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.
<PAGE>
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
<PAGE 1>
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;
<PAGE 2>
* 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.
<PAGE 3>
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.
<PAGE 4>
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.
<PAGE 5>
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.
<PAGE 6>
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.
<PAGE 7>
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.
<PAGE 8>
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)
<TABLE>
<CAPTION>
Age as of Company Position Date Elected
Name 9/30/95 Since 1990 To Position
---- -------- ---------- -----------
<S> <C> <C> <C>
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.
</TABLE>
<PAGE 9>
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.
<PAGE 10>
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
<TABLE>
<CAPTION>
For the Year Ended September 30 1995 1994 1993
- ------------------------------- ---- ---- ----
<S> <C> <C> <C>
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
</TABLE>
Productive Wells
<TABLE>
<CAPTION>
At September 30, 1995 Gas Oil
- --------------------- --- ---
<S> <C> <C>
Productive Wells - gross 2,115 257
- net 1,941 202
</TABLE>
Developed and Undeveloped Acreage
<TABLE>
<CAPTION>
At September 30, 1995
- ---------------------
<S> <C>
Developed Acreage - gross 595,787
- net 520,849
Undeveloped Acreage - gross 624,085
- net 588,431
</TABLE>
Drilling Activity
<TABLE>
<CAPTION>
Productive Dry
------------------ ------------------
For the Year Ended September 30 1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Net Wells Completed - Exploratory 5 5 9 0 4 6
- Development 6 8 16 0 0 3
</TABLE>
Present Activities
<TABLE>
<CAPTION>
At September 30, 1995
- ---------------------
<S> <C>
Wells in Process of Drilling - gross 7
- net 6
</TABLE>
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
<PAGE 11>
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.
<PAGE 12>
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.
<PAGE 13>
ITEM 6 Selected Financial Data
<TABLE>
<CAPTION>
Year Ended September 30 1995 1994 1993 1992 1991
- ----------------------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
<PAGE 14>
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
<PAGE 15>
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.
<TABLE>
<CAPTION>
Operating Revenues
Year Ended September 30 (in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
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
=============================================================================
</TABLE>
<PAGE 16>
<TABLE>
<CAPTION>
System Natural Gas Volumes
Year Ended September 30 (in billion cubic feet) 1995 1994 1993
- -------------------------------------------------------------------------
<S> <C> <C> <C>
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.
</TABLE>
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.
<PAGE 17>
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.
<TABLE>
<CAPTION>
Degree Days
Percent Colder
(Warmer) Than
Year Ended September 30 Normal Actual Normal Last Year
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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%
- ---------------------------------------------------------------------------
</TABLE>
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.
<PAGE 18>
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.
<PAGE 19>
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.
<TABLE>
<CAPTION>
Production Volumes
Year Ended September 30 1995 1994 1993
- ----------------------------------------------------------
<S> <C> <C> <C>
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
===========================================================
</TABLE>
<PAGE 20>
<TABLE>
<CAPTION>
Weighted Average Prices
Year Ended September 30 1995 1994 1993
- ----------------------------------------------------------
<S> <C> <C> <C>
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
</TABLE>
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.
<PAGE 21>
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:
<TABLE>
<CAPTION>
Sources (Uses) of Cash
Year Ended September 30 (in millions) 1995 1994 1993
- -----------------------------------------------------------------
<S> <C> <C> <C>
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)
==================================================================
</TABLE>
<PAGE 22>
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:
<TABLE>
<CAPTION>
1995
Year Ended September 30 (in millions) Amount Percentage
- -----------------------------------------------------------------------
<S> <C> <C>
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.
<PAGE 23>
Other Nonregulated capital expenditures consisted primarily of
timberland purchases.
The Company's estimated capital expenditures for the next three years
are:
</TABLE>
<TABLE>
<CAPTION>
Year Ended September 30 (in millions) 1996 1997 1998
- --------------------------------------------------------------------
<S> <C> <C> <C>
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
====================================================================
</TABLE>
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.
<PAGE 24>
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.
<PAGE 25>
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.
<PAGE 26>
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.
<PAGE 27>
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.
<PAGE 28>
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.
<PAGE 29>
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.
<PAGE 30>
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
<PAGE 31>
<TABLE>
<CAPTION>
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
Year Ended September 30 (Thousands of Dollars) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
</TABLE>
<PAGE 32>
<TABLE>
<CAPTION>
National Fuel Gas Company
Consolidated Balance Sheets
At September 30 (Thousands of Dollars) 1995 1994
---- ----
<S> <C> <C>
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
</TABLE>
<PAGE 33>
<TABLE>
<CAPTION>
National Fuel Gas Company
Consolidated Balance Sheets
At September 30 (Thousands of Dollars) 1995 1994
---- ----
<S> <C> <C>
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
</TABLE>
<PAGE 34>
<TABLE>
<CAPTION>
National Fuel Gas Company
Consolidated Statement of Cash Flows
Year Ended September 30 (Thousands of Dollars) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
</TABLE>
<PAGE 35>
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
<PAGE 36>
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
<PAGE 37>
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:
<PAGE 38>
<TABLE>
<CAPTION>
At September 30 (in thousands) 1995 1994
---- ----
<S> <C> <C>
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.
</TABLE>
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
<PAGE 39>
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:
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======= ======= =======
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1993
----
<S> <C>
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
=======
</TABLE>
<PAGE 40>
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:
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======= ======= =======
</TABLE>
Significant components of the Company's deferred tax liabilities and
assets were as follows:
<TABLE>
<CAPTION>
At September 30 (in thousands) 1995 1994
------------------------- -------------------------
Accumulated Deferred Accumulated Deferred
Deferred Income Taxes Deferred Income Taxes
Income Taxes Current* Income Taxes Current*
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
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."
</TABLE>
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.
<PAGE 41>
Note D - Capitalization
<TABLE>
<CAPTION>
Summary of Changes in Common Stock Equity
Earnings
Paid Reinvested
Common Stock In in the
(in thousands) Shares Amount Capital Business
------ ------ ------- ----------
<S> <C> <C> <C> <C>
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.
</TABLE>
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
<PAGE 42>
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:
<TABLE>
<CAPTION>
Number of
Shares Subject Option Price
to Option Per Share
- ----------------------------------------------------------------------
<S> <C> <C>
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.
</TABLE>
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.
<PAGE 43>
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:
<TABLE>
<CAPTION>
At September 30 (in thousands) 1995 1994
---- ----
<S> <C> <C>
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.
</TABLE>
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.
<PAGE 44>
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.
<PAGE 45>
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:
<TABLE>
<CAPTION>
At September 30 (in thousands) 1995 1994
---------------------- ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
<S> <C> <C> <C> <C>
Long-Term Debt $562,500 $570,236 $558,500 $541,327
======== ======== ======== ========
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended September 30 1995 1994
--------------- -------------
<S> <C> <C>
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) -
</TABLE>
<PAGE 46>
The Company had the following swap agreements outstanding at September
30, 1995:
<TABLE>
<CAPTION>
Natural Gas Swap Agreements:
Notional Amount
Fiscal Year (Equivalent Bcf) Fixed Price per Mcf
----------- ---------------- -------------------
<C> <C> <C>
1996 17.6 $1.70 - $2.16
1997 3.9 $1.70 - $1.98
1997 1.7 (1)
1998 0.6 (1)
----
23.8
====
</TABLE>
<TABLE>
<CAPTION>
Crude Oil Swap Agreements:
Notional Amount
Fiscal Year (Equivalent bbl) Fixed Price per bbl
----------- ---------------- -------------------
<C> <C> <C>
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.
</TABLE>
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
<PAGE 47>
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:
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======= ======= =======
</TABLE>
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:
<TABLE>
<CAPTION>
At September 30 (in thousands) 1995 1994
---- ----
<S> <C> <C>
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)
======== ========
</TABLE>
<PAGE 48>
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:
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994
---- ----
<S> <C> <C>
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
======= =======
</TABLE>
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
<PAGE 49>
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:
<TABLE>
<CAPTION>
At September 30 (in thousands) 1995 1994
---- ----
<S> <C> <C>
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)
======== ========
</TABLE>
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.
<PAGE 50>
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.
<PAGE 51>
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
<PAGE 52>
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.
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
========== ======== ========
</TABLE>
<PAGE 53>
<TABLE>
<CAPTION>
Identifiable Assets
At September 30 (in thousands)
<S> <C> <C> <C>
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.
</TABLE>
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
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.
<PAGE 54>
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.
<TABLE>
<CAPTION>
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)
- -------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
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
<PAGE 55>
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:
<TABLE>
<CAPTION>
Price Range Dividends
Quarter Ended High Low Declared
- ------------- ---- --- ---------
<S> <C> <C> <C>
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
</TABLE>
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.
<TABLE>
<CAPTION>
Capitalized Costs Relating to Oil and Gas Producing Activities
At September 30 (in thousands) 1995 1994
---- ----
<S> <C> <C>
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
======== ========
</TABLE>
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.
<TABLE>
<CAPTION>
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======= ======= =======
</TABLE>
<PAGE 56>
<TABLE>
<CAPTION>
Results of Operations for Producing Activities
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======= ======= =======
</TABLE>
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.
<PAGE 57>
<TABLE>
<CAPTION>
Gas Oil
Year Ended MMcf Mbbl
-------------------------- ----------------------
September 30 1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
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
======= ======= ======= ====== ====== ======
</TABLE>
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.
<PAGE 58>
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
<TABLE>
<CAPTION>
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
<PAGE 59>
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
<TABLE>
<CAPTION>
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
- ----------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
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
======= ======= ====== ====== =======
</TABLE>
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.
<PAGE 60>
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)
<PAGE 61>
* 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
<PAGE62>
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)
<PAGE 63>
(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)
<PAGE 64>
* 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.
<PAGE 65>
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
<PAGE 66>
/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
<PAGE 67>
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
<PAGE 68>
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
<PAGE 69>
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.
RALPH E. Davis Associates, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
3555 TIMMONS LANE-SUITE 1105
HOUSTON, TEXAS 77027
(713) 622 -8955
October 17, 1995
Seneca Resources Corporation
333 Clay Street, Suite 4150
Houston, Texas 77002
Attention: Mr. Don A. Brown
Vice President
Re: 0il, Condensate and Natural Gas Reserves,
Seneca Resources Corporation
As of October 1, 1995
Gentlemen:
At your request, the firm of Ralph E. Davis Associates, Inc. has audited an
evaluation of the proved oil, condensate and natural gas reserves on leaseholds
in which Seneca Resources Corporation has certain interests. This report
presents a summary of the Proved Developed (producing and non-producing) and
Proved Undeveloped reserves anticipated to be produced from Seneca Resources'
interest.
Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil.
Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the
official temperature and pressure bases of the areas wherein the gas reserves
are located.
The summarized results of the reserve audit are as follows:
<PAGE 2>
RALPH E. DAVIS ASSOCIATES, INC.
Seneca Resources Corp.
Mr. Don A. Brown
October 17, 1995
Page 2
Estimated Proved Reserves
Net to Seneca Resources Corporation
As of October 1, 1995
Proved Reserves
--------------------------------------------
Developed
-----------------------
Remaining Reserves Producing Non-Producing Undeveloped Total
Gulf Coast Division:
Oil/Condensate, MBbls 704 5,122 2,062 7,888
Gas, MMSCF 41,973 39,694 47,114 128,781
West Coast Division:
Oil/Condensate, MBbls 5,993 2,891 5,866 14,750
Gas, MMSCF 13,435 5,693 11,840 30,968
East Coast Division;
Oil/Condensate, MBbls 227 0 0 227
Gas, MMSCF 61,317 392 0 61,709
TOTAL:
Oil/Condensate, MBbls 6,924 8,013 7,928 22,865
Gas, MMSCF 116,725 45,779 58,954 221,458
DISCUSSION:
The scope of this study was to audit the proved reserves attributable to the
interests of Seneca Resources Corporation. Reserve estimates were prepared by
Seneca using acceptable evaluation principals for each source. The quantities
presented herein are estimated reserves of oil, condensate and natural gas that
geologic and engineering data demonstrate can be recovered from known reservoirs
under existing economic conditions with reasonable certainty.
Ralph E. Davis Associates, Inc. has audited the reserve estimates, the data
incorporated into preparing the estimates and the methodology used to evaluate
the reserves. Certain changes to either individual reserve estimates or the
categorization of reserves were suggested by Ralph E. Davis Associates, Inc. and
accepted by Seneca Resources. It is our opinion that the reserves presented
herein meet all the criteria of Proved Reserves.
<PAGE 3>
RALPH E. DAVIS ASSOCIATES, INC.
Seneca Resources Corp.
Mr. Don A. Brown
October 17, 1995
Page 3
Neither Ralph E. Davis Associates, Inc. nor any of its employees have any
interest in Seneca Resources Corporation or the properties reported herein. The
employment and compensation to make this study are not contingent on our
estimate of reserves.
We appreciate the opportunity to be of service to you in this matter, and will
be glad to address any questions or inquiries you may have.
Very truly yours,
RALPH E. DAVIS ASSOCIATES, INC.
/s/ Allen C. Barron
Allen C. Barron, P. E.
Vice President
CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2
FT CONTRACT NUMBER: 95005
THIS AGREEMENT entered into this 15th day of December 1994, by and between
EMPIRE STATE PIPELINE, a joint venture, hereinafter referred to as
"Transporter," and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter
referred to as "Shipper."
ARTICLE I
1. Transporter's Transportation Service hereunder shall be subject to
receipt of all requisite regulatory authorizations from the New York
Public Service Commission ("Commission") , or any successor
regulatory authority, and any other necessary governmental
authorizations, in a manner and form acceptable to Transporter.
2. Subject to the terms and provisions of this Agreement, Shipper
agrees to deliver or cause to be delivered to Transporter, Gas for
Transportation, and Transporter agrees to receive, transport and
redeliver Equivalent Quantities of Gas to Shipper or for the account
of Shipper, on a firm basis, up to an aggregate Maximum Daily
Quantity of 40,112 dekatherms ("Dth") . Section I of Exhibit C,
attached hereto and made a part hereof, sets forth one or more
routings of Transportation provided hereunder, by designation of the
Point(s) of Receipt and Point(s) of Delivery, and specifies the
portion of the aggregate Maximum Daily Quantity which is related to
and agreed upon relative to each such routing.
3. Transporter may, if tendered by Shipper, transport daily
quantities in excess of the Maximum Daily Quantity specified in
Paragraph 2, above, if it can do so without adverse effect on
Transporter's operations or its ability to meet all other
obligations.
4. Transportation service rendered hereunder may be wholly or partly
interrupted, subject to the requirements of the General Information,
when such curtailment or interruption is desirable due to operating
conditions or insufficient pipeline capacity available on
Transporter's system.
ARTICLE II
1. Shipper shall deliver or cause to be delivered Gas hereunder at
the Point(s) of Receipt set forth in Exhibit "A", which is attached
hereto and made a part hereof.
ARTICLE III
1. Transporter shall redeliver to Shipper or for the account of
Shipper Equivalent Quantities of Gas transported hereunder at the
Point(s) of Delivery set forth on Exhibit "B", which is attached
hereto and made a part hereof.
<PAGE 2>
CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2
ARTICLE IV
This Agreement shall be effective for an initial period as of
[ ] until [ ].
ARTICLE V
1. Each Month, Shipper shall pay Transporter for the service
hereunder, an amount determined in accordance with Transporter's
Service Classification No. 1 (Rate Schedule FT), and the applicable
provisions of the General Information of Transporter's New York
Public Services Commission Gas Tariff, as filed with the Commission.
Such Service Classification and General Information are incorporated
by reference and made a part hereof. Section II of Exhibit C hereto
sets forth one or more routings of Transportation provided hereunder,
by designation of the Point(s) of Receipt and Point(s) of Delivery,
and specifies for each such routing, the rates, differentials and any
other charges applicable to service under this Service Agreement for
such routing, as agreed by Transporter and Seller or as fixed by
Transporter pursuant to Section 3.2 of Service Classification No. 1.
Transporter may unilaterally effect an amendment to Section II of
Exhibit C to reflect any changes made pursuant to said Section 3.2,
which is incorporated herein by reference, and/or pursuant to
Commission authorization or direction. Any rates or differentials so
specified shall be increased pursuant to Section 16 of the above
referenced General Information.
2. It is further agreed that Transporter may seek authorization from
the Commission and/or other appropriate body for such changes to any
rate(s) and terms set forth herein or in Service Classification No. 1
or in the General Information as may be found necessary to assure
Transporter just and reasonable rates and terms. Nothing herein
contained shall be construed to deny Shipper any rights it may have
under applicable law, including the right to participate fully in
rate proceedings by intervention or otherwise to contest increased
rates in whole or in part.
ARTICLE VI
1. Definition. The term "force majeure" as used herein shall mean
acts of God, strikes, lockouts, or other industrial disturbances;
acts of the public enemy, wars, blockades, insurrections, riots,
epidemics, landslides, lightning, earthquakes, fires, storms
(including but not limited to hurricanes or hurricane warnings),
crevasses, floods, washouts; arrests and restraints of the
government, either Federal or State, civil or military; and civil
disturbances. Relative to Transporter's service and solely to the
operation of its system, force majeure shall also mean shutdowns for
<PAGE 3>
purposes of necessary repairs, relocation, or construction of
facilities; breakage or accident to machinery or lines of pipe; the
necessity for testing (as required by governmental authority or as
deemed necessary by Transporter for the safe operation thereof), the
necessity of making repairs or alterations to machinery or lines of
pipe; failure of surface equipment or pipe lines; accidents,
breakdowns, inability to obtain necessary materials, supplies or
permits, or labor to perform or comply with any obligation or
condition of this Agreement, rights of way; and any other causes,
whether of the kind herein enumerated or otherwise which are not
reasonably in Transporter's control. It is understood and agreed that
the settlement of strikes or lockouts or controversies with
landowners involving rights of way shall be entirely within
Transporter's discretion and that the above requirement that any
force majeure shall be remedied with all reasonable dispatch shall
not require the settlement of strikes or lockouts or controversies
with landowners involving rights of way by acceding to the demands of
the opposing party when such course is inadvisable in the discretion
of Transporter.
2. Force Majeure. If by reason of force majeure either party hereto
is rendered unable, wholly or in part, to carry out its obligations
under this Agreement, it is agreed that if such party gives notice in
full particulars of such force majeure in writing or by telecopy to
the other party within a reasonable time after the occurrence of the
cause relied on, the party giving such notice, so far as and to the
extent that it is affected by such force majeure, shall not be liable
for damages during the continuance of any inability so caused, but
for no longer period, and such cause shall so far as possible be
remedied with all reasonable dispatch. Transporter shall not be
liable for damages to Shipper other than for acts of gross negligence
or willful misconduct, and only in circumstances in which conditions
of force majeure do not exist.
3. Limitations. Such force majeure affecting the performance
hereunder by either Transporter or Shipper, however, shall not
relieve such party of liability in the event of failure to use due
diligence to remedy the situation and to remove the cause in an
adequate manner and with all reasonable dispatch, nor shall such
causes or contingencies affecting such performance relieve Shipper
from its obligations to make payments then due or becoming due under
this agreement.
ARTICLE VII
1. Payment. Shipper shall pay Transporter the amount due for the
preceding Month on or before the twenty-fifth (25th) Day of the
Month. All payments by Shipper to Transporter shall be made in the
form of wire transfer directed to a bank account
<PAGE 4>
designated by Transporter's Controller or by check at Transporter's
general of office, or at such other address as Transporter shall
designate such that funds are available on the date payment is due.
If rendering of a bill by Transporter is delayed after the tenth
(10th) Day of the Month, then the time of payment shall be extended
accordingly unless Shipper is responsible for such delay.
Should Shipper fail to pay all of the amount of any bill as herein
provided when such amount is due, interest on the unpaid portion of
the bill shall accrue at the prime rate or rates charged by Citibank,
N.A. New York, New York to responsible commercial and industrial
borrowers, plus two percentage points, for each of the Months from
the due date until the date of payment. Transporter may also impose
late payment or failure to pay charges not inconsistent with
regulations or orders of the Commission. If such failure to pay
continues for thirty (30) Days after payment is due, Transporter, in
addition to any other remedy it may have hereunder, shall upon notice
to Shipper, suspend further delivery of Gas until such amount is
paid; provided, however, that if Shipper in good faith shall dispute
the amount of any such bill or part thereof and shall pay to
Transporter such amounts, if any, as it concedes to be correct and,
at any time thereafter within thirty (30) Days of a demand made by
Transporter, shall furnish a good and sufficient surety bond in an
amount and with surety satisfactory to Transporter or other assurance
acceptable to Transporter, guaranteeing payment to Transporter of the
amount ultimately found due upon such bill after a final
determination which may be reached either by agreement or judgment of
the courts, as may be the case, then Transporter shall not be
entitled to suspend further delivery of such Gas unless and until
default be made in the conditions of such bond. In the event
Transporter suspends delivery of Gas for non payment by Shipper, and
Shipper continues non payment for thirty (30) Days after such
suspension, Shipper shall be deemed to have consented to termination
of its Service Agreement and abandonment of service. Written notice
of any termination and abandonment shall be given to Shipper at least
seventy-two (72) hours before such termination and abandonment, and
shall include an adequate explanation.
If there are claimed errors in a billing hereunder and Shipper and
Transporter are unable to agree relative thereto, any resort by
either of the parties to legal proceedings shall be commenced within
fifteen (15) Months after the supposed cause of action is alleged to
have arisen, or shall thereafter be forever barred.
<PAGE 5>
2. Responsibility for Gas. Shipper shall be deemed in exclusive
control and possession of the Gas until such Gas has been delivered
to Transporter at the Point of Receipt and after such Gas has been
redelivered to or for the account of Shipper at the Point of
Delivery. Transporter shall be in exclusive control and possession of
such Gas between the Point(s) of Receipt and the Point(s) of Delivery
set forth in this Agreement. The party which shall be in exclusive
control and possession of such Gas shall be responsible for all
injury or damage caused thereby to any third party.
3. Indemnification of Transporter. In the absence of gross negligence
or willful misconduct on the part of Transporter's officers,
employees or agents, Shipper waives and indemnities against any and
all claims against Transporter, its officers, employees or agents,
arising out of or in any way connected with (i) the quality, use or
condition of the Gas after delivery from Transporter's line for the
account of such Shipper; (ii) any losses or shrinkage of Gas during
or resulting from transportation hereunder; and (iii) all other
claims and demands arising out of the performance of the duties of
the Transporter, its officers, employees or agents. Shipper agrees to
supply Transporter with a waiver of subrogation of Shipper's
insurance company for all claims subject to the indemnification and
the save harmless provisions covered by this paragraph.
4. Warranty. Shipper warrants for itself, its successors, and
assigns, that it has, or will have, at the time of delivery of the
Gas for transportation hereunder, good title to such Gas to be
delivered to Transporter for Transportation, or the contractual right
to allow and cause such gas to be delivered to and transported by
Transporter. Shipper warrants for itself, its successors, and
assigns, and any person(s) which grant such contractual right to
Shipper, that the Gas it warrants hereunder shall be free and clear
of all liens, encumbrances or claims, that it will indemnify and save
Transporter harmless from all suits, actions, debts, accounts,
damages, costs, losses, and expenses arising from or out of any
adverse claims of any and all persons to said Gas and/or to
royalties, taxes, license fees, or charges thereon which are directly
applicable to such delivery of Gas and that it will indemnify and
save Transporter harmless from all taxes or assessments which may be
directly levied and assessed upon such delivery and which are by law
payable and the obligation of the party making such delivery.
5. waivers. No waiver by either Transporter or Shipper of any one
or more defaults by the other in the performance of any provisions
hereunder shall operate or be construed as a waiver of any future
default or defaults, whether of a like or a different character.
<PAGE 6>
Transporter may waive enforcement of provisions of its tariff, where
economically and operationally feasible.
6 Interpretation of Laws. This Agreement shall be interpreted,
performed and enforced in accordance with the laws of the State of
New York.
7. No Third Party Beneficiary. It is expressly agreed that there is
no Third Party Beneficiary of this Agreement, and that the provisions
of this Agreement and this General Information do not impart
enforceable rights in anyone who is not a party or successor or
assignee of any party to this Agreement.
