, 1981
Secretary and Treasurer
of Leidy. September 1, 1993
Vice President
of Horizon. February 21,
1997 ***
Officer of certain other
subsidiaries of the
Company from prior to
1992.
Age as of Current Company Date Elected To
Name 9/30/97 Positions Current Positions
---- --------- --------------- -----------------
Walter E. DeForest 56 Senior Vice President of
Distribution Corporation. August 1, 1993
President of Leidy. September 1, 1993
Bruce H. Hale 48 Senior Vice President of February 21, 1997,
Supply Corporation. and from February
21, 1992 through
December 31,
1992.****
Vice President of Horizon. September 13, 1995
Dennis J. Seeley 54 Senior Vice President of
Distribution Corporation. February 21, 1997
and from April 1,
1991 through
February 18,
1993 *****
David F. Smith 44 Senior Vice President of
Distribution Corporation. January 1, 1993
Secretary of
Distribution Corporation. June 20, 1986
Officer of certain other
subsidiaries of the
Company from prior
to 1992.
* 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.
** Vice President of Seneca from January 1, 1994 through April 30, 1995,
Executive Vice President of Seneca from May 1, 1995 through September
30, 1996.
*** Secretary and Treasurer of Horizon from September 13, 1995 through
February 21, 1997.
**** Senior Vice President of Distribution Corporation from April 1, 1991
through February 20, 1992, and again from January 1, 1993 through
February 21, 1997.
***** Senior Vice President of Supply Corporation from January 1, 1993 through
February 21, 1997.
ITEM 2 PROPERTIES
General Information on Facilities
The investment of the Company in net property, plant and equipment was $1,819.4
million at September 30, 1997. Approximately 74% 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, which
is primarily located in the Gulf Coast, southwestern, western and Appalachian
regions of the United States. During the past five years, the Company has made
significant additions to plant in order to expand and improve transmission and
distribution facilities for both retail and transportation customers and to
augment the reserve base of oil and gas. Net plant has increased $403.0 million,
or 28%, since 1992.
The Utility segment has the largest net investment in property, plant
and equipment, compared with the Company's other business segments. Its net
investment in its gas distribution network (including 14,762 miles of
distribution pipeline) and its services represent approximately 58% and 28%,
respectively, of the Utility segment's net investment of $899.2 million.
The Pipeline and Storage segment represents a net investment of $450.9
million in transmission and storage facilities at September 30, 1997.
Transmission pipeline, with a net cost of $145.1 million, represents 32% of this
segment's total net investment and includes 2,677 miles of pipeline required to
move large volumes of gas throughout its service area. Storage facilities
consist of 34 storage fields, 4 of which are jointly operated with certain
pipeline suppliers, and 494 miles of pipeline. Included in the storage
facilities net investment is $82.1 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 31 compressor stations with 70,550 installed
compressor horsepower.
The Exploration and Production segment had a net investment in
properties amounting to $443.2 million at September 30, 1997. Of this amount,
Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast
regions was $388.7 million, and Seneca's net investment in oil and gas
properties in the Appalachian region aggregated $45.5 million.
The Regulated Operations' facilities provided the capacity to meet its
1997 peak day sendout, including transportation service, of 2,047 MMcf, which
occurred on January 17, 1997. Withdrawals from storage provided approximately
41% of the requirements on that day.
Company maps, which are included on pages 1 and 2 of the paper copy of
the combined Annual Report to Shareholders/Form 10-K, 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
L-Supplementary Information for Oil and Gas Producing Activities. Note L sets
forth proved developed and undeveloped reserve information for Seneca. Supply
Corporation holds reserves related to held for future use storage wells.
Information on such reserves is included on Supply Corporation's Form 2 "Annual
Report of Natural Gas Companies" filed with the FERC.
Seneca is not regulated by the FERC, and thus is not required to file
Form 2. Seneca's oil and gas reserves reported in Note L as of September 30,
1997, were estimated by Seneca's qualified geologists and engineers and were
audited by independent petroleum engineers from Ralph E. Davis, Inc.
The following is a summary of certain oil and gas information taken
from Seneca's records:
Production
For the Year Ended September 30 1997 1996 1995
- ------------------------------- ---- ---- ----
Average Sales Price per Mcf of Gas $ 2.60 $ 2.35 $ 1.67
Average Sales Price per Barrel of Oil $20.63 $19.50 $16.16
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 0.35 $ 0.31 $ 0.44
Productive Wells
At September 30, 1997 Gas Oil
- --------------------- --- ---
Productive Wells - gross 1,806 269
- net 1,718 221
Developed and Undeveloped Acreage
At September 30, 1997
- ---------------------
Developed Acreage - gross 612,932
- net 538,368
Undeveloped Acreage - gross 886,398
- net 682,520
Drilling Activity
Productive Dry
------------------ ------------------
For the Year Ended September 30 1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
Net Wells Completed - Exploratory 4.21 4.22 4.32 3.49 7.35 0.27
- Development 1.84 8.02 6.16 1.60 0 0
Present Activities
At September 30, 1997
- -----------------------------------------------------------------------------
Wells in Process of Drilling - gross 11.00
- net 7.23
There are currently no waterflood projects or pressure maintenance operations of
material importance.
ITEM 3 Legal Proceedings
None
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 1997.
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 K-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, 1997, 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, 1997,
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: 1997 1996 1995 1994 1993
- ----------------------- ---- ---- ---- ---- ----
Summary of Operations (Thousands)
Operating Revenues $1,265,812 $1,208,017 $975,496 $1,141,324 $1,020,382
---------- ---------- -------- ---------- ----------
Operating Expenses:
Purchased Gas 528,610 477,357 351,094 497,687 409,005
Operation and Maintenance 288,026 309,206 292,505 291,390 283,230
Property, Franchise and Other
Taxes 100,549 99,456 91,837 103,788 95,393
Depreciation, Depletion and
Amortization 111,650 98,231 71,782 74,764 69,425
Income Taxes - Net 68,674 66,321 43,879 47,792 41,046
--------- --------- -------- ---------- ----------
1,097,509 1,050,571 851,097 1,015,421 898,099
--------- --------- -------- ---------- ----------
Operating Income 168,303 157,446 124,399 125,903 122,283
Other Income 3,196 3,869 5,378 3,656 4,833
--------- --------- -------- ---------- ----------
Income Before Interest Charges 171,499 161,315 129,777 129,559 127,116
Interest Charges 56,811 56,644 53,883 47,124 51,899
--------- --------- -------- ---------- ----------
Income Before Cumulative Effect 114,688 104,671 75,894 82,435 75,217
Cumulative Effect of Changes in
Accounting - - - 3,237 -
--------- -------- ---------- ---------- --------
Net Income Available for Common
Stock $114,688 $104,671 $ 75,894 $ 85,672 $ 75,217
======== ======== ======== ========== ==========
Per Common Share Data
Earnings $3.01 $2.78 $2.03 $2.32* $2.15
Dividends Declared $1.71 $1.65 $1.60 $1.56 $1.52
Dividends Paid $1.70 $1.64 $1.59 $1.55 $1.51
Dividend Rate at Year-End $1.74 $1.68 $1.62 $1.58 $1.54
At September 30:
- ---------------
Number of Common Shareholders 20,267 21,640 21,429 22,465 22,893
====== ====== ======== ========== ==========
Net Property, Plant and Equipment (Thousands)
Regulated:
Utility $ 889,216 $ 855,161 $ 822,764 $ 787,794 $ 754,466
Pipeline and Storage 450,865 452,305 463,647 443,622 436,547
---------- ---------- ---------- ---------- ----------
1,340,081 1,307,466 1,286,411 1,231,416 1,191,013
---------- ---------- ---------- ---------- ----------
Nonregulated:
Exploration and Production 443,164 375,958 339,950 295,418 273,470
Other 36,110 26,167 22,690 18,579 16,209
---------- ---------- ---------- ---------- ----------
479,274 402,125 362,640 313,997 289,679
---------- ---------- ---------- ---------- ----------
Corporate 11 15 131 137 122
---------- ---------- ---------- ---------- ----------
Total Net Plant $1,819,366 $1,709,606 $1,649,182 $1,545,550 $1,480,814
========== ========== ========== ========== ==========
Total Assets (Thousands) $2,267,331 $2,149,772 $2,036,823 $1,980,806 $1,801,540
========== ========== ========== ========== ==========
Capitalization (Thousands)
Common Stock Equity $ 913,704 $ 855,998 $ 800,588 $ 780,288 $ 736,245
Long-Term Debt, Net of Current
Portion 581,640 574,000 474,000 462,500 478,417
---------- ---------- ---------- ---------- ----------
Total Capitalization $1,495,344 $1,429,998 $1,274,588 $1,242,788 $1,214,662
========== ========== ========== ========== ==========
* 1994 includes Cumulative Effect of Changes in Accounting of $0.09, which
resulted from the adoption of SFAS 109, "Accounting for Income Taxes" and SFAS
112, "Employers' Accounting for Postemployment Benefits".
ITEM 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
1997 Compared with 1996
National Fuel's earnings were $114.7 million, or $3.01 per common share, in
1997. This compares with earnings of $104.7 million, or $2.78 per common share,
in 1996.
The earnings increase in 1997 was attributable to higher earnings of
the Company's Utility and Pipeline and Storage segments, as well as a reduction
in losses of its Other Nonregulated segment, partly offset by lower earnings of
the Exploration and Production segment.
Utility earnings increased as a result of new rates effective in
October 1996 and lower operation and maintenance(O&M) expense. Partly offsetting
these positive impacts to earnings was warmer weather in 1997 compared with
1996, as well as the inclusion in 1996 earnings of a downward revision of
estimated purchased gas costs for 1995. The Pipeline and Storage segment
earnings increase was attributable to higher revenue from unbundled pipeline
sales and open access transportation, as well as lower O&M expense for the year.
In the Other Nonregulated segment, net losses in 1997 were significantly less
than in 1996. The 1996 losses included expenses associated with the Company's
withdrawal from participation in an international power project. Exploration and
Production earnings decreased as a result of higher operation and depletion
expense, which more than offset increased revenues resulting from increased
prices and the slight increase in production.
1996 Compared with 1995
National Fuel's earnings were $104.7 million, or $2.78 per common share, in
1996. This compares with earnings of $75.9 million, or $2.03 per common share,
in 1995.
The earnings increase in 1996 was attributable to higher earnings of
the Company's Exploration and Production, Utility, and Pipeline and Storage
segments. The Other Nonregulated segment incurred losses in 1996 as compared
with earnings in 1995.
Exploration and Production earnings increased because of significant
increases in natural gas and oil production combined with higher gas and oil
prices. The earnings increase of the Utility segment reflects the positive
impact of colder weather, new rates that became effective in September 1995 in
both the New York and Pennsylvania jurisdictions, and the results of
management's emphasis on controlling O&M expense. Also, purchased gas cost
adjustments in the Utility segment's New York jurisdiction increased 1996
earnings. The Pipeline and Storage segment's earnings increase was attributable
to a retroactive rate increase combined with the recording of a reserve for a
storage project in 1995. Partly offsetting the increased earnings of the
Pipeline and Storage segment were lower revenues related to unbundled pipeline
sales and open access transportation. An early retirement offer to certain
salaried, non-union hourly and union employees of both the Utility and Pipeline
and Storage segments resulted in a reduction to 1996 earnings for both segments.
The 1996 losses of the Other Nonregulated segment were mainly attributable to
withdrawal from an international power project.
Operating Revenues
Year Ended September 30 (Thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Utility
Retail Revenues:
Residential $ 709,968 $ 678,395 $569,603
Commercial 167,338 165,824 137,869
Industrial 22,412 25,648 18,269
- -----------------------------------------------------------------------------
899,718 869,867 725,741
Off-System Sales 43,857 30,907 18,255
Transportation 49,285 49,180 37,183
Other (1,494) 4,372 4,885
- -----------------------------------------------------------------------------
991,366 954,326 786,064
- -----------------------------------------------------------------------------
Pipeline and Storage
Storage Service 64,221 67,975 59,826
Transportation 92,858 92,401 88,766
Other 15,615 16,177 15,995
- -----------------------------------------------------------------------------
172,694 176,553 164,587
- -----------------------------------------------------------------------------
Exploration and Production 119,260 114,462 56,232
Other Nonregulated 83,915 68,930 57,075
- -----------------------------------------------------------------------------
203,175 183,392 113,307
- -----------------------------------------------------------------------------
Less: Intersegment Revenues 101,423 106,254 88,462
- -----------------------------------------------------------------------------
Total Operating Revenues $1,265,812 $1,208,017 $975,496
=============================================================================
Operating Income (Loss) Before Income
Taxes
Year Ended September 30 (Thousands) 1997 1996 1995
- ------------------------------------------------------------------------------
Utility $123,856 $115,257 $ 83,774
Pipeline and Storage 73,523 72,914 67,884
Exploration and Production 42,694 46,408 16,404
Other Nonregulated (743) (8,581) 3,021
Corporate (2,353) (2,231) (2,805)
- ------------------------------------------------------------------------------
Total Operating Income Before Income
Taxes $236,977 $223,767 $168,278
==============================================================================
System Natural Gas Volumes
Year Ended September 30 (billion cubic feet) 1997 1996 1995
- -------------------------------------------------------------------------
Regulated Gas Sales
Residential 85.7 90.7 79.9
Commercial 22.6 24.9 22.2
Industrial 5.1 6.0 4.8
Off-System 14.1 11.1 9.4
- -------------------------------------------------------------------------
127.5 132.7 116.3
- -------------------------------------------------------------------------
Nonregulated Gas Sales
Gas Sales for Resale - - 0.4
Production (equivalent billion cubic feet) 50.0 49.2 25.4
- -------------------------------------------------------------------------
50.0 49.2 25.8
- -------------------------------------------------------------------------
Total Gas Sales 177.5 181.9 142.1
- -------------------------------------------------------------------------
Transportation
Utility 59.6 58.2 52.8
Pipeline and Storage 309.3 325.0 290.8
Nonregulated 0.5 0.6 2.5
- -------------------------------------------------------------------------
369.4 383.8 346.1
- -------------------------------------------------------------------------
Marketing Volumes 21.0 20.2 18.8
- -------------------------------------------------------------------------
Less Intra and Intersegment Volumes:
Transportation 160.4 157.7 154.2
Production 4.3 4.8 5.0
Gas Sales - 0.8 -
Marketing - 0.1 -
- -------------------------------------------------------------------------
164.7 163.4 159.2
- -------------------------------------------------------------------------
Total System Natural Gas Volumes 403.2 422.5 347.8
=========================================================================
Utility
Operating Revenues
1997 Compared with 1996
Operating revenues increased $37.0 million in 1997 compared with 1996. Despite
lower sales volumes for residential, commercial and industrial customers (mainly
due to weather that was, on average, 5.6% warmer than the prior year) revenues
increased because of the pass through of increased gas costs, higher off-system
sales and the general base rate increase of $7.2 million in Distribution
Corporation's New York jurisdiction effective October 1, 1996. Gas costs were up
due to a 7% increase in the average costs of purchased gas (see discussion of
purchased gas below under the heading "Purchased Gas"). The increase in
off-system sales reflects the continued emphasis by Distribution Corporation to
utilize available capacity on various upstream pipelines. While off-system sales
contributed to the revenue increase, the margins on such sales, after sharing
with customers, are minimal. Other operating revenues in 1997 were reduced by a
$3.0 million cumulative refund provision to the Utility's customers for a 50%
sharing of earnings over a predetermined amount in accordance with the New York
rate settlement of July 1996.
1996 Compared with 1995
Operating revenues increased $168.3 million in 1996 compared with 1995. This
increase reflects general rate increases in the New York and Pennsylvania rate
jurisdictions, effective in September 1995, pass through of increased gas costs,
higher transportation volumes and higher off-system sales. The base rate
increases amounted to $14.2 million and $6.0 million in New York and
Pennsylvania, respectively. The recovery of increased gas costs was due to
higher gas sales volumes (mainly due to weather that was, on average, 16.7%
colder than 1995 as well as a 25% increase in the average cost of purchased gas
(see discussion of purchased gas below under the heading "Purchased Gas").
