UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONUnited States
Securities and Exchange Commission
Washington, D. C.D.C. 20549
FORMForm 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTIONAnnual Report Pursuant to Section 13 ORor 15(d) OF
THE SECURITIES EXCHANGE ACT OFof
The Securities Exchange Act of 1934
For the Fiscal Year Ended September 30, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From..........to..........1995
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANYNational 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:
NONENone
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 (or for such shorter period that the
registrant was required to file such reports), 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 $953,688,000$1,164,782,000 as of November 30, 1994.1995.
Common stock, $1 par value, outstanding as of November 30, 1994:
37,337,0561995:
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 16, 1995,15, 1996 are incorporated by reference into Part III of this
report.
NATIONAL FUEL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Fiscal Year Ended September 30, 19941995
TABLE OF CONTENTS
Page
GLOSSARY OF TERMS 3
PART I
ITEM 1. BUSINESS
THE COMPANY AND ITS SUBSIDIARIES 61
RATES AND REGULATION 72
THE UTILITY OPERATION 83
THE PIPELINE AND STORAGE 14
SELECTED STATISTICS OFSEGMENT 3
THE SYSTEM'S REGULATED OPERATIONS 16 EXPLORATION AND PRODUCTION 17SEGMENT 3
OTHER NONREGULATED 19OPERATIONS 4
SOURCES AND AVAILABILITY OF RAW MATERIALS 4
COMPETITION 195
SEASONALITY 7
CAPITAL EXPENDITURES 227
ENVIRONMENTAL MATTERS 227
MISCELLANEOUS 228
EXECUTIVE OFFICERS OF THE COMPANY 238
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES 249
EXPLORATION AND PRODUCTION ACTIVITIES 249
ITEM 3. LEGAL PROCEEDINGS
PARAGON/TGX PROCEEDINGS 2710
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 3012
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
SHAREHOLDER MATTERS 3112
ITEM 6. SELECTED FINANCIAL DATA 3213
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 3314
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 5228
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 9559
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 9559
ITEM 11. EXECUTIVE COMPENSATION 9559
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT 9560
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 9560
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K 9660
SIGNATURES 10165
GLOSSARY OF TERMSPART I
ITEM 1 Business
The following termsCompany and abbreviations used in the text of this report
are defined as indicated:
Bcf - Billion cubic feet.
Btu - British thermal unit.
Bypass - Obtaining service from a new supplier without utilizing the facility
of the former supplier.
Cogeneration - The use of gas for on-site production of both electricity and
heat for industrial and large commercial users.
Company or Registrant -its Subsidiaries
National Fuel Gas Company.
Condensate - A liquid hydrocarbon recovered atCompany (the Company or Registrant), a registered holding
company under the surface as natural gas is
produced.
Data-Track - Data-Track Account Services, Inc.
Degree Day - A measure of the coldness of weather experienced, based on the
extent to which the daily mean temperature falls below a reference
temperature, usually 65 degrees Fahrenheit (F). For example, on a day when
the mean temperature is 35 degrees F, there would be 30 degree days
experienced.
Development Well - A well drilled to a known producing formation in a
previously discovered field.
Distribution Corporation - National Fuel Gas Distribution Corporation.
Empire - Empire Exploration, Inc.
Exploratory Well - A well drilled to a previously untested geologic structure
to determine the presence of oil or gas.
Farm Out - An arrangement whereby the owner of a lease assigns the lease, or
some portion of it, to another party for drilling.
FERC - Federal Energy Regulatory Commission.
Firm Transportation - Pipeline transportation under contractual arrangements
providing service not subject to interruption.
Highland - Highland Land & Minerals, Inc.
Holding Company Act - Public Utility Holding Company Act of 1935, as amended.
Horizontal Drilling -A drilling technique in which the well bore runs
horizontal or parallel to the earth's surface. This exposes a greater portion
of the underground producing rock formation to the well bore than conventional
vertical drilling, improving overall productivity by permitting maximum
recovery from a reservoir.
GLOSSARY OF TERMS (Continued)
Leidy Hub - Leidy Hub, Inc.
Mbbl - Thousand barrels.
Mcf - Thousand cubic feet.
MMcf - Million cubic feet.
MMcfe - Million cubic feet equivalent.
NFR - National Fuel Resources, Inc.
NGV - Natural gas vehicle.
Nonregulated Operations - Consist of the Company's Exploration and Production
and Other Nonregulated business segments.
Note or Notes - Notes to Consolidated Financial Statements.
PaPUC - Pennsylvania Public Utility Commission.
Penn-York - Penn-York Energy Corporation.
PSC - State of New York Public Service Commission.
Regulated Operations - Consist of the Company's Utility and Pipeline and
Storage business segments.
Reserves - Estimated volumes of oil, gas or other minerals that can be
recovered from deposits in the earth with reasonable certainty.
Seneca - Seneca Resources Corporation.
SEC - Securities and Exchange Commission.
SFV - Straight fixed-variable.
Supply Corporation - National Fuel Gas Supply Corporation.
System - The Company and its subsidiaries.
Throughput - The sum of volumes of gas sold and volumes of gas transported
for customers.
Transportation Service - The movement of gas for third parties through
pipeline facilities for a fee.
UCI - Utility Constructors, Inc.
Unbundled Service - The separation of pipeline company services, such as
storage, gathering and transmission, with rates charged which reflect the cost
of each service.
GLOSSARY OF TERMS (Continued)
Underground Storage -The injection of large quantities of natural gas into
underground rock formations for storage during periods of low market demand
and withdrawal during periods of peak market demand.
WNC - Weather normalization clause.
Working Gas - Gas in an underground storage field that is available for market
which is in excess of the base gas.
PART I
ITEM 1. BUSINESS
COMPANY AND SUBSIDIARIES
The Company, a registered holding company under theamended (the
Holding Company Act,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 the
subsidiary companies identified below. All referencesits subsidiaries. Reference to
years"the Company" in this report are tomeans the Company's fiscal year ended September 30 unless otherwise noted.Registrant or the Registrant and its
subsidiaries collectively, as appropriate in the context of the disclosure.
The System constitutesCompany is an integrated natural gas operation and consistsconsisting of
operations which are regulated as to their rates and operations which are
not so regulated. The Regulated Operations fall within twothree major business segments:
Utility Operation and Pipeline and Storage. The Nonregulated Operations
consist principally of the Exploration and Production business segment. Other
Nonregulated operations include the System's natural gas marketing and
brokerage operations, pipeline construction operations, sawmill and dry kiln
operations, and natural gas market area hub operations.1. The Utility Operation is carried out by Distribution Corporation.