8. Counterparts. This Agreement may be executed in any number of
counterparts, each of which shall be deemed an original, but all of
which together shall constitute but one and the same instrument.
9. Headings. The headings contained in this Agreement are for
reference purposes only and shall not affect the meaning or
interpretation of this Agreement.
ARTICLE VIII
NOTICE
1. Except as may be otherwise provided, any notice, request, demand,
statement or bill provided for in this Agreement or any notice which
a party may desire to give the other shall be in writing and mailed
by regular mail, effective as of the postmark date, to the post
office address of the party intended to receive the same, as follows:
Transporter: Empire State Pipeline
500 Renaissance Center
Detroit, Michigan 48243
Attention: Gas Control (Nominations)
Gas Measurement (Meter Statements)
Volume Management (Other Statements)
Cash Control (Payments)
System Marketing
(All other matters)
Shipper: National Fuel Gas Distribution Corporation
10 Lafayette Square
Buffalo, New York 14203
Attention: Contract Administration (invoices)
Walter E. DeForest, Senior V.P.
(all other matters)
<PAGE 7>
CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2
ARTICLE IX
MISCELLANEOUS
1. Transporter and Shipper further agree as follows:
a. Shipper represents and warrants, to the satisfaction of the
Federal Energy Regulatory Commission, Transporter and the Commission,
that, until Transporter obtains the necessary regulatory
authorization to transport gas in interstate commerce, all Gas
transported hereunder shall be consumed in the State of New York.
b. Shipper shall pay Transporter a rate for the service provided
hereunder which, in no event, shall be less than the minimum rate,
nor greater than the maximum rate, approved by the Commission, and as
set forth in Transporter's Schedule for Gas Service. Subject to the
foregoing, Shipper shall pay Transporter a total rate, which [
].
CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2
c. It is understood and agreed that Shipper shall have the right to
defer commencement of 27,300 Dth per day of the service hereunder. If
Shipper defers service for such quantity, service for such quantity
shall commence no later than [ ].
CONFIDENTIAL TREATMENT OF BRACKETED MATERIAL REQUESTED PURSUANT TO RULE 24b-2
<PAGE 8>
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their respective officers or Representatives thereunto duly
authorized.
EMPIRE STATE PIPELINE
(Transporter)
By /s/ Richard A. Lietz
Its Chairman of the Management Committee
ATTEST: NATIONAL FUEL GAS DISTRIBUTION COMPANY
(Shipper)
/s/ David F. Smith By /s/ Walter E. DeForest
Secretary Its Sr. Vice President
<PAGE 9>
EXHIBIT "A"
to
Agreement between
Empire State Pipeline (Transporter)
and
NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Shipper)
Dated______________________________
POINT(S) OF RECEIPT AND PRESSURES
---------------------------------
Point(s) of Receipt by Transporter
Maximum Allowable
Measuring Operating Pressure
Number Name Location Party "NMOP"
- --------- --------- ---------- --------- ------------------
012000010 CHIPPAWA CHANNEL
(EMPIRE/TCPL)
<PAGE 10>
EXHIBIT "B"
to
Agreement between
Empire State Pipeline (Transporter)
and
NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Shipper)
Dated_______________________
POINT(S) OF DELIVERY BY TRANSPORTER
-----------------------------------
Measuring
Number Name Location Party
- --------- ------------ --------- -----
012003010 GRAND ISLAND
(EMPIRE/NFGS)
<PAGE 11>
EXHIBIT "C"
to
Agreement between
Empire State Pipeline (Transporter)
and
NATIONAL FUEL GAS DISTRIBUTION CORPORATION (Shipper)
Dated____________________________
MAXIMUM DAILY
QUANTITY, TRANSPORTATION
AND ADDITIONAL CHARGES
------------------------
I. MAXIMUM DAILY QUANTITY
Point(s) of Receipt Point(s) of Delivery Maximum Daily
Number(s) Number(s) Quantity (Dth)
- ------------------- -------------------- --------------
012000010 012003010 40,112
II. TRANSPORTATION AND ADDITIONAL CHARGES
Effective
Point(s) Point(s) Transportation Effective
of Receipt of Delivery Charge Other
Number(s) Number(s) ($ per Dth) Charges
- ---------- ----------- -------------- ---------
012000010 012003010 Reservation Charge: (1) (1)
Commodity Charge: (1) (1)
Note: (1) Refer to Service Classification No. 1. of Transporter's New York
Public Service Commission's Gas Tariff.
SERVICE AGREEMENT
(ESS Service)
AGREEMENT made this 1st day of August, 1993, by and between National
Fuel Gas Supply Corporation, a Pennsylvania corporation, hereinafter called
"Transporter," and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter
called "Shipper."
WITNESSETH: That in consideration of the mutual covenants
herein contained, the parties hereto agree that Transporter will store natural
gas for Shipper during the term, at the rates and on the terms and conditions
hereinafter provided.
ARTICLE I
Quantities
Beginning on the date on which storage service is commenced
hereunder and thereafter for the remaining term of this Agreement, and subject
to the provisions of Transporter's ESS Rate Schedule Transporter agrees to
cause to be injected into storage for Shipper's account, store, and withdraw
from storage, quantities of natural gas as follows:
Maximum Storage Quantity (MSQ) of 23,882,071 Dekatherms (Dth)
Maximum Daily Injection Quantity (MDIQ) of 140,483 Dth
Maximum Daily Withdrawal Quantity (MDWQ) of 511,633 Dth
ARTICLE II
Rate
Unless otherwise mutually agreed in a written amendment to
this Agreement, for each dekatherm of gas transported for Shipper by Transporter
hereunder, Shipper shall pay Transporter the maximum rate provided under Rate
Schedule ESS set forth in Transporter's effective FERC Gas Tariff. In the event
that the Transporter places on file with the Federal Energy Regulatory
Commission ("Commission") another rate schedule which may be applicable to
transportation service rendered hereunder, then Transporter, at its option, may
from and after the effective date of such rate schedule, utilize such rate
schedule in performance of this Agreement. Such a rate schedule(s) or
superseding rate schedule(s) and any revisions thereof which shall be filed and
<PAGE 2>
become effective shall apply to and be a part of this Agreement. Transporter
shall have the right to propose, file and make effective with the Commission,
or other body having jurisdiction, changes and revisions of any effective rate
schedule(s), or to propose, file, and make effective superseding rate schedules,
for the purpose of changing the rate, charges, and other provisions thereof
effective as to Shipper.
Shipper agrees to reimburse Transporter for the filing fees
associated with this service and paid to the Commission.
ARTICLE III
Term of Agreement
This Agreement shall be effective as of the effective date of
the tariff sheets implementing the restructuring of Transporter's services in
Docket No. RS92-21, and shall continue in effect until March 31, 2003, and shall
continue in effect from year to year thereafter until terminated by either
Shipper or Transporter effective as of April 1st of any year, upon twelve (12)
months written notice to the other.
ARTICLE IV
Regulatory Approval
Performance under this Agreement by Transporter and Shipper
shall be contingent upon Transporter and Shipper receiving all necessary
regulatory or other governmental approvals upon terms satisfactory to each.
Should Transporter and Shipper be denied such approvals to provide the service
contemplated herein or construct and operate any necessary facilities therefor
upon the terms and conditions requested in the application therefor, then
Transporter's and Shipper's obligations hereunder shall terminate.
ARTICLE V
Incorporation By Reference of Tariff Provisions
To the extent not inconsistent with the terms and conditions
of this agreement, the provisions of Rate Schedule FT, or any effective
superseding rate schedule or otherwise applicable rate schedule, including any
provisions of the General Terms and Conditions incorporated therein, and any
<PAGE 3>
revisions thereof that may be made effective hereafter are
hereby made applicable to and a part hereof by reference.
ARTICLE VI
Miscellaneous
1. No change, modification or alteration of this Agreement
shall be or become effective until executed in writing by the parties hereto,
and no course of dealing between the parties shall be construed to alter the
terms hereof, except as expressly stated herein.
2. No waiver by any party of any one or more defaults by the
other in the performance of any provisions of this Agreement shall operate or be
construed as a waiver of any other default or defaults, whether of a like or of
a different character.
3. Any company which shall succeed by purchase, merger or
consolidation of the gas related properties, substantially as an entirety, of
Transporter or of Shipper, as the case may be, shall be entitled to the rights
and shall be subject to the obligations of its predecessor in title under this
Agreement. Either party may, without relieving itself of its obligations under
this Agreement, assign any of its rights hereunder to a company with which it is
affiliated, but otherwise, no assignment of this Agreement or of any of the
rights or obligations hereunder shall be made unless there first shall have been
obtained the consent thereto in writing of the other party. Consent shall not be
unreasonably withheld.
4. Except as herein otherwise provided, any notice, request,
demand, statement or bill provided for in this Agreement, or any notice which
either party may desire to give the other, shall be in writing and shall be
considered as duly delivered when mailed by registered or certified mail to the
Post Office address of the parties hereto, as the case may be, as follows:
Transporter: National Fuel Gas Supply
Corporation
Gas Supply - Transportation
Room 1200
10 Lafayette Square
Buffalo, New York 14203
<PAGE 4>
Shipper: National Fuel Gas Distribution
Corporation
10 Lafayette Square
Buffalo, New York 14203
or at such other address as either party shall designate by formal written
notice. Routine communications, including monthly statements, shall be
considered as duly delivered when mailed by either registered, certified, or
ordinary mail, electronic communication, or telecommunication.
5. Transporter and Shipper shall proceed with due diligence to
obtain such governmental and other regulatory authorizations as may be required
for the rendition of the services contemplated herein, provided that Transporter
reserves the right to file and prosecute applications for such authorizations,
any supplements or amendments thereto and, if necessary, any court review, in
such manner as it deems to be in its best interest, including the right to
withdraw the application or to file pleadings and motions (including motions for
dismissal).
6. This Agreement and the respective obligations of the
parties hereunder are subject to all present and future valid laws, orders,
rules and regulations of constituted authorities having jurisdiction over the
parties, their functions or gas supply, this Agreement or any provision hereof.
Neither party shall be held in default for failure to perform hereunder if such
failure is due to compliance with laws, orders, rules or regulations of any such
duly constituted authorities.
7. The subject headings of the articles of this Agreement are
inserted for the purpose of convenient reference and are not intended to be a
part of the Agreement nor considered in any interpretation of the same.
8. No presumption shall operate in favor of or against either
party hereto as a result of any responsibility either party may have had for
drafting this Agreement.
9. The interpretation and performance of this Agreement shall
be in accordance with the laws of the State of Pennsylvania, without recourse to
the law regarding the conflict of laws.
IN WITNESS WHEREOF, the parties hereto have caused this
Agreement to be signed by their respective Presidents or Vice Presidents
thereunto duly authorized and their respective corporate seals to be hereto
<PAGE 5>
affixed and attested by their respective Secretaries and Assistant Secretaries,
the day and year first above written.
NATIONAL FUEL GAS SUPPLY
CORPORATION
Transporter
Attest:
/s/ Richard M. DiValerio By /s/ Richard Hare
Secretary President
(Corporate Seal)
NATIONAL FUEL GAS DISTRIBUTION
CORPORATION
Shipper
Attest:
/s/ David F. Smith By /s/ Philip C. Ackerman
Secretary President
(Corporate Seal)
SERVICE AGREEMENT
(ESS Service)
AGREEMENT made this 19th day of September 1995, by and between
NATIONAL FUEL GAS SUPPLY CORPORATION, a Pennsylvania corporation, hereinafter
called "Transporter", and NATIONAL FUEL GAS DISTRIBUTION CORPORATION,
hereinafter called "Shipper".
WITNESSETH: That, in consideration of the mutual covenants herein
contained, the parties hereto agree that Transporter will store natural gas for
Shipper during the term, at the rates and on the terms and conditions
hereinafter provided.
ARTICLE I
Quantities
Beginning on the date on which storage service is commenced hereunder
and thereafter for the remaining term of this Agreement, and subject to
the provisions of Transporter's ESS Rate Schedule, Transporter agrees to cause
to be injected into storage for Shipper's account, store, and withdraw from
storage, quantities of natural gas as follows:
Maximum Storage Quantity (MSQ) of 2,000,000 Dekatherms (Dth)
Maximum Injection Quantity (Contract MDIQ) of 11,765 Dth
Maximum Withdrawal Quantity (Contract MDWQ) of 13,245 Dth
ARTICLE II
Rate
Unless otherwise mutually agreed in a written amendment to this
Agreement, or unless a different rate is specified in the release forms attached
hereto, for each dekatherm of gas transported for Shipper by Transporter
hereunder, Shipper shall pay Transporter the maximum rate provided under Rate
Schedule ESS set forth in Transporter's effective FERC Gas Tariff. In the event
that the Transporter places on file with the Federal Energy Regulatory
Commission ("Commission") another rate schedule which may be applicable to
transportation service rendered hereunder, then Transporter, at its option, may
from and after the effective date of such rate schedule, utilize such rate
schedule in performance of this Agreement. Such a rate schedule(s) or
<PAGE 2>
superseding rate schedule(s) and any revisions thereof which shall be filed
and become effective shall apply to and be a part of this Agreement. Transporter
shall have the right to propose, file and make effective with the Commission,
or other body having jurisdiction, changes and revisions of any effective rate
schedule(s), or to propose, file, and make effective superseding rate schedules,
for the purpose of changing the rate, charges, and other provisions thereof
effective as to Shipper.
Shipper agrees to reimburse Transporter for the filing fees associated
with this service and paid to the Commission.
ARTICLE III
Term of Agreement
This Agreement shall be effective as of January 1996, and shall
continue in effect until April 15, 2006, and shall continue in effect thereafter
until terminated by either Shipper or Transporter effective as of April 1 of
any year, upon twelve (12) months' written notice to the other.
ARTICLE IV
Regulatory Approval
Performance under this Agreement by Transporter and Shipper shall be
contingent upon Transporter and Shipper receiving all necessary regulatory or
other governmental approvals upon terms satisfactory to each. Should
Transporter and Shipper be denied such approvals to provide the service
contemplated herein or construct and operate any necessary facilities
therefor upon the terms and conditions requested in the application
therefor, then Transporter's and Shipper's obligations hereunder shall
terminate.
In particular, performance under this Agreement shall be contingent
upon permanent certification of Transporter's storage facilities at Allegany
State Park.
ARTICLE V
Incorporation By Reference of Tariff Provisions
To the extent not inconsistent with the terms and conditions of this
Agreement, the provisions of Rate Schedule ESS, or any effective superseding
rate schedule or otherwise applicable rate schedule, including any provisions
of the General Terms and Conditions incorporated therein, and any revisions
<PAGE 3>
thereof that may be made effective hereafter are hereby made applicable to and a
part hereof by reference.
ARTICLE VI
Miscellaneous
1. No change, modification or alteration of this Agreement
shall be or become effective until executed in writing by the parties hereto,
and no course of dealing between the parties shall be construed to alter the
terms hereof, except as expressly stated herein.
2. No waiver by any party of any one or more defaults by the
other in the performance of any provisions of this Agreement shall operate or be
construed as a waiver of any other default or defaults, whether of a like or of
a different character.
3. Any company which shall succeed by purchase, merger or
consolidation of the gas related properties, substantially as an entirety, of
Transporter or of Shipper, as the case may be, shall be entitled to the rights
and shall be subject to the obligations of its predecessor in title under this
Agreement. Either party may, without relieving itself of its obligations under
this Agreement, assign any of its rights hereunder to a company with which it is
affiliated, but otherwise, no assignment of this Agreement or of any of the
rights or obligations hereunder shall be made unless there first shall have been
obtained the consent thereto in writing of the other party. Consent shall not be
unreasonably withheld.
4. Except as herein otherwise provided, any notice, request,
demand, statement or bill provided for in this Agreement, or any notice which
either party may desire to give the other, shall be in writing and shall be
considered as duly delivered when mailed by registered or certified mail to the
Post Office address of the parties hereto, as the case may be, as follows:
Transporter: National Fuel Gas Supply
Corporation
Gas Supply - Transportation
Room 1200
10 Lafayette Square
Buffalo, New York 14203
<PAGE 4>
Shipper: National Fuel Gas Distribution
Corporation
10 Lafayette Square
Buffalo, New York 14203
or at such other address as either party shall designate by formal written
notice. Routine communications, including monthly statements, shall be
considered as duly delivered when mailed by either registered, certified, or
ordinary mail, electronic communication, or telecommunication.
5. Transporter and Shipper shall proceed with due diligence to
obtain such governmental and other regulatory authorizations as may be required
for the rendition of the services contemplated herein, provided that Transporter
reserves the right to file and prosecute applications for such authorizations,
any supplements or amendments thereto and, if necessary, any court review, in
such manner as it deems to be in its best interest, including the right to
withdraw the application or to file pleadings and motions (including motions for
dismissal).
6. This Agreement and the respective obligations of the
parties hereunder are subject to all present and future valid laws, orders,
rules and regulations of constituted authorities having jurisdiction over the
parties, their functions or gas supply, this Agreement or any provision hereof.
Neither party shall be held in default for failure to perform hereunder if such
failure is due to compliance with laws, orders, rules or regulations of any such
duly constituted authorities.
7. The subject headings of the articles of this Agreement are
inserted for the purpose of convenient reference and are not intended to be a
part of the Agreement nor considered in any interpretation of the same.
8. No presumption shall operate in favor of or against either
party hereto as a result of any responsibility either party may have had for
drafting this Agreement.
9. The interpretation and performance of this Agreement shall
be in accordance with the laws of the State of Pennsylvania, without recourse to
the law regarding the conflict of laws.
10. Upon the date performance commences under this Agreement,
the ESS Service Agreement dated June 23, 1994 (Agreement #36604) between
Transporter and Shipper shall terminate.
<PAGE 5>
The parties hereto have caused this Agreement to be signed by
their respective Presidents or Vice Presidents thereunto duly authorized and
their respective corporate seals to be hereto affixed and attested by
their respective Secretaries and Assistant Secretaries, the day and year first
above written.
NATIONAL FUEL GAS SUPPLY
CORPORATION
(Transporter)
/s/ William A. Ross
William A. Ross
Vice President
NATIONAL FUEL GAS DISTRIBUTION
CORPORATION
(Shipper)
/s/ Walter E. DeForest
Walter E. DeForest
Senior Vice President
SERVICE AGREEMENT
(EFT Service)
AGREEMENT made this 1st day of August, 1993, by and between NATIONAL FUEL
GAS SUPPLY CORPORATION, a Pennsylvania corporation, hereinafter called
"Transporter" and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter called
"Shipper."
WHEREAS, Shipper has requested that Transporter transport natural gas; and
WHEREAS, Transporter has agreed to provide such transportation for Shipper
subject to the terms and conditions hereof.
WITNESSETH: That, in consideration of the mutual covenants herein
contained, the parties hereto agree that Transporter will transport for Shipper,
on a firm basis, and Shipper will furnish, or cause to be furnished, to
Transporter natural gas for such transportation during the term hereof, at the
prices and on the terms and conditions hereinafter provided.
ARTICLE I
Quantities
Beginning on the date on which deliveries of gas are commenced hereunder
and thereafter for the remaining term of this Agreement, and subject to the
provisions of Transporter's EFT Rate Schedule, Transporter agrees to transport
for Shipper's account up to the following quantities of natural gas:
Contract Maximum Daily Transportation Quantity (MDTQ) of 1,148,648 Dekatherms
(Dth)
ARTICLE II
Rate
Unless otherwise mutually agreed in a written amendment to this Agreement,
for each dekatherm of gas transported for Shipper by Transporter hereunder,
Shipper shall pay Transporter the maximum rate provided under Rate Schedule EFT
set forth in Transporter's effective FERC Gas Tariff. In the event that the
Transporter places on file with the Federal Energy Regulatory Commission
("Commission") another rate schedule which may be applicable to transportation
service rendered hereunder, then Transporter, at its option, may from and after
the effective date of such rate schedule, utilize such rate schedule in
performance of this Agreement. Such a rate schedule(s) or superseding rate
schedule(s) and any revisions thereof which shall be filed and become effective
shall apply to and be a part of this Agreement. Transporter shall have the right
to propose, file and make effective with the Commission, or other body having
jurisdiction, changes and revisions of any effective rate schedule(s), or to
propose, file, and make effective superseding rate schedules, for the purpose of
changing the rate, charges, and other provisions thereof effective as to
Shipper.
<PAGE 2>
Shipper agrees to reimburse Transporter for the filing fees associated with
this service and paid to the Commission.
ARTICLE III
Term of Agreement
This Agreement shall be effective as of the effective date of the tariff
sheets implementing the restructuring of Transporter's services in Docket No.
RS92-21, and shall continue in effect until March 31, 2003, and shall continue
in effect from year to year thereafter until terminated by either Shipper or
Transporter upon twelve (12) months written notice to the other.
ARTICLE IV
Points of Receipt and Delivery
The Point(s) of Receipt for all gas that may be received for Shipper's
account for transportation by Transporter, and the receipt entitlements
applicable to each point of receipt, or combinations of receipt points, are set
forth in Appendix A.
The Point(s) of Delivery for all gas to be delivered by Transporter for
Shipper's account are set forth in Appendix B.
ARTICLE V
Incorporation By Reference of Tariff Provisions
To the extent not inconsistent with the terms and conditions of this
agreement, the provisions of Rate Schedule EFT, or any effective superseding
rate schedule or otherwise applicable rate schedule, including any provisions of
the General Terms and Conditions incorporated therein, and any revisions thereof
that may be made effective hereafter are hereby made applicable to and a part
hereof by reference.
ARTICLE VI
Cancellation of Prior Contracts
If this Agreement becomes effective as an executed service agreement, it
shall supersede and cancel all prior firm sales agreements between the parties,
including but not limited to the Service Agreement dated November 1, 1974
between National Fuel Gas Distribution Corporation as Buyer and National Fuel
Gas Supply Corporation as Seller, and the agreement dated October 3, 1952,
between United Natural Gas Company and Mercer Gas Light and Fuel Company.
<PAGE 3>
ARTICLE VII
Miscellaneous
1. No change, modification or alteration of this Agreement shall be or
become effective until executed in writing by the parties hereto, and no course
of dealing between the parties shall be construed to alter the terms hereof,
except as expressly stated herein.
2. No waiver by any party of any one or more defaults by the other in the
performance of any provisions of this Agreement shall operate or be construed as
a waiver of any other default or defaults, whether of a like or of a different
character.
3. Any company which shall succeed by purchase, merger or consolidation of
the gas related properties, substantially as an entirety, of Transporter or of
Shipper, as the case may be, shall be entitled to the rights and shall be
subject to the obligations of its predecessor in title under this Agreement.
Either party may, without relieving itself of its obligations under this
Agreement, assign any of its rights hereunder to a company with which it is
affiliated, but otherwise, no assignment of this Agreement or of any of the
rights or obligations hereunder shall be made unless there first shall have been
obtained the consent thereto in writing of the other party. Consent shall not be
unreasonably withheld.
4. Except as herein otherwise provided, any notice, request, demand,
statement or bill provided for in this Agreement, or any notice which either
party may desire to give the other, shall be in writing and shall be considered
as duly delivered when mailed by registered or certified mail to the Post Office
address of the parties hereto, as the case may be, as follows:
Transporter: National Fuel Gas Supply Corporation
Gas Supply - Transportation
Room 1200
10 Lafayette Square
Buffalo, New York 14203
Shipper: National Fuel Gas Distribution
Corporation
10 Lafayette Square
Buffalo, New York 14203
or at such other address as either party shall designate by formal written
notice. Routine communications, including monthly statements, shall be
considered as duly delivered when mailed by either registered, certified, or
ordinary mail, electronic communication, or telecommunication.
5. Transporter and Shipper shall proceed with due diligence to obtain such
governmental and other regulatory authorizations as may be required for the
rendition of the services contemplated herein, provided that Transporter
reserves the right to file and prosecute applications for such authorizations,
any supplements or amendments thereto and, if necessary, any court review, in
such manner as it deems to be in its best interest, including the right to
withdraw the application or to file pleadings and motions (including motions for
dismissal).