Higher transportation volumes due to colder weather, new customers and increases
in production at various manufacturing facilities also contributed to higher
operating revenues. The increase in off-system sales reflects the continued
utilization of Distribution Corporation's available capacity on various upstream
pipelines. As noted above, the margins on such sales are minimal.
Operating Income
1997 Compared with 1996
Operating income before income taxes increased $8.6 million in 1997 compared
with 1996. The increase resulted primarily from the increases in 1997 revenue
discussed above combined with lower O&M expense partly offset by certain
purchased gas costs adjustments, totalling $4.2 million, associated with lost
and unaccounted-for gas in the New York Division of Distribution Corporation
that lowered purchased gas expense in 1996. O&M expense decreased primarily as a
result of an early retirement offer to certain salaried, non-union hourly and
union employees of Distribution Corporation that was effective October 1, 1996.
The 1996 results included expenses for this retirement offer of $6.4 million.
The 1997 results include $0.9 million of operating expenses associated with an
early retirement offer to certain Pennsylvania operating union employees in
1997. O&M expense also decreased as a result of management's continued emphasis
on controlling costs.
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 pre-tax operating income and 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 1997, the WNC in
New York resulted in a benefit to customers of $0.2 million as weather, overall,
was colder than normal for the period of October 1996 through May 1997. Since
the Pennsylvania rate jurisdiction does not have a
WNC, uncontrollable weather variations directly impact pre-tax operating income
and earnings. In the Pennsylvania service territory, weather was 5.5% warmer
than last year and 2.8% colder than normal. The warmer weather in 1997 compared
with 1996 lowered pre-tax operating income by approximately $3.2 million.
1996 Compared with 1995
Operating income before income taxes increased $31.5 million in 1996 compared
with 1995. The increase reflects higher gas revenue, as discussed above. It also
reflects certain purchased gas cost adjustments associated with lost and
unaccounted-for gas in Distribution Corporation's New York jurisdiction having a
net impact of reducing purchased gas expense by $4.2 million. Partly offsetting
the above increases was the impact of an early retirement offer to certain
salaried, non-union hourly and union employees of Distribution Corporation
resulting in additional operating expenses in the Utility segment of $6.4
million in 1996. This offer was undertaken as a means to reduce future costs.
In 1996, the WNC in New York resulted in a benefit to customers of
$10.6 million as weather, overall, was colder than normal for the period of
October 1995 through May 1996. In the Pennsylvania service territory, weather in
1996 was 17.1% colder than in 1995 and 8.1% colder than normal. The colder
weather in 1996 compared with 1995 had a positive impact on the Pennsylvania
rate jurisdiction's pre-tax operating income of approximately $7.6 million.
Degree Days
Percent (Warmer) Colder
in 1997 Than
-----------------------
Year Ended September 30 Normal Actual Normal 1996
- -------------------------------------------------------------------------------
1997: Buffalo 6,690 6,793 1.5% (5.7%)
Erie 6,223 6,395 2.8% (5.5%)
- -------------------------------------------------------------------------------
1996: Buffalo 6,728 7,203 7.1% 16.5%
Erie 6,258 6,764 8.1% 17.1%
- -------------------------------------------------------------------------------
1995: Buffalo 6,693 6,181 (7.6%) (11.4%)
Erie 6,128 5,774 (5.8%) (14.2%)
- -------------------------------------------------------------------------------
Purchased Gas
The cost of purchased gas is by far the Company's single largest operating
expense. Annual variations in purchased gas costs can be attributed directly to
changes in gas sales volumes, the price of gas purchased and the operation of
purchased gas adjustment clauses.
Currently, Distribution Corporation has contracted for long-term firm
transportation capacity with Supply Corporation and six other upstream pipeline
companies, for long-term gas supplies with a combination of producers and
marketers and for storage service with Supply Corporation and three
nonaffiliated companies. In addition, Distribution Corporation can satisfy a
portion of its gas requirements through spot market purchases. Changes in
wellhead prices have a direct impact on the cost of purchased gas. Distribution
Corporation's average cost of purchased gas, including the cost of
transportation and storage, was $4.26 per thousand cubic feet (Mcf) in 1997, an
increase of 7% from the average cost of $3.98 per Mcf in 1996. The average cost
of purchased gas in 1996 was 25% higher than the $3.19 per Mcf in 1995.
Pipeline and Storage
Operating Revenues
1997 Compared with 1996
Operating revenues decreased $3.9 million in 1997 compared with 1996. As
discussed below, 1996 revenues reflected a rate increase which was retroactive
to June 1, 1995. The retroactive rates added approximately $2.0 million to
revenues in 1996 that related to 1995. The corresponding decrease in 1997
primarily impacted storage service revenues, which decreased by $3.8 million. In
addition to the retroactive rate impact, storage service revenues decreased as a
result of customers opting for more flexible services at discounted rates. A
slight increase in transportation revenues primarily reflects an increase in
surcharge adjustments. Other operating revenues decreased slightly as higher
revenues from unbundled pipeline sales and open access transportation (an
increase of $3.3 million) was more than offset by lower 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). Cashout revenue decreased by $3.7 million. However,
there is no earnings impact as cashout revenue is offset by an equal amount of
purchased gas expense.
While transportation volumes in this segment decreased 15.7 Bcf, the
decrease in volumes did not have a significant impact on earnings as a result of
Supply Corporation's straight fixed-variable (SFV) rate design.
1996 Compared with 1995
Operating revenues increased $12.0 million in 1996 compared with 1995. Higher
transportation and storage revenues reflect the impact of a $6.0 million rate
increase effective on April 1, 1996 retroactive to June 1, 1995. The retroactive
rates added approximately $2.0 million to revenues in 1996 that relate to 1995.
Higher volumes of gas transported as well as certain surcharge adjustments also
increased revenues in 1996. Other operating revenues increased only slightly,
but include an increase of approximately $4.6 million related to cashout revenue
mostly offset by a decrease of approximately $4.4 million related to unbundled
pipeline sales and open access transportation.
Operating Income
1997 Compared with 1996
Operating income before income taxes increased $0.6 million in 1997 compared
with 1996. This slight increase primarily reflects lower O&M expenses (including
labor) combined with higher revenues related to unbundled pipeline sales and
open access transportation. The cost of an early retirement offer to certain
Pennsylvania operating union employees in 1997 resulted in $1.0 million of
additional operating expenses. However, such expenses were $0.8 million less
than the expenses associated with the 1996 early retirement offer, as discussed
below. Partly offsetting these increases was the retroactive rate effect
recorded in 1996 and lower storage service revenues, as discussed above.
1996 Compared with 1995
Operating income before income taxes increased $5.0 million in 1996 compared
with 1995. This increase reflects the revenue increase discussed above as well
as the recording of a $3.7 million reserve in the fourth quarter of 1995 for
previously deferred preliminary survey and investigation charges for a storage
project. Partly offsetting the increase was the impact of higher operating
expenses, including an early retirement offer to certain salaried, non-union
hourly and union employees of Supply Corporation resulting in additional
operating expenses in the Pipeline and Storage segment of $1.8 million in 1996.
This offer was undertaken as a means to reduce future costs.
Exploration and Production
Operating Revenues
1997 Compared with 1996
Operating revenues increased $4.8 million in 1997 compared with 1996. Gas
revenues increased $9.4 million as a result of higher prices (the weighted
average gas price increased $0.25 per Mcf) slightly offset by decreased natural
gas production. Oil revenues increased $5.3 million as a result of increases in
oil production and prices. The weighted average oil price increased $1.13 per
barrel (bbl) (See tables below). The increase in oil production is the result of
a full year of production in 1997 at Vermilion 252 compared with only seven
months in 1996. Partly offsetting the increase in gas and oil revenue was the
recognition of a pre-tax loss on hedging of approximately $21.5 million compared
with a pre-tax loss of $11.8 million in 1996. Gains or losses on hedging
activities are offset by lower or higher prices received for actual natural gas
and crude oil production. Refer to further discussion of the Company's hedging
activities under "Financing Cash Flow" and in Note F - Financial Instruments in
Item 8 of this report.
1996 Compared with 1995
Operating revenues increased $58.2 million in 1996 compared with 1995. Gas
revenues increased $56.2 million as a result of an 85% increase in natural gas
production and an increase in the weighted average gas price of $0.68 per Mcf.
Oil revenues increased $22.0 million as a result of production, which was more
than twice the prior year, and an increase in the weighted average oil price of
$3.34 per bbl (See tables below). In 1995, natural gas and oil production was
delayed when prices were low in order to preserve the value received for
reserves. Increased production reflects offshore finds at West Cameron 552 and
Vermilion 252 and the acquisition of West Delta Block 30 in September 1995, as
well as production from the 1995 Hamp Lease acquisition in California. Partly
offsetting the above increases in gas and oil revenues was the recognition of a
pre-tax loss on hedging of approximately $11.8 million in 1996 compared with a
pre-tax gain of $6.9 million in 1995. Refer to further discussion of the
Company's hedging activities under "Financing Cash Flow" and in Note F -
Financial Instruments in Item 8 of this report.
Production Volumes
Year Ended September 30 1997 1996 1995
- -----------------------------------------------------------
Gas Production
(million cubic feet)
Gulf Coast 32,377 32,355 14,294
West Coast 1,135 990 840
Appalachia 5,074 5,422 5,808
- -----------------------------------------------------------
38,586 38,767 20,942
===========================================================
Oil Production
(thousands of barrels)
Gulf Coast 1,404 1,195 287
West Coast 490 533 433
Appalachia 8 14 19
- -----------------------------------------------------------
1,902 1,742 739
===========================================================
Weighted Average Prices*
Year Ended September 30 1997 1996 1995
- -----------------------------------------------------------
Weighted Average Gas Price/Mcf
Gulf Coast $2.60 $2.33 $1.56
West Coast $1.79 $1.25 $1.33
Appalachia $2.79 $2.65 $2.01
Weighted Average Price $2.60 $2.35 $1.67
- -----------------------------------------------------------
Weighted Average Oil Price/bbl
Gulf Coast $21.37 $20.45 $16.94
West Coast $18.49 $17.41 $15.66
Appalachia $21.28 $18.43 $15.72
Weighted Average Price $20.63 $19.50 $16.16
*Weighted average prices do not reflect gains or losses from hedging activities.
Operating Income
1997 Compared with 1996
Operating income before income taxes decreased $3.7 million in 1997 compared
with 1996. This decrease reflects higher depletion expense and higher operating
expenses (lease operating expenses, salary expenses and production taxes) due to
increased activities, which more than offset the increase in revenues, discussed
above.
1996 Compared with 1995
Operating income before income taxes increased $30.0 million in 1996 compared
with 1995. This increase reflects the higher operating revenues discussed above,
partly offset by higher depletion expense and higher operating expenses (lease
operating expenses and production taxes) due to increased production.
Other Nonregulated
Operating Revenues
1997 Compared with 1996
Operating revenues increased $15.0 million in 1997 compared with 1996. The
increase primarily reflects higher operating revenues from NFR, the Company's
gas marketing subsidiary, and Highland, the Company's sawmill and timber
subsidiary. NFR's operating revenues increased largely because of higher natural
gas prices and an increase in marketing volumes. Also, NFR recognized a pre-tax
gain on futures contracts of approximately $1.4 million during 1997 compared to
a pre-tax gain of approximately $1.0 million in 1996. Refer to further
discussion of the Company's hedging activities under "Financing Cash Flow" and
in Note F - Financial Instruments in Item 8 of this report. Highland's operating
revenues increased as a result of increased lumber sales resulting from the
operation of a new lumber mill beginning in January 1997.
1996 Compared with 1995
Operating revenues increased $11.9 million in 1996 compared with 1995. The
increase primarily reflects higher operating revenues from NFR, largely because
of higher natural gas prices and an increase in marketing volumes. Also, NFR
recognized a pre-tax gain on futures contracts of approximately $1.0 million
during 1996 compared to a pre-tax gain of approximately $0.2 million in 1995.
Offsetting this increase was a decrease in operating revenues from UCI, the
Company's discontinued pipeline construction subsidiary.
Operating Income
1997 Compared with 1996
The Other Nonregulated segment experienced an operating loss before income taxes
of $0.7 million in 1997 as compared with an operating loss before income taxes
of $8.6 million in 1996. The decrease in operating loss relates primarily to
expenses incurred in the prior year by Horizon, the Company's foreign and
domestic energy projects subsidiary, relating to its withdrawal from
participation in an international power project in August 1996. In 1997, Horizon
sold its rights to this power project for approximately $2.8 million, including
cash proceeds and the assumption of certain liabilities by the purchaser. As
discussed below, the entire project was written off in 1996. Partly offsetting
the lower losses of Horizon was increased depletion expenses in this segment's
timber operations related to cutting timber with a higher cost.
1996 Compared with 1995
The Other Nonregulated segment experienced an operating loss before income taxes
of $8.6 million in 1996 compared with operating income before income taxes of
$3.0 million in 1995. Expenses incurred by Horizon were the main factors in this
decrease. In August 1996, Horizon withdrew from participation in the development
of a 151 megawatt power plant near Kabirwala, Punjab Province, in east-central
Pakistan (Kabirwala Project). As a result of this withdrawal, certain
pre-operating costs were charged to earnings. Total pre-tax charges in 1996
associated with the Kabirwala Project were approximately $9.0 million. UCI also
experienced a significant decrease in operating income before income taxes as a
result of discontinuing its pipeline construction operations late in 1995. NFR
experienced an increase in operating income before income taxes based primarily
on increased volumes marketed.
Income Taxes, Other Income and Interest Charges
Income Taxes
Income taxes increased $2.4 million and $22.4 million in 1997 and 1996,
respectively, mainly because of an increase in pre-tax income.
Other Income
Other income decreased $0.7 million and $1.5 million in 1997 and 1996,
respectively. The 1997 decrease resulted, in part, from certain nonrecurring
items recorded in 1996 for Supply Corporation, including a gain on disposition
of property, as well as interest income related to a retroactive rate
settlement. In addition, the 1997 decrease reflects losses from Leidy Hub's
equity investment in various gas hub partnerships and losses from Horizon's
equity investment in Severoceske Teplarny, a.s. (SCT). The SCT losses relate to
the period April 1997 (when Horizon made its initial equity investment in SCT)
through September 30, 1997. Since SCT is a heating utility, it typically
experiences losses during the summer months. The 1996 decrease resulted
primarily because 1995 included a gain of $2.5 million recorded by UCI on the
sale of its pipeline construction equipment. This was partly offset by the
nonrecurring items, noted above, that were recorded in 1996.
Interest Charges
Interest on long-term debt increased $1.3 million in 1997; however, it did not
change significantly in 1996 compared with 1995. The increase in 1997 can be
attributed to a higher average amount of long-term debt outstanding in 1997,
offset slightly by a lower average interest rate. Although there was a higher
average amount of long-term debt outstanding in 1996 compared with 1995, this
was almost completely offset by a lower average interest rate.
Other interest charges decreased $1.1 million in 1997 and increased
$2.8 million in 1996. The decrease in 1997 resulted primarily from lower
interest expense on Amounts Payable to Customers offset in part by higher
interest on short-term borrowings because of higher average amounts outstanding.
The increase in 1996 resulted primarily from a higher average balance of
outstanding short-term borrowings offset partly by a lower weighted average
interest rate on such borrowings. Additionally, 1996 experienced an increase in
interest expense as a result of higher interest on Amounts Payable to Customers.
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 (in millions) 1997 1996 1995
- --------------------------------------------------------------------
Provided by Operating Activities $294.7 $168.5 $174.4
Capital Expenditures (214.0) (171.6) (182.8)
Short-Term Debt, Net Change (107.3) 52.1 35.1
Long-Term Debt, Net Change 98.2 11.2 3.1
Issuance of Common Stock 7.1 9.0 2.5
Common Dividends (64.3) (61.2) (59.2)
Investment in Unconsolidated
Foreign Subsidiary (21.1) - -
Other Investing Activities 1.4 (1.4) 10.6
- --------------------------------------------------------------------
Net Increase (Decrease) in Cash
and Temporary Cash Investments $(5.3) $6.6 $(16.3)
====================================================================
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 and allowance for funds used
during construction.