Pipeline and Storage operations are carried out by Supply Corporation.
Effective July 1, 1994, all of the Company's natural gas storage services were
consolidated into Supply Corporation through the merger of Penn-York into
Supply Corporation. Seneca is engaged in Exploration and Production
operations. Effective July 1, 1994, all of the Company's Exploration and
Production operations were consolidated into Seneca through the merger of
Empire into Seneca. Supply Corporation's exploration and production
activities were transferred to Empire, effective on January 1, 1994. Other
Nonregulated operations are carried out by NFR, UCI, Highland, Seneca,
Data-Track and Leidy Hub.
No single customer, or group of customers under common control,
accounted for 10% or more of the System's consolidated revenues in 1994.
Financial information about the Company's business segments can be found
in Note H - "Business Segment Information," on pages 79 to 81 of this report.National Fuel Gas Distribution
Corporation (Distribution Corporation), a New York corporation, is a public utility
thatcorporation. Distribution
Corporation sells natural gas and provides natural gas transportation serviceservices
through a local distribution system located in western New York and northwestern
Pennsylvania. During 1994, Distribution Corporation
served an average of 727,700 retail customers, compared with an average of
724,400 retail customers served during 1993. The principalPennsylvania (principal metropolitan areas
served areareas: Buffalo, Niagara Falls and
Jamestown, New York, andYork; Erie and Sharon, Pennsylvania.Pennsylvania).
2. The Pipeline and Storage segment is carried out by National Fuel Gas Supply
Corporation (Supply Corporation), a Pennsylvania corporation, is engaged in thecorporation. Supply Corporation
provides interstate natural gas transportation and storage of natural gasservices for
Systemaffiliated and nonaffiliated companies. Supply Corporation owns and operatescompanies through (i) an integrated gas pipeline
system extending from southwestern Pennsylvania to the New York-Canadian border
at the Niagara River.River, and (ii) 30 underground natural gas storage fields owned
and operated by Supply Corporation owns and operates 30four other underground natural gas
storage fields in its operating area and four additional
underground storage fields are operated jointly with certainvarious major interstate gas pipeline
companies.
ITEM 1. BUSINESS (Continued)3. The Exploration and Production segment is carried out by Seneca Resources
Corporation (Seneca), a Pennsylvania corporation,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.
Seneca's production is,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 the most part, sold to
purchasersutilities and end-users located in the vicinitynortheastern
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 its wells. In addition,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.
NFR, a New York corporation, is engaged in the marketing and brokerage
of natural gas and performs energy management services for utilities and
end-users.
UCI,holdings;
* Highland Land & Minerals, Inc. (Highland), a Pennsylvania corporation
is engaged in pipeline construction and
other construction work for the System and nonaffiliated companies, and is
headquartered in Linesville, Pennsylvania.
Highland, a Pennsylvania corporation,which operates a sawmill and kiln in Kane, Pennsylvania.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, particularly Distribution Corporation, primarily
throughCompany'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 issuanceCompany'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 collection notices.
Leidy Hub, a New York corporation, is a partnerthe 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 Ellisburg-Leidy
Northeast Hub Company, which operates a natural gas market area hub in
northeastern Pennsylvania serving the consuming regionspaper copy of the Northeast,
Mid-AtlanticCompany's combined Annual Report to Shareholders/Form
10-K, are included in this electronic filing as Exhibit 13 and Canada.incorporated
herein by reference.
Rates and Regulation
The hub offers services designed to simplify the
complexities and the volatility of the gas market for gas buyers and sellers.
RATES AND REGULATION
All System companies areCompany is subject to regulation by the SECSecurities 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-Systemintra-Company transactions and limitations on
diversification. Distribution Corporation is subjectThe SEC has recommended to regulation byCongress the PSC and the PaPUC
concerning rates and other matters. Supply Corporation is subject to
regulation by the FERC, concerning rates and other matters. In addition,
System companies are subject to federal, state and local laws and regulations
concerning numerous other matters.
On November 2, 1994, the SEC issued a concept release soliciting comment
on modernizationconditional repeal of
the Holding Company Act. The SEC has deemed thatAct, in conjunction with legislation which would allow the
various state regulatory commissions to have access to such books and records of
companies in a
reexamination of the need for, and role of, a federal holding company statute
issystem as would be necessary in lightfor effective
regulation, and allow for federal audit authority and oversight of affiliate
transactions. The effect of these changes if implemented, combined with other
recent utilitySEC 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 developments.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 modernizationregulatory changes, if any, may
occur as a result offrom this reexaminationproposal, and therefore what the impact will be
on the Company.
ITEM 1. BUSINESS (Continued)
UTILITY OPERATION
Gas SalesCompany might
be.
The Utility Operation's rates, services and Transportationother 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 System's Utility Operation is conducted solely through Distribution
Corporation. Substantially allPipeline and Storage segment's rates, services and other
matters are regulated by the Federal Energy Regulatory Commission (FERC). For
additional discussion of its sales are requirements sales (i.e.,
sales that varythe Pipeline and are not subjectStorage 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 significant minimum take obligations).
In 1994, Distribution Corporation's sales and transportation volumes by
customer class were 52% residential, 21% commercial and 27% industrial. In
1994, the Utility
Operation accountedand the Pipeline and Storage segment as the Regulated Operations.
In addition, the Company is subject to the same federal, state and
local regulations on various subjects as other companies doing business in the
same locations.
The Company's operations other than Supply Corporation and Distribution
Corporation are not regulated as to prices or rates for services. Accordingly,
this report occasionally refers collectively to the Exploration and Production
segment and the Other Nonregulated operations as the Nonregulated Operations.
The Utility Operation
The Utility Operation contributed approximately 52%50% of Systemthe Company's operating
income before income taxes. Information regarding the resultstaxes in 1995.
Additional discussion of
operations for the Utility Operation can be foundindustry 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,Operations" (MD&A), and in Item 8 at Notes B-Regulatory Matters, H-Commitments
and Contingencies and I-Business Segment Information.
The Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 40% of the Company's
operating income before income taxes in 1995.
The Pipeline and Storage segment currently has service agreements
for substantially all of its firm transportation capacity, which totals
approximately 1,860 million cubic feet (MMcf) per day. The Utility Operation has
contracted for approximately 1,120 MMcf per day or 60% of that capacity until
2003 and continuing year-to-year thereafter.
The Pipeline and Storage segment has available for sale to
customers approximately 60.8 billion cubic feet (Bcf) of firm storage capacity.