<PAGE 4>
6. This Agreement and the respective obligations of the parties hereunder
are subject to all present and future valid laws, orders, rules and regulations
of constituted authorities having jurisdiction over the parties, their functions
or gas supply, this Agreement or any provision hereof. Neither party shall be
held in default for failure to perform hereunder if such failure is due to
compliance with laws, orders, rules or regulations of any such duly constituted
authorities.
7. The subject headings of the articles of this Agreement are inserted for
the purpose of convenient reference and are not intended to be a part of the
Agreement nor considered in any interpretation of the same.
8. No presumption shall operate in favor of or against either party hereto
as a result of any responsibility either party may have had for drafting this
Agreement.
9. The interpretation and performance of this Agreement shall be in
accordance with the laws of the State of Pennsylvania, without recourse to the
law regarding the conflict of laws.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their duly authorized personnel and attested by their respective
Secretaries or Assistant Secretaries, the day any year first above written.
NATIONAL FUEL GAS SUPPLY
CORPORATION
Transporter
Attest:
/s/ R. M. DiValerio By /s/ Richard Hare
Secretary President
(Corporate Seal)
NATIONAL FUEL GAS DISTRIBUTION
CORPORATION
Shipper
Attest:
/s/ David F. Smith By /s/ P.C. Ackerman
Secretary President
(Corporate Seal)
<PAGE 5>
Appendix A to
EFT Service Agreement
Between
NATIONAL FUEL GAS SUPPLY CORPORATION
AND
NATIONAL FUEL GAS DISTRIBUTION CORPORATION
RECEIPT POINTS AND RECEIPT ENTITLEMENTS
<PAGE 6>
Appendix B to
EFT Service Agreement
Between
NATIONAL FUEL GAS SUPPLY CORPORATION
AND
NATIONAL FUEL GAS DISTRIBUTION CORPORATION
<PAGE 7>
Appendix A is a list of about 2,000 receipt points including some information on
each receipt point. Appendix B is a list of about 2,000 delivery points
including some information on each delivery point. Both Appendices are omitted
from this filing but are available from the Company on request.
AMENDMENT 5/1/95
TO
SERVICE AGREEMENT
(EFT Service)
AGREEMENT made as of May 1, 1995, by and between NATIONAL FUEL GAS
SUPPLY CORPORATION, a Pennsylvania corporation, hereinafter called "Transporter"
and NATIONAL FUEL GAS DISTRIBUTION CORPORATION, hereinafter called "Shipper."
WHEREAS, Transporter and Shipper are parties to a Service Agreement
(EFT Service) dated August 1, 1993 (the "Agreement"); and
WHEREAS, Transporter's effective FERC Gas Tariff provides that Shipper
may request changes in the Primary Receipt Points under the Agreement, which
changes shall be accomplished by amendment of the Agreement; and
WHEREAS, Article II of the Agreement provides that Shipper shall pay
Transporter the maximum rate provided under Rate Schedule EFT set forth in
Transporter's effective FERC Gas Tariff, unless otherwise agreed in a written
amendment to the Agreement; and
WHEREAS, Transporter offered to its qualifying shippers a discounted
rate for the quantity of gas which a shipper requested, within a window period
which expired December 13, 1994, to allocate to the interconnection between the
facilities of Transporter and the facilities of Empire State Pipeline at Grand
Island, New York ("Grand Island") as a primary receipt point; and
WHEREAS, Shipper within the window period accepted Transporter's offer
to discount for a Maximum Daily Transportation Quantity under the Agreement
("MDTQ") of 12,812 Dth/day (the "Grand Island Quantity", subject to reduction as
described in Section 2 below); and
WHEREAS, Shipper and Transporter desire to amend the Agreement to
provide for a different rate and different Primary Receipt Points as set forth
below;
WITNESSETH: That, in consideration of the mutual covenants herein
contained, the parties hereto agree as follows:
1. The first three pages of Appendix A to the Agreement, which identify
some of Shipper's Primary Receipt Points, are hereby deleted and
replaced by the three pages contained in the attached Appendix A.
2. As of May 1, 1995, the discount described below (the "Discount") shall
be effective. To the extent Shipper thereafter requests and receives a
reduction of the portion of his MDTQ which is attributed to Grand
Island as the primary receipt point, the Grand Island Quantity shall be
reduced accordingly.
3. The Discount shall consist of :
(a) first, to the extent permitted by then-current FERC order, a
discount of any applicable Gas Research Institute surcharges;
and then
(b) second, the reduction of Shipper's Reservation Charge (which
is a charge per month per Dth of MDTQ), such that the total
amount of the Discount shall be one dollar and sixty-seven
cents ($1.67) per month per Dth times the Grand Island
Quantity.
(c) The Discount shall consist of a reduction of the
then-currently effective rate which would, absent the
Discount, be charged to Shipper. If, for a month Shipper is
charged a motioned-in rate subject to refund, Shipper shall
thereafter receive a refund which takes into account the
amount Shipper actually paid for that month, to place Shipper
in the same position he would have been by computing the
Discount with respect to the finally approved rate.
(d) Transporter and Shipper agree not to seek before the FERC any
change to the methodology for (i) calculating the rate
applicable to quantities subject to the Discount (the
"Discounted Rate") or (ii) allocating costs or imputing
revenues to the service which is subject to the Discounted
Rate (the "Discounted Service"), including the allocation of
additional system costs to said rate and/or service. If FERC
imputes different revenues and/or allocates different costs to
the Discounted Service in future rate proceedings, the amount
of the Discount shall be subject to decrease on a prospective
basis from the date of the FERC order to fully reflect such
changes. If any such rate proceeding results in a settlement
which does not identify the applicable costs and revenues for
the Discounted Service, but if the written litigation position
of the FERC Staff does expressly identify such costs and
revenues, such litigation position shall be the basis for the
adjustment.
<PAGE>
4. The Discount shall begin on May 1, 1995, and shall continue in effect
so long as the Grand Island Quantity remains more than zero, but for no
longer than the earlier to occur of:
(a) the effective date of termination of the Agreement (for this
purpose the Agreement shall not be considered as effectively
terminated if it is renewed or rolled over into another
service agreement); or
(b) October 31, 2014.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their duly authorized personnel and attested by their respective
Secretaries or Assistant Secretaries, as of the day and year first above
written.
NATIONAL FUEL GAS SUPPLY CORPORATION
Transporter
Attest:
By /s/ Richard Hare
- --------------------- ------------------------------
Secretary President
(Corporate Seal)
NATIONAL FUEL GAS DISTRIBUTION CORPORATION
Shipper
Attest:
By /s/ Philip C. Ackerman
- --------------------- -----------------------------
Secretary President
(Corporate Seal)
<PAGE>
APPENDIX A
Replacement Pages to Exhibit A
<PAGE>
<TABLE>
<CAPTION>
National Fuel Gas Supply Corporation Pipeline Receipt Points
Available to National Fuel Gas Distribution Corporation
Line
Meter Name Meter Number Designation Township County State
<S> <C> <C> <C> <C> <C>
Columbia Gas Transmission Corporation
Ellwood City 600065 N Franklin Beaver PA
First Fork 632291 YM7 Grove Cameron PA
Smethport 630202 D-6 Smethport McKean PA
Sugar Grove 617733 R,U Franklin Warren PA
Ward 622885 PY Ward Allegany NY
Waterford 620549 Q Waterford Erie PA
Wellsville Domestic Accounts 606000 Various Domestic Customers Wellsville Allegany NY
CNG Transmission Corporation
Allegany Domestic Accounts Q38000 Various Domestic Customers Amity Allegany NY
Allegheny National Forest 51051 L Spring Creek Elk PA
Belmont 60185 6" Amity Allegany NY
Caledonia 60154 W/WM2 Caledonia Livingston NY
Consolidated ( Horton ) 9871 ZW384 Horton Elk PA
Donovan 60178 63 Wellsville Allegany NY
East Emporium 601040 FM100 Wharton Potter PA
Ellisburg Station 60288 YM54 Allegany Potter PA
Ellisburg Storage NFSTG Storage Allegany Potter PA
Eshbaugh 51052 C Limestone Clarion PA
Johnsonburg 60047 3" Sheldon Wyoming NY
Porterville 60051 Porterville Station Elma Erie NY
Reef Well 602220 4" Fremont Steuben NY
Sanford 60181 A,B,C Genesee Allegany NY
Silver Springs 60049 8" Genesee Falls Wyoming NY
West Wellsville 60179 67 Wellsville Allegany NY
Wyoming 60050 V Perry Wyoming NY
<PAGE>
Tennessee Gas Pipeline Corporation
Zone 5 points
Clarence 2-0497 XM-2 Clarence Erie NY
Colden Storage 6-0003 T Eden Erie NY
East Aurora 2-0077 X Wales Erie NY
Hamburg(E.Eden) 2-0076 T,X Eden Erie NY
Lewiston 2-0092 8" Lewiston Niagara NY
Mayville 2-0088 6" Chautauqua Chautauqua NY
Nashville Storage 2-0243 RM-32 Hanover Chautauqua NY
Pekin 2-0326 Z Lewiston Niagara NY
Sherman 2-0428 4" Sherman Chautauqua NY
Zone 4 points
Cochranton 2-0314 S-M2 E. Fairfield Crawford PA
Coudersport 2-0074 Y-M2 Hebron Potter PA
Cranberry Sales 2-0703 H Cranberry Venango PA
Hebron Storage 6-0001 Storage Hebron Potter PA
Lamont 2-0072 K Highland Elk PA
Mercer 2-0069 N-M44 Jefferson Mercer PA
Pettis 2-0071 H-M2 Wayne Crawford PA
Rose Lake 2-0527 Y-M2 Allegany Potter PA
Russel City 2-0301 L Highland Elk PA
Sharon 2-0496 N-M51 Pulaski Lawrence PA
Townville 2-0390 4" Townville Crawford PA
Union City 2-0200 Q Union Erie PA
Wattsburg 2-0075 D-20 Wayne Erie PA
East Aurora, NY ( Enserch )
East Aurora 2-0077 X Wales Erie NY
Rate Schedule T - 1
Zone 5 points
Clarence 2-0497 XM-2 Clarence Erie NY
Colden Storage 6-0003 T Eden Erie NY
East Aurora 2-0077 X Wales Erie NY
Hamburg(E.Eden) 2-0076 T,X Eden Erie NY
Zone 4 points
Coudersport 2-0074 Y-M2 Hebron Potter PA
Cranberry Sales 2-0703 H Cranberry Venango PA
Lamont 2-0072 K Highland Elk PA
Mercer 2-0069 N-M44 Jefferson Mercer PA
Pettis 2-0071 H-M2 Wayne Crawford PA
Wattsburg 2-0075 D-20 Wayne Erie PA
Texas Eastern Transmission Corporation
Bristoria 70015 N Rich Hill Greene PA
Empire State Pipeline
Grand Island 012003010 SUPPLY Grand Island Erie NY
Transcontinental Gas Pipeline Corporation
Wharton 6172 YM7 Wharton Potter PA
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Receipt Entitlements
National Fuel Gas Distribution Corporation
------------------------------------------
( all Quantities in Dth )
<S> <C>
Upstream Receipts
Empire State Pipeline 40,122
CNG Transmission Corp. 150,107
Columbia Gas Transmission Corp. 26,165
Texas Eastern Transmission Corp. 72,652
TGP East Aurora, NY 16,300
Zone 4 Points 158,812
Zone 5 Points 82,119
Rate Schedule T-1 Points 30,750
Transcontinental Gas Pipe Line Corp. 26,332
Total Upstream Receipts 603,359
Appalachian Production
New York Production
Central 941
Lakeshore 297
Northern 297
PY3 644
Southeast 340
Pennsylvania Production
Lines L & D 11736
Line Q Erie-Meadville 991
Clarion 248
Dubois 1981
Line Q Forest 594
Hebron 248
Elk County 1685
Eldred 1979
Lines M & N 22253
Lewis Run 2078
Sharon-Mercer 346
---
Total Appalachian Production 46,658
Deliveries from Storage 511,633
-------
Total Receipt Entitlements 1,161,650
=========
</TABLE>
SERVICE AGREEMENT
THIS AGREEMENT entered into this first day of August, 1993, by and between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter
referred to as "Seller," first party, and National Fuel Gas Distribution
Corporation, hereinafter referred to as "Buyer," second party,
WITNESSETH
WHEREAS, pursuant to the requirements of Order Nos. 636, 636-A and 636-B,
issued by the Federal Energy Regulatory Commission, National Fuel Gas Supply
Corporation ("National") has assigned to one of its customers upstream capacity
previously provided under Seller's FT Rate Schedule Contract #0.3698; and
WHEREAS, upon the effective date of this Agreement, the contractual
arrangement between National and Seller is terminated and abandonment of service
under the FT Rate Schedule Contract #0.3698 is automatically authorized; and
WHEREAS, Buyer has been assigned all National's capacity previously
provided under FT Rate Schedule Contract #0.3698, and agrees to such assignment
and assumes National's obligations pursuant to the Service Agreement and
Seller's FT Rate Schedule of Vol. 1 of its FERC Gas Tariff; and
WHEREAS, Seller will provide service hereunder to Buyer pursuant to
Seller's blanket certificate authorization and Rate Schedule FT for the assigned
capacity designated hereinbelow.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of Seller Is
Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas
for transportation and Seller agrees to receive, transport and redeliver natural
gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm
equivalent of a Transportation Contract Quantity ("TCQ") of 25,442 Mcf per day.
2. Transportation service rendered hereunder shall not be subject to
curtailment or interruption except as provided in Section 11 of the General
Terms and Conditions of Seller's FERC Gas Tariff.
ARTICLE II
POINT(S) OF RECEIPT
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt
hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline
system at the varying pressures that may exist in such system from time to time;
provided, however, the pressure of the gas delivered or caused to be delivered
by Buyer shall not exceed the maximum operating pressures) of Seller's pipeline
system at such point(s) of receipt. In the event the maximum operating
pressure(s) of Seller's pipeline system, at the point(s) of receipt hereunder,
is from time to time increased or decreased, then the maximum allowable
pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at
the point(s) of receipt shall be correspondingly increased or decreased upon
<PAGE 2>
SERVICE AGREEMENT
(Continued)
written notification of Seller to Buyer. The point (s) of receipt for natural
gas received for transportation pursuant to this agreement shall be:
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas
transported hereunder at the following point (s) of delivery and at a pressure
(s) of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of August 1, 1993 and shall remain in
force and effect until 8:00 a.m. Eastern Standard Time October 31, 2004 and
thereafter until terminated by Seller or Buyer upon at least three (3) years
prior written notice; provided, however, this agreement shall terminate
immediately and, subject to the receipt of necessary authorizations, if any,
Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable
judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide
adequate security in accordance with Section 8.3 of Seller's Rate Schedule FT.
As set forth in Section 8 of Article II of Seller's August 7, 1989 revised
Stipulation and Agreement in Docket Nos. RP88-68 et.al., (a) pregranted
abandonment under Section 284.221(d) of the Commission's Regulations shall not
apply to any long term conversions from firm sales service to transportation
service under Seller's Rate Schedule FT and (b) Seller shall not exercise its
right to terminate this service agreement as it applies to transportation
service resulting from conversions from firm sales service so long as Buyer is
willing to pay rates no less favorable than Seller is otherwise able to collect
from third parties for such service.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in
accordance with Seller's Rate Schedule FT and the applicable provisions of the
General Terms and Conditions of Seller's FERC Gas Tariff as filed with the
Federal Energy Regulatory Commission, and as the same may be legally amended or
superseded from time to time. Such Rate Schedule and General Terms and
Conditions are by this reference made a part hereof.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or
causes to be delivered to Seller shall include the quantity of gas retained by
Seller for applicable compressor fuel, line loss make-up (and injection fuel
under Seller's Rate Schedule GSS, if applicable) in providing the transportation
service hereunder, which quantity may be changed from time to time and which
will be specified in the currently effective Sheet No. 44 of Volume No. 1 of
this Tariff which relates to service under this agreement and which is
incorporated herein.
<PAGE 3>
SERVICE AGREEMENT
(Continued)
3. In addition to the applicable charges for firm transportation service
pursuant to Section 3 of Seller' s Rate Schedule FT, Buyer shall reimburse
Seller for any and all filing fees incurred as a result of Buyer's request for
service under Seller's Rate Schedule FT, to the extent such fees are imposed
upon Seller by the Federal Energy Regulatory Commission or any successor
governmental authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This Agreement supersedes and cancels as of the effective date hereof
the following contracts):
National Fuel Gas Supply Corporation/Transcontinental Gas Pipe Line
Corporation former FT Service Agreement Contract #0.3698, dated
February 1, 1992.
2. No waiver by either party of any one or more defaults by the other in
the performance of any provisions of this agreement shall operate or be
construed as a waiver of any future default or defaults, whether of a like or
different character.
3. The interpretation and performance of this agreement shall be in
accordance with the laws of the State of Texas, without recourse to the law
governing conflict of laws, and to all present and future valid laws with
respect to the subject matter, including present and future orders, rules and
regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the
parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as
duly delivered when mailed to the other party at the following address:
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
P. 0. Box 1396
Houston, Texas 77251
Attention: Customer Services, Northern
Market Area
(b) If to Buyer:
National Fuel Gas Distribution Corporation
10 Lafayette Square
Buffalo, NY 14203
Attention: Mr. Walter DeForest
Such addresses may be changed from time to time by mailing appropriate notice
thereof to the other party by certified or registered mail.
<PAGE 4>
SERVICE AGREEMENT
(Continued)
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be
signed by their respective officers or representatives thereunto duly
authorized.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(seller)
By /s/ Thomas E. Skains
Thomas E. Skains, Senior Vice President
Transportation and Customer Services
NATIONAL FUEL GAS DISTRIBUTION CORPORATION
By /s/ S. Dennis Holbrook
S. Dennis Holbrook, Vice President
<PAGE 5>
EXHIBIT "A"
(FT) System Contract #.6487
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
1. Suction Side of Seller's Compressor 4,325
station 30 at the Existing Point of
Interconnection between Seller's
Central Texas Lateral and Seller's
Mainline at Wharton County, Texas.
(Station 30 TP#7133)
2. Existing Point of Interconnection 4,325
between Seller and Valero Transmission
company (Seller Meter No. 3396) at
Wharton County, Texas. (Wharton Valero
TP#6690)
3. Existing Point of Interconnection 4,325
between Seller and Meter named
Spanish Camp (Seller Meter
No. 3365) Wharton County, Texas.
(Spanish Camp-Delhi TP#6895)
4. Existing Point of Interconnection 4,325
between Seller and Meter named Denton
Cooley #1 (Seller Meter No. 3331), in
Fort Bend County, Texas.
(Denton Cooley #1 TP#1106)
5. Existing Point of Interconnection between 4,325
Seller and Meter named Randon East (Fulshear)
(Seller Meter No. 1427), in Fort Bend County,
Texas. (Randon East (Fulshear) TP#299)
6. Existing Point of Interconnection 4,325
between Seller and Meter named Katy-
Enserch (Seller Meter No. 4259), in
Fort Bend County, Texas. (Katy-
Enserch TP#5518)
7. Existing Point of Interconnection 4,325
between Seller and Houston Pipeline
Company (Seller Meter No. 3364) at
Fulshear, Fort Bend County, Texas.
(Fulshear-HPL TP#6097)
<PAGE 6>
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
8. Existing Point of Interconnection between 4,325
Seller and Meter named White Oak Bayou-
Exxon Gas System, Inc. (Seller Meter No.
3545), in Harris County, Texas.
(White Oak Bayou-EGSI TP#1036)
9. Existing Point of Interconnection 4,325
between Seller and Houston Pipeline
Company (Seller Meter No. 4359) at
Bammel, Harris County, Texas.
(Bammei-HPL TP#6014)
10. Existing Point of Interconnection 4,325
between Seller and Delhi Pipeline
Company (Seller Meter No. 3346) at
Hardin County, Texas.
(Hardin-Delhi TP#6696)
11. Existing Point of Interconnection between 4,325
Seller and Meter named Vidor Field Junction
(Seller Meter No. 3554), in Jasper County,
Texas. (Vidor Field Junction TP#2337)
12. Existing Point of Interconnection between 4,325
Seller and Meter named Starks McConathy
(Seller Meter No. 3535), in Calcasieu Parish,
Louisiana. (Starks McConathy TP#7346)
13. Existing Point of Interconnection between 4,325
Seller and Meter named DeQuincy Intercon
(Seller Meter No. 2698), in Calcasieu Parish,
Louisiana. (DeQuincy Intercon TP#7035)
14. Existing Point of Interconnection between 4,325
Seller and Meter named DeQuincy Great Scott
(Seller Meter No. 3357), in Calcasieu Parish,
Louisiana. (DeQuincy Great Scott TP#6809)
15. Existing Point of Interconnection between 4,325
Seiler and Meter named Perkins-Phillips
(Seller Meter No. 3532), in Calcasieu Parish,
Louisiana. (Perkins-Phillips TP#7508)
<PAGE 7>
Buyer's
Cumulative
Mainline capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
16. Existing Point of Interconnection between 4,325
seller and Meter named Perkins (Intercon)
(Seller Meter No. 3395), in Calcasieu Parish,
Louisiana. (Perkins (Intercon) TP#7036)
17. Existing Point of Interconnection between 4,325
seller and Meter named Perkins East (Seller
Meter No. 2369), in Beauregard Parish,
Louisiana. (Perkins East TP#139)
18. Discharge Side of Seller's Compressor 10,686
station 45 at the Existing point of
Interconnection between Seller's
Southwest Louisiana Lateral and Seller's
Mainline Beauregard Parish, Louisiana.
(Station 45 TP#7101)
19. Existing Point of Interconnection between 10,686
Seller and Texas Eastern Transmission
Corporation. (Seller Meter No. 4198) at
Ragley, Beauregard Parish, Louisiana.
(Ragley-TET TP#6217)
20. Existing Point of Interconnection between 10,686
Seller and Trunkline Gas Company (Seller
Meter No. 4215) at Racjley, Beauregard Parish,
Louisiana. (Ragley-Trunkline TP#6218)
21. Existing Point of Interconnection between 10,686
Seller and Tennessee Gas Transmission
Company (Seller Meter No. 3371) at Kinder,
Allen Parish, Louisiana. (Kinder-TGT TP#6149)**
22. Existing Point of Interconnection between 10,686
Seller and Texas Gas Transmission Corporation
(Seller Meter Nos. 3227, 4314, 4457) at Eunice,
Evangeline Parish, Louisiana.
(Eunice Mamou Tx Gas TP#6923)
23. Suction Side of Seller's Compressor Station 50 15,520
at the Existing Point of Interconnection
between Seller's Central Louisiana Lateral and
Seller's Mainline Evangeline Parish, Louisiana.
(Station 50 TP#6948)
<PAGE 8>
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
24. Existing Point of Interconnection between 15,520
Seller and Columbia Gulf Transmission Corporation
(Seller Meter No. 3142) at Eunice, Evangeline Parish,
Louisiana. (Eunice Evangeline Col. Gulf TP#6414)
25. Discharge Side of Seller's Compressor 15,520
Station 54 at Seller's Washington Storage
Field, St. Landry Parish, Louisiana.
(Station 54 TP#6768)
26. Existing Point of Interconnection between 15,520
Seller and Acadian Pipeline (Seller Meter
No. 3506) in Pointe Coupee Parish, Louisiana.
(Morganza-Acadian Pipeline TP#7060)
27. Existing Point of Interconnection (Seller 15,520
Meter No. 3272) at M.P. 566.92, Morganza Field,
Pointe Coupee Parish, Louisiana.
(Morganza Field TP#576)
28. Existing Point of Interconnection between Seller 15,520
and Meter named West Feliciana Parish-Creole
(Seller Meter No. 4464), in West Feliciana Parish,
Louisiana. (West Feliciana Parish-Creole TP#7165)
29. Existing Point of Interconnection between Seller 15,520
and Mid-Louisiana Gas Company (Seller Meter Nos.
