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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, 1995
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 New York Stock Exchange
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 $1,164,782,000 as of November 30, 1995.
Common stock, $1 par value, outstanding as of November 30, 1995:
37,437,663 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Annual Report to Shareholders for 1995 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 15, 1996 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, 1995
TABLE OF CONTENTS
Page
PART I
ITEM 1. BUSINESS
THE COMPANY AND ITS SUBSIDIARIES 1
RATES AND REGULATION 2
THE UTILITY OPERATION 3
THE PIPELINE AND STORAGE SEGMENT 3
THE EXPLORATION AND PRODUCTION SEGMENT 3
OTHER NONREGULATED OPERATIONS 4
SOURCES AND AVAILABILITY OF RAW MATERIALS 4
COMPETITION 5
SEASONALITY 7
CAPITAL EXPENDITURES 7
ENVIRONMENTAL MATTERS 7
MISCELLANEOUS 8
EXECUTIVE OFFICERS OF THE COMPANY 8
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES 9
EXPLORATION AND PRODUCTION ACTIVITIES 9
ITEM 3. LEGAL PROCEEDINGS
PARAGON/TGX PROCEEDINGS 10
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 12
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
SHAREHOLDER MATTERS 12
ITEM 6. SELECTED FINANCIAL DATA 13
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 14
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 28
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 59
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 59
ITEM 11. EXECUTIVE COMPENSATION 59
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT 60
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 60
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K 60
SIGNATURES 65
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 Operation 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. 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.
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 and Louisiana, in California and in the
Appalachian region of the United States.
Other Nonregulated operations are carried out by the following
subsidiaries:
* National Fuel Resources, Inc. (NFR), a New York corporation engaged in
the marketing and brokerage of natural gas and the performance of energy
management services for utilities and end-users located in the northeastern
United States;
* 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. (a
Delaware limited liability company which in turn owns 50% of QuickTrade, L.L.C.,
another Delaware limited liability company);
* 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 Sceptre Power
Company, a partnership which includes a team with considerable experience in
developing such energy projects;
* 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;
* 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 industry 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 1995. 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
under the headings "Exploration and Production and Other Nonregulated
Activities," "Utility Operation," and "Pipeline and Storage," which are included
in the paper copy of the Company's combined Annual Report to Shareholders/Form
10-K, are included in this electronic filing as Exhibit 13 and 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 to Congress the conditional repeal of
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. The effect of these changes if implemented, combined with other
recent SEC rule changes, would be to significantly reduce the number of
applications filed under the Holding Company Act, exempt routine financings and
expand diversification opportunities. 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. The Company is
unable to predict at this time what type of regulatory changes, if any, may
result from this proposal, and therefore what the impact on the Company might
be.
The Utility Operation'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 Operation'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). 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.
This report occasionally refers collectively to the Utility
Operation and the Pipeline and Storage segment as the Regulated Operations.
In addition, the Company is subject to the same federal, state and
local regulations on various subjects as other companies doing business in the
same locations.
The Company's operations other than Supply Corporation and Distribution
Corporation 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 operations as the Nonregulated Operations.
The Utility Operation
The Utility Operation contributed approximately 50% of the Company's operating
income before income taxes in 1995.
Additional discussion of the Utility Operation industry segment
appears in the forepart of the paper copy of the Company's combined Annual
Report to Shareholders/Form 10-K under the heading "Utility Operation," which is
included in this electronic filing as Exhibit 13, below under the headings
"Sources and Availability of Raw Materials" and "Competition," in Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" (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 40% of the Company's
operating income before income taxes in 1995.
The Pipeline and Storage segment currently has service agreements
for substantially all of its firm transportation capacity, which totals
approximately 1,860 million cubic feet (MMcf) per day. The Utility Operation has
contracted for approximately 1,120 MMcf per day or 60% of that capacity until
2003 and continuing year-to-year thereafter.
The Pipeline and Storage segment has available for sale to
customers approximately 60.8 billion cubic feet (Bcf) of firm storage capacity.
The Utility Operation has contracted for 25.3 Bcf or 42% of that capacity, in
service agreements with initial terms of approximately 10 years and continuing
year-to-year thereafter, effective beginning in 1993 (23.3 Bcf) and 1996 (2.0
Bcf). Nonaffiliated customers were contracted for 35.5 Bcf of storage capacity
throughout 1995.
The primary terms of current storage service agreements,
representing 23.3 Bcf of the firm storage capacity contracted for by
nonaffiliated customers, expired in 1995. Service continues year-to-year and can
be terminated by the customer on one year's notice. Six such customers have
given notice of termination or reduction effective March 31, 1996, accounting
for a reduction of 4.2 Bcf of contracted firm storage capacity at that time. The
Pipeline and Storage segment is actively marketing this available capacity.
Additional discussion of the Pipeline and Storage segment appears in the
forepart of the paper copy of the Company's combined Annual Report to
Shareholders/Form 10-K under the heading "Pipeline and Storage," which is
included in this electronic filing as Exhibit 13, below under the headings
"Sources and Availability of Raw Materials," "Competition" and "Environmental
Matters," Item 7 "MD&A," and Item 8 at Notes B-Regulatory Matters, H-Commitments
and Contingencies and I-Business Segment Information.
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 10% of the
Company's operating income before income taxes in 1995.
Additional discussion of the Exploration and Production segment appears
in the forepart of the paper copy of the Company's combined Annual Report to
Shareholders/Form 10-K under the heading "Exploration and Production and Other
Nonregulated Activities," which is included in this electronic filing as Exhibit
13, 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.
Other Nonregulated Operations
Other Nonregulated operations contributed approximately 2% of the Company's
operating income before income taxes in 1995. Corporate operations reduced the
Company's operating income before income taxes by approximately 2%.
Horizon was formed in 1995 to engage in foreign and domestic energy
projects, including foreign utility companies and exempt wholesale generators of
electricity. The SEC in 1995 authorized the Company (through Horizon and
intermediate companies) to (i) invest up to an aggregate of $150.0 million
through December 2001 in such activities, and (ii) issue debt and equity,
provide guarantees and assume liabilities up to that amount in order to finance
such activities. The Company contributed $1.0 million in capital to Horizon in
1995. Horizon was at year-end 1995 considering investment opportunities in
eastern Europe, South America and Asia, and is the controlling partner in
Sceptre Power Company, a partnership which includes a team with considerable
experience in developing such energy projects.
NFR is seeking to add the brokering of electric power to its
existing gas marketing business. In 1995, NFR obtained authorization from the
FERC to become an electric power broker in connection with the FERC's announced
restructuring of the electric power industry. NFR's application for
authorization from the SEC to engage in such activities was pending at year-end
1995.
Leidy recognized a loss of less than $1.0 million in 1995 from
writing off Leidy's equity investment in Metscan, Inc., a developer of
electronic gas meter reading devices, which ceased operations and liquidated.
Leidy's business now consists exclusively of activities related to natural gas
hubs as described below.
The SEC in 1995 authorized Leidy to enter into a transaction (which
was consummated in October 1995) by which Leidy invested less than $1.0 million
to acquire a 14.5% ownership interest in Enerchange, L.L.C. (Enerchange). This
investment effectively gave Leidy (i) a somewhat larger portion of the profits
or losses of Ellisburg-Leidy Northeast Hub Company, (ii) a portion of the
profits or losses of natural gas hubs in Chicago and Los Angeles, (iii) 14.5% of
Enerchange's profits or losses in buying and selling gas at all three market
hubs, and (iv) 14.5% of Enerchange's profits or losses as a 50% owner of
QuickTrade, L.L.C., which is developing an on-line computer service on which
subscribers will buy and sell gas at hubs and obtain related services.
Additional discussion of the Other Nonregulated operations appears in
the forepart of the paper copy of the Company's combined Annual Report to
Shareholders/Form 10-K under the heading "Exploration and Production and Other
Nonregulated Activities," subheading "Other Nonregulated Activities," which is
included in this electronic filing as Exhibit 13, below under the headings
"Sources and Availability of Raw Materials" and "Competition," Item 7 "MD&A,"
and Item 8 at Note I-Business Segment Information.
Sources and Availability of Raw Materials
Natural gas is the principal raw material for the Utility Operation and some of
the Other Nonregulated operations, as discussed below. The Pipeline and Storage
segment transports and stores gas owned by its customers, whose gas originates
in the southwestern United States, Canada and Appalachia. Some of the Other
Nonregulated operations rely 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 forepart of the paper copy of the Company's
combined Annual Report to Shareholders/Form 10-K under the heading "Exploration
and Production and Other Nonregulated Activities," which is included in this
electronic filing as Exhibit 13, Item 7 "MD&A," and Item 8 at Notes I-Business
Segment Information and L - Supplementary Information for Oil and Gas Producing
Activities.
In 1995, the Utility Operation purchased 130.8 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 77% 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%, 15% and 5%,
respectively, of the Utility Operation's 1995 gas purchases. Gas purchases from
Vastar Resources, Inc. and Natural Gas Clearinghouse (southwest gas under
long-term contract) represented 13% and 12%, respectively, of total 1995 gas
purchases by the Utility Operation. No other producer or marketer provided the
Utility Operation with 10% or more of its gas requirements in 1995.
To move its gas from the point of purchase to its distribution
system in New York and Pennsylvania, the Utility Operation purchases firm
transportation and storage services from various interstate pipeline companies
including Supply Corporation. See Item 8, Note H-Commitments and Contingencies,
for a discussion of the Utility Operation's obligations under its nonaffiliated
pipeline capacity, gas purchase and gas storage contracts.
The Utility Operation also transports gas owned by others
(principally industrial and commercial end-users). Gas produced by Appalachian
producers, especially in Pennsylvania and New York, remained an important source
of supply for the Utility Operation's transportation customers, who also
purchased gas from the southwestern United States and Canadian suppliers.
Other Nonregulated operations need natural gas for NFR's marketing
and Leidy's hub services, but are relatively indifferent as to the source.
Competition
The natural gas industry was competitive in 1995 and is expected to become more
competitive in the future. Competition existed among providers of natural gas,
as well as between natural gas and other sources of energy.
Management continues to believe that there will be increased usage
of natural gas nationwide over the longer term, so that opportunities exist for
increased sales. This increased use of natural gas nationwide is expected to
result mainly from the increased use of natural gas as an electric generation
and cogeneration fuel, conversion of home heating load from oil to gas, economic
and population growth, competitive prices and technological developments. The
long-term trend in natural gas will depend upon the balance of supply and
demand, as well as weather (colder weather generally increases demand and thus
price). As noted, demand is expected to increase over the longer term. Supply
will be impacted by the potential increase in domestic supplies due to more
efficient exploration and production technology and the amount of gas imported
into the United States from Canada and Mexico.
The continuing deregulation of the natural gas industry should also
enhance the competitive position of natural gas relative to other energy sources
by removing some of the regulatory impediments to adding customers and
responding to market forces. In addition, the environmental advantages of
natural gas compared with other fuels should increase the role of natural gas as
an energy source. The potential environmental role of natural gas was enhanced
by passage of the federal Clean Air Act Amendments of 1990, which United States
industries have not completed implementing. 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 others to restructure the electric industry much the
same as the FERC restructured the gas industry. It is unclear at this point what
impact this restructuring will have on the natural gas industry.
The Company competes on the basis of price, service, quality 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 Operation
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. Competition has arrived for utilities. The PSC issued an
order in 1995 providing for the Utility Operation to be the first gas utility in
New York to implement unbundling of its services pursuant to a 1994 PSC order on
restructuring. The Utility Operation now offers unbundled flexible services to
its large commercial and industrial customers. This unbundling is an important
step toward the Utility Operation's goal of opening its market area to
competition for all customers, including residential. Competition for
large-volume customers continues, with pipeline companies increasingly
attempting to sell or transport gas directly to end-users located within the
Utility Operation's service territories (i.e., bypass). The FERC remains
unwilling to shield local distribution companies from such bypass. In addition,
competition continues with fuel oil suppliers, and may increase with electric
utilities making retail energy sales.
Responding to those developments, the Utility Operation is now
better able to compete, through its unbundled flexible services, in its most
vulnerable markets (the large commercial and industrial markets). The Utility
Operation 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
The Pipeline and Storage segment 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. The Pipeline and
Storage segment 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
northeastern 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. The Pipeline and Storage segment will continue to
evaluate ways to take advantage of its location to open new markets and expand
existing ones, especially in the gas storage business.
There is, however, increased competition to provide services to the
northeastern market in the form of other proposed pipeline expansions and
proposed storage projects. The northeastern utilities which are currently the
largest customers of transportation and storage services are showing some
hesitance to enter into new long-term transportation or storage arrangements
while their state commissions are considering significant restructuring of their
bundled sales services.
Competition: the Exploration and Production Segment
The Exploration and Production segment competes with other gas and oil
producers, and with fuel oil and electricity wholesalers and producers, with
respect to its sales of oil and gas. The Exploration and Production segment also
competes 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: Other Nonregulated Operations
In the Other Nonregulated operations, NFR competes with other gas 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 Operation, as virtually all of its residential and
commercial customers use gas for space heating. The effect on the Utility
Operation in New York is mitigated somewhat 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.
The Pipeline and Storage segment's volumes transported and stored
may vary materially depending on weather, without materially affecting its
earnings. The Pipeline and Storage segment'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
Supply Corporation was engaged in discussions, but not formal proceedings, with
the New York Department of Environmental Conservation (NYDEC) concerning the 71
plugged and abandoned gas wells located within the boundaries of the Bennington
and Holland, New York underground natural gas storage fields. Before 1995,
Supply Corporation voluntarily replugged 27 wells which were believed to be
venting small amounts of natural gas to the atmosphere. In November 1995, the
NYDEC informed Supply Corporation that it had accepted Supply Corporation's
proposed monitoring program and would not require the previously contemplated
replugging of wells unless those wells started to vent gas to the atmosphere.
A discussion of environmental matters involving the Company is
included in Item 8, Note H-Commitments and Contingencies.
Miscellaneous
The Company had 2,925 full-time employees at September 30, 1995, a decrease of
7% from the 3,148 employed at September 30, 1994.
Agreements covering employees in collective bargaining units in New
York were last renegotiated in October 1994 and are scheduled to expire in
February 1998. Agreements covering most employees in collective bargaining units
in Pennsylvania were renegotiated in calendar 1993 and are scheduled to expire
in April and May 1996. The Company expects to begin negotiations with the
Pennsylvania unions early in calendar 1996.
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.
Executive Officers of the Company (1)
Age as of Company Position Date Elected
Name 9/30/95 Since 1990 To Position
---- -------- ---------- -----------
Bernard J. Kennedy 64 Chairman of the
Board of Directors. March 21, 1989
Chief Executive
Officer. August 1, 1988
President. January 1, 1987
Director. March 29, 1978
Chairman of the Board
of certain subsidiaries
of the Company. August 1, 1988
Philip C. Ackerman 51 Director. March 16, 1994
Senior Vice President. June 1, 1989
President of
Distribution Corporation. October 1, 1995
President of Seneca. June 1, 1989
Executive Vice President
of Supply Corporation. October 1, 1994
President of Horizon. September 13, 1995
President of certain other
of the Company's
subsidiaries from
prior to 1990.
Richard Hare 57 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
William J. Hill 65 Director. September 20, 1995
President of
Distribution
Corporation until
October 1, 1995. June 1, 1989
(1) The Company has been advised that there are no family relationships
among any of the officers listed, and that there is no arrangement or
understanding among any one of them and any other persons pursuant to
which he was elected as an officer.