The Utility Operation has contracted for 25.3 Bcf or 42% of that capacity, in
service agreements with initial terms of approximately 10 years and continuing
year-to-year thereafter, effective beginning in 1993 (23.3 Bcf) and 1996 (2.0
Bcf). Nonaffiliated customers were contracted for 35.5 Bcf of storage capacity
throughout 1995.
The primary terms of current storage service agreements,
representing 23.3 Bcf of the firm storage capacity contracted for by
nonaffiliated customers, expired in 1995. Service continues year-to-year and can
be terminated by the customer on one year's notice. Six such customers have
given notice of termination or reduction effective March 31, 1996, accounting
for a reduction of 4.2 Bcf of contracted firm storage capacity at that time. The
Pipeline and Storage segment is actively marketing this available capacity.
Additional discussion of the Pipeline and Storage segment appears in the
forepart of the paper copy of the Company's combined Annual Report to
Shareholders/Form 10-K under the heading "Pipeline and Storage," which is
included in this electronic filing as Exhibit 13, below under the headings
"Sources and Availability of Raw Materials," "Competition" and "Environmental
Matters," Item 7 "MD&A," and Item 8 at Notes B-Regulatory Matters, H-Commitments
and Contingencies and I-Business Segment Information.
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 10% of the
Company's operating income before income taxes in 1995.
Additional discussion of the Exploration and Production segment appears
in the forepart of the paper copy of the Company's combined Annual Report to
Shareholders/Form 10-K under the heading "Exploration and Production and Other
Nonregulated Activities," which is included in this electronic filing as Exhibit
13, below under the heading "Competition," Item 7 "MD&A," and Item 8 at Notes
F-Financial Instruments, I-Business Segment Information and L-Supplementary
Information for Oil and Gas Producing Activities.
Other Nonregulated Operations
Other Nonregulated operations contributed approximately 2% of the Company's
operating income before income taxes in 1995. Corporate operations reduced the
Company's operating income before income taxes by approximately 2%.
Horizon was formed in 1995 to engage in foreign and domestic energy
projects, including foreign utility companies and exempt wholesale generators of
electricity. The SEC in 1995 authorized the Company (through Horizon and
intermediate companies) to (i) invest up to an aggregate of $150.0 million
through December 2001 in such activities, and (ii) issue debt and equity,
provide guarantees and assume liabilities up to that amount in order to finance
such activities. The Company contributed $1.0 million in capital to Horizon in
1995. Horizon was at year-end 1995 considering investment opportunities in
eastern Europe, South America and Asia, and is the controlling partner in
Sceptre Power Company, a partnership which includes a team with considerable
experience in developing such energy projects.
NFR is seeking to add the brokering of electric power to its
existing gas marketing business. In 1995, NFR obtained authorization from the
FERC to become an electric power broker in connection with the FERC's announced
restructuring of the electric power industry. NFR's application for
authorization from the SEC to engage in such activities was pending at year-end
1995.
Leidy recognized a loss of less than $1.0 million in 1995 from
writing off Leidy's equity investment in Metscan, Inc., a developer of
electronic gas meter reading devices, which ceased operations and liquidated.
Leidy's business now consists exclusively of activities related to natural gas
hubs as described below.
The SEC in 1995 authorized Leidy to enter into a transaction (which
was consummated in October 1995) by which Leidy invested less than $1.0 million
to acquire a 14.5% ownership interest in Enerchange, L.L.C. (Enerchange). This
investment effectively gave Leidy (i) a somewhat larger portion of the profits
or losses of Ellisburg-Leidy Northeast Hub Company, (ii) a portion of the
profits or losses of natural gas hubs in Chicago and Los Angeles, (iii) 14.5% of
Enerchange's profits or losses in buying and selling gas at all three market
hubs, and (iv) 14.5% of Enerchange's profits or losses as a 50% owner of
QuickTrade, L.L.C., which is developing an on-line computer service on pages 33which
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
51Shareholders/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
report.
On average, 97%electronic filing as Exhibit 13, Item 7 "MD&A," and Item 8 at Notes I-Business
Segment Information and L - Supplementary Information for Oil and Gas Producing
Activities.
In 1995, the Utility Operation purchased 130.8 Bcf of Distribution Corporation'sgas. Gas
purchases from various producers and marketers in the southwestern United States
under long-term (two years or longer) contracts accounted for 77% of these
purchases. Purchases of gas in Canada under long-term contracts, purchases of
gas in Canada and the United States on the spot market (contracts of less than a
year) and purchases from Appalachian producers accounted for 3%, 15% and 5%,
respectively, of the Utility Operation's 1995 gas purchases. Gas purchases from
Vastar Resources, Inc. and Natural Gas Clearinghouse (southwest gas under
long-term contract) represented 13% and 12%, respectively, of total 1995 gas
purchases by the Utility Operation. No other producer or marketer provided the
Utility Operation with 10% or more of its gas requirements in 1995.
To move its gas from the point of purchase to its distribution
system in New York and Pennsylvania, the Utility Operation purchases firm
transportation and storage services from various interstate pipeline companies
including Supply Corporation. See Item 8, Note H-Commitments and Contingencies,
for a discussion of the Utility Operation's obligations under its nonaffiliated
pipeline capacity, gas purchase and gas storage contracts.
The Utility Operation also transports gas owned by others
(principally industrial and commercial end-users). Gas produced by Appalachian
producers, especially in Pennsylvania and New York, remained an important source
of supply for the Utility Operation's transportation customers, who also
purchased gas from the southwestern United States and Canadian suppliers.
Other Nonregulated operations need natural gas for NFR's marketing
and Leidy's hub services, but are relatively indifferent as to the source.
Competition
The natural gas industry was competitive in 1995 and is expected to become more
competitive in the future. Competition existed among providers of natural gas,
as well as between natural gas and other sources of energy.
Management continues to believe that there will be increased usage
of natural gas nationwide over the longer term, so that opportunities exist for
increased sales. This increased use of natural gas nationwide is expected to
result mainly from the increased use of natural gas as an electric generation
and cogeneration fuel, conversion of home heating load from oil to gas, economic
and population growth, competitive prices and technological developments. The
long-term trend in natural gas will depend upon the balance of supply and
demand, as well as weather (colder weather generally increases demand and thus
price). As noted, demand is expected to increase over the longer term. Supply
will be impacted by the potential increase in domestic supplies due to more
efficient exploration and production technology and the amount of gas imported
into the United States from Canada and Mexico.