4137, 4184, 3229) at Ethei, East Feliciana Parish,
Louisiana. (Ethel-Mid LA TP#6083)
30. Existing Point of Interconnection between Seller 15,520
and Meter named Liverpool Northwest (Seller Meter
No. 3390), in St. Helena Parish, Louisiana.
(Liverpool Northwest TP#6757)
31. Suction Side of Seller's Compressor Station 62 on 9,922
Seller's Southeast Louisiana Lateral in Terrabonne
Parish, Louisiana. (Station 62 TP#7141)
32. Existing Point of Interconnection between Seller 9,922
and Meter named Terrebonne - LIG in Terrebonne
Parish, Louisiana.(Terrebonne-LIG TP#4123)
<PAGE 9>
Buyer's
Cumulative
Mainline capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
33. Existing Point of Interconnection between Seller 9,922
and Meter named Texas Gas - TLIPCO - Thibodeaux
(Seller Meter No. 3533), in Lafourche Parish,
Louisiana. (TXGT-TLIPCO-Thibodeaux TP#7206)
34. Existing Point of Interconnection between 9,922
Seller and Meter named Romeville-Monterey
Pipeline (Seller Meter No. 4410), in
St. James Parish, Louisiana.
(Romeville-Monterey Pipeline TP#580)
35. Existing Point of Interconnection between 9,922
Seller and Meter named St. James CCIPC
(Seller Meter No. 4462), in St. James Parish,
Louisiana. (St. James CCIPC TP#7164)**
36. Existing Point of Interconnection between 9,922
Seller and Meter named St. James Faustina-
(St. Amelia) (Seller Meter No. 3328), in
St. James Parish, Louisiana.
(St. James Faustina (St. Amelia) TP#6268)**
37. Existing Point of Interconnection between 9,922
Seller and Meter named St. James Acadian
(Seller Meter No. 4366), in St. James Parish,
Louisiana. (St. James Acadian TP#6677)**
38. Existing Point of Interconnection between 9,922
Seller and Meter named Livingston-Flare
(Seller Meter No. 3540), in Livingston Parish,
Louisiana. (Livingston-Flare TP#8739)
39. Existing Point of Interconnection between 9,922
Seller and Florida Gas Transmission Company
(Seller Meter No. 3217) at St. Helena, St.
Helena Parish, Louisiana. (St. Helena FGT TP#6267)
40. Existing Point of Interconnection between 9,922
Seller and Meter named Beaver Dam Creek
(Seller Meter No. 3536), in St. Helena Parish,
Louisiana. (Beaver Dam Creek TP#8218)
41. Suction Side of Seller's Compressor Station 25,442
65 at the Existing Point of Interconnection
between Seller's Southeast Louisiana Lateral
and Seller's Mainline St. Helena Parish,
Louisiana. (Station 65 TP#6685)
<PAGE 10>
Buyer's
Cumulative
Mainline capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
42. Existing Point of Interconnection between 25,442
Seller and Meter named Amite County/Koch
(Seller Meter No. 3332), in Amite County,
Mississippi. (Amite County/Koch TP#6701)
43. Existing Point of Interconnection between 25,442
Seller and Meter named McComb (Seller Meter
No. 3461), in Pike County, Mississippi.
(McComb TP#6446)
44. Existing Point of Interconnection between 25,442
Seller and United Gas Pipeline Company at
Holmesville (Seller Meter No. 3150), Pike
County, Mississippi. (Holmesville-United TP#6128)
45. Discharge Side of Seiler's Compressor Station 25,442
70 at M.P. 661.77 in Walthall County,
Mississippi.
(M.P. 661.77-Station 70 Discharge TP#7142)
46. Existing Point of Interconnection between 25,442
Seller and United Gas Pipeline Company at
Walthall (Seller Meter No. 3095), Walthall
County, Mississippi. (Walthall-UGPL TP#6310)
47. Existing Point of Interconnection between 25,442
Seller and Meter named Darbun-Pruett 34-10
(Seller Meter No. 3446) at M.P. 668.46 on
Seller's Main Transmission Line, Darbun Field,
Walthall County, Mississippi.
(Darbun-Pruett TP#6750)
48. Existing Point of Interconnection between 25,442
Seller and Meter named Ivy Newsome (Seller
Meter No. 3413) in Marion County, Mississippi.
(Ivy Newsome TP#6179)
49. Existing Point of Interconnection between 25,442
Seller and West Oakvale Field at M.P. 680.47-
Marion County, Mississippi.
(M.P. 680.47-West Oakvale Field TP#7144)
<PAGE 11>
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
50. Existing Point of Interconnection between 25,442
Seiler and East Morgantown Field at M.P.
680.47 in Marion County, Mississippi.
(M.P. 680.47-East Morgantown Field TP#7145)
51. Existing Point of Interconnection between 25,442
Seller and Greens Creek Field, at M.P.
681.84 Marion County, Mississippi.
(M.P. 681.84 Greens Creek Field TP#7146)
52. Existing Point of Interconnection between 25,442
Seller and Meter named M.P. 685.00-Oakvale
Unit 6-6 in Jefferson Davis County,
Mississippi.
(M.P. 685.00-Oakvale Unit 6-6 TP#1376)
53. Existing Point of Interconnection between 25,442
Seller and Meter named M.P. 687.23-Oakvale
Field in Marion County, Mississippi.
(M.P. 687.23-Oakvale Field TP#7147)
54. Existing Point of Interconnection between 25,442
Seller and Bassfield at named M.P. 696.40
in Marion County, Mississippi.
(M.P. 696.40 Bassfield TP#9439)
55. Existing Point of Interconnection between 25,442
Seller and Meter named Lithium/Holiday Creek
-Frm (Seller Meter No. 3418), in Jefferson
Davis County, Mississippi.
(Lithium/Holiday Creek-Frm TP#7041)
56. Existing Point of Interconnection between 25,442
Seller and S.W. Sumrall Field and Holiday
Creek at M.P. 692.05-Holiday Creek in
Jefferson Davis, Mississippi.
(M.P. 692.05-Holiday Creek TP#7159)
57. Existing Point of Interconnection between 25,442
Seller and ANR Pipe Line Company at Holiday
Creek (Seller Meter No. 3241), Jefferson
Davis County, Mississippi.
(Holiday Creek-ANR TP#398)
<PAGE 12>
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
58. Existing Point of Interconnection between 25,442
Seller and Mississippi Fuel Company at
Jeff Davis (Seller Meter No. 3252),
Jefferson Davis County, Mississippi.
(Jefferson Davis County-Miss Fuels TP#6579)
59. Existing Point of Interconnection between 25,442
Seller and Meter named Jefferson Davis-Frm
(Seller Meter No. 4420), in Jefferson Davis
County, Mississippi.
(Jefferson Davis-Frm TP#7033)
60. Existing Point of Interconnection between 25,442
Seller and Carson Dome Field M.P. 696.41,
in Jefferson Davis County, Mississippi.
(M.P. 696.41-Carson Dome Field TP#7148)
61. Existing Point of Interconnection between 25,442
Seller and Meter Station named Bassfield-ANR
Company at M.P. 703.17 on Seller's Main
Transmission Line (Seller Meter No. 3238),
Covington County, Mississippi.
(Bassfield-ANR TP#7029)
62. Existing Point of Interconnection between 25,442
Seller and Meter named Patti Bihm #1 (Seller
Meter No. 3468), in Covington County,
Mississippi. (Patti Bihm #1TP#7629)
63. Discharge Side of Seller's Compressor at 25,442
Seller's Eminence Storage Field (Seller
Meter No. 4166 and 3160) at Covington County,
Mississippi. (Eminence Storage TP#5561)
64. Existing Point of Interconnection between 25,442
Seller and Dont Dome Field at M.P. 713.39
in Covington County, Mississippi.
(M.P. 713.39-Dont Dome TP#1396)
65. Existing Point of Interconnection between 25,442
Seller and Endevco in Covington County,
Mississippi.
(Hattiesburg-Interconnect Storage TP#1686)
<PAGE 13>
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
66. Existing Point at M.P. 719.58 on Seller's 25,442
Main Transmission Line (Seller Meter No.
3544), Centerville, Dome Field, Jones County,
Mississippi. (Centerville Dome Field TP#1532)
67. Existing Point of Interconnection between 25,442
Seller and Meter named Calhoun (Seller Meter
No. 3404), in Jones County, Mississippi.
(Calhoun TP#378)
68. Existing Point at M.P. 727.78 on Seller's 25,442
Main Transmission Line, Jones County,
Mississippi.
(Jones County-Gitano TP#7166)
69. Existing Point of Interconnection between 25,442
Seller and a Meter named Koch Reedy Creek
(Seller Meter No. 3333), Jones County,
Mississippi.
(Reedy Creek-Koch TP#670)
70. Existing Point of Interconnection between 25,442
Seller and Meter named Sharon Field
(Seller Meter No. 3000), in Jones County,
Mississippi. (Sharon Field TP#419)
71. Existing Point of Interconnection between 25,442
Seller and Tennessee Gas Transmission Company
at Heidelberg (Seller Meter No. 3109), Jasper
County, Mississippi.
(Heidelberg-Tennessee TP#6120)
72. Existing Point of Interconnection between 25,442
Seller and Mississippi Fuel Company at
Clarke (Seller Meter No. 3254), Clarke
County, Mississippi.
(Clarke County-Miss Fuels TP#6047)
73. Existing Point of Interconnection between 25,442
Seller and Meter named Clarke County-Koch
at M.P. 757.29 in Clarke County, Mississippi.
(Clarke County-Koch TP#5566)
<PAGE 14>
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt (Mcf/day)*
74. Existing Point of Interconnection 25,442
between Seiler's mainline and Mobil Bay
Lateral at M.P. 784.66 in Choctaw County,
Alabama. (Station 85-Mainline Pool TP#6971)
75. Existing Point of Interconnection between 25,442
Seller and Magnolia Pipeline in Chilton County,
Alabama.(Magnolia Pipeline-Interconnect TP#1808)
76. Existing Point of Interconnection between 25,442
Seller and Southern Natural Gas Company, (Seller
Meter No. 4087) at Jonesboro, Clayton County, Georgia.
(Jonesboro-SNG TP#6141)
77. Existing Point of Interconnection between 25,442
Seller and Columbia Gas Transmission (Seller
Meter No. 7157) at Dranesville, Fairfax County,
Virginia.(Dranesville-Colgas TP#6068)**
78. Existing Point of Interconnection between 25,442
Seller and Columbia Gas Transmission (Seller
Meter No. 4080) at Rockville, Baltimore County,
Maryland.(Rockville-Colgas TP#6227)**
79. Existing Point of Interconnection between 25,442
Seller and Columbia Gas Transmission (Seller
Meter No. 3088) at Downington, Chester County,
Pennsylvania.(Downington-Colgas TP#6067)**
80. Existing Point of Interconnection between 25,442
Seller and Texas Eastern Transmission Corporation
(Seller Meter No. 4233) at Skippack, Montgomery
County, Pennsylvania. (Skippack-TET TP#6249)
Buyer shall not tender, without the prior consent of Seller, at any point(s) of
receipt on any day a quantity in excess of the applicable Buyer's Cumulative
Mainline Capacity Entitlement for such point(s) of receipt.
<PAGE 15>
* These quantities do not include the additional quantities of gas retained by
Seller for applicable compressor fuel and line loss make-up provided for in
Article V, 2 of this Service Agreement, which are subject to change as provided
for in Article V, 2 hereof.
** Receipt of gas by displacement only.
<PAGE 16>
Exhibit B
1. Seller's Eminence Storage Field, Prevailing pressure in
Covington County, Mississippi. Seller's pipeline system
not to exceed maximum
allowable operating
pressure.
2. Existing points of interconnection Not less than the available
Between Buyer and Seller near pipeline pressure on
Wharton, Pennsylvania.** Seller's transmission
system at the points of
delivery to Buyer.
3. Existing points of interconnection Not less than the available
between Buyer and Seller at Leidy pipeline pressure on
Clinton, Pennsylvania.* Seller's transmission
system at the points of
delivery to Buyer.
*Receipt of gas by displacement only.
**Including Wharton Storage.
SERVICE AGREEMENT
THIS AGREEMENT entered into this first, day of October, 1993, by and
between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation,
hereinafter referred to as "Seller," first party, and NATIONAL FUEL GAS
DISTRIBUTION CORPORATION, hereinafter referred to as "Buyer," second party,
WITNESSETH
WHEREAS, pursuant to the requirements of Order Nos. 636, 636-A and 636-B,
issued by the Federal Energy Regulatory Commission, Consolidated Natural Gas
Transmission Corporation ("CNG") has assigned to several of its customers
upstream capacity previously provided under Seller's FT Rate Schedule Service
Agreement #.6156; and
WHEREAS, upon the effective date of this agreement, the contractual
arrangement between CNG and Seller is terminated and abandonment of service
under the FT Rate Schedule Service Agreement #.6156 is automatically authorized;
and
WHEREAS, Buyer has been assigned a portion of CNG's capacity previously
provided under FT Rate Schedule Service Agreement #.6156, and agrees to such
assignment and assumes, in part, CNG's obligations pursuant to the Service
Agreement and Seller's FT Rate Schedule of Vol. I of its FERC Gas Tariff; and
WHEREAS, Seller will provide service hereunder to Buyer pursuant to
Seller's blanket certificate authorization and Rate Schedule FT for the assigned
capacity designated hereinbelow.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of Seller's
Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas
for transportation and Seller agrees to receive, transport and redeliver natural
gas to Buyer or for the account of Buyer, on a firm Basis, up to the dekatherm
equivalent of a Transportation Contract Quantity ("TCQ") of 11,390 Mcf per day.
2. Transportation service rendered hereunder shall not be subject to
curtailment or interruption except as provided in Section 11 of the General
Terms and Conditions of Seller's FERC Gas Tariff.
ARTICLE II
POINT(S) OF RECEIPT
Buyer shall deliver or cause to be delivered gas at the points of receipt
hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline
system at the varying pressures that may exist in such system from time to time;
provided, however, the pressure of the gas delivered or caused to be delivered
by Buyer shall not exceed the maximum operating pressures of Seller's pipeline
system at such point(s) of receipt. In the event the maximum operating pressures
of Seller's pipeline system, at the point(s) of receipt hereunder, is from time
to time increased or decreased, then the maximum allowable pressure(s) of the
gas delivered or caused to be delivered by Buyer to Seller at the point(s) of
receipt shall be correspondingly increased or decreased upon
<PAGE 2>
SERVICE AGREEMENT
(Continued)
written notification of Seller to Buyer. The point (s) of receipt for natural
gas received for transportation pursuant to this agreement shall be:
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas
transported hereunder at the following point(s) of delivery and at a pressures)
of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of October 1, 1993 and shall remain in
force and effect until 8:00 a.m. Eastern Standard Time October 31, 2012 and
thereafter until terminated by Seller or Buyer upon at least one year prior
written notice; provided, however, this agreement shall terminate immediately
and, subject to the receipt of necessary authorizations, if any, Seller may
discontinue service hereunder if (a) Buyer, in Seller's reasonable judgement
fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate
security in accordance with Section 8.3 of Seller's Rate Schedule FT. As set
forth in Section 8 of Article II of Seller's August 7, 1989 revised Stipulation
and Agreement in Docket Nos. RP88-68 et.al., (a) pregranted abandonment under
Section 284.221(d) of the Commission's Regulations shall not apply to any long
term conversions from firm sales service to transportation service under
Seller's Rate Schedule FT and (b) Seller shall not exercise its right to
terminate this service agreement as it applies to transportation service
resulting from conversions from firm sales service so long as Buyer is willing
to pay rates no less favorable than Seller is otherwise able to collect from
third parties for such service.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in
accordance with Seller's Rate Schedule FT and the applicable provisions of the
General Terms and Conditions of Seller's FERC Gas Tariff as filed with the
Federal Energy Regulatory Commission, and as the same may be legally amended or
superseded from time to time. Such Rate Schedule and General Terms and
Conditions are by this reference made a part hereof.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or
causes to be delivered to Seller shall include the quantity of gas retained by
Seller for applicable compressor fuel, line loss make-up (and injection fuel
under Seller's Rate Schedule GSS, if applicable) in providing the transportation
service hereunder, which quantity may be changed from time to time and which
will be specified in the currently effective Sheet No. 44 of Volume No. I of
this Tariff which relates to service under this agreement and which is
incorporated herein.
<PAGE 3>
SERVICE AGREEMENT
(Continued)
3. In addition to the applicable charges for firm transportation service
pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall reimburse Seller
for any and all filing fees incurred as a result of Buyer's request for service
under Seller's Rate Schedule FT, to the extent such fees are imposed upon Seller
by the Federal Energy Regulatory Commission or any successor governmental
authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This agreement supersedes and cancels as of the effective date hereof
the following contract(s):
Consolidated Natural Gas Transmission Corporation
and Transcontinental Gas Pipe Line Corporation
former FT Service Agreement #.6156, dated November
1, 1992.
2. No waiver by either party of any one or more defaults by the other in
the performance of any provisions of this agreement shall operate or be
construed as a waiver of any future default or defaults, whether of a like or
different character.
3. The interpretation and performance of this agreement shall be in
accordance with the laws of the State of Texas, without recourse to the law
governing conflict of laws, and to all present and future valid laws with
respect to the subject matter, including present and future orders, rules and
regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the
parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as
duly delivered when mailed to the other party at the following address:
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
P. 0. Box 1396
Houston, Texas 77251
Attention: Customer Services, Northern Market Area
(b) If to Buyer:
National Fuel Gas Distribution Corporation
1O Lafayette Square
Buffalo, NY 14203
Attention: Mr. S. Dennis Holbrook
Such addresses may be changed from time to time by mailing appropriate notice
thereof to the other party by certified or registered mail.
<PAGE 4>
SERVICE AGREEMENT
(Continued)
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be
signed by their respective officers or representatives thereunto duly
authorized.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Seller)
By /s/ Thomas E. Skains
Thomas E. Skains, Senior Vice President
Transportation and Customer Services
NATIONAL FUEL GAS DISTRIBUTION CORPORATION
(Buyer)
By /s/ Philip C. Ackerman
Philip C. Ackerman, ExecuTive Vice President
<PAGE 5>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
1. Existing Point of Interconnection 11,144
between Seller's Central Louisiana and UTOS
(Seller's Meter No. 3500) in Cameron
Parish, Louisiana. (UTOS-TGPL Meter-TP#6402)
2. Existing Point of Interconnection 11,144
between Seller and Florida Gas Transmission
at Vinton (Seller Meter No. 4381) in
Calcasieu Parish, Louisiana. (Vinton-FGT-TP #6304)**
3. Existing Point of Interconnection 11,144
between Seller and Fina at Vinton
(Seller Meter No. 2778) in Calcasieu Parish,
Louisiana. (Vinton-Fina TP#927)**
4. Existing Point of Interconnection 11,144
between Seller and United Gas Pipe Line
at Vinton (Seller Meter No. 4348) in
Calcasieu Parish, Louisiana.
(Vinton-UGPL (Starks) TP#6306)**
5. Existing Point of Interconnection 11,144
between Seller and Tennessee Gas
Transmission at Vinton (Seller Meter No.
4374) in Calcasieu Parish, Louisiana.
(Vinton-TGT (Starks) TP#6349) * *
6. Existing Point of Interconnection 11,144
between Seller and Meter named
Starks McConathy (Seller Meter No. 3535)
in Calsasieu Parish, Louisiana. (
Starks McConathy-TP-#6349)
7. Existing Point of Interconnection 11,144
between Seller and Meter named DeQuincy
Intercon (Seller Meter No. 2698) in
Calcasieu Parish, Louisiana.
(DeQuincy Intercon-TP#7O35)
<PAGE 6>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
8. Existing Point of Interconnection 11,144
between Seller and Meter named De Quincy
Great Scott (Seller Meter No. 3357) in
Calcasieu Parish, Louisiana.
(DeQuincy Great Scott-TP#6809)
9. Existing Point of Interconnection 11,144
between Seller and Meter named
Perkins-Phillips (Seller Meter No. 3532)
in Calcasieu Parish, Louisiana.
(Perkins-Phillips-TP#7508)
10. Existing Point of Interconnection 11,144
between Seller and Meter named Perkins
(Intercon) (Seller Meter No. 3395) in
Calcasieu Parish, Louisiana.
(Perkins(Intercon) TP#7036)
11. Existing Point of Interconnection 11,144
between Seller and Meter named Perkins
East (Seller Meter No. 2369) in Beauregard
Parish, Louisiana. (Perkins - East TP#139)
12. Discharge Side of Seller's 11,144
Compressor Station 45 at the existing
point of Interconnection between Seller's
South west Louisiana Lateral and Seller's
Mainline Beauregard Parish, Louisiana.
(Station 45 TP#7101)
13. Existing Point of Interconnection 11,390
between Seller and Texas Eastern Transmission
Corporation, (Seller Meter No. 4198)
in Ragley, Beauregard Parish, Louisiana.
(Ragley-TET TP#6217)
14. Existing Point of Interconnection 11,390
between Seller and Trunkline Gas Company
(Seller Meter No. 4215) in Ragley, Beauregard
Parish, Louisiana. (Ragley-Trunkline TP#6218)
<PAGE 7>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
15. Existing Point of Interconnection 11,390
between Seller and Tennessee Gas
Transmission Company (Seller Meter No.
3371) in Kinder, Allen Parish, Louisiana.
(Kinder TET-TP#6149)
16. Existing Point of Interconnection 11,390
between Seller and Texas Gas
Transmission Corporation (Seller Meter
No.3227,4314,4457) in Eunice, Evangeline
Parish, Louisiana. (Eunice Mamou Tx
Gas TP#6923)
17. Existing Point of Interconnection 11,390
between Seller and Meter named
Fenris, East (Seller Meter
No. 2394) in Evangeline Parish,
Louisiana. (Fenris East TP#159)
18. Existing Point of Interconnection 159
between Seller and Vermilion Block
16 (Seller Meter No. 4477) in
Offshore Louisiana. (Vermilion
Block 16 TP#53)
19. Existing Point of Interconnection 159
between Seller and Meter named Pecan
Island (Seller Meter No. 2716) in
Vermilion Parish, Louisiana.
(Pecan-Island TP#6924)
20. Existing point of Interconnection 748
between Seller and Cow Island Gas
Processing Plant in Vermilion Parish,
Louisiana. (Cow Island Plant TP#6511)
21. Existing Point of Interconnection 748
between Seller and Meter named
Kaplan-Sabine in Vermilion Parish,
Louisiana. (Kaplan-Sabine TP#6388)
<PAGE 8>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
22. Existing Point of Interconnection 748
between Seller and Meter named
LeLeux-Fla Exploration (Seller Meter
No. 3293) in Vermilion Parish, Louisiana.
(Leleux-Fla Exploration-TP#169)
23. Existing Point of Interconnection 748
between Seller and Tennessee Gas
Transmission at Crowley (Seller Meter
No. 3222) in Acadia Parish, Louisiana.
(Crowley-TGT TP#6058)
24. Existing Point of Interconnection 9,074
between Seller and Meter named
Egan-C Con Gas Con Gas/Col Gulf
(Seller Meter No. 3168) in Acadia
Parish, Louisiana. (Egan-C Con
Gas/Col Gul-TP#6076)
25. Existing Point of Interconnection 9,822
between Seller and Texas Gas
Transmission at Ritchie South
(Seller Meter No. 3517) in Acadia
Parish, Louisiana. (Ritchie
South-TXG TP#7330)
26. Existing Point of Interconnection 9,822
between Seller and ANR at Eunice
(Seller Meter No. 3136 and No. 4136)
in Acadia Parish, Louisiana.
(Eunice - ANR TP#6085)
27. Suction side of Seller's Compressor 11,390
Station 50 at the Existing Point of
Interconnection between Seller's
Central Louisiana Lateral and Seller's
Mainline Evangeline Parish, Louisiana.
(Station 50 TP#6948)
28. Existing Point of Interconnection 11,390
between Seller and Columbia Gulf
Transmission Corporation (Seller Meter
No. 3142) in Eunice, Evangeline Parish.