ITEM 2 PROPERTIES
General Information on Facilities
The investment of the Company in net property, plant and equipment was $1,649.2
million at September 30, 1995. Approximately 78% of this investment is in the
Utility Operation 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.
The Utility Operation 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 14,666 miles of
distribution pipeline) and its services represent approximately 58% and 27%,
respectively, of the Utility Operation's net investment of $822.8 million.
The Pipeline and Storage segment represents a net investment of $463.6
million in transmission and storage facilities at September 30, 1995.
Transmission pipeline, with a net cost of $145.1 million, represents 31% of this
segment's total net investment and includes 2,778 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 511 miles of pipeline. Included in the storage
facilities net investment is $85.6 million of base gas. The Pipeline and Storage
segment has 31 compressor stations with 73,450 installed compressor horsepower.
The Exploration and Production segment had a net investment in
properties amounting to $340.0 million at September 30, 1995. Of this amount,
Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast
regions was $285.2 million, and Seneca's net investment in oil and gas
properties in the Appalachian region aggregated $54.8 million.
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 $442.8 million, or 37%, since 1990.
The Regulated Operation's facilities provided the capacity to meet its
1995 peak day sendout, including transportation service, of 1,847 MMcf, which
occurred on February 5, 1995. Withdrawals from storage provided approximately
45% of the requirements on that day.
Company maps, which are included in the paper copy of the Company's
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. For a further
discussion of oil and gas producing activities, refer to Note L-Supplementary
Information for Oil and Gas Producing Activities, under Item 8 of this Form
10-K.
Supply Corporation files Form 2 "Annual Report of Natural Gas
Companies" and Form 15 "Annual Report of Gas Supply" with the FERC. The reserve
disclosures in these reports were filed as of December 31, 1994, and represent
reserves related to Supply Corporation's held for future use storage wells.
These reserves are appropriately not included in reserves reported in Note L.
Seneca is not regulated by the FERC, and thus is not required to file
Forms 2 and 15. Seneca's oil and gas reserves reported in Note L as of September
30, 1995, 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 1995 1994 1993
- ------------------------------- ---- ---- ----
Average Sales Price per Mcf of Gas $ 1.67 $ 2.18 $ 2.20
Average Sales Price per Barrel of Oil $16.16 $14.86 $16.78
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ .44 $ .45 $ .54
Productive Wells
At September 30, 1995 Gas Oil
- --------------------- --- ---
Productive Wells - gross 2,115 257
- net 1,941 202
Developed and Undeveloped Acreage
At September 30, 1995
- ---------------------
Developed Acreage - gross 595,787
- net 520,849
Undeveloped Acreage - gross 624,085
- net 588,431
Drilling Activity
Productive Dry
------------------ ------------------
For the Year Ended September 30 1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
Net Wells Completed - Exploratory 5 5 9 0 4 6
- Development 6 8 16 0 0 3
Present Activities
At September 30, 1995
- ---------------------
Wells in Process of Drilling - gross 7
- net 6
There are currently no waterflood projects or pressure maintenance
operations of material importance.
ITEM 3 Legal Proceedings
Paragon/TGX Proceedings
A. New York Litigation
Since November 30, 1984, Distribution Corporation has been involved in
litigation against Paragon Resources, Inc. (Paragon) and TGX Corp. (collectively
Paragon/TGX), in the United States District Court for the Western District of
New York (the District Court). Distribution Corporation
sought a declaratory judgment concerning the contract effect of a December 20,
1983 PSC order (the Disapproval Order) which, among other things, disapproved a
1974 gas purchase agreement between Distribution Corporation's predecessor in
interest, Iroquois Gas Corporation, and Paragon (the Paragon Contract).
Paragon/TGX counterclaimed for (i) a declaration that the Disapproval Order did
not affect the Paragon Contract in any way, whatsoever, (ii) approximately $4.4
million in respect of take-or-pay claims, and (iii) unquantified amounts in
respect of other alleged breaches of the Paragon Contract. Commencing with its
payment for production received in September 1984, and continuing through
December 1993, when Paragon/TGX purported to assign the Paragon Contract,
Distribution Corporation paid Paragon/TGX for Paragon Contract gas at prices
below those developed by the Paragon Contract's price formula, as the same have
been impacted, from time to time, by the Natural Gas Policy Act of 1978.
On December 3, 1991, the United States Court of Appeals for the Second
Circuit (the Second Circuit) issued an opinion regarding a partial summary
judgment granted by the District Court. The Second Circuit essentially held that
the Disapproval Order had "voided the Contract's price term," but that
Paragon/TGX had elected an option available to it under the Paragon Contract to
continue that contract, in the aftermath of the Disapproval Order, at "a price
consistent with" that order. The Second Circuit also remanded the case to the
District Court for further proceedings.
In a letter dated December 13, 1991, TGX demanded that Distribution
Corporation pay it $21.9 million (including interest), alleged to represent the
difference between the amount received by Paragon/TGX in respect of Paragon
Contract gas delivered during the period September 1984 through October 1991,
and the amount allegedly due TGX in respect of such gas during such period.
Distribution Corporation rejected TGX's demand.
On September 29, 1994, Paragon/TGX served an amended answer and
counterclaim. That pleading restates Paragon/TGX's claims for unquantified money
damages respecting Distribution Corporation's alleged (i) breach of contract
price and "take-or-pay" provisions, (ii) "lack of good faith . . . material
breach" of the contract, and (iii) repudiation of the contract. The pleading
also adds two new, but unquantified claims - (i) consequential damages suffered
upon the sale of properties and assignment of the Paragon Contract at less than
full value, and (ii) damages related to the allegation that Distribution
Corporation "tortiously and with intent injured TGX in the conduct of its
business." Distribution Corporation filed a timely reply to Paragon/TGX's
claims.
Various motions have been heard before the District Court. A United
States Magistrate Judge is now handling other preliminary matters and discovery
issues before the case is ultimately set for trial.
B. State Commission Proceedings
In 1992, Distribution Corporation filed two petitions with the PSC that involved
the Paragon Contract. Distribution Corporation sought authority from the PSC to
defer, and ultimately recover through rates, a partial settlement payment made
to TGX. Distribution Corporation also requested the PSC to review the prices
charged by TGX in the context of the "just and reasonable" standard of Section
110(4) of the New York Public Service Law and issue a declaratory order
regarding its findings.
The PSC consolidated the proceedings, and, in an order issued on
May 5, 1995, (i) authorized Distribution Corporation to recover through rates
the amounts previously paid to TGX, and (ii) dismissed Distribution
Corporation's petition regarding the New York Public Service Law Section 110(4)
issues because the PSC determined there was no "properly reviewable contract"
that had been filed with it.
In September 1995, Distribution Corporation filed a petition with
the New York Supreme Court (Albany County, Special Term) seeking judicial review
of the PSC's May 1995 order regarding the dismissal of Distribution
Corporation's petition for a declaratory order.
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 1995.
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
Form 10-K, and reference is made thereto.
ITEM 6 Selected Financial Data
Year Ended September 30 1995 1994 1993 1992 1991
- ----------------------- ---- ---- ---- ---- ----
Summary of Operations (Thousands)
Operating Revenues $975,496 $1,141,324 $1,020,382 $920,450 $865,131
-------- ---------- ---------- -------- --------
Operating Expenses:
Purchased Gas 351,094 497,687 409,005 363,690 364,246
Operation Expense and Maintenance 292,505 291,390 283,230 263,084 245,253
Property, Franchise and Other
Taxes 91,837 103,788 95,393 89,158 83,095
Depreciation, Depletion and
Amortization 71,782 74,764 69,425 55,726 50,805
Income Taxes - Net 43,879 47,792 41,046 35,231 23,285
-------- ---------- ---------- -------- --------
851,097 1,015,421 898,099 806,889 766,684
-------- ---------- ---------- -------- --------
Operating Income 124,399 125,903 122,283 113,561 98,447
Other Income 5,378 3,656 4,833 5,790 11,793
-------- ---------- ---------- -------- --------
Income Before Interest Charges 129,777 129,559 127,116 119,351 110,240
Interest Charges 53,883 47,124 51,899 59,041 61,250
-------- ---------- ---------- -------- --------
Income Before Cumulative Effect 75,894 82,435 75,217 60,310 48,990
Cumulative Effect of Changes in
Accounting - 3,237 - - -
-------- ---------- ---------- -------- --------
Net Income Available for Common
Stock $ 75,894 $ 85,672 $ 75,217 $ 60,310 $ 48,990
======== ========== ========== ======== ========
Per Common Share Data
Earnings $2.03 $2.32* $2.15 $1.94 $1.63
Dividends Declared $1.60 $1.56 $1.52 $1.48 $1.44
Dividends Paid $1.59 $1.55 $1.51 $1.47 $1.43
Dividend Rate at Year-End $1.62 $1.58 $1.54 $1.50 $1.46
Number of Common Shareholders at
Year-End 21,429 22,465 22,893 23,218 22,662
======== ========== ========== ======== ========
Net Property, Plant and Equipment (Thousands)
Regulated:
Utility Operation $ 822,764 $ 787,794 $ 754,466 $ 719,755 $ 678,933
Pipeline and Storage 463,647 443,622 436,547 423,383 380,008
---------- ---------- ---------- ---------- ----------
1,286,411 1,231,416 1,191,013 1,143,138 1,058,941
---------- ---------- ---------- ---------- ----------
Nonregulated:
Exploration and Production 339,950 295,418 273,470 261,446 248,787
Other 22,690 18,579 16,209 11,670 5,896
---------- ---------- ---------- ---------- ----------
362,640 313,997 289,679 273,116 254,683
---------- ---------- ---------- ---------- ----------
Corporate 131 137 122 128 127
---------- ---------- ---------- ---------- ----------
Total Net Plant $1,649,182 $1,545,550 $1,480,814 $1,416,382 $1,313,751
========== ========== ========== ========== ==========
Total Assets (Thousands) $2,038,302 $1,981,657 $1,801,540 $1,760,830 $1,560,834
========== ========== ========== ========== ==========
Capitalization (Thousands)
Common Stock Equity $ 800,588 $ 780,288 $ 736,245 $ 632,333 $ 542,109
Long-Term Debt, Net of Current
Portion 474,000 462,500 478,417 479,500 442,071
---------- ---------- ---------- ---------- ----------
Total Capitalization $1,274,588 $1,242,788 $1,214,662 $1,111,833 $ 984,180
========== ========== ========== ========== ==========
* 1994 includes Cumulative Effect of Changes in Accounting of $.09. See Notes A
and G to Consolidated Financial Statements.
ITEM 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
1995 Compared with 1994
National Fuel's earnings were $75.9 million, or $2.03 per common share, in 1995.
This compares with earnings of $82.4 million, or $2.23 per common share in 1994
(before the cumulative effect of the mandated changes in accounting for income
taxes and post-employment benefits, which added a net $3.2 million, or $0.09 per
common share of earnings in 1994).
The earnings decrease in 1995 was attributable to lower earnings of the
Company's Exploration and Production segment and Utility Operation, partly
offset by higher earnings of the Pipeline and Storage segment, Other
Nonregulated, and Corporate operations.
Exploration and Production earnings declined because of low gas prices
coupled with management's decision, based on those low gas prices, to delay Gulf
Coast activity causing reduced levels of gas and oil production. The Utility
Operation's earnings suffered from the warm weather and the impact of lower
normalized usage per residential and commercial account. Additionally, the
Utility Operation's New York jurisdiction annual reconciliation of gas costs,
performed in August of each year, determined an amount of lost and
unaccounted-for gas in excess of that allowed to be recovered by the Public
Service Commission of the State of New York (PSC). The Pipeline and Storage
segment earnings reflect the application of a final rule issued by the Federal
Energy Regulatory Commission (FERC) in September 1995, which addresses and
clarifies financial reporting aspects of the current practices for unbundled
pipeline sales and open access transportation. The increase in earnings from the
application of this rule was partly offset by higher operating and interest
expense as well as the recording of a reserve for previously deferred
preliminary survey and investigation charges for the Laurel Fields Storage
Project. An open season held during August and September 1995 for nominations
for firm storage capacity for this proposed underground natural gas storage
development project failed to produce sufficient interest to proceed with the
project at this time. Accordingly, this project has been delayed until at least
1997. Increased earnings in the Company's Other Nonregulated operations resulted
mainly from a gain on the sale of equipment, net of accrued expenses, by the
Company's pipeline construction subsidiary. This sale pertained to a strategic
decision to discontinue the operations of this subsidiary. The Company's gas
marketing subsidiary also increased earnings on a year-to-year basis as a result
of increased margins and an increase in customers. In addition, Corporate
operations benefited from cost saving measures, including the relocation of
corporate headquarters.
1994 Compared with 1993
National Fuel's earnings (before the cumulative effect of the changes in
accounting for income taxes and post-employment benefits, discussed above) were
$82.4 million, or $2.23 per common share, in 1994. This represents an
approximate 10% increase over 1993 earnings of $75.2 million and a 4% increase
from 1993 earnings per common share of $2.15. Share amounts reflect a greater
number of weighted average shares outstanding in 1994, principally because of
the sale of 2.5 million shares of common stock in May 1993.
The earnings increase in 1994 was attributable to higher earnings in
the Company's Nonregulated and Utility operations, offset in part by lower
earnings in the Pipeline and Storage segment. The increase in the Nonregulated
operations consisted of higher earnings in the Exploration and Production
segment as a result of record oil and gas production, more than compensating for
a decline in oil and gas prices. Furthermore, the Company's natural gas
marketing, pipeline construction and timber operations had improved earnings.
The Utility Operation's earnings increased slightly
because of colder weather and the impact of rate increases in New York and
Pennsylvania. These increases were partly offset by an earnings decrease in the
Pipeline and Storage segment, which resulted mainly because of two nonrecurring
items in 1993: the settlement of a Supply Corporation rate case which resulted
in a partial reduction of a provision for refund due customers; and a change in
rate design, effective August 1, 1993, which increased 1993 earnings.