The continuing deregulation of the natural gas industry should also
enhance the competitive position of natural gas relative to other energy sources
by removing some of the regulatory impediments to adding customers and
responding to market forces. In addition, the environmental advantages of
natural gas compared with other fuels should increase the role of natural gas as
an energy source. The potential environmental role of natural gas was enhanced
by passage of the federal Clean Air Act Amendments of 1990, which United States
industries have not completed implementing. Moreover, natural gas is abundantly
available in North America, which makes it a dependable alternative to imported
oil.
The electric industry is moving toward a more competitive
environment as a result of the federal Energy Policy Act of 1992 and initiatives
undertaken by the FERC and others to restructure the electric industry much the
same as the FERC restructured the gas industry. It is unclear at this point what
impact this restructuring will have on the natural gas industry.
The Company competes on the basis of price, service, quality and
reliability, product performance and other factors. Sources and providers of
energy, other than those described under this "Competition" heading, do not
compete with the Company to any significant extent.
Competition: the Utility Operation
The changes precipitated by the FERC's restructuring of the gas industry in
Order No. 636 are redefining the roles of the gas utility industry and the state
regulatory commissions. Competition has arrived for utilities. The PSC issued an
order in 1995 providing for the Utility Operation to be the first gas utility in
New York to implement unbundling of its services pursuant to a 1994 PSC order on
restructuring. The Utility Operation now offers unbundled flexible services to
its large commercial and industrial customers. This unbundling is an important
step toward the Utility Operation's goal of opening its market area to
competition for all customers, including residential. Competition for
large-volume customers continues, with pipeline companies increasingly
attempting to sell or transport gas directly to end-users located within the
Utility Operation's service territories (i.e., bypass). The FERC remains
unwilling to shield local distribution companies from such bypass. In addition,
competition continues with fuel oil suppliers, and may increase with electric
utilities making retail energy sales.
Responding to those developments, the Utility Operation is now
better able to compete, through its unbundled flexible services, in its most
vulnerable markets (the large commercial and industrial markets). The Utility
Operation continues to (i) develop or promote new sources and uses of natural
gas and/or new services, rates and contracts and (ii) emphasize and provide high
quality service to its customers.
Competition: the Pipeline and Storage Segment
The Pipeline and Storage segment competes for market growth in the natural gas
market with other pipeline companies transporting gas in the northeastern United
States and with other companies providing gas storage services. The Pipeline and
Storage segment has some unique characteristics which enhance its competitive
position. Its facilities are located adjacent to Canada and the northeastern
United States, and provide part of the link between gas-consuming regions of the
northeastern United States and gas-producing regions of Canada and the
southwestern, southern and midwestern regions of the United States. This
location offers the opportunity for increased transportation and storage
services in the future. The Pipeline and Storage segment will continue to
evaluate ways to take advantage of its location to open new markets and expand
existing ones, especially in the gas storage business.
There is, however, increased competition to provide services to the
northeastern market in the form of other proposed pipeline expansions and
proposed storage projects. The northeastern utilities which are currently the
largest customers of transportation and storage services are showing some
hesitance to enter into new long-term transportation or storage arrangements
while their state commissions are considering significant restructuring of their
bundled sales services.
Competition: the Exploration and Production Segment
The Exploration and Production segment competes with other gas and oil
producers, and with fuel oil and electricity wholesalers and producers, with
respect to its sales of oil and gas. The Exploration and Production segment also
competes with other oil and gas exploration and production companies of various
sizes for leases and drilling rights for exploration and development prospects.
To compete in this environment, the Exploration and Production
segment originates and acts as operator on most prospects, minimizes risk of
exploratory efforts through partnership-type arrangements, applies the latest
technology for both exploratory studies and drilling operations and focuses on
market niches that suit its size, operating expertise and financial criteria.
Competition: Other Nonregulated Operations
In the Other Nonregulated operations, NFR competes with other gas marketers and
energy management services providers. Leidy competes with other natural gas hub
service providers. Highland competes with other sawmills in northwestern
Pennsylvania. Horizon competes with other entities seeking to develop foreign
and domestic energy projects.
Seasonality
Variations in weather conditions can materially affect the volume of gas
delivered by the Utility Operation, as virtually all of its residential and
commercial customers use gas for space heating, which makes throughput, forheating. The effect on the most part,
weather-sensitive. In Distribution Corporation'sUtility
Operation in New York jurisdiction, it
was 3.6% colder than the prior year and 3.9% colder than normal, based upon
the number of Degree Days for the year. In Distribution Corporation's
Pennsylvania jurisdiction, it was 9.6% colder than the prior year and 8.4%
colder than normal, based upon the number of Degree Days for the year.
Weather that was colder than the prior year contributed to a 5 Bcf
increase in retail sales in 1994. Although industrial volumes sold remained
level when compared with the prior year, they reflected a 2.5 Bcf switch from
sales to transportation service, offset by increased gas sales to a new
cogeneration customer.
The impact that major weather variances have on revenues and margins is temperedmitigated somewhat by a weather normalization clause
that the PSC has authorized in
Distribution Corporation's New York retail jurisdiction. This WNCwhich is designed to adjust the rates of retail customers to reflect the impact
of deviations from normal weather. Weather that is more than 2.2% warmer than
normal results in a surcharge being added to customers' current bills, while
weather that is more than 2.2% colder than normal results in a refund being
credited to customers' current bills.
In 1994, the WNC was in effect for the period
from October 1993 through May 1994. During this time, there were periods of
both warmer than normal and colder than normal weather. Overall, the WNC
resulted in a net reduction to customer bills of approximately $5.8 million in
1994.
Distribution Corporation requested a WNC in the Pennsylvania rate
jurisdiction in its March 8, 1994 rate case filing. However, the PaPUC denied
Distribution Corporation's request. This decision continues to subject
Distribution Corporation's operating results to the impact of major weather
variances.
Distribution Corporation offers large commercial and industrial
customers transportation services and flexible rate designs. Transportation
service, which allows end-users to purchase gas directly from a producer or
marketer and transport it through the System's pipeline network, provides the
ITEM 1. BUSINESS (Continued)
customer with various options in buying gas and transportation services, thus
providing the opportunity for cost savings to the customer. In 1994, 52.2 Bcf
of gas were transported to such customers of Distribution Corporation, a 7%
increase over the 48.9 Bcf transported in 1993. Transportation volumes
represented 30% of the Utility segment's total throughput in 1994 and 29% in
1993.
The volume of gas transported by this segment increased 3.3 Bcf in 1994
mainly because of industrial and commercial boiler fuel sales customers
switching to transportation service, which amounted to approximately 2.9 Bcf.