(Eunice-Evangeline Col. Gulf TP#6414)
<PAGE 9>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
29. Existing Point of Interconnection 11,390
between Seller and Acadian Pipeline
(Seller Meter No. 3506) in Pointe
Coupee Parish, Louisiana.
(Morganza - Acadian TP#7060)
30. Existing Point of Interconnection 11,390
(Seller Meter No. 3272) at M.P. 566.92,
Morganza Field, Pointe Coupee Parish,
Louisiana. (Morganza Field-TP#576)
31. Existing Point of Interconnection 11,390
between Seller and Meter named West
Feliciana Parish-Creole (Seller Meter
No. 4464) in West Feliciana Parish
Louisiana. (West Feliciana Parish-Creole TP#7165)
32. Existing Point of Interconnection 11,390
between Seller and Mid-Louisiana Gas
Company (Seller Meter Nos. 4137,4184 3229)
in Ethel, Feliciana Parish, Louisiana.
(Ethel-Mid LA TP#6083)
33. Existing Point of Interconnection 955
between Seller and Eugene Island Block. 205
(Seller Meter Nos. 2498 and 2535) Offshore
Louisiana. (Eugene Island Block 205 - TP# 9)
34. Existing Point of Interconnection 955
between Seller and Eugene Island Block 195,
Offshore Louisiana. (Eugene Island Block
195-TP#2884)
35. Existing Point of Interconnection 955
between Seller and Eugene Island
Block 126 Mobil, (Seller Meter
No. 4229) Offshore Louisiana.
(Eugene Island Block 128 Mobil
TP-#6788)
<PAGE 10>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
36. Existing Point of Interconnection 955
between Seller and Eugene Island Block
79 Interconnect (Sellers Meter No. 3380)
Offshore Louisiana. (Eugene Island
Block 79 Interconnect TP# 6893)
37. Existing Point of Interconnection 955
between Seller and Meter named Mosquito
Bay-Peltex (Seller Meter No. 2659) in
Terrebonne Parish, Louisiana.
(Mosquito Bay Peltex TP#207)
38. Existing Point of Interconnection 955
between Seller and Meter named Bayou
Penchant (Seller Meter No. 2631)
in Terrebonne Parish, Louisiana.
(Bayou Penchant TP#6650)
39. Existing Point of Interconnection 955
between Seller and Meter named Bayou
Piquant (Seller Meter No. 2191) in
Terrebone Parish, Louisiana.
(Bayou Puquant TP#506)
40. Existing Point of Interconnection 4,776
between Seller and Ship Shoal Block
222/224 (Seller Meter Nos. 2492,2555 2575)
Offshore Louisiana. (Ship Shoal Block 222/224-TP#42)
41. Existing Point of Interconnection 4,776
between Sellers and Ship Shoal Block
190 Junction, Offshore Louisiana.
(Ship Shoal Block 190 Junction - TP #991
42. Existing Point of Interconnection 5,763
between Seller and Ship Shoal Block 185
(186), (Seller Meter No. 2529)
offshore Louisiana. (Ship Shoal Block
185 (186)-TP#6925)
<PAGE 11>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
43. Existing Point of Interconnection 5,763
between Seller and Ship Shoal Block 70
Junction, Offshore Louisiana. (Ship
Shoal Block 70 JunctionTP#6242)
44. Existing Point of Interconnection 5,763
between Seller and Meter named Lake
Decade East-Tenneco (Seller Meter No.
2686 and No. 3528) in Terrebonne Parish,
Louisiana. (Lake Decade East-Tenneco TP#6843)
45. Existing Point of Interconnection 5,763
between Seller and Meter named Lake Hatch
(Seller Meter No. 3291) in Terrebonne
Parish, Louisiana. (Lake Hatch TP#569)
46. Suction side of Seller's Compressor 6,718
Station 62 on Seller's Southeast Louisiana
Lateral in Terrebonne Parish, Louisiana.
(Station 62 TP#7141)
47. Existing Point of Interconnection 6,718
between Seller and Meter named Terrebonne
- LIG in Terrebonne Parish, Louisiana.
(Terrebonne - LIG TP#4123
48. Existing Point of Interconnection 6,718
between Seller and United Gas Pipe Line
at Gibson, (Seller Meter No. 3156) in
Terrebonne Parish, Louisiana.
(Gibson-UGPL TP#6101)
49. Existing Point of Interconnection 6,718
between Seller and Louisiana Interstate
at Hebert (Seller Meter No. 4368) in
Terrebonne Parish, Louisiana. (Hebert-Lig TP#6392)
50. Existing Point of Interconnection 6,718
between Seller and Meter named Texas Gas-TLIPCO
Thibodeaux (Seller Meter No. 3533) in
Lafourche Parish, Louisiana.
(TXGT-TLIPCO-Thibodeaux P#7206)
<PAGE 12>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
51. Existing Point of Interconnection 6,718
between Seller and Meter named St.
James CCIPC (Seller Meter No. 4462)
in St James Parish, Louisiana.
(St. James CCPIC TP# 7164)**
52. Existing Point of Interconnection 6,718
between Seller and Meter named St. James
Faustina (St. Amelia)(Seller No. 3328)
in St. James Parish, Louisiana.
(St. James Faustina (St. Amelia)TP#6268)**
53. Existing Point of Interconnection 6,718
between Seller and Meter named St James
Acadian (Seller Meter No. 4366) in St.
James Parish, Louisiana.
(St. James Acadian-TP#6677)**
54. Existing Point of Interconnection 6,718
between Seller and Meter named Romeville
Monterey Pipeline (Seller Meter No. 4410)
in St James Parish, Louisiana.
(Romeville Monterey Pipeline-TP#580)
55. Existing Point of Interconnection 6,718
between Seller and Meter named Livingston
Flare (Seller Meter No. 3450) in
Livingston Parish, Louisiana.
(Livingston-Flare-TP#8739)
56. Existing Point of Interconnection 6,718
between Seller and Florida Gas Transmission
Company (Seller Meter No. 3217 and No. 4305)
in St. Helena, St. Helena Parish, Louisiana.
(St. Helena FGT-TP#6267)
57. Existing Point of interconnection 6,718
between Seller and Meter named Beaver Dam Creek
(Seller Meter No. 3536) in St. Helena Parish,
Louisiana. (Beaver Dam Creek TP#8218)
<PAGE 13>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
58. Existing Point of Interconnection 6,718
between seller and Meter named Liverpool
Northwest (Seller Meter No. 3390) in
St. Helena Parish, Louisiana.
(Liverpool Northwest-TP#6757)
59. Suction side of Seller's 11,390
compressor Station 65 at the Existing
Point of Interconnection between
Seller's Southeast Louisiana Lateral
and Seller's Mainline St. Helena Parish,
Louisiana. (Station 65 TP#6685)
60. Existing Point of Interconnection 11,390
between Seller and Meter named Amite
County/Koch (Seller Meter No. 3332)
in Amite County, Mississippi.
(Amite County Koch-TP#6701)
61. Existing Point of Interconnection 11,390
between Seller and Meter named McComb
(Seller Meter No. 3461) in Pike County,
Mississippi. (McComb TP#6446)
62. Existing Point of Interconnection 11,390
between Seller and United Gas Pipe
Line company at Holmesville (Seller Meter
no. 3150) Pike County, Mississippi.
(Holmesville-United TP#6128)
63. Discharge Side of Seller's 11,390
Compressor Station 70 at M.P.
661.77 in Walthall County, Mississippi.
(M.P. 661.77Station 70 Discharge TP#7142)
64. Existing Point of Interconnection 11,390
between Seller and United Gas Pipeline
Company A Walthall (Seller Meter No.
3095) in Walthall County, Mississippi.
(Walthall - UGPL TP#-6310)
<PAGE 14>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
65. Existing Point of Interconnection 11,390
between Seller and Meter named Darbun-
Pruett 34-10 (Seller Meter No. 3446)
at M.P. 668.46 on Seller's Main
Transmission Line, Darbun Field, Walthall
County, Mississippi. (Darbun
Pruett TP#6750)
66. Existing Point of Interconnection 11,390
between Seller and Meter named Ivy
Newsome (Seller Meter No. 3413) in
Marion County, Mississippi.
(Ivy Newsome-TP#6179)
67. Existing Point of Interconnection 11,390
between Seller and West Oakvale
Field at M.P. 680.47 Marion County,
Mississippi.(M.P. 680.47-West Oakvale
Field-TP#7144)
68. Existing Point of Interconnection 11,390
between Seller and East Morgantown
Field at M.P. 680.47 in Marion
county, Mississippi. (M.P. 680.47
E. Morgantown Field-TP#7145)
69. Existing Point of Interconnection 11,390
between Seller and Greens Creek
Field, at M.P. 681.84 Marion County,
Mississippi. (M.P. 681.84 Greens
Creek Field TP-#7l46)
70. Existing Point of Interconnection 11,390
between Seller and Meter named M.P.
685.00-Oakville Unit 6-6 in Jefferson
Davis County, Mississippi. (M.P. 685.
00 Oakville Unit 6-6 T.P.#1376)
71. Existing Point of Interconnection 11,390
between Seller and Meter named M.P.
687.23 Oakvale Field in Marion County,
Mississippi. (M.P. 687.23 Oakvale Field
TP#7l47)
<PAGE 15>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
72. Existing Point of Interconnection 11,390
between Seller and Bassfield at named
M.P. 696.40 in Marion County,
Mississippi. (M.P. 696.40 Bassfield-
TP#9439)
73. Existing Point of Interconnection 11,390
between Seller and Meter named Lithium-
Holiday Creel:-Frm (Seller Meter No. 3418)
in Jefferson Davis County, Mississippi.
(Lithium Holiday Creek-Frm-TP#7041)
74. Existing Point of Interconnection 11,390
between Seller and S. W. Sumrall
Field and Holiday creek at M.P. 692.
05-Holiday Creek in Jefferson Davis
County, Mississippi. (M.P. 692.05
Holiday Creek TP#7159)
75. Existing Point of Interconnection 11,390
between Seller and ANR Pipe Line
Company at Holiday Creek (Seller
Meter No. 3241) Jefferson Davis
County, Mississippi. (Holiday
Creek-ANR TPM#398)
76. Existing Point of Interconnection 11,390
between Seller and Mississippi
Fuel Company at Jeff Davis (Seller
Meter No. 3252) in Jefferson Davis
County, Mississippi. (Jefferson Davis
County - Miss Fuels TP#6579)
77. Existing Point of Interconnection 11,390
between Seller and Meter named
Jefferson Davis-Frm (Seller Meter
No. 4420) in Jefferson Davis County,
Mississippi. (Jefferson
Davis-Frm-TP#7033)
<PAGE 16>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
78. Existing Point of Interconnection 11,390
between Seller and Carson Dome Field
M.P. 696.41, in Jefferson Davis County,
Mississippi. (M.P. 696.41 Carson
Dome Field TP#7148)
79. Existing Point of Interconnection 11,390
between Seller and Meter Station named
Bassfield-ANR Company at M.P.
703.17 on Seller's Main Transmission
Line (Seller Meter No. 3238) in Covington
County, Mississippi. (Bassfield
ANR TP#7029)
80. Existing Point of Interconnection 11,390
between Seller and Meter named Patti
Bihm #1 (Seller Meter No. 3468) in
Covington County, Mississippi.
(Patty Bihm #1-TP#7629)
81. Discharge Side of Seller's Compressor 11,390
at Seller's Eminence Storage Field (Seller
Meter 4166 and 3160) Covington County,
Mississippi. (Eminence Storage TP#4103)
82. Existing Point of Interconnection 11,390
between Seller and Dont Dome Field at M.P.
713.39 in Covington, County Mississippi.
(M.P. 713.39-Dont Dome TP#1396)
83. Existing Point of Interconnection 11,390
between Seller and Endevco in Covington
County, Mississippi. (Hattiesburg-Interconnect
Storage TP#1686)
84. Existing Point at M.P. 719.58 on 11,390
Seller's Main Transmission Line (Seller
Meter No. 3544) in Centerville Dome Field,
Jones County, Mississippi. (Centerville Dome
Field-TP#1532)
<PAGE 17>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
85. Existing Point of Interconnection 11,390
between Seller and Meter named Calhoun
(Seller Meter No. 3404) in Jones
County, Mississippi. (Calhoun - TP# 378)
86. Existing Point at M.P. 727.78 on 11,390
Seller's Main Transmission Line,
Jones County, Mississippi.
(Jones County - Gitano TP#7166)
87. Existing Point of Interconnection 11,390
between Seller and a Meter named Koch
Reedy Creek (Seller Meter No. 333) in
Jones County, Mississippi.
(Reedy Creek Koch TP#670)
88. Existing Point of Interconnection 11,390
between Seller and Meter named Sharon
Field (Seller Meter No. 3000) in Jones
County, Mississippi. (Sharon Field TP#419)
89. Existing Point of Interconnection 11,390
between Seller and Tennessee Gas Transmission
Company at Heidelberg (Seller Meter No. 3109)
in Jasper County, Mississippi.
(Heidelberg Tennessee TP#6120)
90. Existing Point of Interconnection 11,390
between Seller and Mississippi Fuel Company
at Clarke (Seller Meter No. 3254) in Clarke
County, Mississippi. (Clarke County Miss
Fuels TP#6047)
91. Existing Point of Interconnection 11,390
between Seller and Meter named Clarke County-Koch
at M.P. 7575.29 in Clarke County, Mississippi.
(Clarke County Koch-TP#5566)
<PAGE 18>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
92. Existing Point of Interconnection 11,390
between Seller's Mainline and Mobile Bay
Lateral at M.P. 784.66 in Choctaw County,
Alabama. (Station 85 Mainline Pool TP# 6971)
93. Existing Point of Interconnection 11,390
between Seller and Magnolia Pipeline in
Chilton County, Alabama. (Magnolia Pipeline
Interconnect TP# 1808)
94. Existing Point at M.P. 719.58 on 11,390
Seller and Southern Natural Gas Company
(Seller Meter No. 4087) in Jonesboro
Clayton County, Georgia. (Jonesboro SNG TP#6141)
95. Existing Point of Interconnection 11,390
between Seller and Columbia Gas Transmission
(Seller Meter No. 7157) in Dranesville, Fairfax
County, Virginia (Dranesville Colgas-TP#6068)**
96. Existing Point of Interconnection 11,390
between Seller and Columbia Gas Transmission
(Seller Meter No. 4080) in Rockville, Baltimore
County, Maryland. (Rockville-Colgas-TP#6227)**
97. Existing Point of Interconnection 11,390
between Seller and Columbia Gas Transmission
(Seller Meter No. 3088) in Downington, Chester
County, Pennsylvania. (Downington-Colgas-TP#6O67)**
98. Existing Point of Interconnection 11,390
between Seller and Texas Eastern Transmission
Corporation (Seller Meter no. 4133) in Skippack,
Montgomery County, Pennsylvania.
(Skippack-TET-TP#6249)**
<PAGE 19>
EXHIBIT A
BUYER'S
CUMULATIVE
MAINLINE CAPACITY
POINT(S) OF RECEIPT ENTITLEMENT (Mcf/d)*
- ------------------- --------------------
Buyer shall not tender, without the prior consent of Seller, at any point(s) of
receipt on any day a quantity in excess of the applicable Buyer's Cumulative
Mainline Capacity Entitlement for such point(s) of receipt.
- ---------------------------------------
* These quantities do not include the additional quantities of gas retained by
Seller for applicable compressor fuel and line loss make-up provided for in
Article V, 2 of this Service Agreement, which are subject to change as
provided for in Article, V, 2 hereof.
** Receipt of gas by displacement only.
<PAGE 20>
Exhibit B
Point (s) of Delivery Pressure(s)
- --------------------- -----------
1. Seller's Eminence Storage Field Prevailing pressure in
Covington County, Mississippi. Seller's pipeline
system not to exceed
maximum allowable
operating pressure.
2. The point of interconnection Not less than one
between Seller and CNG Transmission thousand (100) pounds
Corporation near Leidy Storage per square inch gauge
Field, Clinton County, Pennsylvania. or at such other
pressure as may be
agreed upon in the day
to day operations of Buyer
and Seller.
3. The point of interconnection Prevailing pressure
between Seller and CNG Transmission in Seller's pipeline
Corporation near Nokesville in system not to exceed
Prince William County, Virginia maximum allowable
provided that deliveries to such operating pressure.
interconnection shall be limited
to the offpeak months of April
through October of each calendar
year.
AMENDMENT TO
NATIONAL FUEL GAS COMPANY
1993 AWARD AND OPTION PLAN
I, Bernard J. Kennedy, pursuant to the authorization granted
by the National Fuel Gas Company Board of Directors on September 20, 1995, do
hereby execute the following amendment to the National Fuel Gas Company 1993
Award and Option Plan ("1993 Plan"), effective August 29, 1995.
Section 17 of the 1993 Plan is hereby amended to read as
follows:
"No award under the Plan shall be subject in
any manner to alienation, anticipation, sale, transfer
(except by will or the laws of the descent and
distribu-tion, or pursuant to a qualified domestic
relations order), assignment, pledge or encumbrance,
except that, unless the Committee specifies otherwise,
awards of nonqualified stock options or SAR's granted on
or after August 29, 1995 to the Chief Executive Officer
of the Company, or to the President of National Fuel Gas
Distribution Corporation, National Fuel Gas Supply
Corporation or Seneca Resources Corporation, shall be
transferable without consideration, subject to all the
terms and conditions to which such non-qualified stock
options or SARs are otherwise subject, to members of a
Participant's immediate family as defined in SEC Rule
16a-1 promulgated under the Exchange Act, trusts for the
benefit of the Participant or such family members, and
entities which are wholly-owned by the Participant or
such family members. If and when the SEC amends Rule
16b-3 promulgated under the Exchange Act to permit
transferability of certain awards under plans intended to
satisfy Rule 16b-3, all nonqualified stock option and SAR
awards under the Plan shall also be transferable, subject
to all the terms and conditions to which such awards are
other-wise subject, to the maximum extent permitted by
<PAGE 2>
16b-3, as so amended and as from time to time in effect,
unless the Committee specifies otherwise. Except as
expressly permitted by this paragraph, an Award shall be
exercisable during the Participant's lifetime only by
him."
NATIONAL FUEL GAS COMPANY
October 27, 1995 /s/ Bernard J. Kennedy
- ----------------- --------------------------------------
Dated Bernard J. Kennedy
President, Chief Executive Officer
and Chairman of the Board of Directors
AMENDMENT TO
NATIONAL FUEL GAS COMPANY
DEFERRED COMPENSATION PLAN
I, Bernard J. Kennedy, am duly authorized by Section 10.3 of the
National Fuel Gas Company Deferred Compensation Plan ("Plan") to amend the Plan
under certain circumstances, and I was also duly authorized by the Board of
Directors of National Fuel Gas Company ("Company") on September 20, 1995, to
amend the Plan to permit me to receive my full employer matching contribution
under the National Fuel Gas Company Tax-Deferred Savings Plan for Nonunion
Employees ("TDSP") through the tophat mechanism without contributing to the
TDSP, and to permit me or my successor as President to accord this treatment to
other employees of the Company and its subsidiaries from time to time.
Accordingly, I do hereby amend Section 9.2 of the Plan as follows, effective
August 1, 1995 (i.e., effective beginning with the Plan's Deferral Period
beginning on such date):
1. Paragraphs (b) - (d) are hereby relabeled as paragraph (c) - (e).
2. A new paragraph (b) is hereby added:
"(b) In addition to the tophats described above, Bernard J. Kennedy,
President of the Company, shall receive the following benefit,
and the President of the Company may from time to time designate
in writing other employees of the Company and its subsidiaries
to receive the following benefit, which shall be a "tophat" in
addition to those described above. Such persons shall receive,
or be credited with, for each pay period in a Plan Year for
which they are eligible for this benefit, an amount equal to
their Maximum Matching Contribution Percentage for each such pay
period times their Base Salary with respect to each such pay
period, adjusted as of the end of the Plan Year to reflect the
increased value of their TDSP accounts had such amounts been
actually contributed as additional employer matching
contributions to the TDSP, less the amounts paid or credited for
<PAGE 2>
such Plan Year or part thereof pursuant to Paragraph (a),
clauses (i) - (ii) of this Section 9.2.
The purpose of this tophat is to enable employees
(including the President), who might or would otherwise be
later forced to pay the 15 percent excise tax under
Section 4980A of the Code, if they continue to contribute
to the TDSP (and have employer matching contributions
contributed to the TDSP for their account), to minimize or
eliminate the risk of paying that avoidable and excessive
tax.
The following example illustrates how the tophat
provisions of this paragraph (b) shall work in conjunction
with the paragraph (a) (iii) example and shall assume that
a participant is eligible for this paragraph (b) benefit
for an entire Plan Year. Using the same assumptions as set
forth in (a) (iii), the participant's Maximum Matching
Contribution Percentage times Base Salary for the Plan
Year is $25,200. The participant already received $16,867
by virtue of the other tophats in section 9.2, and thus
would receive $8,333 by virtue of this paragraph (b)
tophat. As previously noted in the paragraph (a) (iii)
example, this paragraph (b) tophat, like the others, would
be adjusted for changes in the value of Company common
stock.
As can be seen by this illustration, this paragraph
(b) tophat basically permits an eligible employee to
obtain, through the tophat mechanism, what he would have
obtained as a TDSP matching contribution, without having
to contribute to the TDSP."
Dated: September 27, 1995 /s/ Bernard J. Kennedy
----------------------
Bernard J. Kennedy
President, Chief Executive Officer
and Chairman of the Board of Directors
EXECUTIVE RETIREMENT PLAN
As adopted on July 10, 1987
(effective February 19, 1987);
and as amended on the following
dates:
Amended and Restated March 1, 1988;
Amended and Restated April 25, 1988;
Amended and Restated May 2, 1988;
Amended September 13, 1993;
Amended November 18, 1993;
Amended February 17, 1994;
Amended September 27, 1995
This Plan Document is current as of
November 1, 1995.
NATIONAL FUEL GAS COMPANY
AND PARTICIPATING SUBSIDIARIES
EXECUTIVE RETIREMENT PLAN
<PAGE 2>
TABLE OF CONTENTS
ARTICLE PAGE NO.
- ------- --------
ARTICLE I Purpose . . . . . . . . . . . . . . . . . . . . . 1
ARTICLE II Definitions . . . . . . . . . . . . . . . . . . . 3
ARTICLE III Determination of Retirement Benefits . . . . . . 9
ARTICLE IV Vesting; Forfeiture . . . . . . . . . . . . . . . 15
ARTICLE V Form of Payment of Benefits . . . . . . . . . . . 17
ARTICLE VI Source of Payment . . . . . . . . . . . . . . . . 19
ARTICLE VII Administration of the Plan . . . . . . . . . . . 20
ARTICLE VIII Amendment and Termination . . . . . . . . . . . . 22
ARTICLE IX General Provisions. . . . . . . . . . . . . . . . 23
<PAGE 3>
ARTICLE 1
Purpose
1.1 National Fuel Gas Company established this National Fuel Gas
Company and Participating Subsidiaries Executive Retirement Plan effective as of
February 19, 1987 for the purpose of attracting and retaining executives, and
for these additional purposes: (1) to provide retirement benefits to eligible
employees in addition to basic retirement benefits provided them under the
National Fuel Gas Company Retirement Plan as it may be amended and restated; (2)
to provide retirement benefits to such employees to make up for benefit
reductions, if any, under the National Fuel Gas Company Retirement Plan caused
by participation in the National Fuel Gas Company Deferred Compensation Plan, as
it may be amended and restated; (3) to provide retirement benefits to such
employees without regard to the $200,000 limit on qualified plans' covered
compensation that became effective respecting the National Fuel Gas Company
Retirement Plan effective July 1, 1989 (and as that limit may change from time
to time); and (4) to provide to such employees benefits which would have been
payable from the tax-exempt trust under the National Fuel Gas Company Retirement
Plan but for the limitations placed by Section 415 of the Internal Revenue Code
of 1986, as it may be amended, on benefits payable and contributions made with
respect to such employees under such plans.
<PAGE 4>
1.2 The National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan is intended to constitute an unfunded deferred
compensation plan under Section 201(2) of the Act and the Company's obligation
to pay benefits hereunder, if any, is unfunded and unsecured.