Operating Revenues
Year Ended September 30 (in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
Utility Operation
Retail Revenues:
Residential $ 569,603 $ 677,068 $ 613,039
Commercial 137,869 177,249 156,851
Industrial 18,269 31,096 31,609
- -----------------------------------------------------------------------------
725,741 885,413 801,499
Off-System Sales 18,255 6,930 945
Transportation 37,183 34,419 30,213
Other 4,885 4,911 3,961
- -----------------------------------------------------------------------------
786,064 931,673 836,618
- -----------------------------------------------------------------------------
Pipeline and Storage
Wholesale Revenues - - 444,142
Storage Service 59,826 58,971 41,041
Transportation 88,766 90,416 45,313
Other 15,995 3,734 4,072
- -----------------------------------------------------------------------------
164,587 153,121 534,568
- -----------------------------------------------------------------------------
Exploration and Production 56,232 70,261 58,636
Other Nonregulated 57,075 72,036 42,099
- -----------------------------------------------------------------------------
113,307 142,297 100,735
- -----------------------------------------------------------------------------
Less: Intersegment Revenues 88,462 85,767 451,539
- -----------------------------------------------------------------------------
Total Operating Revenues $ 975,496 $1,141,324 $1,020,382
=============================================================================
Operating Income (Loss) Before Income
Taxes
Year Ended September 30 (in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
Utility Operation $ 83,774 $ 90,584 $ 86,690
Pipeline and Storage 67,884 62,302 67,375
Exploration and Production 16,404 21,767 12,980
Other Nonregulated 3,021 2,505 (986)
Corporate (2,805) (3,463) (2,730)
- -----------------------------------------------------------------------------
Total Operating Income Before Income
Taxes $168,278 $173,695 $163,329
=============================================================================
System Natural Gas Volumes
Year Ended September 30 (in billion cubic feet) 1995 1994 1993
- -------------------------------------------------------------------------
Regulated Gas Sales
Residential 79.9 90.6 86.9
Commercial 22.2 26.9 25.6
Industrial 4.8 6.5 6.5
Wholesale * - - 118.7
Off-System 9.4 3.3 0.3
- -------------------------------------------------------------------------
116.3 127.3 238.0
- -------------------------------------------------------------------------
Nonregulated Gas Sales
Gas Sales for Resale 0.4 0.3 -
Production (in equivalent billion cubic feet) 25.4 29.5 24.9
- -------------------------------------------------------------------------
25.8 29.8 24.9
- -------------------------------------------------------------------------
Total Gas Sales 142.1 157.1 262.9
- -------------------------------------------------------------------------
Transportation
Utility Operation 52.8 52.2 48.9
Pipeline and Storage * 290.8 296.6 138.6
Nonregulated 2.5 1.4 -
- -------------------------------------------------------------------------
346.1 350.2 187.5
- -------------------------------------------------------------------------
Marketing Volumes 18.8 18.2 7.3
- -------------------------------------------------------------------------
Less Intersegment Volumes:
Transportation 154.2 164.8 40.1
Production 5.0 2.5 4.3
Gas Sales - 0.1 112.2
- -------------------------------------------------------------------------
159.2 167.4 156.6
- -------------------------------------------------------------------------
Total System Natural Gas Volumes 347.8 358.1 301.1
=========================================================================
* The elimination of wholesale volumes, as well as the increase in
transportation volumes from 1993 to 1994 reflects Supply Corporation's
adoption of FERC Order 636, effective on August 1, 1993.
Utility Operation
Operating Revenues
1995 Compared with 1994
Operating revenues decreased $145.6 million in 1995 compared with 1994. This
decrease reflects the recovery of decreased gas costs mainly because of lower
gas sales of 11.0 billion cubic feet (Bcf) as well as a 15% decline in the
average cost of purchased gas.
The decline in residential and commercial gas sales of 15.4 Bcf can be
attributed mainly to weather in Distribution Corporation's service territory
that was, on average, 12.3% warmer than last year. The decline in industrial
volumes of 1.7 Bcf reflects lower sales to a cogeneration customer. These
declines were partly offset by an increase in off-system gas sales of 6.1 Bcf.
Distribution Corporation, in each of its jurisdictions, has a mechanism whereby
it has the opportunity to recover certain costs and retain a portion of the
margin on these off-system sales.
1994 Compared with 1993
Operating revenues increased $95.1 million in 1994 compared with 1993. This
increase reflects recovery of increased gas costs mainly due to higher gas
sales, as well as general rate increases in the New York rate jurisdiction
effective in both July 1993 and 1994 and in the Pennsylvania rate jurisdiction
in December 1993 and higher revenues from off-system sales.
Higher residential and commercial sales of 5.0 Bcf resulted primarily
from weather in Distribution Corporation's service territory that was, on
average, 6.5% colder than the prior year.
Operating Income
1995 Compared with 1994
Operating income before income taxes decreased $6.8 million in 1995 compared
with 1994. This decrease reflects the lower gas sales, discussed above, coupled
with higher operating expenses. Although Distribution Corporation received
general rate increases in New York and Pennsylvania in July 1994 and December
1994, respectively, the weather related reduction in volumes sold, especially in
the Pennsylvania jurisdiction, negatively impacted margins. In both
jurisdictions, lower normalized usage per residential and commercial account
than was established in the ratemaking process also contributed to lower pretax
operating income. In addition, Distribution Corporation's annual reconciliation
of gas costs in its New York jurisdiction, performed in August each year,
determined an amount of lost and unaccounted-for gas in excess of that allowed
to be recovered by the PSC. The Utility Operation recognized an additional $4.3
million of gas cost expense as a result of this reconciliation.
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 pretax operating income and earnings for the New York rate
jurisdiction. In 1995, the WNC in New York preserved pretax operating income of
$8.2 million as weather, overall, was warmer than normal for the period of
October 1994 through May 1995. Since the Pennsylvania rate jurisdiction does not
have a WNC, uncontrollable weather variations directly impact pretax operating
income and earnings. In the Pennsylvania service territory, weather was 14.2%
warmer than last year and 5.8% warmer than normal. The warmer weather in 1995
compared with 1994 had a negative impact on pretax operating income and earnings
for the Pennsylvania rate jurisdiction.
1994 Compared with 1993
Operating income before income taxes increased $3.9 million in 1994 compared
with 1993. This increase reflects higher revenues, discussed above, partly
offset by increased operating expenses. The severe cold weather during January
and February 1994 necessitated an unusually high number of system repairs and
related site restoration work, which increased maintenance expense.
In 1994, the WNC in New York resulted in a benefit to customers of $5.8
million. In the Pennsylvania service territory, weather was 9.6% colder than the
prior year and 8.4% colder than normal. The colder weather in 1994 compared with
1993 had a positive impact on pretax operating income and earnings for the
Pennsylvania rate jurisdiction.
Degree Days
Percent Colder
(Warmer) Than
Year Ended September 30 Normal Actual Normal Last Year
- ------------------------------------------------------------------------------
1995: Buffalo 6,693 6,181 (7.6%) (11.4%)
Erie 6,128 5,773 (5.8%) (14.2%)
- ----------------------------------------------------------------------------
1994: Buffalo 6,710 6,975 3.9% 3.6%
Erie 6,202 6,726 8.4% 9.6%
- ---------------------------------------------------------------------------
1993: Buffalo 6,723 6,730 0.1% 1.3%
Erie 6,484 6,135 (5.4%) 2.5%
- ---------------------------------------------------------------------------
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 five upstream pipeline
companies, for long-term gas supplies with a combination of producers and
marketers and for storage service with Supply Corporation and two nonaffiliated
companies. In addition, Distribution Corporation can satisfy a portion of its
gas requirements through spot market purchases. Distribution Corporation's
average cost of purchased gas, including the cost of transportation and storage,
was $3.19 per thousand cubic feet (Mcf) in 1995, a decrease of 15% from the
average cost of $3.74 per Mcf in 1994. The average cost of purchased gas in 1994
was 3% lower than the $3.84 per Mcf in 1993.
Pipeline and Storage
Operating Revenues
1995 Compared with 1994
Operating revenues increased $11.5 million in 1995 compared with 1994. The
increase reflects the application of a final rule issued by the FERC in
September 1995, which addresses and clarifies financial reporting aspects of the
current practices for unbundled pipeline sales and open access transportation.
The Company restated interim operating revenues, operating income, net income
and earnings per share in the first three quarters of fiscal 1995 to conform
with the new requirements. For further details, refer to Note J - Quarterly
Financial Data (unaudited), in Item 8 of this report. Management cannot predict
as to whether or not comparable revenue relating to unbundled pipeline sales and
open access transportation would be generated in the future, since much depends
on the efficiency of transporting gas through Supply Corporation's system.
1994 Compared with 1993
Operating revenues decreased $381.4 million in 1994 compared with 1993. This
decline reflects Supply Corporation's restructured operations under FERC Order
636, which became effective August 1, 1993. Under Order 636, Supply
Corporation's gas purchasing and sales functions were discontinued and replaced
with new transportation and storage services. Thus the recovery of purchased gas
costs has been eliminated from Supply Corporation's revenues.
Operating Income
1995 Compared with 1994
Operating income before income taxes increased $5.6 million in 1995 compared
with 1994. This increase reflects the increase in operating revenues discussed
above, offset in part by higher operating expense and the recording, in the
fourth quarter of 1995, of a reserve in the amount of $3.7 million for
previously deferred preliminary survey and investigation charges for the Laurel
Fields Storage Project, as discussed above.
1994 Compared with 1993
Operating income before income taxes decreased $5.1 million in 1994 compared
with 1993. This decrease was principally because of two nonrecurring items
reflected in 1993. A rate case settlement in 1993, discussed above, resulted in
Supply Corporation recording approximately $2.8 million of revenues in 1993 that
related to 1992. In addition, the change to the straight fixed-variable (SFV)
rate design contributed additional revenues of approximately $2.7 million for
August and September 1993, when compared to Supply Corporation's former rate
design.
Exploration and Production
Operating Revenues
1995 Compared with 1994
Operating revenues decreased $14.0 million in 1995 compared with 1994. This
decrease reflects lower natural gas prices and management's decision to delay
production activity in its Gulf Coast operations based on the decrease in
prices. Natural gas production decreased 2.3 Bcf, or 10%, 2.0 Bcf of which
occurred in the Gulf Coast operations. In addition, the weighted average price
received for natural gas in fiscal 1995 decreased $0.51 per Mcf, or 23%. Oil
production was down 291,000 barrels, or 28%. This drop reflects natural
depletion and lower condensate production related to decreased gas production.
Although the weighted average price received for oil in fiscal 1995 increased
9%, this was not enough to offset the lower production level. The fluctuations
in prices denoted above do not reflect revenue from hedging activities, which
contributed approximately $7.0 million in revenues during 1995.
1994 Compared with 1993
Operating revenues increased $11.6 million in 1994 compared with 1993. This
increase was primarily attributable to Seneca's Gulf Coast operations and
reflects the continued success of both its offshore drilling program in the Gulf
of Mexico and its horizontal drilling program in central Texas. Gas production
and oil production (mainly condensate from gas wells) hit record levels in 1994
and were up 34% and 59%, respectively, in the Gulf Coast Region and 17% and 24%,
respectively, for all geographic regions combined.
The weighted average price received for gas and oil production in 1994
as compared to 1993 decreased $0.02 per Mcf and $1.92 per barrel (bbl),
respectively. Nonetheless, efforts to stabilize prices through hedging
activities contributed approximately $1.6 million of operating revenues for the
year.
Production Volumes
Year Ended September 30 1995 1994 1993
- ----------------------------------------------------------
Gas Production
(million cubic feet)
Gulf Coast 14,294 16,296 12,134
West Coast 840 706 1,059
Appalachia 5,808 6,271 6,681
- -----------------------------------------------------------
20,942 23,273 19,874
===========================================================
Oil Production
(thousands of barrels)
Gulf Coast 287 615 387
West Coast 433 404 431
Appalachia 19 11 13
- -----------------------------------------------------------
739 1,030 831
===========================================================
Weighted Average Prices
Year Ended September 30 1995 1994 1993
- ----------------------------------------------------------
Weighted Average Gas Price/Mcf
Gulf Coast $1.56 $2.03 $1.99
West Coast $1.33 $1.58 $1.62
Appalachia $2.01 $2.65 $2.67
Weighted Average Price $1.67 $2.18 $2.20
- ------------------------------------------------------------
Weighted Average Oil Price/bbl
Gulf Coast $16.94 $15.54 $17.84
West Coast $15.66 $13.79 $15.76
Appalachia $15.72 $15.92 $18.81
Weighted Average Price $16.16 $14.86 $16.78
Operating Income
1995 Compared with 1994
Operating income before income taxes decreased $5.4 million in 1995 compared
with 1994. This decrease reflects the lower revenues discussed above, partly
offset by lower depletion expense, which is directly related to lower revenues.
Lower operation and maintenance (O & M) expense also partly offset the decrease
in revenues. The decrease in O & M was a result of decreased production.
1994 Compared with 1993
Operating income before income taxes increased $8.8 million in 1994 compared
with 1993. This increase reflects the higher revenues discussed above, partly
offset by higher depletion expense which is directly related to higher revenues.
O & M expense remained substantially level in 1994 compared with 1993. Although
O & M expense related to increased production activity in the Gulf Coast
operations was higher in 1994 than 1993, it was offset by a charge to O & M in
1993 for work performed on Appalachian wells that did not recur in 1994.
Other Nonregulated
Operating Revenues
1995 Compared with 1994
Operating revenues decreased $15.0 million in 1995 compared with 1994. This
decrease reflects lower operating revenues from UCI, the Company's pipeline
construction subsidiary, as a result of management's decision to discontinue its
pipeline construction operations. The decrease also reflects lower revenues from
NFR, the Company's gas marketing subsidiary, largely because of lower natural
gas prices in 1995 compared with 1994.
1994 Compared with 1993
Operating revenues increased $29.9 million in 1994 compared with 1993. This
increase is almost entirely due to higher revenues from NFR as its gas marketing
volumes more than doubled to 18.2 Bcf in 1994 from 7.3 Bcf in 1993.
Operating Income
1995 Compared with 1994
Operating income before income taxes increased $0.5 million in 1995 compared
with 1994. This increase can be attributed to improved performance by NFR as a
result of improved margins and an increase in customers combined with better
performance by UCI prior to the discontinuance of its pipeline construction
operations.
1994 Compared with 1993
Operating income before income taxes increased $3.5 million in 1994 compared
with 1993. This increase is due to the improved performance of UCI, which,
although still operating at a loss, had higher margins than in 1993. In
addition, the improved performance of NFR and the Company's timber operations
enhanced operating income before income taxes of this segment.
Income Taxes, Other Income and Interest Charges
Income Taxes
Income taxes decreased in 1995, mainly because of a decrease in pretax income.
The opposite was true in 1994 as income taxes increased because of an increase
in pretax income. Income taxes in 1995 reflect lower Section 29 nonconventional
fuel tax credits. These credits, which relate to production from qualified gas
wells, decreased to $0.9 million in 1995 from $1.7 million in 1994 and $2.6
million in 1993. These credits are a direct reduction of income tax expense.
Other Income
Other income increased $1.7 million in 1995, primarily because of a gain of $2.5
million recorded by UCI on the sale of its pipeline construction equipment. The
sale of the equipment resulted from management's decision to discontinue its
pipeline construction operations.
Other income decreased $1.2 million in 1994. A portion of the decrease
in 1994 was because Distribution Corporation discontinued the accrual of
interest income on deferred contract reformation costs (CRC) in April 1993, in
accordance with a settlement with the PSC for full recovery of CRC. In addition,
the decrease in 1994 reflects lower interest income on temporary cash
investments.
Interest Charges
Interest on long-term debt increased $4.2 million in 1995 and decreased $1.8
million in 1994. The increase in 1995 can be attributed to a higher average
amount of long-term debt balance in 1995 compared to 1994. The decrease in 1994
was mainly due to refinancing activities, whereby higher-interest long-term debt
was replaced with lower-interest long-term debt.
Other interest charges increased $2.6 million in 1995 and decreased
$3.0 million in 1994. The increase in 1995 resulted primarily from an increase
in the weighted average interest rate on short-term borrowings, partly offset by
lower average outstanding balances. In addition, interest in 1995 includes
increased interest expense on Amounts Payable to Customers. The decline in 1994
reflects lower interest on short-term borrowings because of lower average
amounts outstanding, offset in part by an increase in the weighted average
interest rate.