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 Company considers supplier refunds and over-recovered purchased gas
costs as a substitute for short-term borrowings. 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 totalled $294.7 million in
1997, an increase of $126.2 million compared with the $168.5 million provided by
operating activities in 1996. The majority of this increase occurred in the
Utility segment as a result of an increase in cash receipts from gas sales and
transportation service, a net increase in cash received as refunds from upstream
pipelines, and lower O&M costs. Lower O&M costs in the Pipeline and Storage
segment also contributed to the increase as did an increase in cash receipts
from gas and oil sales in the Exploration and Production segment.
Investing Cash Flow
Capital Expenditures
Capital expenditures represent the Company's additions to property, plant and
equipment and are exclusive of equity investments in corporations and/or
partnerships. The Company's cash outlay for capital expenditures totalled $214.0
million in 1997. Noncash capital expenditures totalled $12.3 million in the
Other Nonregulated segment and related to Seneca's issuance of long-term notes
to third parties in exchange for land and timber. The table below presents these
expenditures by business segment:
Year Ended September 30 (in millions) 1997
- ---------------------------------------------
Utility $ 66.9
Pipeline and Storage 22.6
Exploration and Production 120.3
Other Nonregulated 16.5
- ---------------------------------------------
$226.3
=============================================
Most of the Utility segment's capital expenditures were for the
replacement of mains and main extensions, as well as for the replacement of
service lines and, to a minor extent, the installation of new services.
The bulk of the Pipeline and Storage segment's capital expenditures
were made for additions, improvements and replacements to this segment's
transmission and storage systems.
The Exploration and Production segment spent approximately $96.6
million on its offshore program in the Gulf of Mexico, including offshore
drilling expenditures, geological expenditures and lease acquisitions. Offshore
exploratory and development drilling was concentrated on Ship Shoal 258,
Vermilion 225, High Island 194, Main Pass 256, Main Pass 257, West Cameron 182,
West Delta 30, West Cameron 540, Vermilion 309, Galveston 210, High Island A364
and High Island 179. Offshore lease acquisitions included South Marsh Island
122, Mustang Island 796 and 818 in Texas state waters and Eugene Island 9 and 91
in Louisiana state waters. Other offshore acquisitions included East Cameron 36,
Visca Knowl 564, Oxy-High Island A356, Barrett-High Island A364 and Shell-High
Island 179.
Approximately $23.7 million was spent on the Exploration and Production
segment's onshore program, including horizontal drilling in central Texas and
developmental and exploratory drilling in California. In addition, acquisitions
included leases in California and Wyoming.
Other Nonregulated capital expenditures consisted primarily of
timberland purchases.
The Company's estimated capital expenditures for the next three years
are:1
Year Ended September 30 (in millions) 1998 1999 2000
- --------------------------------------------------------------------
Utility $51.9 $56.9 $55.9
Pipeline and Storage 28.0 20.5 20.5
Exploration and Production 132.2 143.9 139.6
Other Nonregulated 0.3 0.3 0.3
- --------------------------------------------------------------------
$212.4 $221.6 $216.3
====================================================================
Estimated expenditures for the Utility segment during the next three
years will be concentrated in the areas of main replacements and extensions,
service line replacements and, to a minor extent, the installation of new
services.1
Estimated expenditures for the Pipeline and Storage segment in 1998
will be concentrated in the reconditioning of storage wells and the replacement
of storage and transmission lines.1 Approximately $6.4 million is included in
the 1998 budget for the Niagara Expansion Project, which would provide
approximately 25,000 Dekatherms (Dth) per day of firm year-round capacity and
23,000 Dth per day of firm winter only capacity from the Niagara Falls, New York
import point to interconnections at Leidy and Wharton, Pennsylvania.1
Supply Corporation began transportation service for the additional 25,000 Dth
per day in November 1997 and has filed for Federal Energy Regulatory Commission
(FERC) approval concerning the 23,000 Dth per day expansion of firm winter only
capacity. Supply Corporation anticipates receiving such FERC approval by April
or May of 1998.1
Supply Corporation also has a proposed 1999 Niagara Expansion Project
(1999 Expansion), which would expand transportation capacity from the Canadian
border at Niagara Falls, New York, to Leidy, Pennsylvania. Given the uncertain
status of the 1999 Expansion, no amount has been included in the 1998 or 1999
budget as the timing of the "go ahead" for the 1999 Expansion will depend on
several factors, including signed precedent agreements and FERC approval.1 A
timetable has not been set for filing with the FERC.
Estimated capital expenditures in 1998 for the Exploration and
Production segment are approximately 10.0% higher than capital spending in 1997
as the Company sees significant opportunities for growth in this segment.1 These
expenditures will be directed mainly toward developing Seneca's offshore and
onshore prospects, reserve acquisitions and significantly expanding exploration
activities.1 Approximately 75% of these expenditures will be directed offshore.1
In November 1997, the Company signed a letter of intent with the
Whittier Trust Company to purchase for cash properties in the Midway-Sunset and
Lost Hills field in the San Joaquin Basin of California. This potential
acquisition will complement the Exploration and Production segment's reserve
mix, bringing its new potential reserve base to 58% oil and 42% gas.1 This
potential acquisition would also provide the Exploration and Production segment
with the opportunity to continue its focus of growth by increasing its
activities in the domestic onshore areas.1 The purchase price of these
properties is expected to be in the range of $130 million to $150 million and is
dependent upon various factors, including acceptance by Trust participants and
swapping of certain Coalinga field properties for additional properties in the
Midway-Sunset fields.1 The Company anticipates financing this purchase with
long-term debt.1 No amount for this potential acquisition has been included in
the estimated capital expenditure table above.
The Company's capital expenditure program is under continuous review.
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 in the Company's other business segments depends, to a
large degree, upon market conditions.1
Investment in Unconsolidated Foreign Subsidiary
In 1997, Horizon's wholly owned subsidiary, Bruwabel, acquired a 36.8% equity
interest in SCT. SCT is a company with district heating and power generation
operations located in the northern part of the Czech Republic. For calendar
1996, SCT reported profits of approximately $5.0 million. Bruwabel paid $22.0
million, including legal and finders fees, for its 36.8% equity interest.
Bruwabel received a dividend of $0.9 million from its investment in SCT during
1997.
In December 1997, Bruwabel acquired an additional 34% equity interest
in SCT for approximately $22.0 million, thus raising its total ownership to
70.8%. As such, Bruwabel will begin to consolidate SCT into its financial
statements during the first quarter of 1998. The acquisition was financed with
short-term borrowings.
Bruwabel's investment in SCT 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 1997, the Czech Koruna devalued in
relation to the U.S. Dollar, resulting in a negative adjustment to stockholders
equity in the amount of approximately $2.0 million. This amount is reported as a
Cumulative Translation Adjustment in Common Stock Equity on the Consolidated
Balance Sheet. If the Czech Koruna increases in value in relation to the U.S.
Dollar, the $2.0 million Cumulative Translation Adjustment could reverse and
potentially become a positive adjustment to Common Stock Equity. Management
cannot predict whether the Czech Koruna will increase or decrease in value
against the U.S. Dollar.1
Other Investing Activities
Other cash provided by or used in investing activities reflects cash received on
the sale of the Company's investment in property, plant and equipment and cash
used for other investments.
In June 1997, the Company announced its intention to join as an equal
partner in the Independence Pipeline Project, which is designed to bring gas
from Defiance, Ohio to Leidy, Pennsylvania and is expected to cost $675
million.1 The Independence Pipeline Project as filed with the FERC will consist
of approximately 370 miles of 36-inch diameter pipe with an initial capacity of
approximately 900,000 Dth per day. In September 1997, the Company formed a new
subsidiary, Seneca Independence Pipeline Company (SIP), which has agreed to
purchase, upon receipt of regulatory approval, a one-third general partnership
interest in Independence Pipeline Company, a Delaware general partnership. If
the Independence Pipeline Project is not constructed, SIP's share of the
development costs is estimated not to exceed $6.0 million to $8.0 million.1 It
is expected that SIP will invest approximately $6.8 million in the partnership
during 1998.1 SIP will most likely use short-term borrowings for the projected
investments in 1998.1
In November 1996, Supply Corporation entered into a Memorandum of
Understanding (the MOU) with Green Canyon Gathering Company, a subsidiary of El
Paso Energy, regarding a project to develop, construct, finance, own and operate
natural gas gathering and processing facilities offshore and onshore Louisiana,
at an estimated total cost of about $200 million.1 The MOU has been amended
several times since then, and currently provides for the parties to (i) share
past and future development costs for the Project through December 31, 1998, and
(ii) negotiate toward definitive agreements to form one or more 50-50 entities
and to finance, develop, build, own and operate the Project. The FERC ruled in
March 1997 that most of the Project would be jurisdictional, so additional
regulatory filings would be necessary to construct and operate the Project. The
parties will prepare and make those filings whenever justified by customer
demand. If the MOU expires without any additional filings at the FERC, Supply
Corporation's share of the development costs through December 31, 1998 is
unlikely to exceed $1.2 million, of which Supply Corporation had paid about $0.9
million as of September 30, 1997.1 These paid costs are recorded in Deferred
Charges on the Consolidated Balance Sheet at September 30, 1997. Supply
Corporation is currently using short-term borrowings to finance the Project.
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.1
In August 1997, the Company issued $100.0 million of 6.214% medium-term
notes due in August 2027. After reflecting underwriting discounts and
commissions, the net proceeds to the Company amounted to $99.5 million.
Such proceeds were used to reduce short-term borrowings.
In November 1997, the Company retired $50.0 million of 6.42%
medium-term notes. Short-term borrowings were used to retire these notes.
The Company's embedded cost of long-term debt was 6.9% and 7.0% at
September 30, 1997 and 1996, respectively.
Consolidated short-term debt decreased $107.3 million during 1997. The
Company continues to consider short-term bank loans and commercial paper
important sources of cash for temporarily financing capital expenditures, gas-
in-storage inventory, unrecovered purchased gas costs, exploration and
development expenditures and other working capital needs. In addition, the
Company considers supplier refunds and over-recovered purchased gas costs as a
substitute for short-term debt. Fluctuations in these items can have a
significant impact on the amount and timing of short-term debt.
The Company's present liquidity position is believed to be adequate to
satisfy known demands.1 Under the Company's covenants contained in its indenture
covering its long-term debt, as amended, the Company would have been permitted
to issue up to a maximum of approximately $504.0 million in additional long-term
unsecured indebtedness at September 30, 1997, in light of then current long-term
interest rates. In addition, at September 30, 1997,the Company had regulatory
authorizations and unused short-term credit lines that would have permitted it
to borrow an additional $507.6 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.1
The Company, through Seneca, has entered into certain price swap
agreements to manage a portion of the market risk associated with fluctuations
in the market price of natural gas and crude oil. These price swap agreements
are not held for trading purposes. During 1997, Seneca utilized natural gas and
crude oil price swap agreements with notional amounts of 24.9 equivalent Bcf and
1,371,500 equivalent bbl, respectively. These hedging activities resulted in the
recognition of a pre-tax loss of approximately $21.5 million. This loss was
offset by higher prices received for actual natural gas and crude oil
production.
At September 30, 1997, Seneca had natural gas price swap agreements
outstanding with a notional amount of approximately 36.3 equivalent Bcf at
prices ranging from $1.77 per Mcf to $2.55 per Mcf. The weighted average fixed
price of these swap agreements is approximately $2.15 per Mcf. Seneca also had
crude oil price swap agreements outstanding at September 30, 1997 with a
notional amount of 1,026,000 equivalent bbl at prices ranging from $17.50 per
bbl to $20.56 per bbl. The weighted average fixed price of these swap agreements
is approximately $18.96 per bbl.
The Company, through NFR, participates in the natural gas futures
market to manage a portion of the market risk associated with fluctuations in
the price of natural gas. Such futures are not held for trading purposes. During
1997, NFR recognized a pre-tax gain of approximately $1.4 million related to
such futures contracts. Since these futures contracts qualify and have been
designated as hedges, any gains or losses resulting from market price changes
are substantially offset by the related commodity transaction.
At September 30, 1997, NFR had long positions in the futures market
amounting to a notional amount of 7.4 Bcf at prices ranging from $2.04 per Mcf
to $3.49 per Mcf. The weighted average contract price of these futures contracts
is approximately $2.61 per Mcf. NFR had short positions in the futures market
amounting to a notional amount of 2.3 Bcf at prices ranging from $2.06 per Mcf
to $3.61 per Mcf. The weighted average contract price of these futures contracts
is approximately $2.97 per Mcf.
In addition, the Company has SEC authority to enter into certain
interest rate swap agreements. For further discussion of the Company's
derivative financial instruments, see disclosure in Note F - Financial
Instruments under the heading "Derivative Financial Instruments" in Item 8 of
this report.
The Company's credit risk is the risk of loss that the Company would
incur as a result of nonperformance by counterparties pursuant to the terms of
their contractual obligations related to investments, such as temporary cash
investments, cash surrender values of insurance contracts, and derivative
financial instruments. The Company does not anticipate any material impact to
its financial position, results of operations or cash flow as a result of
nonperformance by counterparties.1 See further discussion in Note F-Financial
Instruments under the heading "Credit Risk" in Item 8 of this report.
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 this 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.1
Rate Matters
Utility
New York Jurisdiction
In November 1995, Distribution Corporation filed in its New York jurisdiction a
request for an annual rate increase of $28.9 million with a requested return on
equity of 11.5%. A two-year settlement with the parties in this rate proceeding
was approved by the Public Service Commission of the State of New York (PSC).
Effective October 1, 1996 and October 1, 1997, Distribution Corporation received
annual base rate increases of $7.2 million. The settlement did not specify a
rate of return on equity. Generally, earnings above a 12% return on equity
(excluding certain items and determined on a cumulative basis over the three
years ending September 30, 1998) will be shared equally between shareholders and
ratepayers. As a result of this sharing mechanism, Distribution Corporation
recorded an estimated cumulative refund provision to its customers of $3.0
million ($2.0 million after-tax) during the fourth quarter of 1997. The final
amount owed to customers, if any, will not be known until the conclusion of the
settlement period.
In June 1997, the PSC issued an order requiring jurisdictional
utilities to file plans to offer heating customers a fixed price service option
for the coming winter heating season. The order also directed the utilities to
submit proposals for increased supply diversity with a view toward fostering
price stability. In August 1997, Distribution Corporation filed in its New York
jurisdiction a plan to comply with the PSC's order and the PSC subsequently
approved the plan in October 1997. The fixed price service option that was
approved gives heating customers the opportunity to be guaranteed a fixed unit
price for natural gas during the billing period of December 1997 through April
1998. The option was made available on a first-come, first-served basis to a
maximum of 100,000 heating customers. Approximately 11,000 heating customers
chose the fixed price service option, which will fix the monthly gas adjustment
at $.13832 per hundred cubic feet, which is 20% less than the average gas
adjustment experienced during the 1996 - 1997 heating season. However, this rate
is higher than the gas adjustment experienced during the 1995 - 1996 heating
season. Distribution Corporation locked in commodity prices for approximately
30% of the New York jurisdiction's planned purchases during the period of
November 1997 through March 1998. Other components of heating customers rates
will remain unchanged.
New York's gas industry restructuring effort continues to develop at a
slow pace. As of the end of September 1997, 14,000 small volume customers across
the state chose aggregator services over their utility. In Distribution
Corporation's service territory, 1,500 small volume customers (out of over
500,000) are purchasing gas from eight aggregators, for a total annual load of
just over 1 Bcf. At the urging of the PSC, Distribution Corporation began to
offer storage release service to aggregators on June 27, 1997. Currently,
Distribution's is the only actual release storage service available in New York
State. Whether aggregators find the service attractive enough to increase
marketing activity remains to be seen.
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.
In April 1997, Distribution Corporation filed a proposal for a customer
choice pilot program, called Energy Select, with the PaPUC. The PaPUC approved
Energy Select in June 1997 and service commenced on October 1, 1997. Energy
Select, which will last one and one-half years, allows 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 is not a supplier of gas in this pilot. Under Energy Select,
Distribution Corporation will continue to deliver the gas to the customer's home
or business and will remain responsible for reading customer meters, the safety
and maintenance of its pipeline system and responding to gas emergencies. The
Company's marketing affiliate, NFR, is a participating supplier in Energy
Select.