In addition, transportation volumes increased by approximately 2 Bcf for
large- and small-volume industrial customers. Partly offsetting these
increases was a decline in transportation in the Pennsylvania jurisdiction of
approximately 0.8 Bcf because of the shut down of three industrial customers
and a decline of approximately 0.8 Bcf because of the bypass of the Company's
pipeline system in favor of local producer gas service. Rates that became
effective in December 1994, in the Pennsylvania rate jurisdiction, compensate
for the loss of throughput related to these customers.
Distribution Corporation has a supplemental service rate in New York and
a bypass rate in Pennsylvania which are intended to induce customers not to
bypass the System. These rates are designed to recover Distribution
Corporation's cost of providing back-up service to customers utilizing an
alternative gas supply. In addition, Distribution Corporation has a flexible
transportation tariff in Pennsylvania and New York, which allows it to
negotiate a competitive rate to encourage customers to stay on the System.
The unbundling of services under the FERC's Order 636 has required
transportation customers to incur storage service costs for use of storage
facilities. These costs were previously bundled and charged only to sales
customers. As a means of providing options to its customers, Distribution
Corporation offers a Daily Metered Transportation rate in Pennsylvania.
Customers using this rate would only incur storage charges for storage service
utilized, as determined through a daily metering process, thus increasing the
importance of each customer's management of its gas needs. Distribution
Corporation has proposed a similar rate in its New York jurisdiction rate case
filed in October 1994.
Through open dialogue with customers, utilization of the various rates
discussed above and Distribution Corporation's in-house gas acquisition
expertise which industrial customers and other end-users may not have,
Distribution Corporation has been able to mitigate bypass of the System.
Distribution Corporation also offers competitive boiler fuel rates to
large commercial and industrial customers in its New York rate jurisdiction.
These rates allow Distribution Corporation to adjust rates monthly to compete
against suppliers of No. 6 oil and other boiler fuels.
ITEM 1. BUSINESS (Continued)
If boiler fuel and supplemental service rates in New York, the bypass
rate in Pennsylvania and flexible transportation rates in both jurisdictions
were not available, Distribution Corporation could become vulnerable to losses
in throughput since natural gas is, in many cases, directly replaceable by
No. 6 oil in industrial boilers, or can be obtained through bypass of the
System.
Distribution Corporation also offers rates in both its New York and
Pennsylvania jurisdictions that provide competitive gas prices encouraging new
technologies, such as the installation of small-packaged cogeneration and
gas-fired cooling and dehumidification systems that utilize gas on an all-year
or summerload basis.
The System continues to encourage the development of the natural gas
vehicle market. The System operates over 400 NGVs along with four
public-access refueling stations. A fifth public-access station is scheduled
to open in 1995.
Distribution Corporation is not currently subject to any material
restrictions upon the connection or service of new residential, commercial and
industrial customers in its service territory. However, because of the high
natural gas saturation and the maturity of Distribution Corporation's service
territory, its focus will be on retaining existing customers through rate
design initiatives and, in the longer term, through the development and
marketing of new natural gas utilization technologies.
Gas Supply
One of the major effects of restructuring of the natural gas industry
under the FERC's Order 636 was the transfer of responsibility for acquiring
gas supply from pipeline companies to natural gas utility companies. This
transfer of responsibility also carried with it the transfer to utility
companies of the risks related to the purchasing of adequate and reliable gas
supplies, transportation arrangements and storage arrangements. In addition,
the role of the state public utility commissions in monitoring the prudency of
purchasing practices of the utility has become more significant.
As a result of Supply Corporation's restructuring, which became
effective August 1, 1993, gas supplies for the System are now obtained by
Distribution Corporation in essentially the same manner operationally, as they
were in recent years by Supply Corporation.
Distribution Corporation's basic gas acquisition objective is to obtain
reliable, diversified, long-term sources of gas supply at competitive prices
and to maintain appropriate levels of pipeline and storage capacity to
transport and store its gas supply.
As a result of Order 636 restructuring, Distribution Corporation was
provided a share of pipeline and storage capacity on Supply Corporation and on
the upstream pipeline companies formerly serving Supply Corporation.
Distribution Corporation has entered into contracts for the necessary capacity
on Supply Corporation and on these upstream pipeline companies, to meet the
requirements of its firm sales customers.
ITEM 1. BUSINESS (Continued)
Distribution Corporation has firm transportation capacity from Supply
Corporation and the following pipeline companies: Tennessee Gas Pipeline
Company, Texas Eastern Transmission Corporation, Transcontinental Gas Pipe
Line Corporation, CNG Transmission Corporation (CNG) and Columbia Gas
Transmission Corporation (Columbia). Total contracted capacity on these
pipelines, in the aggregate, is approximately 155,916 MMcf annually.
Distribution Corporation has contracted storage capacity of 25.3 Bcf
from Supply Corporation as well as contracted storage capacity, in the
aggregate of 4.6 Bcf, from CNG and Columbia. At September 30, 1994,
Distribution Corporation had 28.0 Bcf of gas in storage.
Pipeline companies' transportation and storage rates have been designed
on a SFV basis, as mandated by Order 636. This rate design allows pipeline
companies to recover all of their fixed costs through a demand or reservation
charge. Thus, Distribution Corporation pays nearly all costs of its
contracted pipeline transportation and storage through a demand charge.
Distribution Corporation maintains its current level of firm capacity so it
can continue to provide reliable service to its firm sales customers during
peak winter months. Distribution Corporation must pay to reserve capacity
year round even though the demand of the firm customers significantly
decreases during the summer months. Distribution Corporation has reduced a
small amount of its fixed costs by releasing unused capacity during off-peak
periods and will continue to utilize capacity release programs.
In order to provide gas service to its customers and fill the pipeline
capacity obtained in the Order 636 unbundling process, Distribution
Corporation was assigned Supply Corporation's pre-Order 636 gas purchase
agreements and has since entered into its own gas purchase agreements.
Currently, approximately 92% of Distribution Corporation's daily winter
capacity on upstream pipelines is supported by long-term gas supply contracts,
primarily with Southwest producers. Distribution Corporation's firm gas
supply portfolio is comprised of contracts, having an average six-year term,
which supply gas from a variety of production areas and suppliers. Many of
Distribution Corporation's long-term supply contracts are adjusted to reflect
the seasonal variations in customer demand, thereby decreasing costs. Spot
gas continues to be utilized when short-term gas supplies are plentiful and
when it is economical to do so. During off-peak periods, Distribution
Corporation is able to make off-system sales when supplies are not needed to
provide service to its firm sales customers.
While Distribution Corporation's purchases of Appalachian produced gas
has continued to decline, gas received from local producers and transported by
Supply Corporation and Distribution Corporation for large industrial
end-users, remains an important source of gas supply for these end-users.