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) 1995 1994 1993
- -----------------------------------------------------------------
Provided by Operating Activities $173.5 $199.2 $123.7
Capital Expenditures (182.8) (135.1) (131.9)
Short-Term Debt, Net Change 35.1 (84.3) (30.2)
Long-Term Debt, Net Change 4.0 80.1 (51.1)
Issuance of Common Stock 2.5 9.1 78.8
Common Dividends (59.2) (57.2) (52.2)
All Other-Net 10.6 3.6 0.2
- ------------------------------------------------------------------
Net Increase (Decrease) in Cash
and Temporary Cash Investments $(16.3) $ 15.4 $(62.7)
==================================================================
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. In 1994, noncash items also included the cumulative effect
of required changes in accounting for income taxes and post-employment benefits.
Cash provided by operating activities in the Utility Operation and
Pipeline and Storage segment may vary substantially from year to year because of
supplier refunds, the impact of rate cases, and for the Utility Operation,
fluctuations in weather and over- or under-recovered purchased gas costs. The
impact of weather on cash flow is tempered in the Utility Operation'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 $173.5 million in
1995, a decrease of $25.7 million compared with the $199.2 million provided by
operating activities in 1994. This decrease reflects lower revenues and earnings
in the Exploration and Production segment, mainly from its Gulf Coast
operations, coupled with lower payable balances. This was partly offset by
higher cash flow from the Utility Operation because of an over-recovery of gas
costs, an increase in supplier refunds received during the year, a reduction in
stored gas inventory, and a decrease in receivable balances.
Investing Cash Flow
Capital Expenditures
Capital expenditures totalled $182.8 million in 1995. The table below presents
these expenditures by business segment:
1995
Year Ended September 30 (in millions) Amount Percentage
- -----------------------------------------------------------------------
Utility Operation $ 64.8 35.4%
Pipeline and Storage 38.7 21.2
Exploration and Production 69.7 38.1
Other Nonregulated 9.6 5.3
- --------------------------------------------------------------------
$182.8 100.0%
====================================================================
Most of the Utility Operation'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.
Pipeline and Storage capital expenditures included approximately $5.0
million in connection with its link with the Empire State Pipeline at Grand
Island, New York and approximately $5.1 million related to compressor engine
emission controls necessary to comply with the Clean Air Amendments of 1990. In
addition, capital expenditures were made for additions, improvements and
replacements to this segment's transmission and storage systems.
The Exploration and Production segment spent approximately $49.0
million on its offshore program in the Gulf of Mexico, including offshore lease
acquisitions and drilling expenditures. Lease acquisitions included a 30%
working interest in an oil and gas field in West Delta Blocks 31 and 32. The
majority of offshore drilling expenditures were spent on West Cameron 552, West
Cameron 522, West Delta 17 and Vermillion 252.
Approximately $21.0 million was spent on the Exploration and Production
segment's onshore program, including horizontal onshore drilling in central
Texas and the acquisition of a 240-acre oil field located in the Silverthread
Field in California.
Other Nonregulated capital expenditures consisted primarily of
timberland purchases.
The Company's estimated capital expenditures for the next three years
are:
Year Ended September 30 (in millions) 1996 1997 1998
- --------------------------------------------------------------------
Utility Operation $ 60.7 $ 58.9 $ 57.9
Pipeline and Storage 21.5 20.5 20.5
Exploration and Production 90.4 91.3 95.0
Other Nonregulated 0.3 0.3 0.3
- --------------------------------------------------------------------
$172.9 $171.0 $173.7
====================================================================
Estimated expenditures for the Utility Operation 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.
Estimated expenditures for the Pipeline and Storage segment in 1996
will be concentrated in the reconditioning of storage wells and the replacement
of storage and transmission lines.
Estimated capital expenditures in 1996 for the Exploration and
Production segment are approximately 30% higher than capital spending in 1995 as
the Company sees significant opportunities for growth in this segment. These
expenditures will be directed mainly toward developing Seneca's Gulf Coast
offshore prospects, reserve acquisitions and significantly expanding exploration
activities.
The Company's capital expenditure program is under continuous review.
The amounts are subject to modification for opportunities in the natural gas
industry such as the acquisition of attractive oil and gas properties or storage
facilities and the expansion of transmission line capacities. While the majority
of capital expenditures in the Utility Operation 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. Expenditures in the
Regulated Operations are also dependent on adequate rate relief.
Other
Cash received on the sale of the Company's investment in property, plant and
equipment is reflected as a cash flow from investing activities. Approximately
$4.0 million of cash was received during fiscal 1995 related to the sale of
certain gas reserves in the Gulf of Mexico. Proceeds of this sale were credited
to property, plant and equipment in accordance with the full cost method of
accounting. During the third quarter of fiscal 1995, approximately $6.2 million
of cash was received related to the sale of UCI's pipeline construction
equipment.
On August 29, 1995, the Company received SEC approval to acquire all of
the issued and outstanding common stock of Horizon Energy Development, Inc.
(Horizon), a New York corporation formed to engage in foreign and domestic
energy projects, including foreign utility companies and exempt wholesale
generators of electricity. The SEC authorized the Company (through Horizon and
intermediate companies) to invest up to an aggregate of $150.0 million through
December 2001 in such activities. On September 15, 1995, the Company acquired
500 shares of Horizon $1 par common stock for $1.0 million. Currently, Horizon
is considering investment opportunities in eastern Europe, South America and
Asia, and is the controlling partner in Sceptre Power Company, a partnership
which includes a team with considerable experience in developing such energy
projects.
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.
On May 1, 1995, the Company retired $55.0 million of 6.07% medium-term
notes and $20.0 million of 6.10% medium-term notes, both of which matured on
that date.
On June 8, 1995 and June 23, 1995, the Company retired $20.0 million of
9.32% medium-term notes and $1.0 million of 6.10% medium-term notes,
respectively, which matured on those dates.
On June 12, 1995, the Company issued $50.0 million of 7.375%
medium-term notes due in June 2025. After reflecting underwriting discounts and
commissions, the proceeds to the Company amounted to $49.3 million.
On July 3, 1995, the Company issued $50.0 million of 6.08% medium-term
notes due in July 1998. After reflecting underwriting discounts and commissions,
the proceeds to the Company amounted to $49.8 million.
The Company's embedded cost of long-term debt was 7.3% at both
September 30, 1995 and 1994.
At September 30, 1995, the Company has registered under the Securities
Act of 1933, as amended, and has authority under the Public Utility Holding
Company Act of 1935, as amended, to issue and sell up to $120.0 million of
debentures and/or medium-term notes. The amounts and timing of the issuance and
sale of these debentures and/or medium-term notes will depend on market
conditions and the requirements of the Company.
Consolidated short-term debt increased $35.1 million during 1995. 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.
The Company's present liquidity position is believed to be adequate to
satisfy known demands. 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 $483.0 million in additional long-term
unsecured indebtedness at September 30, 1995, in light of then current long-term
interest rates. In addition, at September 30, 1995, the Company had regulatory
authorizations and unused short-term credit lines that would have permitted it
to borrow an additional $252.4 million of short-term debt. The Company has
recently filed with the SEC for authorization to borrow on a short-term basis
for a five-year period. With this request, the Company is seeking to increase
its short-term borrowing limits. The filing, if approved, would increase the
Company's limit on commercial paper from $105.0 million to $300.0 million and
would increase the aggregate maximum short-term borrowing level from $400.0
million to $600.0 million.
The Company, through Seneca, is engaged in certain price swap
agreements as a means of hedging 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 1995, Seneca utilized
natural gas and crude oil swap agreements with notional amounts of 16.3
equivalent Bcf and 711,000 equivalent bbl, respectively. This activity resulted
in net revenues of approximately $7.0 million.
At September 30, 1995, Seneca had natural gas swap agreements
outstanding with a notional amount of approximately 23.8 equivalent Bcf at
prices ranging from $1.70 per Mcf to $2.16 per Mcf. Seneca also had crude oil
swap agreements outstanding at September 30, 1995 with a notional amount of
1,780,000 equivalent bbl at prices ranging from $17.40 per bbl to $19.00 per
bbl. In addition, the Company has SEC authority to enter into certain interest
rate swap agreements. For further discussion, see disclosure in Note F -
Financial Instruments under the heading "Derivative Financial Instruments" 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.
Rate Matters
Utility Operation
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%. Proceedings in this rate case are ongoing and management cannot
predict their outcome. New rates are expected to become effective in October
1996. Prior to this filing, Distribution Corporation entered into proceedings
concerning a multi-year settlement, the outcome of which is uncertain at this
time.
In October 1994, Distribution Corporation filed in its New York
jurisdiction a request for an annual rate increase of $56.5 million with a
requested return on equity of 12.85%. In September 1995, the PSC issued an order
authorizing a base rate increase of $14.2 million with a return on equity of
10.4%. The new rates became effective as of September 20, 1995.
Pennsylvania Jurisdiction
On March 15, 1995, Distribution Corporation filed in its Pennsylvania
jurisdiction a request for an annual rate increase of $22.0 million with a
return on equity of 13.25%. In September 1995, the Pennsylvania Public Utility
Commission (PaPUC) approved a settlement authorizing a base rate increase of
$6.0 million with no specified rate of return on equity. The new rates became
effective as of September 27, 1995.
On March 8, 1994, Distribution Corporation filed in its Pennsylvania
jurisdiction a request for an annual rate increase of $16.0 million with a
return on equity of 12.25%. A proposal for a WNC was included in this filing. On
December 6, 1994, an order was issued by the PaPUC authorizing an annual rate
increase of $4.8 million with a return on equity of 11.0% and without a WNC. The
new rates became effective as of December 7, 1994.
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
Changes precipitated by the FERC's Order 636 are redefining the roles of the
utility industry and the state regulatory commissions. Competition has arrived
for utilities, and similar to what was done in the pipeline sector of the
natural gas industry, regulators are requiring utilities to unbundle their
services. Details of these recent developments are described below.
Many state regulators believe that utilities can gain efficiency
through performance-based incentive ratemaking. Such ratemaking is intended to
enhance the traditional cost-of-service ratemaking formula, which many believe
does not provide incentives to operate efficiently. Distribution Corporation
proposed several customer service performance incentives in its New York rate
case filed in October 1994. In its September 1995 order concerning the October
1994 rate filing, the PSC adopted incentive mechanisms that will allow it to
administer penalties determined by Distribution Corporation's ability to
maintain required performance levels. The incentives relate to: response time to
customer inquiries and complaints; billing accuracy; keeping appointments for
service; and efficiency in the installation of new service lines.
The New York and Pennsylvania regulatory commissions have instituted
several generic proceedings related, among other things, to restructuring in
response to the FERC's Order 636. Distribution Corporation is working closely
with the state regulatory commissions to resolve the complexities of industry
restructuring. The more significant proceedings, all of which are still pending,
are discussed below:
New York
Finance Proceeding. The purpose of this proceeding is to develop a uniform
method for calculating a utility's rate of return on equity.
Ratesetting Proceeding. This proceeding is intended to develop guidelines for
settlements, incentive ratemaking and multi-year rate filings, in addition to
the traditional single-year procedure. Thus, a menu of options would be
available for each utility to select the appropriate ratemaking proposal.
Generic Restructuring Proceeding. This proceeding is examining the appropriate
retail or end-use impacts resulting from the FERC's Order 636 pipeline
restructuring. In December 1994, the PSC issued an Opinion and Order in this
docket instructing the state's local distribution companies (LDC) to file
tariffs that would, among other things, unbundle retail services, provide for
small-customer aggregation, adopt flexible, market-based rates and divide the
LDC's market into core and non-core segments. In connection with its 1994 rate
case, Distribution Corporation implemented many of the policies and guidelines
contained in the December 1994 Order, and now offers unbundled, flexible
services to its commercial and industrial customers. In November 1995,
Distribution Corporation submitted a filing designed to further comply with the
December 1994 Order by (i) offering transportation service to all customers,
including residential; and (ii) surcharging transportation customers for Order
636 transition costs. These latter changes are subject to approval by the PSC.
Generic Affordability/Gas Cost Incentive Proceeding. This proceeding is
investigating the development of guidelines for "affordable" natural gas utility
service and, on a separate track, an appropriate gas cost incentive mechanism.
For the Affordability track, it is expected that the PSC will issue an order
adopting guidelines for, among other things, rates for low-income or
payment-troubled customers. The Gas Cost Incentive track is expected to result
in guidelines for designing and applying performance-based incentives for the
LDC's gas purchasing function. Among the various incentives being studied are
so-called "hard" price caps and mechanisms that would allow the PSC to
administer rewards or penalties based on the LDC's gas purchasing practices as
measured against benchmarks such as a published gas cost index.
Pennsylvania
FERC Order 636 Proceedings. The PaPUC has thus far responded to the FERC's Order
636 with three generic proceedings addressing different operational areas. They
are proceedings on transportation services, gas procurement practices (including
a gas purchase incentive mechanism) and capacity release. Distribution
Corporation has already implemented many of the proposed changes in previous
rate cases and expects that additional changes will not significantly alter
current operations.
Chairman Quain's Legislative Collaborative. In the latter part of fiscal 1995,
the Chairman of the PaPUC convened a collaborative among the Commonwealth's
LDCs, Staff for the PaPUC, intervenors and marketers/producers to examine
existing public utility laws to determine whether they should be amended to meet
the requirements of the post-Order 636 environment. Under consideration by the
parties are changes to existing laws governing utility practices and development
of new legislation that would allow utilities to seek deregulation of
traditional services. Distribution Corporation has expressed its support for,
and participated in, the drafting of many of the proposals. However,
Distribution Corporation cannot determine the outcome of these proceedings at
this time.
Pipeline and Storage
For a discussion of Supply Corporation's gathering rates, refer to Note B -
Regulatory Matters in Item 8 of this report.
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%.
Settlement discussions to resolve the various issues have achieved a settlement
in principle. This settlement in principle will increase Supply Corporation's
revenues by approximately $6.4 million annually from current levels, with a
return on equity of 11.3%. The former Penn-York Energy Corporation (Penn-York)
services, which were merged into Supply Corporation effective July 1, 1994, will
be rolled-in for ratemaking purposes. Approximately two-thirds of the former
Penn-York service is now on year-to-year contracts and Supply Corporation has
agreed not to seek recovery of revenues related to terminated Penn-York service
from other storage customers for five years, as long as the terminations are not
greater than approximately 30% of the terminable service. Supply Corporation is
marketing and will actively market available storage capacity. Supply
Corporation also agreed not to seek recovery for increased cost of service for
three years. A Stipulation and Agreement incorporating the settlement in
principle was filed with the FERC in September 1995 and the Administrative Law
Judge certified the settlement as uncontested to the FERC on November 6, 1995.
Approval is expected in early calendar year 1996 and rates are expected to
become effective retroactive to June 1, 1995.
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 $8.1 million to
$9.5 million. At September 30, 1995, Distribution Corporation has recorded the
minimum liability of $8.1 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, Distribution Corporation is recovering site investigation
and remediation costs over a three-year period for each site. In Pennsylvania,
Distribution Corporation expects to recover such costs in rates, as the PaPUC
has allowed recovery of other environmental clean-up costs in rate cases. For
further discussion, see disclosure in Note H - Commitments and Contingencies
under the heading "Environmental Matters" in Item 8 of this report.