General rate increases 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.
State Regulatory Environment
The New York and Pennsylvania regulatory commissions continue to address
restructuring of the gas industry in response to the FERC's Order 636.
Distribution Corporation is working closely with the state regulatory
commissions to resolve issues consistent with Distribution Corporation
objectives. Current proceedings and other regulatory and legislative
developments are discussed below:
New York
Generic Restructuring Proceeding. This proceeding is examining the appropriate
retail or end-use impacts resulting from the FERC's Order 636 pipeline
restructuring. On March 28, 1996, the PSC issued an order directing the state's
local distribution companies (LDCs), including Distribution Corporation, to file
additional tariff amendments regarding this proceeding. On April 30, 1996,
Distribution Corporation submitted a filing, effective May 1, 1996 on a
temporary basis, proposing to amend its services to provide a framework for
small customer aggregation in compliance with the PSC's March 28, 1996 Order
(Distribution Corporation already offers unbundled, flexible service to its
commercial and industrial customers). The changes provide the option for all
customers to choose from whom they want to buy gas, which could be Distribution
Corporation, another utility, or a non-utility supplier or marketer. If a
customer purchases gas from a supplier other than Distribution Corporation, the
supplier would obtain and transport the gas to Distribution Corporation's
pipeline system and Distribution Corporation would then deliver the gas to the
customer. Distribution Corporation would continue to be responsible for
maintaining its pipelines and responding to safety calls, but billing and other
traditional services would be assumed by the alternate supplier. On September
12, 1996, the PSC issued an order approving the April 30, 1996 filing, subject
to additional changes. Further revisions were filed as directed for an effective
date of October 1, 1996. On June 27, 1997, Distribution Corporation's tariff was
further amended to provide unbundled storage capacity to qualified marketers.
Filed and approved in compliance with the PSC's restructuring orders, the
service allows marketers to take release of Distribution Corporation's storage
and transmission capacity in order to serve retail end users through the
aggregation services described above. The service includes, to the extent
necessary, inventory transfers at pre-determined prices.
On September 4, 1997, the PSC issued an order addressing upstream
capacity requirements for LDCs. In the PSC's March 28, 1996 order, the LDCs,
including Distribution Corporation, were authorized to require converting sales
customers (or their marketers) to take an allocation of upstream capacity for up
to a three year period. The PSC stated that prior to the start of the third year
(April 1998), each utility would be required to demonstrate "its efforts to
relieve itself of excess capacity." The PSC further held that "we will address
any issues of stranded costs then." The
September 4, 1997 order implements the third year review by directing the
state's LDCs to, no later than April 1, 1998, submit plans addressing upstream
capacity issues including stranded costs. Distribution Corporation is currently
reviewing its portfolio of upstream capacity consistent with the provisions of
the September 4, 1997 order.
Also, on September 4, 1997, the PSC issued a notice inviting comments
on a report prepared by the PSC Staff for the Department of Public Service
entitled "The Future of the Natural Gas Industry" (Position Paper).
Acknowledging that customer choice has not evolved as expected under the Generic
Restructuring orders, the PSC Staff reaches the "fundamental conclusion" that
"the most effective way to establish a robustly competitive market in gas supply
is to separate the merchant and distribution functions." Toward that end, the
Position Paper sets forth a variety of recommendations addressing issues such as
upstream capacity, rate design, system reliability, market power, customer
communication, social programs and taxes. The PSC Staff believes that a five
year period is necessary for LDCs to transition out of the merchant business. On
November 20, 1997, Distribution Corporation filed initial comments supporting
the PSC Staff's proposal that LDCs exit the merchant function. Additional
comments consistent with Distribution Corporation's objectives were offered on
other issues raised in the Position Paper.
Pennsylvania
The PaPUC has not issued a generic rulemaking for industry restructuring, opting
instead for a case-by-case approach promoting small customer aggregation
programs including Distribution's Energy Select pilot described above. Two
issues dealt with generically, however, are affiliate transactions and supplier
fitness standards, for which the PaPUC adopted policy statements in June 1997.
To the extent required, Distribution Corporation has already implemented
procedures consistent with those policy statements.
On the legislative front, a gas restructuring bill was introduced in
1997 proposing to amend the Public Utility Code to require that LDCs exit the
merchant function in three years. Modeled after the 1996 electric competition
law, House Bill 1068 (introduced in the Senate as S.943) would, if enacted,
provide direct access to competitive markets for all retail gas customers. The
Company is not able to predict the outcome of the bill.
However, it appears that the bill would not become law earlier than 1998.1
Pipeline and Storage
On October 31, 1994, Supply Corporation filed for an annual rate increase of
$21.0 million, with a requested return on equity of 12.6%. In February 1996, the
FERC approved a settlement authorizing an annual rate increase of approximately
$6.0 million with a return on equity of 11.3%. The new rates were put into
effect on April 1, 1996, retroactive to June 1, 1995. With this settlement,
Supply Corporation agreed not to seek recovery for increased cost of service
until April 1, 1998. Supply Corporation also agreed not to seek recovery of
revenues related to certain terminated service from other storage customers
until April 1, 2000, as long as the terminations were not greater than
approximately 30% of the terminable service. Management has been successful in
marketing and obtaining executed contracts for such terminated storage service
and does not anticipate a problem in obtaining executed contracts for additional
terminated storage service as it arises. 1
Other Matters
Environmental Matters
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for on-going evaluation of its operations to identify potential
environmental exposures and assure compliance with regulatory policies and
procedures.
It is the Company's policy to accrue estimated environmental clean-up
costs when such amounts can reasonably be estimated and it is probable that the
Company will be required to incur such costs. Distribution Corporation has
estimated that clean-up costs related to several former manufactured gas
plant sites and several other waste disposal sites are in the range of $9.3
million to $9.9 million.1 At September 30, 1997, Distribution Corporation has
recorded the minimum liability of $9.3 million. The ultimate cost to
Distribution Corporation with respect to the remediation of these sites will
depend on such factors as the remediation plan selected, the extent of the site
contamination, the number of additional potentially responsible parties at each
site and the portion, if any, attributed to Distribution Corporation.1 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.
In New York and Pennsylvania, Distribution Corporation is recovering
site investigation and remediation costs in rates. For further discussion, see
disclosure in Note H - Commitments and Contingencies under the heading
"Environmental Matters" in Item 8 of this report.
New Accounting Pronouncements. During 1997, the Financial Accounting Standards
Board issued three new accounting pronouncements that will impact the Company:
Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per
Share"; SFAS 130, "Reporting Comprehensive Income"; and SFAS 131, "Disclosures
about Segments of an Enterprise and Related Information." For further
discussion, see disclosure in Note A - Summary of Significant Accounting
Policies in Item 8 of this report.
Year 2000
As the millennium approaches, the Company is preparing all of its computer
systems to be Year 2000 compliant. Management is in the process of finalizing a
comprehensive review of its computer systems to identify the systems that could
be affected and is developing a conversion plan to resolve the issue. The cost
of upgrading systems will be expensed as incurred. Management estimates that
such costs will be approximately $1.0 million.1
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 two of its major operating
segments.
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 "1", 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. Occurrences affecting the Company's ability to obtain funds from
operations, debt or equity to finance needed capital expenditures and
other investments
9. Ability to successfully identify and finance oil and gas property
acquisitions and ability to operate existing and any subsequently
acquired properties
10. Ability to successfully identify, drill for and produce economically
viable natural gas and oil reserves
11. Changes in the availability and/or price of derivative financial
instruments
12. Inability of the various counterparties to meet their obligations with
respect to the Company's financial instruments
13. 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
14. Significant changes in tax rates or policies or in rates of inflation or
interest
15. Significant changes in the Company's relationship with its employees and
the potential adverse effects if labor disputes or grievances were to
occur
16. Changes in accounting principles and/or the application of such
principles to the Company
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 Disclosure About Market Risk
Not Applicable.
ITEM 8 Financial Statements and Supplementary Data
Index to Financial Statements
- -----------------------------
Page
----
Financial Statements:
Report of Independent Accountants 50
Consolidated Statements of Income and Earnings Reinvested
in the Business, three years ended September 30, 1997 51
Consolidated Balance Sheets at September 30, 1997 and 1996 52-53
Consolidated Statement of Cash Flows, three years ended
September 30, 1997 54
Notes to Consolidated Financial Statements 55-57
Financial Statement Schedules:
For the three years ended September 30, 1997
II-Valuation and Qualifying Accounts 77
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 J - Quarterly Financial Data
(unaudited) and Note L - 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 consistently applied, 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, Price Waterhouse 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 Price Waterhouse
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, 1997 and 1996,
and the results of their operations and their cash flows for each of the three
years in the period ended September 30, 1997, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards 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.
PRICE WATERHOUSE LLP
Buffalo, New York
October 24, 1997
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) 1997 1996 1995
---- ---- ----
Income
Operating Revenues $1,265,812 $1,208,017 $ 975,496
---------- ---------- ----------
Operating Expenses
Purchased Gas 528,610 477,357 351,094
Operation 262,328 282,795 266,786
Maintenance 25,698 26,411 25,719
Property, Franchise and Other Taxes 100,549 99,456 91,837
Depreciation, Depletion and Amortization 111,650 98,231 71,782
Income Taxes - Net 68,674 66,321 43,879
---------- ---------- ----------
1,097,509 1,050,571 851,097
---------- ---------- ----------
Operating Income 168,303 157,446 124,399
Other Income 3,196 3,869 5,378
---------- ---------- ----------
Income Before Interest Charges 171,499 161,315 129,777
---------- ---------- ----------
Interest Charges
Interest on Long-Term Debt 42,131 40,872 40,896
Other Interest 14,680 15,772 12,987
---------- ---------- ----------
56,811 56,644 53,883
---------- ---------- ----------
Net Income Available for Common Stock 114,688 104,671 75,894
Earnings Reinvested in the Business
Balance at Beginning of Year 422,874 380,123 363,854
---------- ---------- ----------
537,562 484,794 439,748
Dividends on Common Stock 64,967 61,920 59,625
---------- ---------- ----------
Balance at End of Year $ 472,595 $ 422,874 $ 380,123
========== ========== ==========
Earnings Per Common Share $3.01 $2.78 $2.03
========== ========== ==========
Weighted Average Common Shares Outstanding 38,083,514 37,613,305 37,396,875
========== ========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
At September 30 (Thousands of Dollars) 1997 1996
---- ----
Assets
Property, Plant and Equipment $2,668,478 $2,471,063
Less - Accumulated Depreciation,
Depletion and Amortization 849,112 761,457
---------- ----------
1,819,366 1,709,606
---------- ----------
Current Assets
Cash and Temporary Cash Investments 14,039 19,320
Receivables - Net 107,417 96,740
Unbilled Utility Revenue 20,433 20,778
Gas Stored Underground 29,856 34,727
Materials and Supplies - at average cost 19,115 21,544
Prepayments 17,807 27,872
---------- ----------
208,667 220,981
---------- ----------
Other Assets
Recoverable Future Taxes 91,011 88,832
Unamortized Debt Expense 23,394 25,193
Other Regulatory Assets 48,350 57,086
Investment in Unconsolidated Foreign Subsidiary 18,887 -
Deferred Charges 12,025 7,377
Other 45,631 40,697
---------- ----------
239,298 219,185
---------- ----------
$2,267,331 $2,149,772
========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
At September 30 (Thousands of Dollars) 1997 1996
---- ----
Capitalization and Liabilities
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 100,000,000 Shares; Issued and
Outstanding - 38,165,888 Shares and 37,851,655
Shares, Respectively $ 38,166 $ 37,852
Paid In Capital 405,028 395,272
Earnings Reinvested in the Business 472,595 422,874
Cumulative Translation Adjustment (2,085) -
---------- ----------
Total Common Stock Equity 913,704 855,998
Long-Term Debt, Net of Current Portion 581,640 574,000
---------- ----------
Total Capitalization 1,495,344 1,429,998
---------- ----------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 92,400 199,700
Current Portion of Long-Term Debt 103,359 -
Accounts Payable 74,105 64,610
Amounts Payable to Customers 10,516 4,618
Other Accruals and Current Liabilities 83,793 82,520
---------- ----------
364,173 351,448
---------- ----------
Deferred Credits
Accumulated Deferred Income Taxes 288,555 281,207
Taxes Refundable to Customers 19,427 21,005
Unamortized Investment Tax Credit 12,041 12,711
Other Deferred Credits 87,791 53,403
---------- ----------
407,814 368,326
---------- ----------
Commitments and Contingencies - -
---------- ----------
$2,267,331 $2,149,772
========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Statement of Cash Flows
------------------------------------
Year Ended September 30 (Thousands of Dollars) 1997 1996 1995
---- ---- ----
Operating Activities
Net Income Available for Common Stock $114,688 $104,671 $ 75,894
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Depreciation, Depletion and Amortization 111,650 98,231 71,782
Deferred Income Taxes 3,800 3,907 8,452
Other 8,030 4,540 275
Change in:
Receivables and Unbilled Utility Revenue (10,332) (20,747) 16,034
Gas Stored Underground and Materials and Supplies 7,300 (6,308) 5,733
Prepayments 10,065 1,881 (9,144)
Accounts Payable 9,495 10,768 (14,451)
Amounts Payable to Customers 5,898 (46,383) 12,287
Other Accruals and Current Liabilities (2,120) 18,200 (1,305)
Other Assets and Liabilities - Net 36,188 (291) 8,804
-------- -------- --------
Net Cash Provided by Operating Activities 294,662 168,469 174,361
-------- -------- --------
Investing Activities
Capital Expenditures (214,001) (171,567) (182,826)
Investment in Unconsolidated Foreign Subsidiary (21,075) - -
Other 1,429 (1,366) 10,646
--------- -------- --------
Net Cash Used in Investing Activities (233,647) (172,933) (172,180)
--------- -------- --------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper (107,300) 52,100 35,100
Net Proceeds from Issuance of Long-Term Debt 99,500 99,650 99,099
Reduction of Long-Term Debt (1,310) (88,500) (96,000)
Proceeds from Issuance of Common Stock 7,074 8,956 2,555
Dividends Paid on Common Stock (64,260) (61,179) (59,194)
-------- -------- --------
Net Cash Provided by (Used in) Financing Activities (66,296) 11,027 (18,440)
-------- -------- --------
Net Increase (Decrease) in Cash and
Temporary Cash Investments (5,281) 6,563 (16,259)
Cash and Temporary Cash Investments at Beginning of Year 19,320 12,757 29,016
-------- -------- --------
Cash and Temporary Cash Investments at End of Year $ 14,039 $ 19,320 $ 12,757
======== ======== ========
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 subsidiaries. All significant intercompany balances and transactions have
been eliminated where appropriate.
The Company currently uses the equity method of accounting for its
investment in Severoceske Teplarny, a.s. (SCT). In 1997, Horizon's wholly-owned
subsidiary, Beheer-En Beleggingsmaatschappij Bruwabel, B.V. (Bruwabel) acquired
a 36.8% equity interest in SCT.
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 state and federal authorities having
jurisdiction. 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.
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.
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. Such cost includes an
Allowance for Funds Used During Construction (AFUDC), which is defined in
applicable regulatory systems of accounts as the net cost of borrowed funds used
for construction purposes and a reasonable rate on other funds when so used. The
rates used in the calculation of AFUDC are determined in accordance with
guidelines established by regulatory authorities.
Included in property, plant and equipment is the cost of gas stored
underground - noncurrent, representing the volume of gas required to maintain
pressure levels for normal operating purposes as well as gas volumes maintained
for system balancing and other purposes, including those needed for no-notice
transportation service.