<PAGE 5>
ARTICLE 2
Definitions
When used herein, the following terms shall have the following
meanings:
2.1 Act means the Employee Retirement Income Security Act of 1974, as
amended from time to time.
2.2 Basic Pension Plan means the National Fuel Gas Company Retirement
Plan, as amended and restated from time to time.
2.3 Beneficiary means the person or persons entitled to receive the
amount, if any, payable under the Basic Pension Plan upon the death of a member
or retired member thereof who also is a Member in the Plan.
2.4 Benefit Limitations means (i) the maximum "annual benefit" payable
under the Basic Pension Plan in accordance with Section 415 of the Code and the
implementing provisions of the Basic Pension Plan (as they operate in
conjunction with the relevant provisions of other Company employee benefit
plans), and (ii) the maximum amount of annual compensation of an employee that
may be taken into account under the Basic Pension Plan in accordance with
Section 401(a)(17) of the Code, as amended and supplemented, and the
implementing provisions of the Basic Pension Plan.
2.5 Board of Directors means the Board of Directors of National Fuel
Gas Company.
<PAGE 6>
2.6 Change in Control shall mean the happening of any of the
following:
(a) the acquisition by any party or parties of the beneficial
ownership of 30% or more of the voting shares of National Fuel
Gas Company; or
(b) the occurrence of a transaction requiring shareholders' approval
for the acquisition of National Fuel Gas Company through
purchase of stock or assets, or by merger, or otherwise; or
(c) the election during any period of 24 months, or less, of 40% or
more of the members of the Board of Directors, without the
approval of three-fourths of the members of the Board of
Directors as constituted at the beginning of the period.
2.7 Code means the Internal Revenue Code of 1986, as amended from
time to time.
2.8 Committee means the committee appointed from time to time by the
Board of Directors to administer the Plan.
2.9 Company means National Fuel Gas Company and each of the following
subsidiaries, which participate in the Plan: National Fuel Gas Distribution
Corporation, National Fuel Gas Supply Corporation, Penn-York Energy Corporation
and Empire Exploration, Inc., each of which has adopted or has indicated that it
will adopt the Plan.
<PAGE 7>
2.10 Early Retirement Date shall be the Retirement Date selected by the
Member that is no earlier than the first day of the calendar month immediately
following or coinciding with the Member's 55th birthday, or any first of a month
thereafter, but prior to the Member's Normal Retirement Date, provided the
Member is Vested.
2.11 Employment Year is the consecutive 12-month period commencing on
the date in which the Member was hired by a Company, and each subsequent
12-month period commencing on each anniversary thereof.
2.12 Final Average Pay shall mean an amount equal to the average of the
Annual Cash Compensation payable by a Company or Companies to a Member for the
60 consecutive month period during the 120 consecutive month period immediately
preceding the date the Member retires (or in the event of a Change in Control,
terminates employment), which produces the highest average. The Member's Annual
Cash Compensation shall include the Member's base salary, whether or not the
receipt of a portion thereof has been deferred, plus the Member's compensation
(whether or not the receipt of all or a portion thereof has been deferred) under
National Fuel Gas Company's short-term annual incentive program, known as the
Annual At Risk Compensation Incentive Program (AARCIP") or any successor program
thereto, when paid or deferred. The Member's Annual Cash Compensation shall
exclude all commissions, stock, option, or SAR awards, special allowances,
supplemental compensation, and any other extra compensation or incentives or
bonuses not provided under the AARCIP.
<PAGE 8>
If an AARCIP award is paid following the Member's retirement date, that
award shall be used in determining the Member's Final Average Pay, if it is
payable in connection with employment periods included in the 60 month period
referred to above. In this event, the Member's Retirement Benefits shall be
increased, once the effect of such award is determined, and the increase shall
be made retroactive to the Member's retirement date, without interest.
Notwithstanding the above, if such a post-retirement AARCIP award is used in
determining Final Average Pay hereunder, AARCIP payments relating to no more
than five of National Fuel Gas Company's fiscal years may be used in determining
Final Average Pay."
An example of the effect of this provision is as follows. Assume that
a Member retires on October 1, 1999, and that his salary and AARCIP bonuses were
as follows for the following calendar year:
AARCIP Bonus (relating
to fiscal year ending
that September 30 but
paid in December)
Salary
1994 $480,000 $120,000
1995 $540,000 $150,000
1996 $600,000 $180,000
1997 $660,000 $210,000
1998 $780,000 $240,000
1999 $840,000 $270,000
<PAGE 9>
This Member's Final Average Pay would be $876,000, computed as follows:
[9/12 ($840,000) + 12/12 ($780,000) + 12/12 ($660,000) + 12/12 ($600,000) +
12/12 ($540,000) + 3/12 ($480,000) + $270,000 + $240,000 + $210,000 + $180,000 +
$150,000] divided by 5.
2.13 Member means any person employed by a Company who is designated as
a Member by the Chief Executive Officer of National Fuel Gas Company.
2.14 Normal Retirement Date is the first day of the month coinciding
with or immediately following the Member's 65th birthday. A Member may retire
and begin to receive a Retirement Benefit, payable commencing on his Normal
Retirement Date, equal to his Additional Benefit Base.
2.15 Plan means the National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan as set forth herein and as amended and
restated from time to time.
2.16 Retirement Date is the date with respect to which Retirement
Benefits under the Plan commence.
2.17 Retirement Benefits means the benefits payable under this Plan.
2.18 Vesting with respect to a Member occurs on the latter of (i) the
first of the month coinciding with or immediately following his 55th birthday or
(ii) the date on which the Member has completed five Years of Service with a
Company. A "Vested" Member is a Member with respect to whom "Vesting" has
occurred.
<PAGE 10>
2.19 Years of Service equals the number of Employment Years completed
by a Member. An Employment Year in which a Member completed 1,000 or more but
less than the normal number of Hours of Service (as such term is defined in the
Basic Pension Plan) for a full-time employee of the Company shall be credited as
a partial Year of Service equal to the number of Hours of Service credited in
such Employment Year divided by the normal number of Hours of Service for a
full-time employee of the Company. Years of Service shall not exceed 40. No more
than one Year of Service shall be credited in any Employment Year.
2.20 In construing the Plan, masculine pronouns shall refer to both
males and females, as appropriate.
<PAGE 11>
ARTICLE 3
Determination of Retirement Benefits
3.1 Total Benefit Base. The Total Benefit Base of a Vested Member shall
be a monthly annuity for his life, commencing at his Normal Retirement Date,
under which the annual payments shall equal an amount calculated by adding the
products of .0197 times the Member's Years of Service not in excess of 30 and
.0132 times his Years of Service, if any, in excess of 30 (but not to exceed
10), and multiplying the sum thereof by his Final Average Pay.
3.2 Social Security Benefit means the annual Primary Insurance Amount
estimated by the Committee to be payable to the Member under the Social Security
Act of 1935, as amended, at his Retirement Date, calculated on the assumption
that the Member will not receive any future wages that would be treated as such
for purposes of that act. If a Member's Retirement Date precedes his attainment
of age 62, the Primary Insurance Amount estimated to be payable to the Member at
age 62 (without assuming any cost of living increases) shall be reduced by .75%
per month for the first 24 months, and by .5% per month for the remaining
months, if any, by which the Member's Retirement Date precedes his attainment of
age 62. The Social Security Benefit, once calculated, will be frozen as of the
Member's Retirement Date.
<PAGE 12>
3.3 Additional Benefit Base for Member Retiring at Normal Retirement
Date. The Additional Benefit Base of a Vested Member who retires on a Normal
Retirement Date shall be a monthly annuity for his life, commencing at his
Normal Retirement Date, under which the annual payments shall equal the Member's
Total Benefit Base less the sum of (i) .0125 times his Years of Service times
his Social Security Benefit and (ii) the Member's Benefit Base (as reduced, if
at all, on account of Benefit Limitations) under the Basic Pension Plan. If the
remainder is negative, the Additional Benefit Base shall be zero.
3.4 Additional Benefit Base for Members Retiring on an Early Retirement
Date. The Additional Benefit Base of a Vested Member who retires on an Early
Retirement Date shall be a monthly annuity for the Member's life, commencing on
such Early Retirement Date, under which the annual payments shall equal (i) the
Member's Adjusted Basic Pension Plan Benefit Base as determined in (a) below,
plus (ii) the Early Retirement Percentage as determined in (b) below times the
remainder of his Total Benefit Base less his Adjusted Basic Pension Plan Benefit
Base, minus (iii) .0125 times his Years of Service times his Social Security
Benefit, minus (iv) the Member's Benefit Base (as reduced, if at all, on account
of Benefit Limitations) under the Basic Pension Plan.
(a) Adjusted Basic Pension Plan Benefit Base equals the Benefit Base as
determined under the Basic Pension Plan without reduction on account of Benefit
Limitations and adjusted as if deferrals
<PAGE 13>
under the National Fuel Gas Company Deferred Compensation Plan were not excluded
from the definition of Final Average Pay under the Basic Pension Plan, and
multiplied by the appropriate Early Retirement Percentage, if applicable, as
provided for in Section 4.02 of the Basic Pension Plan.
(b) The Early Retirement Percentage under the Plan is determined in
accordance with the following scale:
Retirement Age Early Retirement Percentage
-------------- ---------------------------
65 100
64 94
63 88
62 82
61 70
60 58
59 46
58 34
57 22
56 10
55 years and 2 months 0
The Early Retirement Percentage determined in accordance with the above
scale respecting ages 62, 63 and 64, shall be increased by 1/2 of 1% for each
whole calendar month by which a Member's Early Retirement Date follows the first
of the month coinciding with or immediately following his 62nd, 63rd, or 64th
birthday, as the case may be. The Early Retirement Percentage determined in
accordance with the above scale respecting ages 55 years and 2 months, 56, 57,
58, 59,
<PAGE 14>
60, and 61, shall be increased by 1% for each whole calendar month by which his
Early Retirement Date follows the first of the month coinciding with or
immediately following his 55 year and 2 month, 56th, 57th, 58th, 59th, 60th and
61st birthdays, as the case may be. Furthermore, the Early Retirement Percentage
shall be increased by .125% for each whole calendar month by which a Member's
Years of Service exceed 30; provided, however, that this shall never result in
an Early Retirement Percentage in excess of 100%. (In the event a Member desires
to retire on the earliest possible Early Retirement Date, i.e., on the first of
the month coinciding with or immediately following his 55th birthday, the
increase in percentage as a result of Years of Service in excess of 30 shall be
made from a base percentage of -2%, in computing Early Retirement Percentage.)
(c) The benefit a Member will receive through the Plan if he retires
early consists of two parts. The first part will make him whole for any
reduction in the regular pension he receives under the Basic Pension Plan
resulting from Internal Revenue Code limitations and his participation in the
National Fuel Gas Company Deferred Compensation Plan. This is frequently called
a "tophat." The second part is a benefit equal to a percentage of the Plan
benefit normally paid at age 65. This normal Plan benefit is calculated by
subtracting the amount received under the Basic Pension Plan and the "tophat"
from the Total Benefit Base. The percentages are set forth in Section 3.4(b) on
page 10. The benefit payable under this second part but not the "tophat" will be
<PAGE 15>
reduced by a lesser Social Security offset. The offset is .0125 times Years of
Service times Social Security Benefit (as defined in 3.2).
For example, if an employee had 30 Years of Service under this Plan (29
under the Basic Pension Plan) and a Final Average Salary of $100,000; if he
desired to retire at age 58 (10% reduction under the Basic Pension Plan); if the
applicable limits under Section 415 of the Code capped the Basic Pension Plan
annual benefits expressed as a Benefit Base equivalent, at $85,000; and if his
Social Security Benefit as determined hereunder were $10,000; the formula would
work as follows:
(i) Adjusted Basic Pension Benefit Base = [(.0125) ($7,800) + (.015)
($92,200)] (29) (.90) = $38,641.05
(ii) Early Retirement Percentage times [Total Benefit Base minus
(i)] = (.34) [(.591) ($100,000) - $38,641.05] = $6,956.04
(iii) Additional Benefit Base = $38,641.05 + $6,956.04 - [(.0125)
(30) ($10,000)] - $38,641.05 = $3,206.04
(d) If, respecting any Member, his Early Retirement Percentage times
the remainder of Total Benefit Base less Adjusted Basic Pension Plan Benefit
Base, results in a figure which is less than or equal to .0125 times his Years
of Service times his Social Security Benefit, Additional Benefit Base shall
equal Adjusted Basic Pension Plan Benefit Base less the Member's Benefit Base
(as reduced, if at all, on account of Benefit Limitations) under the Basic
Pension Plan. This provides that, if the bonus for Early Retirement under the
Plan is less valuable than the Social Security offset provided hereunder, the
<PAGE 16>
Member will not be prejudiced thereby; i.e., will not lose any portion of the
benefits provided for under the Plan to undo the impact of Benefit Limitations.
3.5 Late Retirement. A Member's Years of Service shall be credited if
they extend beyond his Normal Retirement Date, (but shall not exceed 40 in
total), and the Final Average Pay determination shall reflect such Years of
Service. However, there shall be no actuarial adjustment to his Additional
Benefit Base on account of a Member's retirement after Normal Retirement Date;
for such purpose Additional Benefit Base hereunder shall be computed as if his
late retirement date were his Normal Retirement Date.
3.6 Adjustment of Retirement Benefit. The amount of Retirement Benefits
payable to or in respect of a Member shall be reduced by the amount of any
increases in the benefits payable under the Basic Pension Plan to or in respect
of such Member (whether due to increases in the Benefit Limitations or
otherwise) subsequent to the Member's Retirement Date, and shall be increased by
the amount of any such decrease subsequent to the Member's Retirement Date, as
the case may be. Notwithstanding the above, (i) any increase in benefits payable
under the Basic Pension Plan due to a full or partial cost of living adjustment
or (ii) any increase in Basic Pension Plan benefits due to a change in benefit
formula thereunder shall not cause a reduction in Retirement Benefits. Moreover,
any such increase in (i) or (ii) above, if and to the extent ineffective
respecting a Member due to Benefit Limitations, shall be provided through this
Plan.
<PAGE 17>
ARTICLE 4
Vesting; Forfeiture
4.1 Time of Vesting. No Retirement Benefits will be payable to or in
respect of any Member unless (i) that Member remains employed by the Company
until he is Vested under this Plan; or (ii) Section 4.4 applies.
4.2 Misconduct. Notwithstanding Section 4.1 hereof, no Retirement
Benefits will be payable to or in respect of a Member whose employment is
terminated by the Company for serious, willful misconduct in respect of his
obligations to the Company, including but not limited to the commission of a
felony or a perpetration of a common law fraud which has damaged, or is likely
to result in damage to, the Company.
4.3 Competition. If and so long as a Member or retired Member shall be
employed by any corporation, entity or individual which is then engaged in a
business competitive with the Company, or shall be engaged in any such business,
or shall aid, advise or assist or attempt to aid, advise or assist any
corporation, individual or entity in engaging in any such business, or shall
endeavor, directly or indirectly, to interfere with the relations between the
Company and any customer or engage in any activity that would be deemed by the
Committee in its sole discretion to be detrimental to the Company's best
interests, the rights of such Member or retired Member to Retirement Benefits,
including the rights of any Beneficiary, shall be forfeited with the same
<PAGE 18>
full force and effect as though the Retirement Benefits had not been granted
under any of the provisions of the Plan, unless the Committee determines that
such activity is not detrimental to the best interests of the Company;
provided that from and after 60 days following cessation by the Member or
retired Member of such activity and written notice by him to the Committee, his
right to receive Retirement Benefits hereunder shall be restored, unless the
Committee, in its sole discretion, determines that the prior activity has
caused substantial damage to the Company.
No action under the Section shall be taken upon or after the occurrence
of a Change in Control.
4.4 In the Event of a Change in Control. If a Change in Control occurs,
and a Member hereof at that time or within three years thereafter shall no
longer be an officer of, or employed by, a Company, his Retirement Benefit shall
vest at the time of his cessation of employment with a Company, and shall be
payable to him or for his benefit in the form of a lump sum, based upon his
accrued Additional Benefit Base at Normal Retirement Date and discounting same
by using the interest assumption(s) then used by the Pension Benefit Guaranty
Corporation for computing the value of immediate annuities upon the termination
of a tax-qualified defined benefit plan such as the Basic Pension Plan.
<PAGE 19>
ARTICLE 5
Form of Payment of Benefits
5.1 Coordination with Basic Pension Plan. Retirement Benefits shall be
payable to or in respect of a Member eligible therefor at the same time, in the
same manner and form, and subject to the same terms and conditions as stated in
Sections 5.02 to 5.06 of the Basic Pension Plan, except that there shall be no
disability benefit under this Plan. If Retirement Benefits are to be paid after
the Member's or retired Member's death to his Beneficiary, Retirement Benefits
shall be payable to such Beneficiary in the same time, manner and form as
payments under the Basic Pension Plan.
5.2 Right to Adjust. The Committee shall have the right to adjust
Retirement Benefits payable under this Plan to correct errors, and/or to provide
uniform treatment of Members, retired Members or Beneficiaries.
5.3 Spouse's Benefit. In the event of a Vested Member's death, his
spouse shall receive Retirement Benefits hereunder equal to the greater of (i)
or (ii):
(i) .50 times the Member's Additional Benefit Base computed under
Section 3.3, except that if the Member's surviving spouse is more than five
years younger than the Member, the .50 multiplier described in this clause shall
be reduced by .00125 for each month in excess of 60 that the surviving spouse's
age is less than that of the Member. Thus, for example, the multiplier declines
to .30 if the surviving spouse is 220 months younger than the Member.
<PAGE 20>
(ii) 50% of the Retirement Benefit which the Member would have received
had payment thereof commenced on the day before the date of his death in the
form of the Automatic Joint and Survivor Annuity (as defined and described in
the Basic Pension Plan).
5.4 Lump Sum Payment Option. There shall be one exception to Section
5.1: A Member may elect to receive Retirement Benefits in the form of a lump sum
payment even if he does not or may not select such option under the Basic
Pension Plan. Such election may only be made by means of an irrevocable election
executed in the calendar year prior to the year in which the Member's Retirement
Date occurs. The most recently published mortality table that is generally
accepted by American actuaries and reasonably applicable to the Plan, and a 6
percent annual interest rate or discount rate, shall be used to convert the
Member's Additional Benefit Base to a lump sum equivalent. (However, with
respect to other forms of benefit available under the Plan, the mortality table
used in the Basic Pension Plan and described in Section 1.01 thereof, or a
successor section, shall continue to be used.) If the Member's Additional
Benefit Base, had it been paid in the form of an annuity, would otherwise have
been expected to increase or decrease subsequent to the Member's Retirement
Date, (for example, due to cost of living increases that effectively raise the
maximum amounts that may be paid from the Basic Pension Plan as a result of the
operation of Code Section 415 limits, or due to expected post-retirement AARCIP
awards), the Company may adjust such lump sum payment accordingly and shall
later true it up either by paying an additional sum to the Member or by
receiving a refund of any excess from the Member.
<PAGE 21>
ARTICLE 6
Source of Payment
6.1 All payments provided for under the Plan shall be paid in cash from
the general funds of the Company; provided, however, that such payments shall be
reduced by the amount of any payments made to or in respect of a Member from any
trust or special or separate fund established by the Company to assure such
payments. The Company shall not be required to establish a special or separate
fund or other segregation of assets to assure such payments, and, if the Company
shall make any investments to aid it in meeting its obligations hereunder, the
Member and his Beneficiary shall have no right, title, or interest whatever in
or to any such investments except as may otherwise be expressly provided in a
separate written instrument relating to such investments. Nothing contained in
this Plan, and no action taken pursuant to its provisions, shall create or be
construed to create a trust of any kind between the Company and any Member or
Beneficiary. To the extent that any Member or Beneficiary acquires a right to
receive payments from the Company hereunder, such right shall be no greater than
the right of an unsecured creditor of the Company.
<PAGE 22>
ARTICLE 7
Administration of the Plan
7.1 Committee to Administer. The Plan shall be administered by the
Committee which shall have full power and authority to interpret, construe and
administer the Plan, and review claims for benefits under the Plan, and the
Committee's interpretations and constructions of the Plan and actions thereunder
shall be binding and conclusive on all persons and for all purposes.
7.2 Agents. For purposes of the Act, the members of the Committee shall
be the named fiduciaries of the Plan for administration of the Plan (including
but not limited to complying with reporting and disclosure requirements and
establishing and maintaining Plan records), and shall engage such certified
public accountants, who may be accountants for the Company, as it shall require
or may deem advisable for purposes of the Plan. The Committee may arrange for
the engagement of such legal counsel, who may be counsel for the Company, and
make use of such agents and clerical or other personnel as they each shall
require or may deem advisable for purposes of the Plan. The Committee may rely
upon the written opinion of such counsel and the accountants engaged by the
Committee and may delegate to any agent, who may be a Company employee, or to
any sub-committee or member of the Committee, its authority to perform any act
hereunder, including without limitation those matters involving the exercise of
discretion, provided that such delegation shall be subject to revocation at any
time at the discretion of the Committee.
<PAGE 23>
7.3 Liability; Indemnity. To the maximum extent permitted by the Act,
no member of the Committee, nor any of their agents, including Company officers
or employees, shall be personally liable by reason of any contract or other
instrument executed by any of them in their capacity as members of the Committee
or otherwise, nor for any mistake of judgment made in good faith, and the
Company shall indemnify and hold harmless, directly from its own assets, each
member of the Committee and each other officer, employee, or director of the
Company to whom any duty or power relating to the administration or
interpretation of the Plan or to the management or control of the assets of the
Plan may be delegated or allocated, against any cost or expense (including
counsel fees) or liability (including any sum paid in settlement of a claim with
the approval of the Company) arising out of any act or omission to act in
connection with the Plan unless arising out of such person's own fraud or bad
faith. Said persons shall be entitled to rely conclusively upon, and shall be
fully protected in any action taken by them or any of them in good faith in
reliance upon, any table, valuation, certificate, opinion or report which shall
be furnished to them or any of them by an actuary, accountant, counsel or other
expert who shall be employed or engaged by them.
7.4 Binding Effect of Decisions. The decision or action of this
Committee with respect to any question arising out of or in connection with the
administration, interpretation and application of the Plan and the rules and
regulations promulgated hereunder shall be final, conclusive and binding upon
all persons having any interest in the Plan.
<PAGE 24>
ARTICLE 8
Amendment and Termination
8.1 Subject to the application of Article 4 in the situations therein
enumerated, the Plan may be amended, suspended or terminated, in whole or in
part, by the Board of Directors, and Members may be adversely affected thereby
provided that such actions may not deprive Vested Members of Retirement Benefits
accrued until the date of such actions. However, any amendment that changes the
interest rate described in Section 5.4 or otherwise changes the methods for
computing lump sum equivalents thereunder, or that otherwise reduces or
eliminates the lump sum payment option or any other form of benefit payment
option under the Plan, shall not be considered to be a deprivation of the
accrued Retirement Benefits of Vested Members. In addition, prior to a Change in
Control, the rights of Vested Members may be affected if failing to make changes
would be administratively burdensome and if the Member voluntarily consents to
such change in writing, or if changes are required by law.
<PAGE 25>
ARTICLE 9
General Provisions
9.1 Effect of Corporate Reorganization. This Plan shall be binding upon
and inure to the benefit of the Company and its successors and assigns and the
Member, and his designees, Beneficiaries, legal representatives and estate.
Nothing in this Plan shall preclude the Company from consolidating or merging
into or with, or transferring all or substantially all of its assets to, another
corporation which assumes this Plan and all obligations of the Company
hereunder. Upon such a consolidation, merger or transfer of assets, and
assumption of the Plan, the term "Company" shall refer to such other corporation
and this Plan shall continue in full force and effect.
9.2 Right to Discharge Member. Neither the Plan nor any action taken
hereunder shall be construed as giving to a Member the right to be retained in
the employ of the Company or as affecting the right of the Company to discharge
any Member, at any time without regard to the effect such discharge would have
upon his eligibility for or receipt of benefits under the Plan.