For additional details on sources of gas supply, see the "Sources of Gas
Supply - Regulated Operations" on page 13 of this report.
ITEM 1. BUSINESS (Continued)
Based on information currently available to the Company, Systemwide gas
supply remains sufficient to meet anticipated demand.
In 1994, Distribution Corporation's average cost of purchased gas,
including the cost of transportation and storage, was $3.74 per Mcf, a
decrease of 3% from Distribution Corporation's average cost of $3.84 per Mcf
in 1993. Regulation of gas prices at the wellhead is virtually nonexistent,
and therefore, the market primarily dictates gas supply and gas prices.
The total quantity of gas purchased by Distribution Corporation in 1994
was 145.9 Bcf, compared with 131.5 Bcf purchased by Distribution Corporation
and Supply Corporation (net of intersegment purchases) in 1993, an increase of
14.4 Bcf or 11%.
The 14.4 Bcf increase in purchases was the result of the following
(refer to "Selected Statistics of the System's Regulated Operations" on page
16 of this report): (1) Net injections into storage in 1994 were 4.3 Bcf
compared with net withdrawals from storage in 1993 of 3.0 Bcf. This accounts
for a 7.3 Bcf increase in the amount of gas required to be purchased in 1994.
(2) Gas used in operations, shrinkage and other increased 8.5 Bcf in 1994.
Shrinkage represents a percentage of gas retained by pipeline companies for
purposes such as fueling their compressors. Purchases reported by the System
are gross amounts (i.e., prior to shrinkage). The amount of shrinkage is
dependent upon where title to such gas is taken. The System has experienced a
steady increase in the past several years in the amount of gas it has taken
title to in the Southwest. In 1994, Distribution Corporation took title to
approximately 95% of its gas purchases in the Southwest. Thus, amounts
required to be purchased by Distribution Corporation were higher than amounts
available for sale to Distribution Corporation's customers. (3) A 5.1 Bcf
increase in Distribution Corporation's retail sales required increased
purchases in 1994. (4) Elimination of Supply Corporation nonaffiliated
wholesale sales under Order 636 restructuring, which amounted to 6.5 Bcf in
1993, resulted in decreased purchases in 1994.
Total System throughput increased 34.4 Bcf or 13% to 307.3 Bcf in 1994,
from 272.9 Bcf in 1993. This increase is mainly attributable to higher
volumes of gas transported through Supply Corporation's Canadian gas
transportation facilities and higher retail sales by Distribution Corporation
which were up primarily because of colder weather and increased gas sales to a
new cogeneration customer.
The following table, "Sources of Gas Supply - Regulated Operations",
sets forth the sources and quantities of gas purchases over the past three
years. (System throughput volumes are contained in the table on page 16.)
ITEM 1. BUSINESS (Continued)
Sources of Gas Supply - Regulated Operations
Annual
Contract Volumes Delivered-MMcf
Volumes in Year Ended September 30,
MMcf (1) 1994 1993 1992
Producers and Marketers:
Long-Term Contracts 124,471 (2) 107,487 60,664 28,819
Appalachian 4,595 (3) 4,595 7,366 11,883
Affiliated Production 2,474 (4) 2,474 4,265 5,067
Spot Market - (5) 31,319 52,785 86,142
Interstate Pipelines - (6) - 6,434 2,298
Total Gas Supply - Regulated
Operations 131,540 145,875 131,514 134,209
(1) This column reflects annual volumes under currently existing contracts.
Thermally-expressed annual contract quantities have been converted to
their volumetric equivalent on a nominal 1,000 Btu per cubic foot basis.
(2) The producers and marketers from which Distribution Corporation
purchases gas pursuant to long-term supply contracts (contracts with a
term of two years or longer, the average length of Distribution
Corporation's contracts being six years) are: Chevron U.S.A., Coastal
Gas Marketing, Enron Gas Marketing, Inc., Enron Excess Corporation,
Exxon Company U.S.A., Meridian Oil Trading, Inc., MidCon Gas Services,
Corp., Mobil Natural Gas, Inc., Natural Gas Clearinghouse, Shell Oil
Company, et al., Tejas Power Company, Texaco Gas Marketing, Transco
Energy Marketing Company and Vastar Gas Marketing, Inc. (formerly Arco
Natural Gas Marketing, Inc.). In addition, the amounts include Canadian
gas under contract with Boundary Gas, Inc. and ANE Gas Marketing.
(3) The annual contract volume represents 1994 purchases from independent
producers in the Appalachian region. The independent producer contracts
generally continue until the reserves dedicated to them are economically
depleted. The annual contract volumes applicable to these contracts
vary as a function of the deliverability of the wells committed to them.
The vast majority of this production is long-term dedicated supply.
(4) The annual contract volume represents supply from the System's own
production in the Appalachian region. Volumes decreased significantly
in 1994, as the System's own production is being sold to various
end-users.
(5) No annual contract volume is shown here as, generally, spot contracts
are very short-term.
ITEM 1. BUSINESS (Continued)
(6) No contract volumes are shown here as interstate pipeline companies have
terminated their merchant function under the FERC's Order 636.
Distribution Corporation has contracts with interstate pipeline
companies for pipeline capacity to transport gas purchased under direct
contracts.
For a discussion of Distribution Corporation's obligations under its
nonaffiliated pipeline capacity, gas purchase and gas storage contracts, see
Note G - "Commitments and Contingencies," on pages 77 to 79 of this report.
PIPELINE AND STORAGE
The System's Pipeline and Storage operations are conducted by Supply
Corporation. In 1994, these operations accounted for approximately 36% of
System operating income before income taxes. Information regarding the
results of operations for the Pipeline and Storage operations can be found in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" on pages 33 to 51 of this report.
Pipeline Capacity and Transportation
Supply Corporation currently has service agreements for substantially
all of its pipeline capacity, which approximates 1,860 MMcf per day.
Distribution Corporation has contracted for approximately 1,120 MMcf per day
or 60% of this capacity.
Effective with Supply Corporation's restructuring under Order 636, most
of its upstream pipeline contracts have been assigned to its former sales
customers. Currently, there is a small amount of unallocated capacity on
three upstream pipelines related to capacity which was not accepted by certain
customers. The reservation charges related to the unallocated capacity are
considered stranded transportation costs, a category of Order 636 transition
costs. Supply Corporation is recovering these amounts from its customers
pursuant to FERC authorization.
Supply Corporation's transportation throughput in 1994 was 295.3 Bcf
compared with 138.6 Bcf in 1993. The increase in 1994 is primarily the result
of unbundling of services under Order 636 under which Supply Corporation's
former sales customers became transportation customers. Also, throughput
increased as a result of weather that was colder than the prior year,
increased utilization of Supply Corporation's Canadian gas transportation
facilities and the expanded capacity of these facilities.