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 exploration and development costs are capitalized under the
full-cost method of accounting as prescribed by the Securities and Exchange
Commission (SEC). All costs directly associated with property acquisition,
exploration and development activities are capitalized, with the principal
limitation that such capitalized amounts not exceed the present value of
estimated future net revenues from the production of proved gas and oil reserves
plus the lower of cost or market of unevaluated properties, net of related
income tax effect (the full-cost ceiling). The present value of estimated future
net revenues is computed based on end-of-year prices adjusted for contracted
price changes. At September 30, 1997, Seneca's capitalized costs under the
full-cost method of accounting were well below the full-cost ceiling. There are
certain factors, including price declines, which could lower the full-cost
ceiling and cause an impairment of Seneca's oil and gas assets.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization are computed by application of either
the straight-line method or the gross revenue method, in amounts sufficient to
recover costs over the estimated service lives of property in service, and for
oil and gas properties, over the period of estimated gross revenues from proved
reserves. The costs of unevaluated oil and gas properties are excluded from this
computation. For timber properties, depletion, determined on a property by
property basis, is charged to operations based on the annual amount of timber
cut in relation to the total amount of recoverable timber. The provisions for
depreciation, depletion and amortization, as a percentage of average depreciable
property were 4.6% in 1997, 4.4% in 1996 and 3.5% in 1995.
Gas Stored Underground - Current
Gas stored underground - current is carried at lower of cost or market, on a
last-in, first-out (LIFO) method. Under present regulatory practice, the
liquidation of a LIFO layer is reflected in future gas cost adjustment clauses.
Based upon the average price of spot market gas purchased in September 1997,
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 $47.6 million at September 30, 1997.
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 Czech
Koruna. The translation from the Czech Koruna 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 translation adjustment is reported as a
Cumulative Translation Adjustment, a separate component of Common Stock Equity.
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.
Financial Instruments
The Company, in its Exploration and Production segment and natural gas marketing
operations utilizes price swap agreements and natural gas futures, respectively,
to manage a portion of the market risk associated with fluctuations in the price
of natural gas and crude oil. Gains or losses from the price swap agreements are
accrued in operating revenues on the Consolidated Statement of Income at the
contract settlement dates. Gains or losses from natural gas futures 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.
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 1997, 1996 and 1995 was
$52.4 million, $54.8 million and $53.5 million, respectively. Net income taxes
paid in 1997, 1996 and 1995 were $69.2 million, $60.8 million and $34.6 million,
respectively.
Earnings Per Common Share
Earnings per common share are calculated using the weighted average number of
shares outstanding during each fiscal year. Common stock equivalents in the form
of stock options do not have a material dilutive effect on earnings per common
share.
New Accounting Pronouncements
Earnings Per Share
In February 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 128, "Earnings per Share" (SFAS
128). SFAS 128 replaces the standards for computing earnings per share
previously found in Accounting Principles Board Opinion No. 15, "Earnings per
Share" (APB 15). SFAS 128 requires dual presentation of basic and diluted
earnings per share (EPS) on the face of the income statement for all entities
with complex capital structures. Basic EPS is computed by dividing income
available to common stockholders by the weighted-average number of common shares
outstanding for the period. Diluted EPS reflects the potential dilution that
could occur if securities or other contracts to issue common stock were
exercised or converted into common stock. Such additional shares are added to
the denominator of the basic EPS calculation in order to calculate diluted EPS.
The Company is required to adopt SFAS 128 in the first quarter of 1998.
Earlier application is not permitted and restatement of all prior period EPS
data presented is required. The Company does not believe that common stock
equivalents in the form of stock options will have a material dilutive effect on
its EPS under SFAS 128. However, since SFAS 128 eliminated the 3% materiality
threshold of APB 15, diluted EPS will be disclosed as required by SFAS 128.
Comprehensive Income
In June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" (SFAS
130). SFAS 130 establishes standards for reporting and display of comprehensive
income in a full set of general-purpose financial statements. Comprehensive
income, as described in SFAS 130, includes Net Income Available
for Common Stock as well as items under existing accounting standards that are
reported as adjustments to stockholders' equity. Such adjustments to
stockholders' equity include foreign currency translation adjustments, minimum
pension liability adjustments and unrealized gains and losses on certain
investments in debt and equity securities.
The Company is required to adopt SFAS 130 in the first quarter of 1999.
However, earlier application is permitted. The Company is currently in the
process of determining how it will present comprehensive income and its
components within the guidelines established by SFAS 130. SFAS 130 requires
restatement of prior period financial statements for comparability.
Business Segment Information
In June 1997, the FASB issued SFAS 131, "Disclosures about Segments of an
Enterprise and Related Informtion" (SFAS 131). SFAS 131 establishes standards
for the way that public business enterprises report information about operating
segments in annual financial statements and requires that those enterprises
report selected information about operating segments in interim financial
reports issued to shareholders. It also establishes standards for related
disclosures about products and services, geographic areas, and major customers.
Generally, SFAS 131 requires reporting segment information under a management
approach. The management approach is based on the way that management organizes
the segments within the enterprise for making operating decisions and assessing
performance. SFAS 131 supersedes SFAS 14, "Financial Reporting for Segments of a
Business Enterprise," but retains the requirement to report information about
major customers.
The Company is required to adopt SFAS 131 in its annual report for
1999. However, earlier application is permitted. In the second year of
application, SFAS 131 will be applied to interim periods. The Company is
currently in the process of determining how SFAS 131 will impact its segment
reporting. SFAS 131 would require restatement of prior period financial
statements for comparability.
Note B - Regulatory Matters
Regulatory Assets and Liabilities
Distribution Corporation and Supply Corporation have incurred various costs and
received various credits which have been reflected as regulatory assets and
liabilities on the Company's consolidated balance sheets. Accounting for such
costs and credits as regulatory assets and liabilities is in accordance with
SFAS 71, "Accounting for the Effect of Certain Types of Regulation" (SFAS 71).
This statement sets forth the application of generally accepted accounting
principles for those companies whose rates are established by or are subject to
approval by an independent third-party regulator. Under SFAS 71, regulated
companies defer costs and credits on the balance sheet as regulatory assets and
liabilities when it is probable that those costs and credits will be allowed in
the ratesetting process in a period different from the period in which they
would have been reflected in income by an unregulated company. These deferred
regulatory assets and liabilities are then flowed through the income statement
in the period in which the same amounts are
reflected in rates. Distribution Corporation and Supply Corporation have
recorded the following regulatory assets and liabilities:
At September 30 (Thousands) 1997 1996
---- ----
Regulatory Assets:
Recoverable Future Taxes (Note C) $ 91,011 $ 88,832
Unamortized Debt Expense (Note A) 18,603 20,319
Pension and Post-Retirement Benefit Costs (Note G) 24,200 22,259
Order 636 Transition Costs* 5,015 14,256
Gathering Plant 7,675 9,868
Environmental Clean-up (Note H) 8,697 8,144
Other 2,763 2,559
-------- --------
Total Regulatory Assets 157,964 166,237
-------- --------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) 10,516 4,618
New York Rate Settlement 22,232 1,675
Taxes Refundable to Customers (Note C) 19,427 21,005
Pension and Post-Retirement
Benefit Costs (Note G) 10,446 4,665
Other 1,538 541
-------- --------
Total Regulatory Liabilities 64,159 32,504
-------- --------
Net Regulatory Position $ 93,805 $133,733
======== ========
* Exclusive of amounts being collected through gas costs. Such amounts are
included in unrecovered purchased gas costs or amounts payable to customers.
If for any reason, including deregulation, a change in the method of
regulation, or a change in competitive environment, Distribution Corporation
and/or Supply Corporation ceases to meet the criteria for application of SFAS 71
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 SFAS 71 occurs. Such amounts would be classified as an
extraordinary item.
New York Rate Settlement
The New York jurisdiction of Distribution Corporation entered into a rate
settlement with the Public Service Commission of the State of New York (PSC)
during 1996. The settlement acknowledged that Distribution Corporation may incur
expenses above those included in the current rate structure for certain specific
items. The settlement allows Distribution Corporation to utilize certain refunds
from upstream pipeline companies and certain credits to offset such additional
expenses. At September 30, 1997 and 1996, such refunds and credits combined
amounted to $19.2 million and $1.7 million, respectively. At the end of the
settlement period, if such refunds or credits exceed the specified additional
expenses, the excess amount would be passed back to the customers.
The settlement also provided that earnings above a 12% return on equity
(excluding certain items and determined on a cumulative basis over the three
years ending September 30, 1998) will be shared equally between shareholders and
ratepayers. As a result of this sharing mechanism, Distribution Corporation
recorded an estimated cumulative refund provision to its customers of $3.0
million during the fourth quarter of 1997 related to the two years ended
September 30, 1997. The final amount owed to customers, if any, will not be
known until the conclusion of the settlement period.
Note C - Income Taxes
The components of federal and state income taxes included in the Consolidated
Statement of Income are as follows:
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Operating Expenses:
Current Income Taxes -
Federal $57,807 $55,148 $30,522
State 7,067 7,266 4,905
Deferred Income Taxes 3,800 3,907 8,452
------- ------- -------
68,674 66,321 43,879
Other Income:
Deferred Investment Tax Credit (665) (665) (672)
------- ------- -------
Total Income Taxes $68,009 $65,656 $43,207
======= ======= =======
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) 1997 1996 1995
---- ---- ----
Net Income Available for Common Stock $114,688 $104,671 $ 75,894
Total Income Taxes 68,009 65,656 43,207
-------- -------- --------
Income Before Income Taxes $182,697 $170,327 $119,101
======== ======== ========
Income Tax Expense, Computed at Federal
Statutory Rate of 35% $63,944 $59,614 $41,685
Increase (Reduction) in Taxes Resulting from:
Current State Income Taxes,
Net of Federal Income Tax Benefit 4,594 4,723 3,188
Depreciation 2,560 2,499 2,397
Miscellaneous (3,089) (1,180) (4,063)
------- ------- -------
Total Income Taxes $68,009 $65,656 $43,207
======= ======= =======
Significant components of the Company's deferred tax liabilities and
assets were as follows:
At September 30 (Thousands) 1997 1996
---- ----
Deferred Tax Liabilities:
Excess of Tax Over Book Depreciation $190,913 $182,271
Exploration and Intangible Well
Drilling Costs 117,759 98,293
Other 62,189 67,030
-------- --------
Total Deferred Tax Liabilities 370,861 347,594
-------- --------
Deferred Tax Assets:
Overheads Capitalized for Tax Purposes (19,406) (16,289)
Other (62,900) (50,098)
-------- --------
Total Deferred Tax Assets (82,306) (66,387)
-------- --------
Total Net Deferred Income Taxes $288,555 $281,207
======== ========
SFAS 109, "Accounting for Income Taxes" (SFAS 109), requires the
recognition of regulatory liabilities representing the reduction of previously
recorded deferred income taxes associated with rate-regulated activities that
are expected to be refundable to customers. These amounted to $19.4 million and
$21.0 million at September 30, 1997 and 1996, respectively. Also, SFAS 109
requires the recognition of additional deferred income taxes not previously
recorded because of prior ratemaking practices. Substantially all of these
deferred taxes relate to property, plant and equipment and related investment
tax credits and will be amortized consistent with the depreciation and
amortization of these accounts. The additional deferred taxes and corresponding
regulatory assets, representing future amounts collectible from customers in the
ratemaking process, amounted to $91.0 million and $88.8 million at September 30,
1997 and 1996, respectively.
Note D - Capitalization
Summary of Changes in Common Stock Equity
Earnings
Paid Reinvested Cumulative
(Thousands, Except Common Stock In in the Translation
Per Share Amounts) Shares Amount Capital Business Adjustment
------ ------ ------- ---------- -----------
Balance at
September 30, 1994 37,278 $37,278 $379,156 $363,854 $ -
Net Income Available
for Common Stock 75,894
Dividends Declared on
Common Stock
($1.60 Per Share) (59,625)
Common Stock Issued
Under Stock and
Benefit Plans 156 156 3,875
------ ------- -------- -------- -------
Balance at
September 30, 1995 37,434 37,434 383,031 380,123 -
Net Income Available
for Common Stock 104,671
Dividends Declared
on Common Stock
($1.65 Per Share) (61,920)
Common Stock Issued
Under Stock and
Benefit Plans 418 418 12,241
------ ------- -------- -------- -------
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)
Cumulative Translation
Adjustment (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)
====== ======= ======== ======== =======
* 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, 1997, $398.2 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 commission or service charges
in connection with such acquisitions. The 401(k) Plans allow employees the
opportunity to invest in Company common stock, in addition to a variety of other
investment alternatives. At the discretion of the Company, shares purchased
under these plans are either original issue shares purchased directly from the
Company or shares purchased on the open market by an agent.
The Company also has a Director Stock Plan under which it issues shares
of Company common stock to its non-employee directors as partial consideration
for service as directors.
Shareholder Rights Plan
In 1996, the Company's Board of Directors adopted a shareholder rights plan and
declared a dividend of one right (Right) for each share of common stock held by
the shareholders of record on July 31, 1996. The Rights become exercisable ten
days after actions that result or could result in the acquisition by a person or
entity of 10% or more of the Company's voting stock. If the Rights become
exercisable, each Company stockholder, except an acquirer, will be able to
exercise a Right and receive common stock (or, in certain cases, cash, property
or other securities) of the Company, or common stock of the acquirer, having a
market value equal to twice the Right's then current purchase price. If a Right
were currently exercisable, it would entitle a Company stockholder, other than
an acquirer, to purchase $130 worth of Company common stock (or the common stock
of the acquirer) for $65.
The Company is able to exchange the Rights at an exchange ratio of one
share of common stock per Right. It also is able to redeem, in whole but not in
part, the Rights at a price of $0.01 per Right anytime until ten days after an
acquirer announces that it has acquired or has the right to acquire 10% or more
of the Company's voting stock. All Rights expire on July 31, 2006.
Stock Option and Stock Award Plans
The Company's 1997 Award and Option Plan (1997 Plan) provides for the issuance
of incentive stock options, nonqualified stock options, stock appreciation
rights, restricted stock, performance units and performance shares to key
employees. The 1993 Award and Option Plan (1993 Plan) provided for the issuance
of the same type of awards and options as the 1997 Plan. The 1983 Incentive
Stock Option Plan (1983 Plan) provided for the issuance of incentive stock
options to key employees. The 1984 Stock Plan (1984 Plan) provided for awards of
restricted stock, nonqualified stock options and stock appreciation rights to
key employees. 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.
In October 1995, the FASB issued SFAS 123, "Accounting for Stock-Based
Compensation" (SFAS 123). In 1996, the Company adopted the disclosure provision
of SFAS 123 but opted to remain under the expense recognition provisions of APB
Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for
its stock option and stock award plans. For the years ended September 30, 1997,
1996 and 1995, 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 $8.1 million, $6.7 million and $1.4
million for the years ended September 30, 1997, 1996 and 1995, respectively. Had
compensation expense for stock options granted under the Company's stock plans
been determined based on fair value at the grant dates consistent with the
method of SFAS 123, the Company's net income and earnings per share would have
been reduced to the pro forma amounts below:
1997 1996
- -----------------------------------------------------------------------------
Net Income (Thousands):
As reported $114,688 $104,671
Pro Forma $110,506 $104,322
Earnings per Common Share:
As reported $3.01 $2.78
Pro Forma $2.90 $2.77
The above 1996 pro forma amount relates only to options granted since
the beginning of 1996. Had SFAS 123 been effective prior to 1996, the fair value
of options granted in 1995 but vesting in 1996 would have further reduced 1996
pro forma net income and earnings per share by $1.0 million and $0.03,
respectively.
Transactions involving option shares for all three plans are summarized
as follows:
Number of
Shares Subject Weighted Average
to Option Exercise Price
- ----------------------------------------------------------------------------
Outstanding at September 30, 1994 1,167,337 $26.80
Granted in 1995 362,100 $27.94
Exercised in 1995* (17,615) $19.46
Forfeited in 1995 (11,532) $31.00
- ----------------------------------------------------------------------------
Outstanding at September 30, 1995 1,500,290 $27.13
Granted in 1996 487,750 $34.44
Exercised in 1996* (195,321) $22.72
Forfeited in 1996 (19,468) $27.90
- ----------------------------------------------------------------------------
Outstanding at September 30, 1996 1,773,251 $29.62
Granted in 1997 678,750 $39.61
Exercised in 1997* (274,655) $25.80
Forfeited in 1997 (3,000) $36.81
- ----------------------------------------------------------------------------
Outstanding at September 30, 1997 2,174,346 $33.21
- ----------------------------------------------------------------------------
Option shares exercisable
at September 30, 1997 1,495,596 $30.31
Option shares available for future
grant at September 30, 1997** 1,401,270
- ----------------------------------------------------------------------------
* In connection with exercising these options, 117,326; 77,679; and 3,192
shares were surrendered and canceled during 1997, 1996 and 1995,
respectively.