Accounting for Stock Based Compensation
In October 1995, the Financial Accounting Standards Board issued SFAS 123,
"Accounting for Stock Based Compensation," which establishes a fair value based
method of accounting for employee stock options or similar equity instruments
and encourages all companies to adopt that method of accounting for all of their
employee stock compensation plans. For a further discussion of what this new
accounting standard entails, see Note D - Capitalization in Item 8 of this
report.
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 the
capital-intensive and regulated nature of its major operating segments.
Delays inherent in the ratemaking process prevent the Company from
obtaining immediate recovery of increased operating costs. Also, while the
ratemaking process gives no recognition to the current cost of replacing
property, plant and equipment, based on past practices the Company believes that
it will be allowed to earn on the increased cost of its net investment when
replacement of facilities occurs.
ITEM 8. Financial Statements and Supplementary Data
Index to Financial Statements
- -----------------------------
Page
----
Financial Statements:
Report of Independent Accountants 30
Consolidated Statements of Income and Earnings Reinvested
in the Business, three years ended September 30, 1995 31
Consolidated Balance Sheets at September 30, 1995 and 1994 32-33
Consolidated Statement of Cash Flows, three years ended
September 30, 1995 34
Notes to Consolidated Financial Statements 35-58
Financial Statement Schedules:
For the three years ended September 30, 1995
II-Valuation and Qualifying Accounts 59
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, 1995 and 1994,
and the results of their operations and their cash flows for each of the three
years in the period ended September 30, 1995, 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.
As discussed in Notes A and G to the consolidated financial statements,
the Company adopted the new accounting standards for postretirement benefits
other than pensions, income taxes and other postemployment benefits in fiscal
1994.
PRICE WATERHOUSE LLP
Buffalo, New York
October 27, 1995
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
Year Ended September 30 (Thousands of Dollars) 1995 1994 1993
---- ---- ----
Income
Operating Revenues $ 975,496 $1,141,324 $1,020,382
---------- ---------- ----------
Operating Expenses
Purchased Gas 351,094 497,687 409,005
Operation Expense 266,786 260,411 258,918
Maintenance 25,719 30,979 24,312
Property, Franchise and Other Taxes 91,837 103,788 95,393
Depreciation, Depletion and Amortization 71,782 74,764 69,425
Income Taxes - Net 43,879 47,792 41,046
---------- ---------- ----------
851,097 1,015,421 898,099
---------- ---------- ----------
Operating Income 124,399 125,903 122,283
Other Income 5,378 3,656 4,833
---------- ---------- ----------
Income Before Interest Charges 129,777 129,559 127,116
---------- ---------- ----------
Interest Charges
Interest on Long-Term Debt 40,896 36,699 38,507
Other Interest 12,987 10,425 13,392
---------- ---------- ----------
53,883 47,124 51,899
---------- ---------- ----------
Income Before Cumulative Effect 75,894 82,435 75,217
Cumulative Effect of Changes in
Accounting - 3,237 -
---------- ---------- ----------
Net Income Available for Common Stock 75,894 85,672 75,217
Earnings Reinvested in the Business
Balance at Beginning of Year 363,854 335,907 314,334
---------- ---------- ----------
439,748 421,579 389,551
Dividends on Common Stock 59,625 57,725 53,644
---------- ---------- ----------
Balance at End of Year $ 380,123 $ 363,854 $ 335,907
========== ========== ==========
Earnings Per Common Share
Income Before Cumulative Effect $2.03 $2.23 $2.15
Cumulative Effect of Changes in
Accounting - .09 -
---------- ---------- ----------
Net Income Available for Common Stock $2.03 $2.32 $2.15
========== ========== ==========
Weighted Average Common Shares Outstanding 37,396,875 37,046,249 34,938,722
========== ========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
Consolidated Balance Sheets
At September 30 (Thousands of Dollars) 1995 1994
---- ----
Assets
Property, Plant and Equipment $2,322,335 $2,169,067
Less - Accumulated Depreciation,
Depletion and Amortization 673,153 623,517
---------- ----------
1,649,182 1,545,550
---------- ----------
Current Assets
Cash and Temporary Cash Investments 12,757 29,016
Receivables - Net 75,933 95,494
Unbilled Utility Revenue 20,838 17,311
Gas Stored Underground 25,589 31,900
Materials and Supplies - at average cost 24,374 23,796
Prepayments 29,753 20,609
---------- ----------
189,244 218,126
---------- ----------
Other Assets
Recoverable Future Taxes 94,053 99,742
Unamortized Debt Expense 26,976 28,396
Other Regulatory Assets 37,040 47,737
Deferred Charges 8,653 15,797
Other 33,154 26,309
---------- ----------
199,876 217,981
---------- ----------
$2,038,302 $1,981,657
========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
Consolidated Balance Sheets
At September 30 (Thousands of Dollars) 1995 1994
---- ----
Capitalization and Liabilities
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 100,000,000 Shares; Issued and
Outstanding - 37,434,363 Shares and 37,278,409
Shares, Respectively $ 37,434 $ 37,278
Paid In Capital 383,031 379,156
Earnings Reinvested in the Business 380,123 363,854
---------- ----------
Total Common Stock Equity 800,588 780,288
Long-Term Debt, Net of Current Portion 474,000 462,500
---------- ----------
Total Capitalization 1,274,588 1,242,788
---------- ----------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 147,600 112,500
Current Portion of Long-Term Debt 88,500 96,000
Accounts Payable 53,842 68,293
Amounts Payable to Customers 51,001 38,714
Other Accruals and Current Liabilities 52,118 59,742
---------- ----------
393,061 375,249
---------- ----------
Deferred Credits
Accumulated Deferred Income Taxes 288,763 273,560
Taxes Refundable to Customers 23,080 31,688
Unamortized Investment Tax Credit 13,380 14,057
Other Deferred Credits 45,430 44,315
---------- ----------
370,653 363,620
---------- ----------
Commitments and Contingencies - -
---------- ----------
$2,038,302 $1,981,657
========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
Consolidated Statement of Cash Flows
Year Ended September 30 (Thousands of Dollars) 1995 1994 1993
---- ---- ----
Operating Activities
Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Cumulative Effect of Changes in Accounting - (3,237) -
Depreciation, Depletion and Amortization 71,782 74,764 69,425
Deferred Income Taxes 8,452 4,853 16,919
Other 275 5,780 5,574
Change in:
Receivables and Unbilled Utility Revenue 16,034 863 (21,531)
Gas Stored Underground and Materials and Supplies 5,733 (15,539) 7,156
Unrecovered Purchased Gas Costs - 20,772 (7,739)
Prepayments (9,144) (3,017) (1,489)
Accounts Payable (14,451) 23,774 (2,579)
Amounts Payable to Customers 12,287 (2,062) (18,808)
Other Accruals and Current Liabilities (1,305) 3,072 15,249
Other Assets and Liabilities - Net 7,903 3,534 (13,691)
-------- -------- --------
Net Cash Provided by Operating Activities 173,460 199,229 123,703
-------- -------- --------
Investing Activities
Capital Expenditures (182,826) (135,084) (131,926)
Other 10,646 3,586 225
-------- -------- --------
Net Cash Used in Investing Activities (172,180) (131,498) (131,701)
-------- -------- --------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper 35,100 (84,300) (30,200)
Proceeds from Issuance of Long-Term Debt 100,000 100,000 129,000
Reduction of Long-Term Debt (96,000) (19,917) (180,083)
Proceeds from Issuance of Common Stock 2,555 9,064 78,822
Dividends Paid on Common Stock (59,194) (57,157) (52,224)
-------- -------- --------
Net Cash Used in Financing Activities (17,539) (52,310) (54,685)
-------- -------- --------
Net Increase (Decrease) in Cash and
Temporary Cash Investments (16,259) 15,421 (62,683)
Cash and Temporary Cash Investments at Beginning of Year 29,016 13,595 76,278
-------- -------- --------
Cash and Temporary Cash Investments at End of Year $ 12,757 $ 29,016 $ 13,595
======== ======== ========
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 of which are wholly-owned. All significant intercompany
balances and transactions have been eliminated where appropriate. The
preparation of the consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current year
presentation.
Regulation
Two of the Company's principal subsidiaries, Distribution Corporation and Supply
Corporation, are subject to regulation by 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 for further discussion of regulatory matters.
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.
Supply Corporation collects revenues subject to refund if rates in
effect are pending a final rate case determination by the Federal Energy
Regulatory Commission (FERC). Estimated rate refund liabilities are recorded
which reflect management's current estimate as to the ultimate outcome of each
rate case.
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 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 present value of estimated future net revenues was
computed based on end-of-year prices adjusted for contracted price changes. At
September 30, 1995, Seneca did not experience an impairment of its oil and gas
assets under the SEC full cost accounting rules. There are certain factors,
including price declines, which could 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
calculation. 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, including amounts capitalized or
charged to other operating accounts, were $73.1 million in 1995, $75.7 million
in 1994 and $70.6 million in 1993, and were equivalent to 3.5% in 1995, 3.9% in
1994 and 3.8% in 1993 of average depreciable property, plant and equipment for
those years.
Gas Stored Underground - Current
Gas stored is carried at cost, on a last-in, first-out (LIFO) basis. 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 1995, 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 $19.2 million at September 30,
1995.
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.
Income Taxes
The Company and its wholly-owned subsidiaries file a consolidated federal income
tax return. Prior to its repeal in 1986, Investment Tax Credit was either
reflected currently in income or deferred and amortized to income over the
estimated useful lives of the related property, as required by regulatory
authorities having jurisdiction.
On October 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109), which
changed the method of accounting for income taxes. The cumulative effect of
this change increased net income for the fiscal year ended September 30, 1994 by
$3.8 million as a result of the reduction in deferred income taxes associated
with the Company's nonregulated operations.
Financial Instruments
The Company, in its Exploration and Production segment, utilizes price swap
agreements that effectively hedge a portion of the market risk associated with
fluctuations in the price of natural gas and crude oil. Gains or losses from
these price swap agreements are reflected in operating revenues on the
Consolidated Statement of Income at the time of settlement with the other
parties. Reference is made to Note F - Financial Instruments, for further
discussion of financial instruments.
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 1995, 1994 and 1993 was
$53.5 million, $46.2 million and $48.3 million, respectively. Net income taxes
paid in 1995, 1994 and 1993 were $34.6 million, $37.6 million and $19.9 million,
respectively.
In December 1993, the Company entered into a non-cash investing
activity whereby it issued shares of Company common stock for $3.2 million of
natural gas production assets.
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 Pronouncement
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" (SFAS 121). This statement establishes accounting
standards for the impairment of long-lived assets, certain identifiable
intangibles and goodwill related to those assets to be held and used and for
long-lived assets and certain identifiable intangibles to be disposed of.
Essentially, SFAS 121 requires review of these assets for impairment whenever
events or changes in circumstances indicate that the carrying amount may not be
recoverable. SFAS 121 also requires that a rate-regulated enterprise recognize
an impairment for the amount of costs excluded when a regulator excludes all or
part of a cost from an enterprise's rate base or when regulatory assets are no
longer probable of recovery. The Company has adopted SFAS 121 with no impact on
its results of operations for 1995.
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 (in thousands) 1995 1994
---- ----
Regulatory Assets:
Recoverable Future Taxes (Note C) $ 94,053 $ 99,742
Unamortized Debt Expense (Note A) 22,035 23,751
Pension and Post-Retirement Benefit Costs (Note G) 18,412 17,199
Order 636 Transition Costs* 12,358 8,417
Environmental Clean-up (Note H) 7,475 7,310
Other (1,205) 14,811
-------- --------
Total Regulatory Assets 153,128 171,230
-------- --------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) 51,001 38,714
Taxes Refundable to Customers (Note C) 23,080 31,688
Other 8,628 9,513
-------- --------
Total Regulatory Liabilities 82,709 79,915
-------- --------
Net Regulatory Position $ 70,419 $ 91,315
======== ========
* 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. Distribution Corporation and Supply Corporation are not
currently facing a requirement to discontinue SFAS 71.
Order 636 Transition Costs
As a result of the industrywide restructuring under the FERC's Order 636,
Distribution Corporation is incurring transition costs billed by Supply
Corporation and other upstream pipeline companies.
As of September 30, 1995, Distribution Corporation's estimate of its
exposure to outstanding transition cost claims is in the range of $7.1 million
to $71.0 million. The estimated maximum exposure is declining as transition
costs are incurred and paid. At September 30, 1995, Distribution Corporation has
recorded the minimum liability and corresponding regulatory asset of $7.1
million.
Distribution Corporation is currently recovering transition costs from
its sales customers in New York and its sales and transportation customers in
Pennsylvania. Recovery of the allocable portion of transition costs related to
Distribution Corporation's transportation customers in New York is expected to
begin upon the Public Service Commission of the State of New York's (PSC)
acceptance of a compliance filing made in November 1995. It is expected that the
compliance filing will be accepted by the Spring of 1996.
Distribution Corporation will continue to actively challenge relevant
FERC filings made by upstream pipeline companies to ensure the eligibility and
prudency of all transition cost claims. Management believes that any transition
costs resulting from the implementation of Order 636 which have been determined
to be both eligible and prudently incurred should be fully recoverable from
customers.
Gathering Rates
Supply Corporation has approximately $20.0 million of net production and
gathering facilities used, in part, to gather natural gas of local producers,
including the Company's production in the Appalachian Region. In its
restructuring orders, the FERC has directed Supply Corporation to fully unbundle
the production and gathering cost of service from the transmission cost of
service, and to establish a separate gathering rate. A Stipulation and Agreement
complying with the FERC's directives was filed with the FERC in September 1995
and the Administrative Law Judge certified it as uncontested to the FERC.
Approval is expected early in calendar 1996. If approved, it will permit Supply
Corporation to fully recover its investment in production and gathering plant,
as well as its gathering cost of service.