For a discussion of the impact of the Clean Air Act Amendments of 1990
on Supply Corporation's compressor stations, see Note G - "Commitments and
Contingencies," on pages 77 to 79 of this report.
Underground Storage
To facilitate operational efficiencies, all of the System's natural gas
storage services were consolidated into Supply Corporation through the July 1,
1994 merger of Penn-York into Supply Corporation. Supply Corporation owns and
ITEM 1. BUSINESS (Continued)
operates 30 underground storage fields in its operating area. Four additional
underground storage fields are operated jointly with certain major interstate
pipeline companies. All of these fields are former gas-producing reservoirs
and are operated under FERC certification.
Supply Corporation has available Working Gas capacity of approximately
69.9 Bcf. Of this amount, approximately 7 Bcf has been retained by Supply
Corporation in order to render no notice transportation service and meet other
delivery obligations. Of the remaining available Working Gas capacity of
approximately 62.9 Bcf, Distribution Corporation has contracted for 25.3 Bcf
and nonaffiliated customers have contracted for 35.6 Bcf.
The primary terms of current storage service agreements representing
23.3 Bcf of the amount contracted for by nonaffiliated customers expire on
March 31, 1995. Service continues year-to-year and can be terminated upon one
years notice. None of these customers have elected to terminate service nor
extend their term for ten years as provided under a settlement of a previous
Penn-York rate case.
Supply Corporation's proposed Laurel Fields Storage Project is a 19 Bcf
underground natural gas storage development project. Filings with the FERC
were made in June 1994 to implement this project. An "open season" was held
in August 1994 to identify prospective customers for this project with whom
agreements are currently being negotiated. On November 4, 1994, a proposal
was sent to the FERC to divide the project into two phases. Phase I would
encompass the expansion of the Limestone storage field to accommodate
approximately 7 Bcf of storage and phase II would consist of the development
of the Callen Run storage field, a depleted gas production field. The
estimated cost of both phases of this project, including related transmission
facilities, is approximately $200 million. Timing of the project has not been
finalized.
The Company believes that underground storage will have enhanced
economic value in the post-Order 636 environment. Furthermore, the growing
demand for natural gas for home heating in the Northeast and on the East Coast
creates a demand for peak period gas supplies, which may require additional
storage service. Supply Corporation's storage fields are strategically
located between Southwest and Canadian gas supplies and the growing demand for
natural gas in the Northeast and East Coast areas.
The magnitude of future expansion in the System's Regulated Operations
depends, to a large degree, upon market conditions coupled with adequate rate
relief.
ITEM 1. BUSINESS (Continued)
SELECTED STATISTICS OF THE SYSTEM'S REGULATED OPERATIONS
(Intra-System Sales Eliminated Where Appropriate)
Year Ended September 30,
1994 1993 1992 1991 1990
GAS AVAILABLE FOR SALE (MMcf):
Natural Gas Purchased-
Producers and Marketers 112,082 68,030 40,702 37,078 20,387
Spot Market Purchases 31,319 52,785 86,142 90,822 93,961
Interstate Pipelines - 6,434 2,298 3,103 22,377
143,401 127,249 129,142 131,003 136,725
Natural Gas Produced 2,474 4,265 5,067 5,088 4,823
Total Gas Supply 145,875 131,514 134,209 136,091 141,548
Gas Withdrawn from (delivered
to) Storage - Net (4,306) 2,992 (2,449) (5,671) 2,320
Used in Operations, Shrinkage
and Other (17,535) (8,986) (3,665) (2,446) (1,705)
Total Gas Available for Sale 124,034 125,520 128,095 127,974 142,163
SYSTEM THROUGHPUT (MMcf):
Retail Sales -
Residential 90,565 86,854 84,762 79,299 85,761
Commercial 26,937 25,598 25,909 25,634 28,646
Industrial 6,532 6,528 9,131 9,893 10,872
Wholesale Sales - 6,540 8,293 13,148 16,884
Total Gas Sales 124,034 125,520 128,095 127,974 142,163
Transportation 183,255 147,357 172,505 128,731 101,512
Total System Throughput 307,289 272,877 300,600 256,705 243,675
GAS OPERATING REVENUES INCLUDING TRANSPORTATION
(Thousands of Dollars):
Retail -
Residential $677,068 $613,039 $533,908 $494,332 $517,026
Commercial 177,249 156,851 139,662 135,718 150,637
Industrial 31,096 31,609 35,985 38,395 45,707
Wholesale 6,930* 27,451 30,150 43,917 47,773
Total Gas Operating Revenues 892,343 828,950 739,705 712,362 761,143
Transportation 68,695 64,641 61,204 42,308 35,192
Total Gas Operating Revenues
Including Transportation $961,038 $893,591 $800,909 $754,670 $796,335
AVERAGE NUMBER OF UTILITY
CUSTOMERS:
Retail -
Residential 680,043 676,876 672,877 668,240 663,697
Commercial 46,518 46,344 46,051 45,292 44,859
Industrial 1,181 1,188 1,201 1,202 1,207
Transportation 1,306 1,293 1,088 957 750
729,048 725,701 721,217 715,691 710,513
* 1994 wholesale revenues represent revenues from Distribution
Corporation's off-system sales.
ITEM 1. BUSINESS (Continued)
EXPLORATION AND PRODUCTION
The System's Exploration and Production operations are carried out by
Seneca. Seneca is engaged in the exploration for, and the development 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.
To facilitate operational efficiencies, all of the System's exploration
and production operations were consolidated into Seneca through the July 1,
1994 merger of Empire into Seneca. Supply Corporation's exploration and
production activities were transferred to Empire, effective January 1, 1994.
Exploration and production activities in 1994 accounted for
approximately 13% of System operating income before income taxes. Information
regarding the results of operations for the Exploration and Production
operations can be found in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" on pages 33 to 51 of this report.
Gulf Coast/West Coast Exploration and Production
Seneca's Gulf Coast activities in 1994 were directed toward continued
offshore exploration for natural gas in the Gulf of Mexico and drilling of
horizontal wells for gas production in the Austin Chalk formation in Seneca's
Northeast Clay field in central Texas.
The offshore exploration program uses advanced computer and seismic
technology in an attempt to identify low risk gas prospects which can be
drilled and placed in production in less than one year. As of September 30,
1994, Seneca had acquired and evaluated new offshore seismic data covering an
area of over 45,000 square miles. In 1994, Seneca drilled six gas wells in
the Gulf of Mexico, five of which were successful. The most significant
discovery was in West Cameron Block 552 where one gas well was drilled in 1994.