** Including shares available for restricted stock grants.
The weighted average fair value per share of options granted in 1997
and 1996 was $7.66 and $5.58, respectively. These weighted average fair values
were estimated on the date of grant using a binomial option pricing model which
is a modification of the Black-Scholes option pricing model, with the following
weighted average assumptions for 1997 and 1996, respectively: quarterly dividend
yield of 1.06% and 1.22%, annual expected return of 16.25% and 12.83%, annual
standard deviation (volatility) of 16.76% and 15.62%, risk free rate of 6.58%
and 6.28%, and expected term of 5.0 years and 5.5 years.
The following table summarizes information about options outstanding at
September 30, 1997:
Options Outstanding Options Exercisable
- -------------------------------------------------------------- -----------------------------
Number Weighted Average Weighted Number
Range of Outstanding Remaining Average Exercisable Weighted Average
Exercise Prices at 9/30/97 Contractual Life Exercise Price at 9/30/97 Exercise Price
- --------------- ----------- ---------------- -------------- ----------- ----------------
$18.00 - $25.19 307,941 3.90 years $24.03 307,941 $24.03
$27.94 - $41.63 1,866,405 8.25 years $34.73 1,187,655 $31.94
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 1984 and 1993 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:
1997 1996 1995
- -----------------------------------------------------------------------
Shares of Restricted Stock Awarded 6,300 8,000 8,000
Weighted Average Market Price of
Stock on Award Date $40.875 $36.81 $26.00
- -----------------------------------------------------------------------
As of September 30, 1997, 121,962 shares of non-vested restricted stock
were outstanding. Vesting restrictions will lapse on 107,662 of these shares on
January 2 of each year as follows: 1998 - 18,916 shares; 1999 - 20,916 shares;
2000 - 22,916 shares; 2001 - 24,914 shares; 2002 - 8,000 shares; 2003 - 6,000
shares; 2004 - 4,000 shares; and 2005 - 2,000 shares. For restricted stock
awarded before 1996, generally, the restrictions on transferability do not lapse
until the earliest of (a) six years from the date the vesting restrictions
lapse; (b) the recipient's attainment of age 65; or (c) the recipient's death.
For the 8,000 shares of restricted stock awarded in 1996, all restrictions will
lapse on one-fourth of such shares on each September 26, 2003 through 2006. For
the 6,300 shares of restricted stock awarded in 1997, all restrictions
respecting 5,300 shares will lapse on December 13, 1999 and all restrictions
respecting 1,000 shares will lapse on December 13, 2003.
Redeemable Preferred Stock
As of September 30, 1997, there were 3,200,000 shares of $25 par value
Cumulative Preferred Stock authorized but unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
At September 30 (Thousands) 1997 1996
---- ----
Debentures:
7-3/4% due February 2004 $125,000 $125,000
Medium-Term Notes:
6.42% due November 1997 50,000 50,000
6.08% due July 1998 50,000 50,000
5.58% due March 1999 100,000 100,000
7.25% due July 1999 50,000 50,000
6.60% due February 2000 50,000 50,000
7.395% due March 2023 49,000 49,000
8.48% due July 2024* 50,000 50,000
7.375% due June 2025 50,000 50,000
6.214% due August 2027** 100,000 -
-------- --------
674,000 574,000
Other Notes 10,999 -
-------- --------
684,999 574,000
Less Current Portion 103,359 -
-------- --------
$581,640 $574,000
======== ========
* Callable beginning July 1999.
** Putable beginning August 2002.
Other Notes In January and April 1997, Seneca issued three notes to third
parties totaling $12.3 million in connection with its acquisition of timber
properties. As shown in the table above, the remaining principal amount on such
notes is approximately $11.0 million at September 30, 1997. All notes have an
interest rate of 6.75%. The principal amount will be paid in installments over
the term of the notes which mature in January 1999, October 1999 and June 2001.
The aggregate principal amounts of long-term debt maturing for the next
five years are: $103.4 million in 1998, $153.7 million in 1999, $52.2 million in
2000, $1.6 million in 2001 and none in 2002 (subject to the put of $100
million).
The amounts and timing of the issuance and sale of debt securities will
depend on market conditions, regulatory authorizations, and the requirements of
the Company.
Note E - Short-Term Borrowings
The Company maintains uncommitted or discretionary lines of credit with certain
financial institutions for general corporate purposes. These lines are utilized
primarily as a means of financing, on an interim basis, various working capital
requirements and capital expenditures of the Company, including the Company's
oil and gas exploration and development program and the purchase and storage of
gas. Borrowings under these lines of credit are made at competitive money market
rates, and the Company currently is authorized to borrow up to $600.0 million
thereunder. These credit lines, which are callable at the option of the
financial institutions, are reviewed on an annual basis.
The Company also has authorization to issue as much as $300.0 million
of commercial paper from time to time, but is not likely to exceed $130.0
million because of the terms of the revolving credit arrangement discussed
below. Unless the Company receives additional regulatory authority, its
borrowings under its discretionary lines of credit, or through the issuance of
commercial paper, may not exceed $600.0 million in the aggregate.
Additionally, the Company has entered into an agreement that
establishes a 364-day committed revolving credit arrangement with five
commercial banks, under which it may borrow as much as $130.0 million. This
arrangement may be utilized for general corporate purposes, primarily to support
the issuance of commercial paper. The Company pays a fee to maintain this
arrangement, and may borrow through this arrangement under four interest rate
options. If amounts are borrowed under this arrangement, the $600.0 million
available for borrowing under the discretionary lines of credit is
correspondingly reduced. No borrowings were made under this arrangement during
the fiscal year ended September 30, 1997.
At September 30, 1997, the Company had outstanding notes payable to
banks and commercial paper of $32.4 million and $60.0 million, respectively. At
September 30, 1996, the Company had outstanding notes payable to banks and
commercial paper of $109.7 million and $90.0 million, respectively.
The weighted average interest rate on notes payable to banks was 6.12%
and 5.63% at September 30, 1997 and 1996, respectively. The weighted average
interest rate on commercial paper was 5.64% and 5.56% at September 30, 1997 and
1996, 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:
At September 30 (Thousands) 1997 1996
------------------- -------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
Long-Term Debt $684,999 $704,409 $574,000 $572,001
======== ======== ======== ========
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
Other assets consist principally of cash surrender values of insurance
contracts. The cash surrender values of these insurance contracts amounted to
$35.7 million and $31.6 million at September 30, 1997 and 1996, respectively.
The insurance contracts were established as a funding mechanism for various
benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company, in its Exploration and Production segment, has entered into certain
price swap agreements to manage a portion of the market risk associated with
fluctuations in the price of natural gas and crude oil, thereby providing more
stability to the operating results of that business segment. These agreements
are not held for trading purposes. The price swap agreements call for the
Company 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 the
Company for its natural gas and crude oil production.
The following summarizes the Company's settlements under price swap
agreements during 1997, 1996 and 1995:
Year Ended September 30 1997 1996 1995
--------------- --------------- ---------------
Natural Gas Swap Agreements:
Notional Amount - Equivalent
Billion Cubic Feet (Bcf) 24.9 23.0 16.3
Range of Fixed Prices per
Thousand Cubic Feet (Mcf) $1.71 - $2.10 $1.71 - $3.05 $1.74 - $2.39
Weighted Average Fixed Price
per Mcf $1.92 $1.91 $2.03
Range of Variable Prices
per Mcf $1.77 - $4.11 $1.67 - $3.43 $1.36 - $1.77
Weighted Average Variable Price
per Mcf $2.57 $2.31 $1.59
Gain (Loss) $(16,387,000) $(9,231,000) $7,157,000
Crude Oil Swap Agreements:
Notional Amount - Equivalent
Barrels (bbl) 1,371,500 1,071,000 686,000
Range of Fixed Prices per bbl $17.40 - $18.71 $17.40 - $19.25 $16.68 - $19.60
Weighted Average Fixed Price
per bbl $18.00 $18.22 $18.01
Range of Variable Prices per
bbl $19.22 - $25.18 $17.40 - $23.93 $17.16 - $19.89
Weighted Average Variable Price
per bbl $21.69 $20.72 $18.35
Loss $(5,090,000) $(2,606,000) $(221,000)
The Company had the following swap agreements outstanding at September
30, 1997:
Natural Gas Swap Agreements:
Notional Amount Range of Fixed Weighted Average Fixed
Year (Equivalent Bcf) Prices per Mcf Price per Mcf
---- ---------------- -------------- ----------------------
1998 24.5 $1.77 - $2.55 $2.11
1999 10.5 $2.00 - $2.35 $2.22
2000 1.3 $2.29 $2.29
----
36.3
====
Crude Oil Swap Agreements:
Notional Amount Range of Fixed Weighted Average Fixed
Year (Equivalent bbl) Prices per bbl Price per bbl
---- ---------------- --------------- ----------------------
1998 891,000 $17.50 - $20.56 $18.83
1999 135,000 $19.30 - $20.56 $19.86
---------
1,026,000
=========
At September 30, 1997, the Company had unrecognized losses of
approximately $16.3 million related to price swap agreements which are offset by
corresponding unrecognized gains from the Company's anticipated natural gas and
crude oil production over the terms of the price swap agreements.
The Company, through its natural gas marketing operations, participates
in the natural gas futures market to manage a portion of the market risk
associated with fluctuations in the price of natural gas. Such futures are not
held for trading purposes. At September 30, 1997, the Company had the following
futures contracts outstanding:
Long "Buy" Positions:
Notional Amount Contract Price Weighted Average
Year (Equivalent Bcf) Range Per Mcf Contract Price Per Mcf
- ---- ---------------- -------------- ----------------------
1998 6.6 $2.04 - $3.49 $2.64
1999 0.8 $2.04 - $2.57 $2.37
---
7.4
===
Short "Sell" Positions:
Notional Amount Contract Price Weighted Average
Year (Equivalent Bcf) Range Per Mcf Contract Price Per Mcf
- ---- ---------------- -------------- ----------------------
1998 2.3 $2.06 - $3.61 $2.97
===
At September 30, 1997, the Company had unrealized gains of
approximately $2.9 million related to these futures contracts. The Company
recorded gains of approximately $1.4 million, $1.0 million and $0.2 million
related to futures contracts during 1997, 1996 and 1995, respectively. Since
these futures contracts qualify and have been designated as hedges, any gains or
losses resulting from market price changes are substantially offset by the
related commodity transaction.
The Company has SEC authority to enter into interest rate and currency
exchange agreements associated with short-term borrowings covering a total
principal amount of $300.0 million. No such agreements were entered into during
the year ended September 30, 1997 and none are currently outstanding.
Credit Risk
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. The Company is at risk in the event of nonperformance by
counterparties on investments, such as temporary cash investments and cash
surrender values of insurance contracts. The Company is exposed to credit risk
from its derivative financial instruments when fluctuations in natural gas and
crude oil market prices result in the Company realizing gains on the price swap
agreements and futures contracts that it has entered into. When credit risk
arises, such risk to the Company is mitigated by the fact that the
counterparties, or the parent companies of such counterparties, are investment
grade financial institutions. As for the Company's derivative financial
instruments, in those instances where the Company is not dealing directly with
the parent company, the Company has obtained guarantees from the parent company
of the counterparty that has issued the price swap agreements. Accordingly, the
Company does not anticipate any material impact to its financial position,
results of operations, or cash flow as a result of nonperformance by
counterparties.
Note G - Retirement Plan and Other Post-Retirement Benefits
Retirement Plan
The Company has a tax-qualified, noncontributory, defined-benefit retirement
plan (Plan) that covers substantially all employees of the Company. The Plan
uses years of service, age at retirement and earnings of employees to determine
benefits.
The Company's policy is to fund 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. Plan funding
is subject to annual review by management and its consulting actuary. Plan
assets primarily consist of equity and fixed income investments and units in
commingled funds.
For financial reporting purposes, the regulated subsidiaries record the
difference between the amounts of pension cost recoverable in rates and the
amounts of pension cost determined by the actuary under SFAS 87, "Employers'
Accounting for Pensions," as deferred pension assets. The amounts deferred are
expected to be recovered in rates as contributions are made to the Plan. Pension
cost in 1997 and 1996 reflects the amount recovered from customers in rates
during the year. Under the PSC's policies, Distribution Corporation segregates
the amount of pension cost collected in rates, but not yet contributed to the
pension plan, into a regulatory liability account. This liability accrues
interest at the PSC mandated interest rate and this interest cost is included in
pension cost. For purposes of disclosure, the liability also remains in the
disclosed pension liability amount because it has not yet been contributed.
In June 1997, the Company completed an early retirement offer for the
Pennsylvania operating union employees of Distribution Corporation and Supply
Corporation. As a result, the Company recorded expense of $1.9 million ($1.2
million after tax) related to special termination benefits, which is included in
1997 pension cost.
In 1996, the Company had an early retirement offer for certain
salaried, non-union hourly and New York union employees of Distribution
Corporation and Supply Corporation. The Company recorded related expense in 1996
of $8.2 million ($5.2 million after-tax), comprised of special termination
benefits and severance pay. The special termination benefits portion of the
expense is included in 1996 pension cost.
The components of pension cost were as follows:
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Service Cost $ 9,988 $11,049 $ 9,680
Interest Cost 33,532 31,422 28,338
Actual Return on Plan Assets (65,791) (48,022) (47,591)
Net Amortization and Deferral 28,643 10,414 9,722
Special Termination Benefits 1,904 6,986 -
------- ------- -------
Pension Cost $ 8,276 $11,849 $ 149
======= ======= =======
The projected benefit obligation was determined using an assumed
discount rate of 7.75% for 1997, and 8% for 1996 and 1995. The effect of the
discount rate change in 1997 was to increase the projected benefit obligation by
$12.8 million. The assumed rate of compensation increase was 5% for all three
years. The expected long-term rate of return on Plan assets was 8.5% for all
three years.
A reconciliation of the Plan's funded status as determined by the
Company's consulting actuary is presented in the following table:
At September 30 (Thousands) 1997 1996
---- ----
Actuarial Present Value of:
Vested Benefit Obligation $341,859 $317,049
======== ========
Accumulated Benefit Obligation $394,605 $367,612
======== ========
Projected Benefit Obligation $462,377 $432,753
Plan Assets at Fair Value 473,205 431,828
-------- --------
Funded Status 10,828 (925)
Unrecognized Net Asset (22,296) (26,278)
Unrecognized Prior Service Cost 12,435 11,947
Unrecognized Net Gain (38,687) (15,111)
-------- --------
Pension Liability $(37,720) $(30,367)
========= ========
Other Post-Retirement Benefits
In addition to providing retirement plan benefits, the Company provides health
care and life insurance benefits for substantially all retired employees under a
post-retirement benefit plan (Post-Retirement Plan).
The Company has established Voluntary Employees' Beneficiary
Association (VEBA) trusts for collectively bargained employees and
non-bargaining employees. The VEBA trusts are similar to the Company's
Retirement Plan trust. Contributions to the VEBA trusts are tax deductible,
subject to limitations contained in the Internal Revenue Code and regulations.
Contributions to the VEBA trusts are made to fund employees' post-retirement
health care and life insurance benefits, as well as benefits as they are paid to
current retirees. Post-Retirement Plan assets primarily consist of equity and
fixed income investments and money market funds.