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 (in thousands) 1995 1994 1993
---- ---- ----
Operating Expenses:
Current Income Taxes -
Federal $30,522 $36,630 $21,148
State 4,905 6,309 2,979
Deferred Income Taxes 8,452 4,853 16,919
------- ------ ------
43,879 47,792 41,046
Other Income:
Deferred Investment Tax Credit (672) (682) (693)
Cumulative Effect of Changes in Accounting:
Adoption of SFAS 109 - (3,826) -
Tax Effect of Adoption of SFAS 112 - (425) -
------- ------ ------
Total Income Taxes $43,207 $42,859 $40,353
======= ======= =======
Prior to the adoption of SFAS 109 in 1994, deferred income tax expense
resulted from timing differences between the recognition of revenues and
expenses for income tax and financial reporting purposes except where not
permitted by regulatory authorities. The sources of these timing differences and
the related income tax effect of each are as follows:
Year Ended September 30 (in thousands) 1993
----
Unrecovered Purchased Gas Costs $11,641
Excess of Tax Over Book Depreciation 6,717
Exploration and Intangible Well Drilling Costs 7,377
Revenue Refunds Payable to Customers (2,994)
Debt Retirement Costs 3,780
Tax Credit Carryforward (2,608)
Miscellaneous (6,994)
-------
Total Deferred Income Taxes $16,919
=======
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 (in thousands) 1995 1994 1993
---- ---- ----
Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217
Total Income Taxes 43,207 42,859 40,353
-------- -------- --------
Income Before Income Taxes $119,101 $128,531 $115,570
======== ======== ========
Income Tax Expense, Computed at
Statutory Rate of 35% in 1995 and 1994
and 34.75% in 1993 $41,685 $ 44,986 $40,161
Increase (Reduction) in Taxes Resulting from:
Current State Income Taxes 3,188 4,101 1,944
Depreciation 2,397 2,174 2,221
Production Tax Credits (899) (1,658) (2,608)
Adoption of SFAS 109 - (3,826) -
Miscellaneous (3,164) (2,918) (1,365)
------- ------- ------
Total Income Taxes $43,207 $42,859 $40,353
======= ======= =======
Significant components of the Company's deferred tax liabilities and
assets were as follows:
At September 30 (in thousands) 1995 1994
------------------------- -------------------------
Accumulated Deferred Accumulated Deferred
Deferred Income Taxes Deferred Income Taxes
Income Taxes Current* Income Taxes Current*
------------ ------------ ------------ ------------
Deferred Tax Liabilities:
Excess of Tax Over Book Depreciation $185,595 $ - $ 174,006 $ -
Exploration and Intangible Well
Drilling Costs 84,380 - 78,224 -
Other 67,831 - 64,181 -
-------- ------- --------- -------
Total Deferred Tax Liabilities 337,806 - 316,411 -
======== ======= ========= =======
Deferred Tax Assets:
Deferred Investment Tax Credits (7,860) - (8,388) -
Overheads Capitalized for Tax Purposes (11,766) - (9,238) -
Unrecovered Purchased Gas Costs - (8,322) - (4,448)
Other (29,417) - (25,225) -
-------- ------- --------- -------
Total Deferred Tax Assets (49,043) (8,322) (42,851) (4,448)
======== ======= ========= =======
Total Net Deferred Income Taxes $288,763 $(8,322) $ 273,560 $(4,448)
======== ======= ========= =======
* Included on the Consolidated Balance Sheets in "Other Accruals and Current
Liabilities."
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 $23.1 million and $31.7 million at September 30,
1995 and 1994, 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
$94.1 million and $99.7 million at September 30, 1995 and 1994, respectively.
Note D - Capitalization
Summary of Changes in Common Stock Equity
Earnings
Paid Reinvested
Common Stock In in the
(in thousands) Shares Amount Capital Business
------ ------ ------- ----------
Balance at September 30, 1992 33,856 $33,856 $284,143 $314,334
Net Income Available for Common Stock 75,217
Dividends Declared on Common Stock
($1.52 Per Share) (53,644)
Common Stock Issued:
Sale of Common Stock 2,500 2,500 71,425
Stock Options and Stock Award Plans 50 50 832
401(k) Plans 115 115 3,423
Customer Stock Purchase Plan 140 140 4,101
Common Stock Issuance Costs (247)
------ ------- -------- --------
Balance at September 30, 1993 36,661 36,661 363,677 335,907
Net Income Available for Common Stock 85,672
Dividends Declared on Common Stock
($1.56 Per Share) (57,725)
Common Stock Issued:
Acquisition of Natural Gas
Production Assets 108 108 3,523
Stock Options and Stock Award Plans 164 164 1,163
401(k) Plans 136 136 4,234
Customer Stock Purchase Plan 209 209 6,559
------ ------- -------- --------
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:
Stock Options and Stock Award Plans 22 22 377
401(k) Plans 88 88 2,310
Customer Stock Purchase Plan 46 46 1,188
------ ------- --------
Balance at September 30, 1995 37,434 $37,434 $383,031 $380,123*
====== ======= ======== =========
* 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, 1995, $305.7 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.
Stock Options and Stock Award Plans
The Company's 1993 Award and Option Plan (1993 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 1983 Incentive Stock Option Plan (1983 Plan) provided for the
issuance of incentive stock options to key employees, and 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 three
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. Stock options
outstanding do not have a materially dilutive effect on earnings per common
share.
Transactions involving option shares for all three plans are summarized
as follows:
Number of
Shares Subject Option Price
to Option Per Share
- ----------------------------------------------------------------------
Outstanding at
September 30, 1992 618,096 $15.59 to $23.88
Granted in 1993 416,500 $25.19 and $31.50
Exercised in 1993* (78,750) $15.59 to $23.88
- ----------------------------------------------------------------------
Outstanding at
September 30, 1993 955,846 $15.59 to $31.50
Granted in 1994 272,000 $31.63
Exercised in 1994* (60,509) $18.00 to $25.19
- ----------------------------------------------------------------------
Outstanding at
September 30, 1994 1,167,337 $15.59 to $31.63
Granted in 1995 362,100 $27.94
Forfeited in 1995 (11,532) $25.19 to $31.63
Exercised in 1995* (17,615) $15.59 to $23.88
- ----------------------------------------------------------------------
Outstanding at
September 30, 1995 1,500,290 $18.00 to $31.63
======================================================================
Shares Exercisable at
September 30, 1995 1,138,190
Shares Reserved for
Future Grant at
September 30, 1995 795,148
- -------------------------------------------------------------------------
* In connection with exercising these options, 3,192, 18,088 and 36,797 shares
were surrendered and/or canceled during 1995, 1994 and 1993, respectively.
On October 4, 1995, an additional 140,000 stock option shares were
granted at an option price per share of $28.56.
During 1995, 8,000 shares of restricted stock were awarded under the
1993 Plan, bringing the total, as of September 30, 1995, to 294,308 shares of
restricted stock awarded under the 1984 Plan and 1993 Plan, since inception.
Restrictions have lapsed respecting 148,814 of these shares. Of the remaining
145,494 shares of restricted stock, restrictions on 113,494 shares will lapse
respecting one-sixth of such shares on each January 2, 1996 through 2001.
Restrictions on 8,000 shares will lapse respecting one-fourth of such shares on
each January 2, 1999 through 2002. Restrictions on 8,000 shares will lapse
respecting one-fourth of such shares on each January 2, 2000 through 2003.
Restrictions on 8,000 shares will lapse respecting one-fourth of such shares on
each January 2, 2001 through 2004. Restrictions on 8,000 shares will lapse
respecting one-fourth of such shares on each January 2, 2002 through 2005. The
market value of the restricted stock on the date the award was made is being
recorded as compensation expense over the periods over which the restrictions
lapse. During the restriction period, share certificates are held by the
Company.
In October 1995, the FASB issued SFAS 123, "Accounting for Stock Based
Compensation" (SFAS 123). This statement establishes a fair value based method
of accounting for employee stock options or similar equity instruments and
encourages all companies to adopt that method of accounting for all of their
employee stock compensation plans.
SFAS 123 allows companies to continue to measure compensation cost for
employee stock options or similar equity instruments using the method of
accounting prescribed by Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees." Companies electing to remain with this method
are required to make pro forma disclosures of net income and earnings per share
as if SFAS 123 accounting had been applied.
The Company is required to adopt the disclosure requirements of SFAS
123 for its fiscal year ending September 30, 1997. Measurement of compensation
cost under SFAS 123, if adopted, is effective for all awards granted after the
beginning of the fiscal year in which that method is first applied. Management
is currently reviewing the provisions of SFAS 123. If the fair value base
measurement provisions are adopted, they are not expected to have a material
impact on the results of operations or financial condition of the Company.
Redeemable Preferred Stock
As of September 30, 1995, 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 (in thousands) 1995 1994
---- ----
Debentures:
7-3/4% due February 2004 $125,000 $125,000
Medium-Term Notes:
6.07% due May 1995 - 55,000
6.10% due May 1995 - 20,000
6.10% due June 1995 - 1,000
9.32% due June 1995 - 20,000
8.875% due December 1995 20,000 20,000
8.90% due December 1995 38,500 38,500
4.53% due September 1996 30,000 30,000
6.42% due November 1997 50,000 50,000
6.08% due July 1998 50,000 -
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 -
-------- --------
562,500 558,500
Less Current Portion 88,500 96,000
-------- --------
$474,000 $462,500
======== ========
* Callable beginning July 1999.
The aggregate principal amounts of long-term debt maturing for the next
five years, including amounts classified as Current Portion of Long-Term Debt,
are: $88.5 million in 1996, none in 1997, $100.0 million in 1998, $50.0 million
in 1999 and $50.0 million in 2000.
During 1995, the Company issued an aggregate $100.0 million of
medium-term notes. In June 1995, $50.0 million of 7.375% medium-term notes due
in June 2025 were issued. After reflecting underwriting discounts and
commissions, the proceeds to the Company from this issuance amounted to $49.3
million. In July 1995, $50.0 million of 6.08% medium-term notes due in July 1998
were issued. After reflecting underwriting discounts and commissions, the
proceeds to the Company from this issuance amounted to $49.8 million.
The Company has authority remaining under a shelf registration and has
authority under the Public Utility Holding Company Act of 1935, as amended, to
issue and sell up to $120.0 million of debentures and/or medium-term notes. The
amounts and timing of the issuance and sale of these debentures and/or
medium-term notes will depend on market conditions 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 $400.0 million
thereunder. These credit lines, which are callable at the option of the
financial institutions, are reviewed on an annual basis and are expected to
remain in place throughout 1996.
The Company may also issue as much as $105.0 million of commercial
paper from time to time, but in no event may its borrowings under its
discretionary lines of credit, or through the issuance of commercial paper,
exceed $400.0 million in the aggregate.
Additionally, the Company has entered into an agreement that
establishes a 364-day committed revolving credit arrangement with seven
commercial banks, under which it may borrow as much as $105.0 million. This
arrangement may be utilized for general corporate purposes, including 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 $400.0 million
available for borrowing under the discretionary lines of credit is
correspondingly reduced. No borrowings under this arrangement were outstanding
at September 30, 1995. The arrangement expires on September 19, 1996, and the
Company expects to renew or replace all or most of this arrangement before then.
The Company has recently filed with the SEC to borrow on a short-term
basis for a five year period. With this request the Company is seeking to
increase its short-term borrowing limits. The filing, if approved, would
increase the Company's limit on commercial paper from $105.0 million to $300.0
million and would increase the aggregate maximum short-term borrowing level from
$400.0 million to $600.0 million.
At September 30, 1995, the Company had outstanding notes payable to
banks and commercial paper of $52.6 million and $95.0 million, respectively. At
September 30, 1994, the Company had outstanding notes payable to banks and
commercial paper of $102.5 million and $10.0 million, respectively.
The weighted average interest rate on notes payable to banks was 6.15%
and 5.13% at September 30, 1995 and 1994, respectively. The weighted average
interest rate on commercial paper was 5.85% and 5.09% at September 30, 1995 and
1994, 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 (in thousands) 1995 1994
---------------------- ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
Long-Term Debt $562,500 $570,236 $558,500 $541,327
======== ======== ======== ========
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
$28.2 million and $21.3 million at September 30, 1995 and 1994, 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 operations, has entered into
certain price swap agreements that effectively hedge a portion of the market
risk associated with fluctuations in the price of natural gas and crude oil.
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."
The following summarizes the Company's activity under swap agreements
during 1995 and 1994:
Year Ended September 30 1995 1994
--------------- -------------
Natural Gas Swap Agreements:
Notional Amount - Equivalent
Billion Cubic Feet (Bcf) 16.3 8.0
Fixed Prices per Thousand Cubic
Feet (Mcf) $1.73 - $2.38 $2.16 - $2.38
Variable Prices per Mcf $1.35 - $1.76 $1.44 - $2.44
Gain $7,157,000 $1,986,000
Crude Oil Swap Agreements:
Notional Amount - Equivalent
Barrels (bbl) 711,000 -
Fixed Prices per bbl $16.68 - $19.60 -
Variable Prices per bbl $17.16 - $19.89 -
Loss $(221,000) -
The Company had the following swap agreements outstanding at September
30, 1995:
Natural Gas Swap Agreements:
Notional Amount
Fiscal Year (Equivalent Bcf) Fixed Price per Mcf
----------- ---------------- -------------------
1996 17.6 $1.70 - $2.16
1997 3.9 $1.70 - $1.98
1997 1.7 (1)
1998 0.6 (1)
----
23.8
====
Crude Oil Swap Agreements:
Notional Amount
Fiscal Year (Equivalent bbl) Fixed Price per bbl
----------- ---------------- -------------------
1996 946,000 $17.40 - $19.00
1997 738,000 $17.40 - $18.33
1998 96,000 $18.31
---------
1,780,000
=========
(1) Price to be set according to market prices at a future date.
Gains or losses from these price swap agreements are reflected in
operating revenues on the Consolidated Statement of Income at the time of
settlement with the other parties. Based upon the September 30, 1995 variable
prices of these price swap agreements, there is an unrecognized gain of
approximately $6.7 million. The actual gain or loss realized upon settlement of
these price swap agreements will depend upon the variable price at the time of
settlement.
The Company has SEC authority to enter into interest rate swaps
associated with short-term and long-term borrowings up to a notional amount of
$350.0 million. However, within this combined limitation, the Company may only
enter into interest rate swaps associated with short-term borrowings up to a
notional amount of $200.0 million. No such agreements were entered into in 1995
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, and on its derivative financial
instruments. The counterparties to the Company's investments and derivative
financial instruments are investment grade financial institutions. Furthermore,
the Company has guarantees from counterparty affiliates on a large portion of
its derivative financial instruments. 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-Employment 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. In 1994, a plan amendment was adopted which provided for
an early retirement window program which was accounted for under the rules
prescribed by SFAS 88, "Employers' Accounting for Settlements and Curtailments
of Defined Benefit Plans and for Termination Benefits." For ratemaking purposes,
pension expense equals the amount funded less amounts capitalized. Since Plan
funding has not been required in recent years, the Company deferred the pension
expense associated with its regulated subsidiaries. The amounts deferred are
expected to be recovered in rates as contributions are made to the Plan. The
actuarial valuation funding report for the 1996 Plan year indicates that a
contribution to the Plan is required. Rate recovery for the Distribution
Corporation portion of pension costs began with rates that went into effect on
September 20, 1995 and September 27, 1995 in New York and Pennsylvania,
respectively.
The components of net periodic pension expense were as follows:
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Service Cost $ 9,680 $10,441 $ 9,181
Interest Cost 28,338 26,532 24,258
Actual Return on Plan Assets (47,591) (16,212) (35,657)
Net Amortization and Deferral 13,570 (16,603) 4,287
Early Retirement Window - 2,855 -
------- ------- -------
Net Periodic Pension Cost 3,997 7,013 2,069
Deferred for Regulatory Purposes (3,848) (6,875) (2,012)
------- ------- -------
Pension Cost Recognized in
Consolidated Statement of Income $ 149 $ 138 $ 57
======= ======= =======
The projected benefit obligation was determined using an assumed
discount rate of 8% in 1995, 8.5% in 1994 and 7.75% in 1993. 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. The unrecognized net asset
that arose from the initial application of SFAS 87, "Employers' Accounting for
Pensions," is being amortized on a straight-line basis over the future working
lifetime of those expected to receive benefits under the Plan. In 1995, in
addition to the decrease in the discount rate from 8.5% to 8%, the mortality
assumption was changed by using a more current mortality table and rates of
assumed retirement were revised to more accurately reflect actual retirement
experience. The effect of the discount rate change was to increase the projected
benefit obligation (PBO) by $22.8 million. The effect of the mortality and
retirement rate changes was to increase the PBO by $15.4 million.