9.3 Withholding. The Company may withhold from any benefits payable
under this Plan all federal, state, city or other taxes as shall be required (as
determined by the Company) pursuant to any law or governmental regulation or
ruling.
9.4 Assignability. No right to any amount payable at any time under
the Plan may be assigned, transferred, pledged, or encumbered, either
voluntarily or by operation of law, except as provided expressly herein as to
<PAGE 26>
payments to a Beneficiary or as may otherwise be required by law. If, by reason
of any attempted assignment, transfer, pledge, or encumbrance, or any bankruptcy
or other event happening at any time, any amount payable under the Plan would be
made subject to the debts or liabilities of the Member or his Beneficiary or
would otherwise not be enjoyed by him, then the Committee, if it so elects,
may terminate such person's interest in any such payment and direct that the
same be held and applied to or for the benefit of the Member, his Beneficiary,
or any other person deemed to be the natural objects of his bounty, taking
into account the expressed wishes of the Member (or, in the event of his death,
his Beneficiary).
<PAGE 27>
9.5 Inability to Utilize Benefits. If the Committee shall find that any
person to whom any amount is or was payable hereunder is unable to care for his
affairs because of illness or accident or other reasons, or has died, then the
Committee, if it so elects, may direct that any payment or any part thereof due
such person shall be paid to his estate (unless a prior claim therefor has been
made by a duly appointed legal representative) or be paid or applied for the
benefit of such person or to or for the benefit of his spouse, children or other
dependents, an institution maintaining or having custody of such person, any
other person deemed by the Committee to be a proper recipient on behalf of such
person otherwise entitled to payment, or any of them, in such manner and
proportion as the Committee may deem proper. Any such payment shall be in
complete discharge of the liability therefor of the Company, the Plan or the
Committee or any member, officer or employee thereof. The Committee may withhold
the payment of any amount that shall be payable in accordance with the
<PAGE 28>
provisions of the Plan to a person under legal disability until a representative
of such person competent to receive such payment on his behalf shall have been
properly appointed.
9.6 Actuarial Equivalents. Except as otherwise set forth in Section
5.4, whenever, under this Plan, it is necessary to determine whether one benefit
is less than, equal to, or larger than another, or whether one benefit is the
actuarial equivalent of another whether or not such benefits are provided under
this Plan, such determination shall be made using mortality, interest and any
other assumptions used at the time in determining actuarial equivalents under
the Basic Pension Plan.
9.7 Health Information. The Member shall provide to the Company, if so
requested and as a precondition for remaining a Member, all health information
and other information as the Company may require should it decide to purchase
life insurance policies or annuity contracts.
9.8 Additional Benefit. The benefits payable under this Plan shall be
in addition to all other benefits provided for Employees of the Company, except
as otherwise provided in this Plan.
9.9 Headings. The captions preceding the sections and articles hereof
have been inserted solely as a matter of convenience and in no way define or
limit the scope or intent of any provisions of the Plan.
9.10 Governing Law. This Plan shall be governed by the laws of the
State of New York as from time to time in effect.
<TABLE>
<CAPTION>
COMPUTATION OF RATIO OF EXHIBIT 12
EARNINGS TO FIXED CHARGES
(UNAUDITED)
Fiscal Year Ended September 30
-------------------------------------------------
1995 1994 1993 1992 1991
-------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS:
Income Before Interest Charges (2) $128,061 $127,885 $125,742 $118,222 $110,240
Allowance for Borrowed Funds Used in Construction 195 209 174 1,088 2,278
Federal Income Tax 30,522 36,630 21,148 17,680 (3,929)
State Income Tax 4,905 6,309 2,979 3,426 341
Deferred Inc. Taxes - Net (3) 8,452 4,853 16,919 14,125 26,873
Investment Tax Credit - Net (672) (682) (693) (706) (738)
Rentals (1) 5,422 5,730 5,621 5,857 4,915
$176,885 $180,934 $171,890 $159,692 $139,980
FIXED CHARGES:
Interest & Amortization of Premium and
Discount of Funded Debt $40,896 $36,699 $38,507 $39,949 $41,916
Interest on Commercial Paper and
Short-Term Notes Payable 6,745 5,599 7,465 12,093 11,933
Other Interest (2) 4,721 3,361 4,727 6,958 9,679
Rentals (1) 5,422 5,730 5,621 5,857 4,915
$57,784 $51,389 $56,320 $64,857 $68,443
RATIO OF EARNINGS TO FIXED CHARGES 3.06 3.52 3.05 2.46 2.05
Notes: (1) Rentals shown above represent the portion of all rentals (other
than delay rentals) deemed representative of the interest factor.
(2) Fiscal 1995, 1994, 1993 and 1992 reflect the reclassification of
$1,716, $1,674, $1,374 and $1,129, respectively, representing the
loss on reacquired debt amortized during each period, from Other
Interest Charges to Operation Expense.
(3) Deferred Income Taxes - Net for fiscal 1994 excludes the cumulative
effect of changes in accounting.
</TABLE>
RALPH E. Davis Associates, INC.
CONSULTANTS-PETROLEUM AND NATURAL GAS
3555 TIMMONS LANE-SUITE 1105
HOUSTON, TEXAS 77027
(713) 622 -8955
CONSENT OF ENGINEER
-------------------
We hereby consent to the reproduction of our audit report dated October 17,
1995, and to the reference to our estimate dated October 1, 1995, appearing in
this National Fuel Gas Company Annual Report on Form 10-K.
We also consent to the incorporation by reference in (i) the Registration
Statement (Form S-8, No. 2-95439), as amended, relating to the National Fuel Gas
Company 1983 incentive Stock Option Plan and the National Fuel Gas Company 1984
Stock Plan, and in the related Prospectuses, (ii) the Registration Statements
(Form S-8, No. 33-28037, and Nos. 2-97641 and 33-17341), as as amended, relating
to the National Fuel Gas Company TaxDeferred Savings Plan and the National Fuel
Gas Company Tax-Deferred Savings Plan for Non-Union Employees, respectively, and
in the related Prospectuses, (iii) the Registration Statement (Form S-3, No.
33-49401), as amended, relating to $350,000,000 of National Fuel Gas Company
debentures and/or medium term notes and in the related Prospectus, (iv) the
Registration Statement (Form S-3, No. 33-51881), as amended, relating to the
National Fuel Gas Company Dividend Reinvestment and Stock Purchase Plan, and in
the related Prospectuses, (v) the Registration Statement (Form S-3, No.
33-36868), as amended, relating to the National Fuel Gas Company Customer Stock
Purchase Plan, and in the related Prospectus, and (vi) the Registration
Statement (Form S-8, No. 33-49693), as amended, relating to the National Fuel
Gas Company 1993 Award and Option Plan, and in the related Prospectus; of the
reproduction of our report dated October 17, 1995, appearing in this National
Fuel Gas Company Annual Report on Form 10-K.
RALPH E. DAVIS ASSOCIATES, INC.
/s/ Allen C. Barron
-------------------------------
Allen C. Barron, P.E.
Vice President
Houston, Texas
October , 1995
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
consituting part of the Registration Statements on Form S-3 (No. 33-51881),
Form S-3 (No. 33-49401), Form S-3 (No. 33-36868), Form S-8 (No. 2-97641),
Form S-8 (No. 33-17341), Form S-8 (No. 33-28037), Form S-8 (No. 2-94539)
and Form S-8 (No. 33-49693) of National Fuel Gas Company of our report dated
October 27, 1995 appearing on page 46 of this Form 10-K.
PRICE WATERHOUSE LLP
Buffalo, New York
December 15, 1995
CERTIFICATE OF AMENDMENT
OF
RESTATED CERTIFICATE OF INCORPORATION
(As Restated March 15, 1985)
OF
NATIONAL FUEL GAS COMPANY
Pursuant to the provisions of Chapters 7 and 9 of Title 14A of the New
Jersey statutes and particularly Sections 14A:7-2(4) and 14A:9-4 thereof,
National Fuel Gas Company, a corporation organized under the laws of the State
of New Jersey, hereby certifies:
FIRST: The name of the Corporation is NATIONAL FUEL GAS COMPANY (the
"Company").
SECOND: The Board of Directors of the Company ("the Board"), at a
meeting duly called and held on December 11, 1986, adopted, inter alia, the
following resolutions:
RESOLVED: That the first sentence of Article
FOURTH of the Company's Restated Certificate of
Incorporation ("Certificate"), be amended to read
as follows:
The total authorized capital stock of this
Corporation shall consist of Three Million Two
Hundred Thousand (3,200,000) shares of Preferred
Stock having the par value of Twenty-Five Dollars
($25) per share and One Hundred Million
(100,000,000) shares of Common Stock having no par
value per share; and it is
FURTHER RESOLVED: That the above proposed
amendment to the Company's Restated Certificate of
Incorporation, as hereby approved by the Board of
Directors, be submitted to a vote of the Company's
common stockholders, at
<PAGE 2>
the Annual Meeting of Stockholders to be held on
February 19, 1987, or any adjournment thereof, with
the recommendation that they approve same; and it
is
FURTHER RESOLVED: That pursuant to Article FOURTH, paragraph 7 of the
Certificate and New Jersey Statutes, Annotated,
14A:7-2, effective upon the issuance of the
necessary Order in connection with the U-1
described in the resolution below, and such other
necessary filing described in said resolution,
the number of authorized shares, $25 par value,
of the Company's Cumulative Preferred Stock,
9.20% Series, none of which shares are currently
outstanding, be, and hereby is, reduced from
1,200,000 to 0; that all of the heretofore
authorized shares of such series be, and hereby
are, reclassified as, and restored to the status
of, shares of Preferred Stock, $25 par value,
which are not part of any series; and that
Article FOURTH of the Certificate be, and
hereby is, amended to delete, in its entirety,
the unnumbered paragraph headed "Cumulative
Preferred Stock, 9.20% Series"; and it is
FURTHER RESOLVED: That all actions heretofore taken, and which
may hereafter be taken as they deem necessary or
appropriate, by the President and officers of the
Company in connection with the above proposed
amendments to the Certificate, including, but not
limited to, the filing of an Application-
Declaration on Form U-1 and amendments thereto,
with the Securities and Exchange Commission
("Commission"), receipt of an Order in connection
therewith, and necessary filings with the Secretary
of State of the State of New Jersey be, and they
hereby are, in all respects authorized, approved,
ratified and confirmed.
<PAGE 3>
THIRD: That said Annual Meeting of Common Stockholders of the Company
was held on the 19th day of February, 1987, pursuant to written notice of the
time, place and purposes of said meeting, including the taking of action upon
the first-mentioned amendment to the Restated Certificate of Incorporation of
the Company approved by the Board as aforesaid.
FOURTH: Said written notice of said Annual Meeting was mailed to each
stockholder of record entitled to vote thereon in accordance with the Company's
By-Laws and not less than 10 nor more than 60 days before the date of said
Annual Meeting.
FIFTH: The number of shares of Common Stock of the Company entitled to
vote as a class at said Annual Meeting was 11,928,496, and each such share
entitled the registered holder thereof to abstain from voting or to vote one
vote for or against the adoption of the first above-mentioned amendment.
SIXTH: At said Annual Meeting, the following votes were registered
with respect to the first above-mentioned amendment set out in paragraph SECOND
above:
For - 9,470,278 shares of Common Stock
Against - 538,602 shares of Common Stock
Abstain - 390,656 shares of Common Stock
A quorum of the holders of Common Stock was present and voting at said
Annual Meeting, and the amendment was duly adopted by the affirmative vote of a
majority of the votes cast by holders of outstanding shares of Common Stock
entitled to vote thereon.
<PAGE 4>
SEVENTH: Article FOURTH of the Restated Certificate of Incorporation
of the Company is also amended so that (i) all of the heretofore authorized
shares of Cumulative Preferred Stock, 9.20% Series, are reclassified as and
restored to the status of shares of Preferred Stock, $25 par value, which are
not part of any series and (ii) the unnumbered paragraph of said Article FOURTH
headed "Cumulative Preferred Stock, 9.20% Series*, is deleted from that Article,
as provided in the second above-mentioned amendment set forth in paragraph
SECOND above.
EIGHTH: The amendments shall become effective on the date of filing.
Dated: March 9, 1987 NATIONAL FUEL GAS COMPANY
By: /s/ Bernard J. Kennedy
Bernard J. Kennedy, President
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL
GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES AND IS QUALIFIED
IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1995
<PERIOD-START> OCT-01-1994
<PERIOD-END> SEP-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,649,182
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 189,244
<TOTAL-DEFERRED-CHARGES> 8,653
<OTHER-ASSETS> 191,223
<TOTAL-ASSETS> 2,038,302
<COMMON> 37,434
<CAPITAL-SURPLUS-PAID-IN> 383,031
<RETAINED-EARNINGS> 380,123
<TOTAL-COMMON-STOCKHOLDERS-EQ> 800,588
0
0
<LONG-TERM-DEBT-NET> 474,000
<SHORT-TERM-NOTES> 52,600
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 95,000
<LONG-TERM-DEBT-CURRENT-PORT> 88,500
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 527,614
<TOT-CAPITALIZATION-AND-LIAB> 2,038,302
<GROSS-OPERATING-REVENUE> 975,496
<INCOME-TAX-EXPENSE> 43,879
<OTHER-OPERATING-EXPENSES> 807,218
<TOTAL-OPERATING-EXPENSES> 851,097
<OPERATING-INCOME-LOSS> 124,399
<OTHER-INCOME-NET> 5,378
<INCOME-BEFORE-INTEREST-EXPEN> 129,777
<TOTAL-INTEREST-EXPENSE> 53,883
<NET-INCOME> 75,894
0
<EARNINGS-AVAILABLE-FOR-COMM> 75,894
<COMMON-STOCK-DIVIDENDS> 59,625
<TOTAL-INTEREST-ON-BONDS> 40,896
<CASH-FLOW-OPERATIONS> 173,460
<EPS-PRIMARY> 2.03
<EPS-DILUTED> 2.03
</TABLE>
AMENDMENT TO
DEATH BENEFITS AGREEMENT
National Fuel Gas Company ("Company"), by action of its Board of
Directors at its September 15, 1993 meeting, authorized the president of the
Company to amend certain existing executive benefit agreements to reflect
compensation that has been or will be provided under the Company's Annual At
Risk Compensation Incentive Program ("AARCIP"). Accordingly, the Company, and
Bernard J. Kennedy ("Executive"), do hereby amend the death benefit agreement,
dated August 28, 1991 respecting the Executive, which was previously executed by
the parties hereto ("Agreement"), as follows:
1. The last two sentences of Article II, paragraph (a) of the
Agreement are hereby amended to read as follows:
"Then, the Policies shall pay to the beneficiary or
beneficiaries of the Executive or any successor owner he has
designated thereunder ("Beneficiary") (i) 72 times the base
monthly salary provided by the Company to the Executive
("Base Monthly Salary") at the time of Executive's death,
plus six times the most recent annual award to the Executive
under the Company's Annual At Risk Compensation Incentive
Program ("AARCIP"), if the Executive dies while employed by
the Company, or (ii) 72 times the Base Monthly Salary for
the month prior to the Executive's commencement of
retirement, plus six times the most recent annual award to
the Executive under the AARCIP. If the payments from the
Policies
<PAGE 2>
hereunder are not sufficient to pay the above amounts in
full, Policy 4 (as described in Article III) and Policy 5
(as described in an addendum to the Agreement) shall pay the
difference to the Beneficiary."
2. Article II, paragraph (c) is amended and restated to read as
follows:
"An example of the Company's recovery from the Policies'
proceeds hereunder is as follows. If the Company had paid a
total of $650,000 in premiums on the Policies, at the time
Executive died, and the Policies paid death benefits of
$6,500,000, the Company would first recover its $650,000.
Then if the Executive's salary were $60,000.00 per month,
Beneficiary would receive 72 times that amount, or
$4,320,000. And, if the most recent award to the Executive
under the AARCIP were $250,000, Beneficiary would receive
six times that amount, or $1,500,000. Then, Company and
Beneficiary would share the $30,000 excess equally.
($6,500,000 - $650,000 - $4,320,000 - $1,500,000 = $30,000.)
Thus, the Company would recover $650,000 plus $15,000, or
$665,000 in total, and the Beneficiary would receive $15,000
in addition to the $5,820,000 death benefit provided for in
paragraph (a)."
<PAGE 3>
In all other respects, the Agreement, and subsequent amendments or
addenda thereto, shall remain unchanged.
In WITNESS WHEREOF, the parties hereto have executed this amendment
at Buffalo, New York, on the 15th day of March, 1994.
NATIONAL FUEL GAS COMPANY
/s/ Robert J. Dauer By: /s/ Bernard J. Kennedy
- ------------------- ---------------------------------
Witness Bernard J. Kennedy
President, Chief Executive Officer
and Chairman of the Board of Directors
/s/ Robert J. Dauer By: /s/ Bernard J. Kennedy
- ------------------- ---------------------------------
Witness Bernard J. Kennedy
EXPLORATION AND PRODUCTION AND OTHER NONREGULATED ACTIVITIES
Management's decisions to delay production, drilling, workovers and
recompletions due to extremely low gas prices, as well as those low prices,
caused 1995 operating income before taxes to decrease to $16.4 million from
$21.8 million in 1994.
Natural gas futures contracts traded on the New York Mercantile Exchange
(NYMEX) have become a valuable tool, not only in hedging the price of our
production, but also in evaluating probable price trends. Last year the NYMEX
prices indicated that the unusually warm winter was an aberration and that with
the return of more normal weather, gas prices would rise. That has clearly been
the case so far in fiscal 1996. We view our reserves as "money in the bank" and
seek to maximize the benefit of that asset to our shareholders by producing at
the most favorable price.
By postponing the drilling of new gas wells, we were unable to counteract
the natural depletion rates of both gas and oil condensate production from
existing wells. Our 1995 gas production declined 2.3 Bcf, or 10%, from the prior
year. The weighted average price received for natural gas in fiscal 1995
decreased $.51 per Mcf. Oil and condensate production decreased by 291,000
barrels, or 28%. A price increase of $1.30 per barrel was not sufficient to
offset the lower level of oil production. West Cameron 552, our significant
discovery offshore in the Gulf of Mexico in 1994, was the largest single field
we shut-in this year. Effective October 5, 1995 it was back on production and,
on December 1, it was producing 61,000 Mcf of gas per day and 870 barrels of oil
condensate per day. We own 100% of the working interest in the block.
Importantly, since we did not engage in much of our planned drilling
activity, we concentrated on acquisitions, thereby positioning ourselves for the
return of more normal weather and prices. Moreover we replaced 154% of our
production in 1995, a good part of it through those acquisitions. In addition,
we maintained our emphasis on cost control. A good indication of this is the
decrease in Seneca's lifting cost over time. Lifting cost is the unit of
production cost (including production and franchise taxes) incurred to raise gas
and oil from a producing formation. Since 1991, our lifting cost has decreased
from $.59 per Mcf equivalent to $.44 per Mcf equivalent. A significant portion
of recent savings was achieved in our Appalachian operations, and reflects the
wisdom of the 1994 merger of those operations into Seneca.
<PAGE 2>
Major Discoveries, Acquisitions in Offshore Gulf Coast
Our focus continues to be centered in the Gulf Coast region. In April we
announced a significant oil discovery at Vermilion 252. We have booked 24.2 Bcf
equivalent to reserves for the discovery and plan on drilling two more wells in
1996.
We made an offshore oil acquisition in West Delta Blocks 31 and 32 with
several co-participants. Our interest in the production is 1,100 Mcf of gas per
day and 800 barrels of oil condensate per day. We are in the process of
evaluating three-dimensional (3-D) seismic data acquired with the purchase to
identify additional drilling opportunities.
Also, we obtained ten of the fourteen drilling leases on which we bid in
the May 1995 Central Gulf of Mexico Federal Lease Sale. In the Western Gulf
Federal Lease Sale in September 1995, we were high bidder on the one lease for
which we bid. That lease has not yet been awarded. These additional prospects,
along with existing prospects, provide us with a 23 block drilling base to
continue a steady program offshore for the next three years.
This year we completed three wells located at West Cameron Block 552 in the
Federal waters offshore Louisiana. One of these is shown on the cover of this
report, as is a slice of the seismic data used to make the find. Two dimensional
and 3-D seismic technology, which enables us to record data and actually create
an image of what is under the ground, is the most notable element of our
successful offshore drilling program. Our skill in using it has resulted in an
82% drilling success ratio in our offshore program since its inception.
Onshore Gulf Program - Horizontal Drilling Maintains Perfect Success Rate
Because of the delays in activity, we drilled only three horizontal wells
in 1995, all of which were successful. This continues our 100% success rate for
a total of 25 wells in this part of our onshore program.
Appalachian Activity
This year we focused on cost cutting in our East program. We reduced our
lifting cost in Appalachia from $.55 per Mcf equivalent last year to $.50 per
Mcf equivalent. In addition, general and administrative expenses were cut by 50%
from $1,406,000 to $698,000. Our cost savings were achieved through a variety of
innovations and efficiencies, including staff reductions and the judicious use
of outside contractors.
West Coast Activity
On our Temescal acreage we drilled three successful wells, all of which
were on proved, but undeveloped sites (meaning that the reserves had been booked
in previous years). Also this year, we made a $3.5 million acquisition of a
240-acre lease located in the Silverthread Field of California. Since assuming
operation, Seneca has improved total production over 25%, without adding
additional personnel. It is an example of the type of acquisition we pursue.
<PAGE 3>
Exciting recent news is the lifting of the export ban on Alaskan oil. The
influx of Alaskan oil has depressed the California oil market for years. The
elimination of the ban should improve the price of California oil.
Hedging Activity
We continue to eliminate a portion of the market risk associated with
fluctuations in the price of natural gas and crude oil through hedging. Our
intent is to lock in prices on approximately 60-75% of expected production, if
we can do so at prices acceptable to us. In 1995, a year of low gas prices,
hedging preserved $7.0 million of pre-tax revenues, or $.12 per share after tax.
Future Plans
Our current plans for fiscal 1996 are to drill up to eight wells offshore
in the Gulf, four to six horizontal wells onshore in Texas, and two wells in
California. In addition, we are seeking to apply successful technologies, like
the use of 3-D seismic data and horizontal drilling, to new areas. As a result,
we will drill up to two wells in the West Texas Permian Basin, where Seneca is
participating in a regional 3-D seismic program, and four to six wells in Ohio
utilizing a unique regional evaluation to identify potential oil plays. As in
the past, we will also evaluate other opportunities and prospects.
Other Nonregulated Activities
National Fuel Resources' Profits Increase
National Fuel Resources (NFR), our nonregulated full service gas marketing
company, increased pre-tax operating income by 46% to $2.4 million.
Many state regulatory commissions are requiring local utilities to allow
customers to purchase gas supplies in the competitive markets. NFR has
capitalized on these changes. In 1995, we expanded our services by opening an
office near Newark, New Jersey. Moreover, NFR also acquired Integrated Gas
Marketing, which marketed to retail commercial and industrial markets,
principally in New York.
In September 1995, NFR received approval from the FERC to become a
wholesale electric power marketer, and is pursuing other necessary approvals. We
expect to begin marketing wholesale electric power within the next year.
Leidy Hub, Inc. Joins New Business Entity
In 1995 Leidy Hub, Inc. formed, with affiliates of NGC Corporation, Nicor
Inc. and Pacific Enterprises, an entity known as Enerchange, L.L.C.
(Enerchange). Enerchange will develop, manage and operate interests in natural
gas hubs located throughout North America. In addition to the Ellisburg-Leidy
Hub, we now have an interest in the Chicago Hub and the California Energy (Los
Angeles) Hub. Leidy Hub is a 14.5% owner of Enerchange.
<PAGE 4>
Enerchange is a 50% participant in another entity formed to develop and
promote an electronic trading system. As more and more local gas utilities
unbundle their sales and transportation services, we anticipate that
Enerchange's three market centers will become a vital link for parties buying
and selling gas.
Timber Division
Earnings were down slightly this year in our timber operation, reflecting a
decline in the price received for lumber. Nonetheless, this business contributes
positively to earnings.