Distribution Corporation and Supply Corporation represent virtually all
of the Company's total post-retirement benefit costs. Distribution Corporation
and Supply Corporation are fully recovering their net periodic post-retirement
benefit costs in accordance with the PSC and the Pennsylvania Public Utility
Commission (PaPUC) and Federal Energy Regulatory Commission (FERC)
authorization, respectively. In accordance with regulatory guidelines, the
difference between the amounts of post-retirement benefit costs recoverable in
rates and the amounts of post-retirement benefit costs determined by the actuary
under SFAS 106, "Employers' Accounting for Post-retirement Benefits Other Than
Pensions," are deferred in each jurisdiction as either a regulatory asset or
liability, as appropriate. The PSC policy regarding amounts collected in rates,
but not contributed, described under the Retirement Plan section in this note,
also applies to other post-retirement benefits.
The Company has elected to amortize the initial accumulated liability
at October 1, 1993 to post-retirement benefit cost on a straight-line basis over
a 20-year period.
The components of post-retirement benefit cost were as follows:
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Service Cost $ 4,056 $ 3,926 $ 3,394
Interest Cost 16,594 14,391 13,027
Actual Return on Post-Retirement Plan Assets (13,618) (9,072) (4,613)
Net Amortization and Deferral 14,115 11,830 12,592
------- ------- -------
Post-Retirement Benefit Cost $21,147 $21,075 $24,400
======= ======= =======
The weighted average assumed discount rate used in determining the
accumulated post-retirement benefit obligation (APBO) was 7.75% for 1997, and 8%
for 1996 and 1995. The effect of the discount rate change in 1997 was to
increase the APBO by $7.0 million. The average assumed annual rate of salary
increase for the applicable life insurance plans was 5% for all three years. The
expected long-term rate of return on Post-Retirement Plan assets was 8.5% for
all three years.
The annual rate of increase in the per capita cost of covered medical
care benefits was assumed to be 12% for 1995, 11% for 1996 and 10% for 1997;
this rate was assumed to decrease gradually to 5.5% by the year 2003 and remain
at that level thereafter. The annual rate of increase for medical care benefits
provided by Healthcare Maintenance Organizations (HMO) was assumed to be 7.5% in
1998 and gradually decline to 5.5% by the year 2003 and remain level thereafter.
The annual rate of increase in the per capita cost of covered prescription drug
benefits was assumed to be 10% for 1995 and 1996, and 8.5% for 1997. This rate
was assumed to decrease gradually to 5.5% by the year 2003 and remain level
thereafter. The annual rate increase in the per capita Medicare Part B
Reimbursement was assumed to be 12.2% for 1995, 12% for 1996 and 3.1% for 1997.
This rate was assumed to be 9% for 1998 and decrease gradually to 5.5% by the
year 2003 and remain level thereafter. These trend assumptions reflect various
changes made for fiscal 1998, the impact of the changes was to increase the APBO
by $6.9 million. Medicare Risk HMO's for retirees over age 65 were introduced by
the HMO providers serving the Company. The effect of this plan amendment was to
reduce the APBO by $10.3 million. Since no unrecognized prior service cost
exists, this plan amendment was used to reduce the unrecognized transition
obligation as of September 30, 1997.
A reconciliation of the Post-Retirement Plan's funded status as
determined by the Company's consulting actuary is in the following table:
At September 30 (Thousands) 1997 1996
---- ----
Accumulated Post-Retirement Benefit Obligation:
Inactives $118,465 $111,970
Actives Fully Eligible 26,528 25,363
Actives Not Yet Fully Eligible 73,377 74,715
-------- --------
218,370 212,048
Fair Value of Post-Retirement Plan Assets 98,639 73,059
-------- --------
Funded Status (119,731) (138,989)
Unrecognized Transition Obligation 114,034 132,055
Unrecognized Net Loss 505 4,510
-------- --------
Post-Retirement Liability $ (5,192) $ (2,424)
========= ========
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 APBO as of October 1, 1996, would be increased by $31.0 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 1997
by $3.5 million.
Note H - Commitments and Contingencies
Leases
System companies have entered into lease agreements, principally for the use of
office space, business machines, transportation equipment and meters. The
Company's policy is to treat all leases as operating leases for both accounting
and ratemaking purposes. While certain of these leases are capital leases, had
they been capitalized, the effect on results of operations and financial
position would not be material. Total lease expense approximated $16.0 million
in 1997, $16.9 million in 1996 and $16.3 million in 1995. At September 30, 1997,
the future minimum payments under the Company's lease agreements for the next
five years are: $11.7 million in 1998, $8.4 million in 1999, $6.6 million in
2000, $5.2 million in 2001 and $4.1 million in 2002. The aggregate future
minimum lease payments attributable to later years is $12.4 million.
Environmental Matters
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for the on-going evaluation of its operations to identify potential
environmental exposures and assure compliance with regulatory policies and
procedures.
Distribution Corporation has incurred and is incurring clean-up costs
at several former manufactured gas plant sites in New York and Pennsylvania.
Distribution Corporation has been designated by the New York Department of
Environmental Conservation (DEC) as a potentially responsible party (PRP) with
respect to one of these sites in New York, and is also engaged in litigation
with the DEC and the party who bought the site from Distribution Corporation's
predecessor.
Distribution Corporation recently received an informal inquiry from a
DEC staff member as to whether Distribution Corporation or a predecessor had
used a former manufactured gas plant site in New York in a way that could
account for a complaint the DEC received from a neighboring landowner.
Distribution Corporation has begun an investigation at that site but has not
incurred any clean-up costs nor has it been able to reasonably estimate the
probability or extent of potential liability.
Distribution Corporation is also 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 several 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 with
respect to the remediation of these sites will depend on such factors as the
remediation plan selected, the extent of the site contamination, the number of
additional PRPs at each site and the portion, if any, attributed to Distribution
Corporation.
It is the Company's policy to accrue estimated environmental clean-up
costs when such amounts can reasonably be estimated and it is probable that the
Company will be required to incur such costs. Distribution Corporation has
estimated that clean-up costs related to the above noted sites are in the range
of $9.3 million to $9.9 million. At September 30, 1997, Distribution Corporation
has recorded the minimum liability of $9.3 million. 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.
In New York and Pennsylvania, Distribution Corporation is recovering
site investigation and remediation costs in rates. Accordingly, the Consolidated
Balance Sheet at September 30, 1997, includes related regulatory assets in the
amount of approximately $8.7 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 80% 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.
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 includes operations which are rate-regulated (regulated) and
operations which are not regulated as to their rates (nonregulated). The
regulated operations fall primarily within two business segments: Utility and
Pipeline and Storage. The nonregulated operations consist principally of the
Exploration and Production business segment. The Other Nonregulated segment
consists primarily of the Company's sawmill and dry kiln operations, natural gas
marketing operations, natural gas hub operations, investment in foreign energy
projects and pipeline construction operations (which were discontinued during
1995, the effect of which was immaterial to the Company).
The Utility segment is regulated by the PSC and the PaPUC and is
carried out by Distribution Corporation. Distribution Corporation sells and
transports gas to retail customers located in western New York and northwestern
Pennsylvania. It also provides off-system sales to customers located in regions
through which the upstream pipelines serving Distribution Corporation pass
(i.e., from the southwestern to northeastern regions of the United States). The
Pipeline and Storage segment is regulated by the FERC and is carried out by
Supply Corporation and SIP. Supply Corporation transports and stores natural gas
for utilities and pipeline companies in the northeastern United States markets.
In 1997, 1996 and 1995, 52%, 51% and 48%,
respectively, of Supply Corporation's revenue was from affiliated companies,
mainly Distribution Corporation. SIP has agreed to purchase, upon receipt of
regulatory approval, a one-third general partnership interest in Independence
Pipeline Company.
Seneca is engaged in exploration for, and development and purchase of,
oil and natural gas reserves in the Gulf Coast areas of Texas, Louisiana, and
Alabama, and in California, Wyoming, and 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. Highland operates two sawmills and one dry kiln
operation in Pennsylvania. NFR is engaged in the marketing and brokerage of
natural gas and electricity and performs energy management services for
utilities and end-users in the northeastern United States markets. Leidy's
activities center around its investment in natural gas hub operations, providing
services to customers in the northeastern, mid-Atlantic, Chicago and Los Angeles
areas of the United States and Ontario, Canada. Horizon is engaged in the
investigation and development of foreign and domestic energy projects. Horizon
has an equity interest in SCT, a company with district heating and power
generation operations located in the northern part of the Czech Republic. It
also owns and operates an additional district heating plant and a power
development group in the Czech Republic. NET was formed in July 1997 to engage
in wholesale natural gas trading and other energy-related activities. NIM was
formed in September 1997 to own a one-third general partnership interest in
DirectLink Gas Marketing Company, which will engage in natural gas marketing and
related business. UCI was engaged in the Company's pipeline construction
operations prior to the discontinuance of its business in the third quarter of
fiscal 1995.
The data presented in the tables below reflect the Company's regulated
and nonregulated business segments for the three years ended September 30, 1997.
Total operating revenues by segment include both revenues from nonaffiliated
customers and intersegment revenues. Operating income is total operating
revenues less operating expenses, not including income taxes. The elimination of
significant intercompany balances and transactions, if appropriate, is made in
order to reconcile segment information with consolidated amounts. Identifiable
assets of a segment are those assets that are used in the operations of that
segment. Corporate assets are principally cash and temporary cash investments,
receivables, deferred charges and cash surrender values of insurance contracts.
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Operating Revenues
Regulated:
Utility $ 991,366 $ 954,326 $786,064
Pipeline and Storage 172,694 176,553 164,587
---------- ---------- --------
1,164,060 1,130,879 950,651
---------- ---------- --------
Nonregulated:
Exploration and Production 119,260 114,462 56,232
Other 83,915 68,930 57,075
---------- ---------- --------
203,175 183,392 113,307
---------- ---------- --------
Intersegment Revenues* (101,423) (106,254) (88,462)
---------- ---------- --------
$1,265,812 $1,208,017 $975,496
========== ========== ========
* Represents primarily Pipeline and Storage revenue from the Utility segment.
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Operating Income (Loss) Before
Income Taxes
Regulated:
Utility $123,856 $115,257 $ 83,774
Pipeline and Storage 73,523 72,914 67,884
-------- -------- --------
197,379 188,171 151,658
-------- -------- --------
Nonregulated:
Exploration and Production 42,694 46,408 16,404
Other (743) (8,581) 3,021
-------- -------- --------
41,951 37,827 19,425
-------- -------- --------
Corporate (2,353) (2,231) (2,805)
-------- -------- --------
$236,977 $223,767 $168,278
======== ======== ========
Identifiable Assets
At September 30 (Thousands)
Regulated:
Utility $1,163,702 $1,154,364 $1,098,757
Pipeline and Storage 510,109 515,569 512,546
---------- ---------- ----------
1,673,811 1,669,933 1,611,303
---------- ---------- ----------
Nonregulated:
Exploration and Production 466,208 396,077 351,262
Other 75,187 38,955 33,734
---------- ---------- ----------
541,395 435,032 384,996
---------- ---------- ----------
Corporate 52,125 44,807 40,524
---------- ---------- ----------
$2,267,331 $2,149,772 $2,036,823
========== ========== ==========
Year Ended September 30 (Thousands)
Depreciation, Depletion and Amortization
Regulated:
Utility $32,972 $31,491 $30,052
Pipeline and Storage 21,459 19,942 19,320
------- ------ -------
54,431 51,433 49,372
------- ------- -------
Nonregulated:
Exploration and Production 51,117 46,042 21,201
Other 6,099 752 1,203
------- ------- -------
57,216 46,794 22,404
------- ------- -------
Corporate 3 4 6
------- ------- -------
$111,650 $98,231 $71,782
======== ======= =======
Capital Expenditures
Regulated:
Utility $ 66,908 $ 63,730 $ 64,844
Pipeline and Storage 22,562 22,260 38,678
-------- -------- --------
89,470 85,990 103,522
-------- -------- --------
Nonregulated:
Exploration and Production 120,282 83,554 69,741
Other 16,558 3,189 9,563
-------- -------- --------
136,840 86,743 79,304
-------- -------- --------
Intersegment Elimination - (1,166) -
-------- -------- --------
$226,310 $171,567 $182,826
======== ======== ========
Note J - 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. Earnings per common share are calculated using the weighted average
number of shares outstanding during each quarter. The total of all quarters may
differ from the earnings per common share shown on the Consolidated Statement of
Income, which is 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.
Financial data for the quarter ended September 30, 1997 reflects an
after tax charge of $2.0 million, or $0.05 per share, related to an estimated
cumulative refund provision to Distribution Corporation's customers, for a 50%
sharing of earnings over a predetermined amount in accordance with Distribution
Corporation's New York rate settlement of July 1996.
Financial data for the quarter ended September 30, 1996 reflects the
after-tax net benefit of gas cost reconciliation adjustments of $2.7 million or
$0.07 per share,and the reversal of estimated lost and unaccounted-for gas
accrued in prior quarters of 1996 of $4.6 million, after-tax, or $0.12 per
share. These items were offset by an after-tax charge to earnings of $5.2
million, or $0.14 per share, related to an early retirement offer to certain
salaried, non-union hourly and union employees of Distribution Corporation and
Supply Corporation. In addition, Horizon recognized a fourth quarter after-tax
charge to earnings of $3.8 million, or $0.10 per share, related to its decision
to withdraw from participation in the development of a 151 megawatt power plant
near Kabirwala, Punjab Province, in east-central Pakistan.
Net Income Earnings
(Loss) (Loss)
Available for Per
Quarter Operating Operating Common Common
Ended Revenues Income Stock Share
- ------- --------- --------- ------------- --------
1997 (Thousands, except earnings per common share)
- ------------------------------------------------------------------------
12/31/96 $363,492 $52,153 $38,590 $1.02
3/31/97 $498,704 $70,812 $57,109 $1.50
6/30/97 $246,051 $31,283 $18,905 $ .50
9/30/97 $157,565 $14,055 $ 84 $ -
1996 (Thousands, except earnings per common share)
- ------------------------------------------------------------------------
12/31/95 $316,328 $46,344 $32,392 $ .87
3/31/96 $492,376 $69,631 $55,692 $1.48
6/30/96 $239,330 $29,687 $17,310 $ .46
9/30/96 $159,983 $11,784 $ (723) $(.02)
Note K - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 1997, there were 20,267 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, 1997 and 1996, are
shown below:
Price Range Dividends
Quarter Ended High Low Declared
- ------------- ---- --- ---------
1997
----
12/31/96 $44-1/8 $36-5/8 $.42
3/31/97 $44-7/8 $39-3/8 $.42
6/30/97 $44-1/8 $40-5/8 $.435
9/30/97 $45-7/16 $40-1/8 $.435
1996
----
12/31/95 $33-7/8 $28-1/2 $.405
3/31/96 $34-7/8 $31-3/8 $.405
6/30/96 $36-3/8 $33-3/4 $.42
9/30/96 $38 $33-3/8 $.42
Note L - 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) 1997 1996
---- ----
Capitalized Costs Subject to Amortization $658,327 $570,815
Capitalized Acquisition Costs Excluded
from Amortization 64,597 35,627
-------- --------
722,924 606,442
Less - Accumulated Depreciation, Depletion
and Amortization 284,429 233,743
-------- --------
$438,495 $372,699
======== ========
Certain costs excluded from amortization represent unevaluated
properties that require additional drilling to determine the existence of oil
and gas reserves. The remaining costs, incurred during and prior to 1997,
consist of individually insignificant oil and gas leases still early in their
primary terms and individually insignificant unproved perpetual oil and gas
rights.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Property Acquisition Costs:
Proved $ 4,154 $ 4,632 $13,186
Unproved 23,120 12,879 12,119
Exploration Costs 76,703 33,191 18,588
Development Costs 15,583 32,747 25,161
Other - 230 559
-------- ------- -------
$119,560 $83,679 $69,613
======== ======= =======
Results of Operations for Producing Activities
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Operating Revenues:
Natural Gas (includes revenues from sales
to affiliates of $10,682, $11,872 and
$8,650, respectively) $100,411 $ 91,018 $ 34,849
Oil, Condensate and Other Liquids 39,237 33,978 11,948
-------- -------- -------
Total Operating Revenues* 139,648 124,996 46,797
Production/Lifting Costs 17,335 15,196 11,215
Depreciation, Depletion and Amortization
($0.36, $0.36 and $0.44, respectively, per
dollar of operating revenues) 50,687 45,502 20,528
Income Tax Expense 24,699 22,069 4,301
-------- -------- --------
Results of Operations for Producing
Activities (excluding corporate overheads
and interest charges) $ 46,927 $ 42,229 $ 10,753
======== ======== ========
*Exclusive of hedging gains and losses. See further discussion in Note F -
Financial Instruments.