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 (in thousands) 1995 1994
---- ----
Actuarial Present Value of:
Vested Benefit Obligation $287,470 $245,095
======== ========
Accumulated Benefit Obligation $333,597 $282,340
======== ========
Projected Benefit Obligation $404,157 $342,050
Plan Assets at Fair Value 399,608 370,150
-------- --------
Funded Status (4,549) 28,100
Unrecognized Net Asset (33,335) (37,502)
Unrecognized Prior Service Cost 12,446 13,339
Unrecognized Net Loss (Gain) 5,419 (19,959)
-------- --------
Pension Liability (20,019) (16,022)
Deferred for Regulatory Purposes 18,849 15,001
-------- --------
Pension Liability Recognized on Consolidated
Balance Sheets $ (1,170) $ (1,021)
======== ========
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 adopted SFAS 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" (SFAS 106), effective October 1, 1993. This
statement required the Company to change its accounting for these
post-retirement benefits from the "pay-as-you-go" (cash) basis to the accrual
basis.
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.
The Company has elected to amortize the initial accumulated liability
to net periodic post-retirement benefit cost on a straight-line basis over a
20-year period. Total post-retirement benefit cost under SFAS 106 was $24.4
million and $23.5 million in 1995 and 1994, respectively, compared with the
costs based on cash payments for retiree health care and life insurance benefits
of $6.0 million in 1993.
The components of net periodic post-retirement benefit cost were as
follows:
Year Ended September 30 (in thousands) 1995 1994
---- ----
Service Cost $ 3,394 $ 3,974
Interest Cost 13,027 13,714
Actual Return on Post-Retirement Plan Assets (4,613) (1,035)
Net Amortization and Deferral 8,739 8,628
------- -------
Net Periodic Post-Retirement Benefit Cost 20,547 25,281
Deferred for Regulatory Purposes, Net 3,853 (1,751)
------- -------
Post-Retirement Benefit Cost
Recognized in Consolidated Statement of Income $24,400 $23,530
======= =======
The weighted-average assumed discount rate used in determining the
accumulated post-retirement benefit obligation was 8% in 1995 and 8.5% in 1994.
The average assumed annual rate of salary increase for the applicable life
insurance plans was 5% for both years. The expected long-term rate of return on
Post-Retirement Plan assets was 8.5% for both years.
The annual rate of increase in the per capita cost of covered medical
care benefits for the active participants and medical plans available to new
retirees was assumed to be 13% for 1994 and 12% for 1995; this rate was assumed
to decrease gradually to 5.5% by the year 2002 and remain at that level
thereafter. The annual rate of increase in the per capita cost of covered
medical care benefits for the medical plans not available to new retirees was
assumed to be 8% for 1994, 7% for 1995, 6% for 1996 and 5.5% for each year after
1996. The annual rate of increase in the per capita cost of covered prescription
drug benefits was assumed to be 14% for 1994 and 10% for 1995. This rate was
assumed to decrease gradually to 5.5% by the year 2005 and remain level
thereafter. The annual rate increase in the per capita Medicare Part B
Reimbursement was assumed to be 12.3% in 1994, 12.2% in 1995, 12% for 1996 and
5.5% for each year after 1996. In 1995, in addition to the decrease in the
discount rate from 8.5% to 8%, there were plan changes to the prescription drug
and life insurance post-retirement benefits. The effect of
the discount rate change was to increase the accumulated post-retirement benefit
obligation (APBO) by $25.8 million. The net effect of the plan changes was to
reduce the APBO by $6.4 million.
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 (in thousands) 1995 1994
---- ----
Accumulated Post-Retirement Benefit Obligation:
Inactives $ 76,272 $ 63,934
Actives Fully Eligible 36,223 31,983
Actives Not Yet Fully Eligible 70,620 60,059
-------- --------
183,115 155,976
Fair Value of Post-Retirement Plan Assets 48,678 29,035
-------- --------
Funded Status (134,437) (126,941)
Unrecognized Transition Obligation 141,561 156,210
Unrecognized Net Gain (8,930) (31,776)
-------- --------
Post-Retirement Liability (1,806) (2,507)
Deferred for Regulatory Purposes, Net (2,102) 1,751
--------- --------
Post-Retirement Benefit Liability Recognized
on Consolidated Balance Sheets $ (3,908) $ (756)
======== ========
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, 1994, would be increased by $23.3 million.
This 1% change would also increase the aggregate of the service and interest
cost components of net periodic post-retirement benefit cost for 1995 by $2.8
million.
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 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 are deferred in each jurisdiction as either a
regulatory asset or liability, as appropriate.
Post-Employment Benefits
In November 1992, the FASB issued SFAS 112, "Employers' Accounting for
Postemployment Benefits" (SFAS 112), which establishes standards of financial
accounting and reporting for benefits, such as salary continuation, severance
pay, workers' compensation and other disability-related benefits, provided to
former or inactive employees subsequent to employment but prior to retirement.
The Company adopted SFAS 112 in the fourth quarter of 1994. The Consolidated
Statement of Income for 1994 includes a charge of $0.6 million, net of income
taxes, as a cumulative effect of a change in accounting principle.
Note H - Commitments and Contingencies
Leases
The Company has 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. Total lease expense approximated $16.3 million in 1995,
$17.2 million in 1994 and $16.9 million in 1993. At September 30, 1995, the
future minimum payments under the Company's lease agreements for the next five
years are: $13.9 million in 1996, $10.9 million in 1997, $7.6 million in 1998,
$5.1 million in 1999 and $3.6 million in 2000. The future minimum lease payments
attributable to later years is $9.7 million.
Obligations Under Firm Contracts
Distribution Corporation has agreements with five nonaffiliated upstream
pipeline companies that provide for the availability of needed pipeline
transportation capacity for periods that extend through 2004. These agreements
provide for payment of a demand or reservation charge, at FERC-approved rates,
for contracted capacity. Distribution Corporation has various gas purchase
agreements with nonaffiliated gas producers that require payment of fixed
monthly charges. These charges are tied to various indices. These agreements
have an average term of six years. Additionally, Distribution Corporation has
agreements with two nonaffiliated companies for gas storage services through
2004 that require payment of a demand charge, at FERC-approved rates, for
contracted storage. At September 30, 1995, the projected aggregate amounts of
such required future payments, based on current FERC-approved rates and current
indices, where applicable, are approximately $97.7 million, $12.7 million and
$2.0 million annually for the next five years, for pipeline capacity, gas
purchases and storage service, respectively. Additionally, these agreements call
for the payment of commodity charges based upon actual quantities shipped,
purchased and stored.
These obligations under firm contracts are considered purchased gas
costs, subject to state commission review, and are being recovered in customer
rates through the inclusion in Distribution Corporation's rate schedules.
For the fiscal year ended September 30, 1995, total gross costs
incurred under these contracts, including commodity charges on actual quantities
shipped, purchased and stored, amounted to $270.7 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 four former manufactured gas plant sites. Distribution Corporation owns two
of those sites in New York and one in Pennsylvania. Distribution Corporation has
been designated by the New York Department of Environmental Conservation (DEC)
as a potentially responsible party (PRP) with respect to a third New York site,
and is also engaged in litigation with the DEC and the party who bought the site
from Distribution Corporation's predecessor. Distribution Corporation's
estimated clean-up costs for all four sites have been accrued.
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. Distribution Corporation's estimated share of the clean-up costs
has been accrued for two of these sites.
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 all of the above noted sites are in the
range of $8.1 million to $9.5 million. At September 30, 1995, Distribution
Corporation has recorded the minimum liability of $8.1 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, Distribution Corporation has received approval from the
PSC to defer and amortize both former manufactured gas and non-manufactured gas
plant site investigation and remediation costs over a three-year period for each
site. These costs are then included in rate cases for recovery through base
rates. Distribution Corporation is currently recovering such costs in this
manner. In Pennsylvania, Distribution Corporation expects to recover such costs
in rates as the PaPUC has allowed recovery of other environmental clean-up costs
in rate cases. Accordingly, the Consolidated Balance Sheets at September 30,
1995, include related regulatory assets in the amount of approximately $7.5
million.
The Company is in compliance with the current standards of the Clean
Air Act Amendments of 1990 (the Act). Supply Corporation's compressor stations
in New York and Pennsylvania were affected by the nitrogen oxide emission
standards of the Act. Supply Corporation incurred capital expenditures for
emission controls of approximately $0.6 million in 1994 and $5.1 million in 1995
to bring its emission controls into compliance with the Act. The Company does
not anticipate incurring significant additional capital expenditures to comply
with the current standards of the Act.
Other
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
Operation and Pipeline and Storage. The nonregulated operations consist
principally of the Exploration and Production business segment. Other
Nonregulated operations consist primarily of the Company's sawmill and dry kiln
operations, natural gas marketing operations, natural gas hub operations and
pipeline construction operations (which were discontinued during 1995, the
effect of which was immaterial to the Company). Late in 1995, the Company formed
a subsidiary for the purpose of investing in foreign and domestic energy
projects.
The Utility Operation 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).
Pipeline and Storage operations are regulated by the FERC and are carried out by
Supply Corporation. Supply Corporation transports and stores natural gas for
utilities and pipeline companies in the northeastern United States markets. In
1995, 48% of Supply Corporation's revenue was from affiliated companies, mainly
Distribution Corporation.
Seneca is engaged in exploration for, and development and purchase of,
oil and natural gas reserves in the Gulf Coast, and the southwestern, western
and Appalachian regions of the United States. Seneca's production is, for the
most part, sold to purchasers located in the vicinity of its wells. Highland
Land & Minerals, Inc. operates a sawmill and dry kiln operation in Pennsylvania.
NFR is engaged in the marketing and brokerage of natural gas and performs energy
management services for utilities and end-users in the northeastern United
States markets. Leidy Hub, Inc. is engaged in the
Company's 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 Energy Development, Inc. was formed in 1995 to
engage in foreign and domestic energy projects. Utility Constructors, Inc.
was engaged in the Company's pipeline construction operations prior to the
discontinuance of its operations 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 years ended September 30, 1995, 1994
and 1993. 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 (in thousands) 1995 1994 1993
---- ---- ----
Operating Revenues
Regulated:
Utility Operation $ 786,064 $ 931,673 $ 836,618
Pipeline and Storage 164,587 153,121 534,568
---------- ---------- ----------
950,651 1,084,794 1,371,186
---------- ---------- ----------
Nonregulated:
Exploration and Production 56,232 70,261 58,636
Other 57,075 72,036 42,099
---------- ---------- ----------
113,307 142,297 100,735
---------- ---------- ----------
Intersegment Revenues* (88,462) (85,767) (451,539)
---------- ---------- ----------
$ 975,496 $1,141,324 $1,020,382
========== ========== ==========
Operating Income (Loss) Before
Income Taxes
Regulated:
Utility Operation $ 83,774 $ 90,584 $ 86,690
Pipeline and Storage 67,884 62,302 67,375
---------- -------- --------
151,658 152,886 154,065
---------- -------- --------
Nonregulated:
Exploration and Production 16,404 21,767 12,980
Other 3,021 2,505 (986)
---------- -------- --------
19,425 24,272 11,994
---------- -------- --------
Corporate (2,805) (3,463) (2,730)
---------- -------- --------
$ 168,278 $173,695 $163,329
========== ======== ========
Identifiable Assets
At September 30 (in thousands)
Regulated:
Utility Operation $1,100,236 $1,106,053 $ 961,990
Pipeline and Storage 512,546 498,798 491,291
---------- ---------- ----------
1,612,782 1,604,851 1,453,281
---------- ---------- ----------
Nonregulated:
Exploration and Production 351,262 311,037 290,346
Other 33,734 33,357 27,867
---------- ---------- ----------
384,996 344,394 318,213
---------- ---------- ----------
Corporate 40,524 32,412 30,046
---------- ---------- ----------
$2,038,302 $1,981,657 $1,801,540
========== ========== ==========
* Represents revenue primarily from Pipeline and Storage to Utility Operation.
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Depreciation, Depletion and Amortization
Regulated:
Utility Operation $ 30,052 $ 28,216 $27,137
Pipeline and Storage 19,320 17,516 16,347
-------- -------- -------
49,372 45,732 43,484
-------- -------- -------
Nonregulated:
Exploration and Production 21,201 27,496 24,249
Other 1,203 1,530 1,686
-------- -------- -------
22,404 29,026 25,935
-------- -------- -------
Corporate 6 6 6
-------- -------- -------
$ 71,782 $ 74,764 $69,425
======== ======== =======
Capital Expenditures
Regulated:
Utility Operation $ 64,844 $ 61,715 $ 61,803
Pipeline and Storage 38,678 20,472 27,420
-------- -------- --------
103,522 82,187 89,223
-------- -------- --------
Nonregulated:
Exploration and Production 69,741 52,458 36,473
Other 9,563 3,603 6,229
-------- -------- --------
79,304 56,061 42,702
-------- -------- --------
Corporate - 20 1
-------- -------- --------
$182,826 $138,268 $131,926
======== ======== ========
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 quarters ended December 31, 1994, March 31,
1995, and June 30, 1995 have been restated to reflect the application of a final
rule issued by the FERC in September 1995, which addresses and clarifies
financial reporting aspects of the current practices for unbundled pipeline
sales and open access transportation.
Financial data for the quarter ended September 30, 1995 reflects the
recording of $4.3 million and $3.7 million of operating expenses by Distribution
Corporation and Supply Corporation, respectively. Distribution Corporation
recognized an additional $4.3 million of gas cost expense as a result of the
annual reconciliation of gas costs in its New York jurisdiction, which is
performed in August of each year. This reconciliation determined an amount of
lost and unaccounted-for gas in excess of that allowed to be recovered by the
PSC. Supply Corporation recorded a reserve in the amount of $3.7 million for
previously deferred preliminary survey and investigation charges related to a
storage project.
Financial data for the quarters ended December 31, 1993 and September
30, 1994, reflect the Company's adoption of SFAS 109 and SFAS 112, respectively.
As discussed in Note A - Summary of Significant Accounting Policies, the Company
adopted SFAS 109 during the quarter ended December 31, 1993. The cumulative
effect of this change increased net income by $3.8 million. As discussed in Note
G - Retirement Plan and Other Post-Employment Benefits, the Company adopted SFAS
112 during the quarter ended September 30, 1994. The cumulative effect of this
change decreased net income by $0.6 million.
Income Net Income Earnings
Before Available for Per
Quarter Operating Operating Cumulative Common Common
Ended Revenues Income Effect Stock Share
------- --------- --------- ---------- ------------- --------
1995 (in thousands, except earnings per common share)
- -------------------------------------------------------------------------------------
12/31/94
- As Previously Reported $271,548 $38,578 $25,861 $25,861 $ .69
- As Restated $279,332 $43,288 $30,571 $30,571 $ .82
3/31/95
- As Previously Reported $376,680 $55,197 $42,047 $42,047 $1.12
- As Restated $378,762 $56,457 $43,307 $43,307 $1.16
6/30/95
- As Previously Reported $191,480 $17,789 $ 7,783 $ 7,783 $ .21
- As Restated $193,461 $18,987 $ 8,981 $ 8,981 $ .24
9/30/95 $123,941 $ 5,667 $(6,965) $(6,965) $(.19)
1994 (in thousands, except earnings per common share)
- -------------------------------------------------------------------------------------
12/31/93 $310,131 $38,745 $27,800 $31,626* $ .86 *
3/31/94 $473,722 $54,686 $43,839 $43,839 $1.18
6/30/94 $216,281 $19,782 $ 9,833 $ 9,833 $ .26
9/30/94 $141,190 $12,690 $ 963 $ 374* $ .01 *
* Includes Cumulative Effect of Changes in Accounting as discussed above.