Pipeline Construction Subsidiary Discontinued
In 1995 we elected to discontinue Utility Constructors, Inc. (UCI), our
nonregulated pipeline construction subsidiary, because of few pipeline
construction projects. The sale of that subsidiary's equipment, net of accrued
expenses, amounted to a gain of $.03 per share to earnings.
New Subsidiary Pursues International and Domestic Energy Projects
Horizon Energy Development, Inc. is a newly formed subsidiary created to
engage in the development, financing and acquisition of international and
domestic electric generation projects and in foreign utility companies. To
facilitate our foreign electric generation initiative, Horizon has succeeded to
the interest of two former partners in a partnership known as Sceptre Power
Company. Our partners in Sceptre have developed a number of domestic power
projects, and they have engaged in the development of foreign and domestic steam
and electric power generation projects since 1993. With the experienced team we
now have in place, we are actively pursuing opportunities in South America,
Eastern Europe and Asia.
UTILITY OPERATION
Efforts in the Utility Operation continue to focus on providing high quality
service at the lowest possible cost to customers, while pursuing an appropriate
rate of return for shareholders. While our customer service and cost containment
performance remain strong, the financial results for the Utility Operation
declined this year, with operating income before income taxes of $83.8 million,
down 8% from $90.6 million in 1994. Extremely warm weather and lower than
expected residential and commercial usage took their toll on this segment in
fiscal 1995.
Temperatures were 7% warmer than normal and 12% warmer than last year.
Consequently, total utility throughput declined by 10.3 Bcf. As designed, a
weather normalization feature in New York rates tempered the impact of the
weather on earnings. We do not have a similar adjustment mechanism in our
Pennsylvania service area and, therefore, weather negatively affected earnings
in this jurisdiction. Also impacting 1995 results was the annual reconciliation
of gas costs in New York that resulted in $4.3 million of lost and unaccounted
for gas that was in excess of that recoverable in rates.
<PAGE 5>
Even with significantly warmer than normal weather, we were able to take
advantage of recently introduced incentive mechanisms in both New York and
Pennsylvania which allow us to retain a portion of the revenues derived from the
sale of gas outside our service territory. We also have an incentive mechanism
in New York under which we retain a portion of the savings realized from the
release to third parties of upstream pipeline capacity when that capacity is not
needed to serve our customers. In 1995, these incentives combined to add
approximately $830,000 to revenues.
Competitive and Customer-Driven Rate Structures
Regulatory changes will continue to impact how we provide service to
customers and generate earnings for the company. Utilities have historically
received most of their revenue from retail sales of gas to homes and businesses.
This is referred to in our industry as "bundled sales" because the customer pays
a single price for a package of services including the cost of gas and the
associated transportation, balancing and storage costs necessary to deliver it.
Recent regulatory actions have now given the company the opportunity to
truly engage in a new competitive era. Of particular note, the Public Service
Commission of the State of New York (PSC) approved a rate design settlement as
part of our most recent rate case under which we became the first New York
utility to "unbundle" gas sales and transportation services pursuant to a
December 1994 PSC order known as the Generic Restructuring Order.
The Generic Restructuring Order instructed all New York gas utilities to
unbundle their services and to offer market-based rates, if appropriate.
Pursuant to that order, our utility negotiated a settlement agreement
providing for transportation service with, among others, groups representing our
large industrial customers. The PSC approved the settlement and, as of September
20, 1995, New York customers who use 5,000 Mcf or more of gas per year may now
choose from a menu of unbundled services including transportation, customized
sales services, and daily or monthly-metered options. Rates for these new
services may be "flexed" at the company's discretion, in order to better respond
to growing competition.
On November 9, 1995, we submitted a filing to the PSC which proposes to
eliminate the 5,000 Mcf per year minimum volume requirement for transportation
service, thereby creating an opportunity for all customers, including
residential, to choose their gas supplier. We anticipate that this proposal will
be approved in some form in the Spring of 1996. Because of the complexity
involved in nominating and managing gas supply, it is not likely that customers
who use less than 2,500 Mcf of gas a year will initially take advantage of the
new unbundled services. However, we are committed to eventually making this
concept work for all customers, including the private homeowner.
<PAGE 6>
A service innovation of this kind is nothing new to us. In fact, we view
the Generic Restructuring Order as a regulatory endorsement of many of the
decisions the company had already implemented. We were the first utility to
unbundle services to our customers when we introduced a transportation rate in
1983 in New York. During the past five years alone we have increased the number
of transportation customers to 1,528 from 752, with nearly all industrial
customers that qualify electing to receive transportation service. We have also
been an innovator in Pennsylvania by offering many unbundled services in that
state to allow customers greater flexibility and lower prices.
National Fuel is, and will continue to be, an industry leader in offering
flexible rate and service options to meet customer needs in an ever-changing and
more price sensitive environment.
Company Efforts Result in Competitive Utility Prices
One of our proudest accomplishments over the past decade has been the
competitiveness of our retail rates. We continue to be one of the lowest priced
gas utilities in the states in which we operate.
However, several factors that remain beyond our control have a direct and
substantial impact on our cost of providing service. Taxes currently represent
some 17.4% of a residential customer's gas bill in New York and 10% in
Pennsylvania. Included in New York is the Gross Receipts Tax, which represents
as much as 8.4% of an average residential customer's bill and, in effect, is
concealed, since by law we are unable to itemize it. Also significant is the
subsidization of uncollectible account expense by those customers who
unfailingly pay their gas bills. We are aggressively addressing these concerns
in an effort to keep natural gas rates as reasonable as possible for our
customers.
At the same time, we are taking steps to reduce costs for customers who
simply cannot make ends meet. We currently have pilot "low income" rates in
effect in New York and Pennsylvania. These programs enable customers to have
continued gas service while reducing their usage and remaining current in their
payments. Also, we are working to establish a pilot transportation program for
the Erie County, New York Department of Social Services that, if approved by the
PSC, would enable the direct purchase of gas supplies for delivery to the
Department's low income clients. This should reduce expenses for the Department
and our customers alike. At the federal level, we are working to preserve
funding for the Low Income Home Energy Assistance Program (LIHEAP) which is
being reduced and is in jeopardy of being eliminated entirely for the winter of
1997. LIHEAP has been a safety net program for many of our customers for 17
years.
Our gas acquisition is focused on maintaining our competitive price
position by taking advantage of opportunities to refine our current contracts
and explore new gas supply alternatives.
<PAGE 7>
An example of these efforts is Distribution Corporation's recent notice to
terminate a transportation agreement with Tennessee Gas Pipeline Company
effective August 1996, which covers 30,750 Decatherms per day. Our intent is to
replace this transportation service with competitively priced winter-only
service from storage service operators. This should produce a savings of about
$5 million per year.
In addition, we signed a gas storage agreement with Avoca Natural Gas
Storage to commence in October 1998. Use of this storage service will replace
other upstream capacity and result in an estimated future savings of over $5
million dollars per year.
Customer Service Emphasized
Our customer satisfaction level remains high at 86.9 percent. We measure
how satisfied our customers are with recent contacts with the company, whether
it be over the telephone, in person at a Consumer Assistance Center, or at their
homes. The results are used to identify training needs, as a guide for the
modification of policies or procedures and as part of the PSC customer service
performance incentive plan. The plan establishes minimum customer service levels
for the company's telephone response time, percentage of field appointments
kept, timeliness of new service line installations, frequency of billing
adjustments and estimated meter readings, customer satisfaction levels and
number of complaints to the PSC.
Our excellent customer service is due to the expertise of our employee
group. With an average tenure of 22 years, our experienced employees work
diligently to provide the low cost, dependable service upon which our customers
have come to rely. Their unwavering commitment is demonstrated by our ability to
maintain strong customer satisfaction levels even while aggressively containing
costs.
Rate Developments
In order to recover the capital investments and operating expenditures
required to provide a safe and reliable utility system for our customers, we
have been on a schedule of filing annual rate increase requests. In December
1994, the Pennsylvania Public Utility Commission (PaPUC) approved a $4.8 million
rate increase with a rate of return on equity of 11.0%. Rates took effect that
same month. In a subsequent case filed in March 1995, a settlement was approved
by the PaPUC in September 1995. The rate change amounted to an increase of $6.0
million in annual revenues with no specified rate of return on equity. New rates
were effective as of September 27, 1995.
<PAGE 8>
In September 1995, the PSC issued an order authorizing a base rate increase
of $14.2 million with a rate of return on equity of 10.4%. Subsequently, the
company filed a rate request with the PSC in November 1995, in which it is
seeking an increase of $28.9 million to be effective in October 1996.
PIPELINE AND STORAGE
The year 1995 was dominated by the need to address major regulatory and Company
initiatives, specifically the continuing restructuring of our industry,
compliance with the Clean Air Act Amendments of 1990 and the placement of the
final touches on the merger into Supply Corporation of its former sister
company, Penn-York. A series of strategies with respect to these issues
converged toward fulfillment this year. As a result, our Pipeline and Storage
segment is well-positioned for the rapidly approaching competitive world.
Moreover, we were able to accomplish our goals while at the same time increasing
earnings.
Financial Performance
In spite of higher operating costs, and the recording of a reserve in the amount
of $3.7 million for previously deferred preliminary survey and investigation
charges for the Laurel Fields Storage Project, operating income before income
taxes increased 9% to $67.9 million in fiscal 1995 compared to $62.3 million
last year. This result reflects the application of a final rule issued by the
Federal Energy Regulatory Commission (FERC) which addresses and clarifies
financial reporting aspects of the current practices for unbundled pipeline
sales and open access transportation.
Positioning Ourselves
In 1995 over 80% of our transportation and storage revenues were attributable to
long-term contracts. Nonetheless, our pipeline and storage business is moving
closer to a truly competitive market. States are beginning to open utility
markets to competition. Some utilities, in turn, have pipeline capacity they no
longer require because certain customers are not purchasing gas from them. In
the short-term the capacity is being sold to others. As existing contracts
expire, utilities will not fully renew current contracts. Hence, pipeline
capacity has become a commodity.
We believe that the ultimate conclusion of this evolution will be a fully
competitive marketplace. Companies like Supply Corporation will be competing
against each other to provide transportation and storage service to those who
require it. It also appears that long-term contracts will generally be a thing
of the past, as customers will want flexibility to respond to further market
changes.
To position ourselves for the new era we have concentrated on putting
regulatory issues behind us so that we can focus on what is important in a
competitive market: providing the most reliable and economical service to our
customers.
Rate Activity
On November 6, 1995, an administrative law judge certified a settlement in
principle to the FERC in Supply Corporation's October 1994 rate case filing,
which would increase our revenue by $6.4 million annually. The services and
facilities of Penn-York, an affiliate merged into Supply Corporation effective
July 1, 1994, will be rolled-in to the latter company's rates. The result will
be a more efficient structure.
<PAGE 9>
Competition already exists for us with respect to approximately two-thirds
of the storage capacity we dedicate to nonaffiliated customers. That capacity is
now subject to year-to-year contracts. In the pending settlement, Supply
Corporation has agreed not to seek recovery from existing customers of lost
revenues related to terminated storage service for five years, as long as the
terminations are not greater than approximately 7 Bcf. We feel confident that we
will be able to remarket such volumes. We also agreed not to file a new rate
case based on increased cost of service for three years. These actions are taken
in recognition of the fact that we are now part of the competitive world.
Gathering Rates
Supply Corporation has approximately $20 million of production and
gathering facilities used, in part, to gather natural gas of local producers in
the Appalachian region. The FERC has directed Supply Corporation to fully
unbundle its production and gathering cost of service from its transportation
cost of service, and to establish a separate gathering rate. An administrative
law judge certified a new settlement in principle on this matter to the FERC in
October 1995. As a consequence, the company believes that it will earn on and
fully recover its investment in production and gathering facilities.
Environmental Compliance
As a result of the requirements of the Clean Air Act Amendments of 1990,
Supply Corporation spent $5.1 million in fiscal 1995 to retrofit 16 compressor
stations with "clean burn" equipment. The refitted units reduce emissions of
nitrogen oxides by about 90 percent, realize fuel savings of three to five
percent, and require less maintenance. Importantly, we successfully completed
this extraordinary and expensive project within the period necessary for
recovery in our latest rate case. Because we do not expect to file a case for at
least three years, this action ensured that our shareholders earn a reasonable
return on their investment for that period.
Laurel Fields Storage Project Postponed
We withdrew our application from the FERC to construct facilities
associated with our Laurel Fields Storage Project. While we believe that the
project is solid, there was not sufficient customer interest at this time due to
the restructuring of the natural gas industry. In particular, many potential
customers are tied to long-term transportation contracts through the year 2000
and beyond. We continue to believe that it makes sound business sense for
customers to store gas near ultimate markets. Because of that belief, we plan on
remarketing our storage proposals in 1997 or 1998, to leave sufficient
construction time to bring the projects to fruition by the year 2000, when many
contracts for pipeline transportation expire giving customers the option to
switch to storage service.
<PAGE 10>
Future Plans
After the final settlement of our current rate case, Supply Corporation's
maximum rates should be fixed for at least three years and possibly longer. By
running a tight ship and keeping capital expenditures within the depreciation
allowance, Supply Corporation has the opportunity to generate appropriate
earnings for the benefit of our shareholders.
Moreover, our affiliates continue to develop the market area hub in the
vicinity of Ellisburg and Leidy, Pennsylvania. Within this area, Supply
Corporation enjoys the unique position of interconnecting with all of the major
pipelines bringing Canadian and southwest gas to the northeast. It is our intent
to foster increases in activity at the hub with the goal of also increasing
volumes transported and revenue for Supply Corporation. Finally, we will
continue to pursue acquisition opportunities as they present themselves.
<PAGE 11>
APPENDIX TO EXHIBIT 13 - This appendix contains a narrative description of image
and graphic information as contained in the discussion of the Company's business
segments included in the paper copy of the Company's combined Annual Report to
Shareholders/Form 10-K.
I. Exploration and Production and Other Nonregulated Activities
a) Graph - Oil and Gas Prices
A bar graph detailing weighted average oil and gas prices (in dollars)
for the years 1991 through 1995, as follows:
1991 1992 1993 1994 1995
---- ---- ---- ---- ----
Gas $2.00 $1.97 $2.20 $2.18 $1.67
Oil $20.62 $17.11 $16.78 $14.86 $16.16
b) Graph - Lifting Costs
A bar graph detailing lift costs (in dollars per equivalent thousand
cubic feet (Mcf)) for the years 1991 through 1995, as follows:
1991 1992 1993 1994 1995
---- ---- ---- ---- ----
$.59 $.62 $.54 $.45 $.44
Dotted line crossing horizontally across the 5 bars indicates the 5-year
average of $.51.
c) Graph - Oil and Gas Proved Reserves
A bar graph detailing oil and gas proved reserves (in million of barrels
(MMbbl) and billion cubic feet (Bcf), respectively) for the years 1993
through 1995, as follows:
1993 1994 1995
---- ---- ----
Gas (in Bcf) 175.1 247.4 221.5
Oil (in MMbbl) 18.5 17.5 22.9
d) Image - Picture of offshore drilling platform in West Delta 30 field
with the following caption: West Delta 30 Field covers 11 blocks and is
one of the largest fields in the Gulf of Mexico. The field was
discovered in the late 1950s and one of the blocks in the field was
<PAGE 12>
purchased by Seneca Resources in September 1995. The field has produced
half a billion barrels of oil and seven-tenths of a trillion cubic feet
of gas.
e) Image - Map of Gulf Coast of Texas and Louisiana, including offshore,
indicating areas where Seneca Resources Corporation has prospects,
successful discoveries and wells on-production.
f) Image - Picture of drilling rig in Temescal 9-5 field with the following
caption: Temescal 9-5, located near Lake Piru, California in Ventura
County, has proven to be a successful well with production at 210 Mcf of
natural gas per day and 193 barrels of oil per day. This field found by
Seneca was the first new discovery in Ventura County in more than ten
years.
g) Image - Map of the United States identifying the location
of the Ellisburg-Leidy Hub, California Hub (Los Angeles)
and Chicago Hub.
II. Utility Operation
a) Image - Picture of employee conferring with
realtor/contractor in Erie, Pennsylvania with the
following caption: The New Services Department
expedites new service requests by giving the customer
one contact who coordinates the application process
through completion. The company's goal is to install
new services within 10 days. Wanda Bender, Supervisor
of New Services, confers with Realtor/Contractor John
Schaefer who is developing a residential subdivision in
Millcreek Township, Erie, Pennsylvania.
b) Image - Picture of airplane de-icing with the following
caption: Process Technologies Inc. (PTI) developed the
Infratek system, a revolutionary natural gas-driven
radiant heat process to improve airplane de-icing and
make it more environmentally friendly. National Fuel
supported PTI's demonstration at the Greater Buffalo
International Airport. Natural gas was used to power
the testing.
<PAGE 13>
c) Graph - Two bar graphs detailing the Utility Operation's transportation
revenues (in millions of dollars) and transportation volumes (in Bcf)
for every other year, beginning in 1985 through 1995, as follows:
1985 1987 1989 1991 1993 1995
---- ---- ---- ---- ---- ----
Revenues
(millions of dollars) $5.4 $10.4 $17.8 $22.4 $30.2 $37.2
Volumes (Bcf) 7.0 16.5 31.4 39.8 48.9 52.8
d) Graph - Bar graph detailing National Fuel's utility rates as being
lower than the state average in both New York and Pennsylvania, based
on an average annual cost for the three years ended September 30, 1995,
as follows:
National Fuel State Average
New York $904 $997
Pennsylvania $860 $882
e) Image - Picture of production at Abbott Laboratories'
Cheektowaga, New York plant with the following caption:
Abbott Laboratories' Cheektowaga, New York plant
manufactures plastic medical components for customers
around the world. It is National Fuel's seventh
cogeneration customer. The gas-fired, 2 megawatt
cogeneration system will allow Abbott to reduce its
energy costs resulting in a payback period of less than
four years and will add 180 MMcf per year to National
Fuel's annual throughput. Plant Manager William P.
Bobo, Jr. and National Fuel's Senior Energy Consultant
Carol Tuzzolino observe Production Specialist Sandy
Conners producing a sight chamber at a plastic injection
molding machine.
<PAGE 14>
f) Graph - A pie graph detailing the use of the New York
revenue dollar (in percents), broken down as follows:
Gas Purchases 45.5%
Other Operating Costs 29.2
Taxes 17.4
Interest Charges 4.1
Earnings 3.8
------
100.0%
III. Pipeline and Storage
a) Graph - A pie graph of the Pipeline and Storage segment's
transportation and storage service revenues by contract length (in
percents) for 1995, broken down as follows:
Less than One Year 3%
One to Five Years 16
Greater than Five Years 81
----
100%
b) Image - Picture of Company's gas dispatch operations
with the following caption: Gas Dispatch operations
have been consolidated to a new Gas Control Operations
Center. Monitoring system operations are Gas Dispatch
personnel John O'Brien, Timothy Duggan, David Fridmann
and Timothy Cody.
c) Image - Picture of employee monitoring compression
equipment at the Company's Independence Compressor
Station, Andover, New York, with the following caption:
New, state-of-the-art emission reduction equipment, as
well as fire and gas detection equipment has been
installed on a number of compressor stations. These
devices will result in 90% cleaner air emission and
improved safety protection. Guy Milligan, Station
Engineer at the Independence Compressor Station,
Andover, New York, regularly monitors compression
equipment.
CERTIFICATE OF AMENDMENT
OF
RESTATED CERTIFICATE OF INCORPORATION
(As Restated March 15, 1985)
OF
NATIONAL FUEL GAS COMPANY
Pursuant to the provisions of Chapter 9 of Title 14A of the New Jersey
Statutes and particularly Section 14A: 9-4 thereof, National Fuel Gas Company, a
corporation organized under the laws of the State of New Jersey, hereby
certifies:
FIRST: The name of the Corporation is NATIONAL FUEL GAS
COMPANY (the "Company").
SECOND: The Board of Directors of the Company ("the Board"), at a
meeting duly called and held on December 10, 1987, adopted, inter alia, the
following resolutions:
RESOLVED: That the following Article NINTH be added to the Company's
Restated Certificate of Incorporation, as amended
("Certificate"):
"NINTH: No director or officer of this corporation
shall be personally liable to the corporation or any of
its shareholders for monetary damages for breach of any
duty owed to the corporation or any of its shareholders,
except to the extent that such exemption from liability
is not permitted under the New Jersey Business
Corporation Act, as the same exists or may hereafter be
amended, or under any revision thereof or successor
statute thereto";
and it is
FURTHER RESOLVED: That the above proposed amendment and addition to the
Company's Certificate, as hereby approved by the Board of
Directors, be submitted to a vote of the Company's common
<PAGE 2>
stockholders at the Annual Meeting of Stockholders to be
held on February 18, 1988, or any adjournment thereof,
with the recommendation that they approve same; and it is
FURTHER RESOLVED: That all actions heretofore taken, and which may hereafter
be taken as the officers of the Company deem
necessary or appropriate, in connection with the above
proposed amendments to the Certificate, including, but
not limited to, the filing of an Application-
Declaration on Form U-1, and amendments thereto, with
the Securities and Exchange Commission ("Commission"),
receipt of an Order in connection therewith, and
necessary filings with the Secretary of State of the
State of New Jersey be, and they hereby are, in all
respects authorized, approved, ratified and confirmed.
THIRD: That said Annual Meeting of Common Stockholders of the Company was
held on the 18th day of February, 1988, pursuant to written notice of the time,
place and purposes of said meeting, including the taking of action upon the
amendment to the Restated Certificate of Incorporation, as amended, of the
Company approved by the Board as aforesaid.
FOURTH: Said written notice of said Annual Meeting was mailed to each
stockholder of record entitled to vote thereon in accordance with the Company's
By-Laws and not less than ten (10) nor more than sixty (60) days before the date
of said Annual Meeting.
FIFTH: The number of shares of Common Stock of the Company entitled to
vote as a class at said Annual Meeting was 25,871,234, and each such share
<PAGE 3>
entitled the registered holder thereof to abstain from voting or to vote one
vote for or against the adoption of the amendment.
SIXTH: At said Annual Meeting, the following votes were registered with
respect to the amendment set out in paragraph SECOND above:
For - 19,752,149 shares of Common Stock
Against - 1,227,581 shares of Common Stock
Abstain - 537,548 shares of Common Stock
A quorum of the holders of Common Stock was present and voting at said
Annual Meeting, and the amendment was duly adopted by the affirmative vote of a
majority of the votes cast by holders of outstanding shares of Common Stock
entitled to vote thereon.
SEVENTH: The amendment shall become effective on the date of filing.
Dated: February 18, 1988 NATIONAL FUEL GAS COMPANY
By: /s/ Bernard J. Kennedy
Name: Bernard J. Kennedy
Title: president
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<TOTAL-CURRENT-ASSETS> 218,126
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0
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WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
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<PERIOD-TYPE> 03-MOS
<FISCAL-YEAR-END> SEP-30-1995
<PERIOD-START> OCT-01-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,582,207
<OTHER-PROPERTY-AND-INVEST> 0
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<TOTAL-DEFERRED-CHARGES> 14,140
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<TOTAL-ASSETS> 2,049,403
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<CAPITAL-SURPLUS-PAID-IN> 381,426
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<TOTAL-COMMON-STOCKHOLDERS-EQ> 798,515
0
0
<LONG-TERM-DEBT-NET> 404,000
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0
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0
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</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL
GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
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<S> <C>
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0
0
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0
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0
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<TOTAL-INTEREST-ON-BONDS> 0
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<EPS-PRIMARY> 1.98
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</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL
GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 09-MOS
<FISCAL-YEAR-END> SEP-30-1995
<PERIOD-START> OCT-01-1994
<PERIOD-END> JUN-30-1995
<BOOK-VALUE> PER-BOOK
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<TOTAL-DEFERRED-CHARGES> 11,699
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<TOTAL-ASSETS> 2,030,682
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<CAPITAL-SURPLUS-PAID-IN> 382,816
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0
0
<LONG-TERM-DEBT-NET> 504,000
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0
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0
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<TOTAL-INTEREST-ON-BONDS> 0
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</TABLE>