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 Oil
Year Ended MMcf Mbbl
---------------------- ---------------------
September 30 1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
Proved Developed and
Undeveloped Reserves:
Beginning of Year 207,082 221,459 247,447 25,749 22,865 17,495
Extensions and
Discoveries 47,951 29,161 9,912 359 5,701 3,863
Revisions of
Previous Estimates 20,820 (3,442) (21,046) (6,224) (1,173) (60)
Production (38,586) (38,767) (20,942) (1,902) (1,742) (739)
Sales of Minerals in
Place (5,464) (1,532) (4,685) (1) (27) (474)
Purchases of Minerals
in Place and Other 646 203 10,773 - 125 2,780
------- ------- ------- ------ ------ ------
End of Year 232,449 207,082 221,459 17,981 25,749 22,865
======= ======= ======= ====== ====== ======
Proved Developed Reserves:
Beginning of Year 163,537 162,504 179,291 14,043 14,937 10,110
======= ======= ======= ====== ====== ======
End of Year 194,454 163,537 162,504 11,354 14,043 14,937
======= ======= ======= ====== ====== ======
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) 1997 1996 1995
---- ---- ----
Future Cash Inflows $1,072,375 $1,003,280 $738,711
Less:
Future Production and Development Costs 252,205 294,778 272,268
Future Income Tax Expense at
Applicable Statutory Rate 257,172 221,956 129,055
---------- ---------- -------
Future Net Cash Flows 562,998 486,546 337,388
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 179,798 157,302 92,120
---------- ---------- --------
Standardized Measure of Discounted Future
Net Cash Flows $ 383,200 $ 329,244 $245,268
========== ========== ========
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $329,244 $245,268 $215,266
Sales, Net of Production Costs (122,313) (109,801) (35,582)
Net Changes in Prices, Net of
Production Costs 78,499 147,330 10,757
Purchases of Minerals in Place 1,138 770 18,602
Sales of Minerals in Place (9,632) (1,141) (5,688)
Extensions and Discoveries 88,228 93,864 47,236
Changes in Estimated Future
Development Costs (20,785) (53,630) (50,366)
Previously Estimated Development
Costs Incurred 43,731 42,780 39,833
Net Change in Income Taxes at
Applicable Statutory Rate (24,797) (52,613) (6,838)
Revisions of Previous Quantity
Estimates (27,317) (15,491) (20,934)
Accretion of Discount and Other 47,204 31,908 32,982
-------- -------- --------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $383,200 $329,244 $245,268
======== ======== ========
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
Schedule II - Valuation and Qualifying Accounts
(Thousands)
---------
Additions
----------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other Deductions End of
Description of Period Expenses Accounts (Note) Period
- ----------- ---------- ---------- ---------- ---------- ----------
Year Ended September 30, 1997
- -----------------------------
Reserve for Doubtful
Accounts $7,672 $16,586 $ - $15,967 $8,291
====== ======= ====== ======= ======
Year Ended September 30, 1996
- -----------------------------
Reserve for Doubtful
Accounts $5,924 $15,191 $ - $13,443 $7,672
====== ======= ====== ======= ======
Year Ended September 30, 1995
- -----------------------------
Reserve for Doubtful
Accounts $5,055 $15,187 $ - $14,318 $5,924
====== ======= ====== ======= ======
Note - 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 26, 1998 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after September 30, 1997. The
information provided in such definitive Proxy Statement 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 26,
1998 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1997. The information provided in such definitive
Proxy Statement 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 26,
1998 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1997. The information provided in such definitive
Proxy Statement is incorporated herein by reference.
ITEM 13 Certain Relationships and Related Transactions
At September 30, 1997, 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:
* Restated Certificate of Incorporation of National Fuel
Gas Company, dated March 15, 1985 (Exhibit 10-OO, Form
10-K for fiscal year ended September 30, 1991 in File
No. 1-3880)
* Certificate of Amendment of Restated Certificate of
Incorporation of National Fuel Gas Company, dated March
9, 1987 (Exhibit 3.1, Form 10-K for fiscal year ended
September 30, 1995 in File No. 1-3880)
* Certificate of Amendment of Restated Certificate of
Incorporation of National Fuel Gas Company, dated
February 22, 1988 (Exhibit 3.2, Form 10-K for fiscal
year ended September 30, 1995 in File No. 1-3880)
* Certificate of Amendment of Restated Certificate of
Incorporation, dated March 17, 1992 (Exhibit EX-3(a),
Form 10-K for fiscal year ended September 30, 1992 in
File No. 1-3880)
3(ii) By-Laws:
3.1 National Fuel Gas Company By-Laws as amended through
September 18, 1997
(4) Instruments Defining the Rights of Security Holders,
Including Indentures:
* Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 2(b) in File No. 2-51796)
* Third Supplemental Indenture dated as of December 1,
1982, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4(a)(4) in File No.
33-49401)
* Tenth Supplemental Indenture dated as of February 1,
1992, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4(a), Form 8-K dated
February 14, 1992 in File No. 1-3880)
* Eleventh Supplemental Indenture dated as of May 1,
1992, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4(b), Form 8-K dated
February 14, 1992 in File No. 1-3880)
* Twelfth Supplemental Indenture dated as of June 1,
1992, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4(c), Form 8-K dated
June 18, 1992 in File No. 1-3880)
* Thirteenth Supplemental Indenture dated as of March 1,
1993, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4(a)(14) in File No.
33-49401)
* Fourteenth Supplemental Indenture dated as of July 1,
1993, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4.1, Form 10-K for
fiscal year ended September 30, 1993 in File No.
1-3880)
* Fifteenth Supplemental Indenture dated as of September
1, 1996 to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York (formerly
Irving Trust Company) (Exhibit 4.1, Form 10-K for
fiscal year ended September 30, 1996 in File No.
1-3880)
* Rights Agreement between National Fuel Gas Company and
Marine Midland Bank dated June 12, 1996 (Exhibit 99.1,
Form 8-K dated June 13, 1996 in File No. 1-3880)
(10) Material Contracts:
(ii) (B) Contracts upon which Registrant's business is
substantially dependent:
* 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)
* 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)
* 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)
* 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)
* Service Agreement with 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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)
* 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:
* 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)
* Ninth Extension to Employment Agreement with Bernard J.
Kennedy, dated September 19, 1996 (Exhibit 10.6, Form
10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
* National Fuel Gas Company 1983 Incentive Stock Option
Plan, as amended and restated through February 18, 1993
(Exhibit 10.2, Form 10-Q for the quarterly period ended
March 31, 1993 in File No. 1-3880)
* National Fuel Gas Company 1984 Stock Plan, as amended
and restated through February 18, 1993 (Exhibit 10.3,
Form 10-Q for the quarterly period ended March 31, 1993
in File No. 1-3880)
* Amendment to the National Fuel Gas Company 1984 Stock
Plan, dated December 11, 1996 (Exhibit 10.7, Form 10-K
for fiscal year ended September 30, 1996 in File No.
1-3880)
* National Fuel Gas Company 1993 Award and Option Plan,
dated February 18, 1993 (Exhibit 10.1, Form 10-Q for
the quarterly period ended March 31, 1993 in File No.
1-3880)
* Amendment to National Fuel Gas Company 1993 Award and
Option Plan, dated December 18, 1996 (Exhibit 10, Form
10-Q for the quarterly period ended December 31, 1996
in File No. 1-3880)
* Amendment to National Fuel Gas Company 1993 Award and
Option Plan, dated December 11, 1996 (Exhibit 10.8,
Form 10-K for fiscal year ended September 30, 1996 in
File No. 1-3880)
* Amendment to National Fuel Gas Company 1993 Award and
Option Plan, dated October 27, 1995 (Exhibit 10.8, Form
10-K for fiscal year ended September 30, 1995 in File
No. 1-3880)
* 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)
* Change in Control Agreement, dated May 1, 1992, with
Philip C. Ackerman (Exhibit EX-10.4, Form 10-K for
fiscal year ended September 30, 1992 in File No.
1-3880)
* Change in Control Agreement, dated May 1, 1992, with
Richard Hare (Exhibit EX-10.5, Form 10-K for fiscal
year ended September 30, 1992 in File No. 1-3880)
* 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)
10.1 Agreement dated August 1, 1986, with Joseph P.
Pawlowski
10.2 Agreement dated August 1, 1986, with Gerald T. Wehrlin
* National Fuel Gas Company Deferred Compensation Plan,
as amended and restated through May 1, 1994 (Exhibit
10.7, Form 10-K for fiscal year ended September 30,
1994 in File No. 1-3880)
* Amendment to 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)
* Amendment to National Fuel Gas Company Deferred
Compensation Plan, dated September 27, 1995 (Exhibit
10.9, Form 10-K for fiscal year ended September 30,
1995 in File No. 1-3880)
10.3 National Fuel Gas Company Deferred Compensation Plan,
as amended and restated through March 20, 1997
10.4 Amendment to National Fuel Gas Company Deferred
Compensation Plan dated June 16, 1997
* 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)
* 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)
* 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)
10.5 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 17, 1997 with Philip
C. Ackerman
10.6 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Richard
Hare
10.7 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Joseph
P. Pawlowski
10.8 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Gerald
T. Wehrlin
* National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan as amended and
restated through November 1, 1995 (Exhibit 10.10, Form
10-K for fiscal year ended September 30, 1995 in File
No. 1-3880)
* National Fuel Gas Company and Participating
Subsidiaries 1996 Executive Retirement Plan Trust
Agreement (II) dated May 10, 1996 (Exhibit 10.13, Form
10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
10.9 Amendments to National Fuel Gas Company and
Participating Subsidiaries Executive Retirement Plan
dated September 18, 1997
* Summary of Annual at Risk Compensation Incentive
Program (Exhibit 10.10, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
* Administrative Rules with Respect to at Risk Awards
under the 1993 Award and Option Plan (Exhibit 10.14,
Form 10-K for fiscal year ended September 30, 1996 in
File No. 1-3880)
* Administrative Rules of the Compensation Committee of
the Board of Directors of National Fuel Gas Company as
amended through December 11, 1996 (Exhibit 10.15, Form
10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
* Excerpts of Minutes from the National Fuel Gas Company
Board of Directors Meeting of December 5, 1991
regarding change in control agreements, non-employee
director retirement plan, and restrictions on
restricted stock (Exhibit 10-UU, Form 10-K for fiscal
year ended September 30, 1991 in File No. 1-3880)
* Excerpts from Minutes from the National Fuel Gas
Company Board of Directors Meeting of September 19,
1996 regarding compensation of non-employee directors
and related amendments of By-Laws (Exhibit 3.1, Form
10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
10.10 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
10.11 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
* Form of Change in Control Agreement, dated May 1, 1992,
with Walter E. DeForest, Bruce H. Hale, Joseph P.
Pawlowski, Dennis J. Seeley, David F. Smith and Gerald
T. Wehrlin, and dated March 16, 1995, with James A.
Beck (Exhibit 10.16, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Letter to Shareholders as contained in the 1997 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 and Counsel:
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
(27) Financial Data Schedules
(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.
* 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, President
Date: December 11, 1997 and Chief Executive Officer
-------------------
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title
--------- -----
/s/ B. J. Kennedy
------------------------- Chairman of the Board,
B. J. Kennedy President, Chief Executive
Officer and Director
Date: December 11, 1997
-----------------
/s/ P. C. Ackerman
------------------------- Senior Vice President, Principal
P. C. Ackerman Financial Officer and Director
Date: December 11, 1997
-----------------
/s/ R. T. Brady
------------------------- Director
R. T. Brady
Date: December 11, 1997
-----------------
/s/ W. J. Hill
------------------------- Director
W. J. Hill
Date: December 11, 1997
-----------------
/s/ B. S. Lee
------------------------- Director
B. S. Lee
Date: December 11, 1997
-----------------
/s/ E. T. Mann
------------------------- Director
E. T. Mann
Date: December 11, 1997
-----------------
/s/ G. L. Mazanec
------------------------- Director
G. L. Mazanec
Date: December 11, 1997
-----------------
/s/ G. H. Schofield
------------------------- Director
G. H. Schofield
Date: December 11, 1997
-----------------
/s/ J. P. Pawlowski
------------------------- Treasurer and Principal
J. P. Pawlowski Accounting Officer
Date: December 11, 1997
-----------------
/s/ A. M. Cellino
------------------------- Secretary
A. M. Cellino
Date: December 11, 1997
-----------------
/s/ G. T. Wehrlin
------------------------- Controller
G. T. Wehrlin
Date: December 11, 1997
-----------------
APPENDIX TO ITEM 2 - PROPERTIES
Four maps outlining the Company's operating areas at September 30, 1997
are included on pages 1 and 2 of the paper format version of the Company's
combined Annual Report to Shareholders/Form 10-K. The first map identifies
the Company's Pipeline and Storage operating area (i.e., Supply
Corporation's storage areas and pipelines). The second map identifies the
Company's Utility Operating area (i.e., Distribution Corporation's service
area). The third map identifies the Company's Exploration and Production
operating area (i.e., Seneca Resources' operating area). The fourth map
identifies the geographic location of the Company's Other Nonregulated
operating areas (i.e., NFR's marketing offices, Horizon's Czech Republic
operations and Highland's sawmill operations).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 1997
Two pie graphs detailing the revenue dollar in 1997: where it came from
and where it went to, broken down as follows:
Where it came from:
$ .560 Residential Sales
.184 Commercial, Industrial and Off-System Sales
.101 Oil and Gas Revenues
.065 Transportation Revenues
.055 Marketing Revenues
.029 Storage Service Revenues
.006 Other Revenues
$1.000 Total
Where it went to:
$ .417 Gas Purchased
.141 Wages, Including Benefits
.133 Taxes
.088 Depreciation
.086 Other Materials and Services
.051 Dividends - Common Stock
.045 Interest
.039 Reinvested in the Business
$1.000 Total
B. Capital Expenditures
A bar graph detailing capital expenditures (millions of dollars) for the
years 1993 through 1997, broken down as follows:
1993 1994 1995 1996 1997
---- ---- ---- ---- ----
Other Nonregulated $ 6.2 $ 3.6 $ 9.6 $ 3.2 $ 16.5
Pipeline and Storage 27.4 20.5 38.7 22.2 22.6
Utility 61.8 61.7 64.8 62.6 66.9
Exploration and Production 36.5 52.5 69.7 83.6 120.3
------ ------ ------ ------ ------
$131.9 $138.3 $182.8 $171.6 $226.3
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS (Concluded)
C. Capitalization Ratios
A bar graph detailing capitalization (percentage) for the years 1993
through 1997, broken down as follows:
Debt (%) Equity (%)
1993 47.8 52.2
1994 46.2 53.8
1995 47.0 53.0
1996 47.5 52.5
1997 46.0 54.0
D. Book Value Per Common Share
A bar graph detailing book value per common share (dollars) for the years
1993 through 1997, as follows:
1993 - 20.08
1994 - 20.93
1995 - 21.39
1996 - 22.61
1997 - 23.94
Exhibit Index
3.1 National Fuel Gas Company By-Laws as amended through
September 18, 1997
10.1 Agreement dated August 1, 1986, with Joseph P. Pawlowski
10.2 Agreement dated August 1, 1986, with Gerald T. Wehrlin
10.3 National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through March 20, 1997
10.4 Amendment to National Fuel Gas Company Deferred Compensation
Plan dated June 16, 1997
10.5 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 17, 1997 with Philip C.
Ackerman
10.6 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Richard Hare
10.7 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Joseph P.
Pawlowski
10.8 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Gerald T.
Wehrlin
10.9 Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan dated September 18,
1997
10.10 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
10.11 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
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Letter to Shareholders as contained in the 1997 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) Financial Data Schedule for 12 months ending September 30,
1997
99.1 Report of Ralph E. Davis Associates, Inc.