Note K - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 1995, there were 21,429 holders of National Fuel Gas Company
common stock. The market for the common stock is 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, 1994 and 1995, are shown
below:
Price Range Dividends
Quarter Ended High Low Declared
- ------------- ---- --- ---------
1994
----
12/31/93 $36-5/8 $32-1/2 $.385
3/31/94 $36-1/4 $29-7/8 $.385
6/30/94 $32-7/8 $28-3/8 $.395
9/30/94 $31-7/8 $28-7/8 $.395
1995
----
12/31/94 $30 $25-1/4 $.395
3/31/95 $28-1/2 $25 $.395
6/30/95 $30-3/4 $27-1/2 $.405
9/30/95 $29-5/8 $26-1/2 $.405
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 (in thousands) 1995 1994
---- ----
Capitalized Costs Subject to Amortization $495,802 $442,224
Capitalized Acquisition Costs Excluded
from Amortization 28,565 16,636
-------- --------
524,367 458,860
Less - Accumulated Depreciation, Depletion
and Amortization 188,241 167,592
-------- --------
$336,126 $291,268
======== ========
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 1995,
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 (in thousands) 1995 1994 1993
---- ---- ----
Property Acquisition Costs $25,305 $ 8,215 $ 9,027
Exploration Costs 18,588 17,855 10,140
Development Costs 25,161 25,102 16,258
Other 559 259 25
------- ------- -------
$69,613 $51,431 $35,450
======= ======= =======
Results of Operations for Producing Activities
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Operating Revenues:
Natural Gas (includes revenues from sales
to affiliates of $8,650, $5,456 and
$11,474, respectively) $34,849 $50,803 $43,679
Oil, Condensate and Other Liquids 11,948 15,307 13,943
------- ------- -------
Total Operating Revenues 46,797 66,110 57,622
Production/Lifting Costs 11,215 13,177 13,452
Depreciation, Depletion and Amortization
($0.44, $0.41 and $0.42, respectively, per
dollar of operating revenues) 20,528 26,992 23,995
Income Tax Expense 4,301 7,907 4,311
------- ------- -------
Results of Operations for Producing
Activities (excluding corporate overheads
and interest charges) $10,753 $18,034 $15,864
======= ======= =======
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 1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
Proved Developed and
Undeveloped Reserves:
Beginning of Year 247,447 175,051 179,811 17,495 18,519 19,805
Extensions and
Discoveries 9,912 94,733 26,416 3,863 1,666 1,713
Revisions of
Previous Estimates (21,046) (2,075) (3,962) (60) (1,660) (1,995)
Production (20,942) (23,273) (19,874) (739) (1,030) (831)
Sales of Minerals in
Place (4,685) (32) (7,401) (474) - (173)
Purchases of Minerals
in Place and Other 10,773 3,043 61 2,780 - -
------- ------- ------- ------ ------ ------
End of Year 221,459 247,447 175,051 22,865 17,495 18,519
======= ======= ======= ====== ====== ======
Proved Developed Reserves:
Beginning of Year 179,291 134,712 126,176 10,110 10,801 11,437
======= ======= ======= ====== ====== ======
End of Year 162,504 179,291 134,712 14,937 10,110 10,801
======= ======= ======= ====== ====== ======
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 (in thousands) 1995 1994 1993
---- ---- ----
Future Cash Inflows $738,711 $705,874 $689,198
Less:
Future Production and Development Costs 272,268 252,901 240,417
Future Income Tax Expense at
Applicable Statutory Rate 129,055 131,060 132,528
-------- -------- --------
Future Net Cash Flows 337,388 321,913 316,253
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 92,120 106,647 106,598
-------- -------- --------
Standardized Measure of Discounted Future
Net Cash Flows $245,268 $215,266 $209,655
======== ======== ========
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $215,266 $209,655 $240,291
Sales, Net of Production Costs (35,582) (52,933) (44,170)
Net Changes in Prices, Net of
Production Costs 10,757 (48,149) (52,266)
Purchases of Minerals in Place 18,602 2,793 61
Sales of Minerals in Place (5,688) (29) (7,286)
Extensions and Discoveries 47,236 96,134 61,476
Changes in Estimated Future
Development Costs (50,366) (36,466) (30,555)
Previously Estimated Development
Costs Incurred 39,833 22,941 30,888
Net Change in Income Taxes at
Applicable Statutory Rate (6,838) 3,098 5,476
Revisions of Previous Quantity
Estimates (20,934) (11,042) (25,891)
Accretion of Discount and Other 32,982 29,264 31,631
-------- -------- --------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $245,268 $215,266 $209,655
======== ======== ========
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
Schedule II - Valuation and Qualifying Accounts
(in 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, 1995
- -----------------------------
Reserve for Doubtful
Accounts $ 5,055 $15,187 $ - $14,318 $5,924
======= ======= ====== ====== ======
Year Ended September 30, 1994
- -----------------------------
Reserve for Doubtful
Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055
======= ======= ====== ======= =======
Year Ended September 30, 1993
- -----------------------------
Reserve for Doubtful
Accounts $ 5,900 $ 8,713 $ - $8,874 $ 5,739
======= ======= ====== ====== =======
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 15, 1996 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after September 30, 1995. 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 15,
1996 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1995. 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 15,
1996 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1995. The information provided in such definitive
Proxy Statement is incorporated herein by reference.
ITEM 13 Certain Relationships and Related Transactions
At September 30, 1995, 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)
3.1 Certificate of Amendment of Restated Certificate of
Incorporation of National Fuel Gas Company, dated
March 9, 1987
3.2 Certificate of Amendment of Restated Certificate of
Incorporation of National Fuel Gas Company, dated
February 22, 1988
* 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:
* National Fuel Gas Company By-Laws as amended
through June 9, 1994 (Exhibit 3.1, Form 10-K for
fiscal year ended September 30, 1994 in File No.
1-3880)
(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)
* Ninth Supplemental Indenture dated as of January 1,
1990, to Indenture dated as of October 15, 1974,
between the Company and The Bank of New York
(formerly Irving Trust Company) (Exhibit EX-4.4,
Form 10-K for fiscal year ended September 30, 1992
in File No. 1-3880)
* 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)
(10) Material Contracts:
(ii) (B) Contracts upon which Registrant's business is
substantially dependent:
10.1 Service Agreement with Empire State Pipeline under
Rate Schedule FT, dated December 15, 1994.
[Portions of this agreement are subject to a
request for confidential treatment under Rule
24b-2]
10.2 Service Agreement between National Fuel Gas
Distribution Corporation and National Fuel Gas
Supply Corporation under Rate Schedule ESS dated
August 1, 1993
10.3 Service Agreement between National Fuel Gas
Distribution Corporation and National Fuel Gas
Supply Corporation under Rate Schedule ESS dated
September 19, 1995
10.4 Service Agreement between National Fuel Gas
Distribution Corporation and National Fuel Gas
Supply Corporation under Rate Schedule EFT dated
August 1, 1993
10.5 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
10.6 Service Agreement with Transcontinental Gas Pipe
Line Corporation under Rate Schedule FT dated
August 1, 1993
10.7 Service Agreement with Transcontinental Gas Pipe
Line Corporation under Rate Schedule FT dated
October 1, 1993
* 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 Texas Eastern Transmission
Corporation under Rate Schedule CDS, dated June 1,
1993 (Exhibit 10.3, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
* Service Agreement with Texas Eastern Transmission
Corporation under Rate Schedule FT-1, dated June 1,
1993 (Exhibit 10.4, 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)
* Eighth Extension to Employment Agreement with Bernard
J. Kennedy, dated September 20, 1991 (Exhibit 10-SS,
Form 10-K for fiscal year ended September 30, 1991 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)
* 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)
10.8 Amendment to National Fuel Gas Company 1993 Award and
Option Plan, dated October 27, 1995
* 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)
* Change in Control Agreement, dated May 1, 1992 with
William J. Hill (Exhibit EX-10.6, 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)
* 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)
10.9 Amendment to National Fuel Gas Company Deferred
Compensation Plan, dated September 27, 1995
10.10 National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan as amended and
restated through November 1, 1995
* Executive Death Benefits Agreement, dated April 1,
1991, with William J. Hill (Exhibit EX-10.8, Form 10-K
for fiscal year ended September 30, 1992 in File No.
1-3880)
* Split Dollar Death Benefits Agreement, dated April 1,
1991, with Richard Hare (Exhibit 10.9, Form 10-K for
fiscal year ended September 30, 1994 in File No.
1-3880)
* Amendment to Split Dollar Death Benefits Agreement,
dated March 15, 1994, with Richard Hare (Exhibit 10.5,
Form 10-K for fiscal year ended September 30, 1994 in
File No. 1-3880)
* Split Dollar Death Benefits Agreement, dated April 1,
1991, with Philip C. Ackerman (Exhibit 10.10, Form
10-K for fiscal year ended September 30, 1994 in File
No. 1-3880)
* Amendment to Split Dollar Death Benefits Agreement,
dated March 15, 1994, with Philip C. Ackerman (Exhibit
10.6, Form 10-K for fiscal year ended September 30,
1994 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)
10.11 Amendment to Death Benefit Agreement of August 28, 1991
with Bernard J. Kennedy, dated March 15, 1994
* 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)
* Excerpts of Minutes from the National Fuel Gas Company
Board of Directors Meeting of December 5, 1991 (Exhibit
10-UU, Form 10-K for fiscal year ended September 30,
1991 in File No. 1-3880)
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Discussion of the Company's business segments as
contained in the 1995 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 13, 1995 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 13, 1995
/s/ P. C. Ackerman Senior Vice President, Principal
P. C. Ackerman Financial Officer and Director
Date: December 13, 1995
/s/ R. T. Brady Director
R. T. Brady
Date: December 13, 1995
/s/ J. M. Brown Director
J. M. Brown
Date: December 13, 1995
/s/ D. N. Campbell Director
D. N. Campbell
Date: December 13, 1995
/s/ W. J. Hill Director
W. J. Hill
Date: December 13, 1995
/s/ L. F. Kahl Director
L. F. Kahl
Date: December 13, 1995
/s/ B. S. Lee Director
B. S. Lee
Date: December 13, 1995
/s/ E. T. Mann Director
E. T. Mann
Date: December 13, 1995
/s/ L. Rochwarger Director
L. Rochwarger
Date: December 13, 1995
/s/ G. H. Schofield Director
G. H. Schofield
Date: December 13, 1995
/s/ J. P. Pawlowski Treasurer and
J. P. Pawlowski Principal Accounting Officer
Date: December 13, 1995
/s/ A. M. Cellino Secretary
A. M. Cellino
Date: December 13, 1995
/s/ G. T. Wehrlin Controller
G. T. Wehrlin
Date: December 13, 1995
APPENDIX TO ITEM 2 - PROPERTIES
Three maps outlining the Company's operating areas at September 30, 1995
are included on page 6 in the paper format version of the Company's
combined Annual Report to Shareholders/Form 10-K, but are not included in
this electronic filing. The first map identifies the Company's
Exploration and Production operating area (i.e., Seneca Resources'
operating area). The second map identifies the Company's Utility
Operating area (i.e., Distribution Corporation's service area). The third
map identifies the Company's Pipeline and Storage operating area (i.e.,
Supply Corporation's storage areas and pipelines).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 1995
Two pie graphs detailing the revenue dollar in 1995: where it came from
and where it went to, broken down as follows:
Where it came from:
$ .581 Residential Sales
.178 Commercial, Industrial and Off-System Sales
.071 Transportation Revenues
.048 Oil and Gas Revenues
.042 Marketing Revenues
.040 Storage Service Revenues
.040 Other Revenues
$1.000 Total
Where it went to:
$ .358 Gas Purchased
.184 Wages, Including Benefits
.138 Taxes
.114 Other Materials and Services
.073 Depreciation
.061 Dividends - Common Stock
.055 Interest
.017 Reinvested in the Business
$1.000 Total
B. Capital Expenditures
A bar graph detailing capital expenditures (millions of dollars) for the
years 1991 through 1995, broken down as follows:
1991 1992 1993 1994 1995
---- ---- ---- ---- ----
Other Nonregulated $ 1.0 $ 7.2 $ 6.2 $ 3.6 $ 9.6
Pipeline and Storage 58.6 58.7 27.4 20.5 38.7
Exploration and Production 31.7 26.3 36.5 52.5 69.7
Utility Operation 64.9 65.7 61.8 61.7 64.8
------ ------ ------ ------ ------
$156.2 $157.9 $131.9 $138.3 $182.8
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS (Concluded)
C. Book Value Per Common Share
A bar graph detailing book value per common share (dollars) for the years
1991 through 1995, as follows:
1991 - $17.53
1992 - 18.68
1993 - 20.08
1994 - 20.93
1995 - 21.39
D. Capitalization Ratios
A bar graph detailing capitalization (percentage) for the years 1991
through 1995, broken down as follows:
Debt (%) Equity (%)
1991 55.0 45.0
1992 54.5 45.5
1993 47.8 52.2
1994 46.2 53.8
1995 47.0 53.0
Exhibit Index
-------------
3.1 Certificate of Amendment of Restated Certificate of Incorporation of
National Fuel Gas Company, dated March 9, 1987
3.2 Certificate of Amendment of Restated Certificate of Incorporation of
National Fuel Gas Company, dated February 22, 1988
10.1 Service Agreement with Empire State Pipeline under Rate Schedule FT,
dated December 15, 1994. [Portions of this agreement are subject to
a request for confidential treatment under Rule 24b-2]
10.2 Service Agreement between National Fuel Gas Distribution Corporation
and National Fuel Gas Supply Corporation under Rate Schedule ESS
dated August 1, 1993
10.3 Service Agreement between National Fuel Gas Distribution Corporation
and National Fuel Gas Supply Corporation under Rate Schedule ESS
dated September 19, 1995
10.4 Service Agreement between National Fuel Gas Distribution Corporation
and National Fuel Gas Supply Corporation under Rate Schedule EFT
dated August 1, 1993
10.5 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
10.6 Service Agreement with Transcontinental Gas Pipe Line Corporation
under Rate Schedule FT dated August 1, 1993
10.7 Service Agreement with Transcontinental Gas Pipe Line Corporation
under Rate Schedule FT dated October 1, 1993
10.8 Amendment to National Fuel Gas Company 1993 Award and Option Plan,
dated October 27, 1995
10.9 Amendment to National Fuel Gas Company Deferred Compensation Plan,
dated September 27, 1995
10.10 National Fuel Gas Company and Participating Subsidiaries Executive
Retirement Plan as amended and restated through November 1, 1995
10.11 Amendment to Death Benefit Agreement of August 28, 1991 with Bernard
J. Kennedy, dated March 15, 1994
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Discussion of the Company's business segments as contained in the
1995 Annual Report and incorporated by reference into this Form 10-K
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
27.1 Financial Data Schedule for 12 months ending September 30, 1995
27.2 Financial Data Schedule for 12 months ending September 30, 1994,
Restated
27.3 Financial Data Schedule for 9 months ending June 30, 1995, Restated
27.4 Financial Data Schedule for 6 months ending March 31, 1995, Restated
27.5 Financial Data Schedule for 3 months ending December 31, 1994,
Restated
99.1 Report of Ralph E. Davis Associates, Inc.