Seneca has continued to achieve its goal of placing new wells in
production within one year. Two of the five successful wells in the Gulf of
Mexico were in production by September 30, 1994. The other three wells are
expected to be in production by March 31, 1995. Future offshore activity
should continue to be strong with Seneca's acquisition of three blocks in the
Federal Lease Sale and acquisition of one block through a farm out. These
acquisitions have increased Seneca's inventory of offshore prospects to
eleven, some of which will be evaluated in 1995.
In addition, Seneca actively pursued identifying and drilling gas
reserves in the tight Austin Chalk formation in its Northeast Clay Field in
central Texas. In 1994, Seneca drilled or participated in five horizontal
wells, all of which were successful. The scope of Seneca's horizontal
drilling is expected to expand in 1995. Seneca has acquired nearly 4,000 acres
and 6,000 acres to the west and east of the Northeast Clay Field,
respectively. Plans are to begin development of this acreage in 1995.
ITEM 1. BUSINESS (Continued)
As a result of this activity in the Gulf Coast Region, 93.4 Bcf of gas
reserves and 1.1 million barrels of oil reserves were added in 1994.
Reserves related to the Gulf Coast Region at September 30, 1994 amounted
to 3.8 million barrels of oil and 153.2 Bcf of gas, or approximately 22% and
62% of Seneca's total oil and gas reserves, respectively. This represents a
decrease of approximately 0.3 million barrels of oil and an increase of 73.7
Bcf of gas compared with September 30, 1993.
Seneca's California activities in 1994 were concentrated primarily on
cost control and improving production in the Sespe and Silverthread Fields in
Ventura, California while continuing development drilling in the new Temescal
Field. In 1994, Seneca drilled one additional successful well in the Temescal
Field.
Reserves related to Seneca's California operations at September 30,
1994, amounted to 13.5 million barrels of oil and 32.0 Bcf of gas, or
approximately 77% and 13% of Seneca's total oil and gas reserves,
respectively. This is a decrease of 0.7 million barrels in oil reserves and
2.4 Bcf of gas compared with September 30, 1993.
During 1994, Seneca's combined Gulf Coast and California operations
produced 1.0 million barrels of oil and 17.0 Bcf of gas compared to 0.8
million barrels of oil and 13.2 Bcf of gas produced in 1993. This represents
an increase of 25% in oil production and 29% in gas production. In 1994, oil
and gas sales were made to marketers and refiners under long-term agreements,
which contain flexible pricing provisions.
Appalachian Exploration and Production
Most of the gas production Seneca owns in the Appalachian region, is
transported to end-users by the System. A percentage of the production from
these wells is dedicated to the System's Regulated Operations' gas supply.
Seneca's drilling programs in this region depend, to a large degree, on gas
prices. In 1994, Seneca drilled or participated in drilling 8 net gas wells,
of which 5 were completed as producers and 3 were plugged and abandoned as dry
holes. Approximately 0.7 Bcf of gas was discovered as a result of these
efforts. This is compared with 1993's drilling program of 18 net wells, of
which 11 were completed as producers, and 1.1 Bcf of gas discovered.
In 1994, Seneca's gas production from its Appalachian wells amounted to
6.3 Bcf compared with 6.6 Bcf in 1993. At September 30, 1994, Seneca had
1,998 net productive wells in the Appalachian Region. Seneca's gas reserves
at September 30, 1994, located in this region amounted to 62.3 Bcf, or
approximately 25% of Seneca's total gas reserves. This represents an increase
in gas reserves of 1.0 Bcf compared with 1993, as current year discoveries
from drilling activities, revisions of previous estimates and acquisitions of
reserves in place more than offset current year production. Seneca's
Appalachian oil production and oil reserves are not significant.
ITEM 1. BUSINESS (Continued)
Oil and Gas Prices
During 1994, the System's weighted average oil price at the wellhead was
$14.86 per barrel, a decrease of $1.92 per barrel, or 11%, from 1993. The
System's weighted average gas price at the wellhead was $2.18 per Mcf, a
decrease of $.02 per Mcf, or 1%, from 1993. Nonetheless, efforts to stabilize
prices through hedging activities contributed approximately $1.6 million of
operating revenues for the year. See further discussion of hedging activities
in Note A - Summary of Significant Accounting Policies on pages 58 to 62 of
this report.
At September 30, 1994, Seneca did not experience an impairment of its
oil and gas assets under the SEC full cost accounting rules. Wellhead price
declines in the future, if material, could have a negative impact on Seneca's
oil and gas assets.
OTHER NONREGULATED
The Systems's Other Nonregulated operations are carried out primarily by
NFR, UCI, Highland and Leidy Hub, which are engaged in natural gas marketing
and brokerage operations and energy management services; pipeline construction
operations; sawmill and dry kiln operations; and natural gas market hub
activities, respectively. Other Nonregulated operations also include the
marketing of timber. In 1994, these operations accounted for 1% of System
operating income before income taxes. Corporate operations reduced System
operating income before income taxes by 2%. Information regarding the results
of operations for the Other Nonregulated operations can be found in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" on pages 33 to 51 of this report.
In 1994, Leidy Hub received SEC approval to enter into a partnership
with a subsidiary of Natural Gas Clearinghouse (Clearinghouse) to develop a
market area hub in north central Pennsylvania, where, in order to manage their
gas supply, customers such as pipelines, marketers and utilities can store or
borrow gas short-term, move gas from one pipeline to another, and buy or sell
gas. The partnership became effective September 1, 1994. Leidy Hub has a 50%
interest in this partnership.
COMPETITION
The natural gas industry was a competitive one in 1994 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 and, therefore, opportunities
exist for increased sales, transportation and storage of natural gas,
primarily on behalf of off-system end-users. 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 and competitive
ITEM 1. BUSINESS (Continued)
prices. Nonetheless, there is currently downward pressure on gas prices due
to milder than normal weather and increased supply because of the continued
growth of Canadian imports and increasing domestic supplies attributable to
more efficient exploration and production technology. While seasonal swings
in gas prices between the heating and nonheating season are expected to
continue, the longer term trend in natural gas prices is dependent upon the
balance of demand and supply. Current estimates of the United States demand
growth rate range from 1 - 4%, while estimates for increases in available
supply range from 2 - 5%.
The continuing deregulation of the gas industry should also enhance the
competitive position of 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 the passage of
the Clean Air Act in 1990. Moreover, natural gas, which is abundantly
available in North America, is a dependable domestic alternative to foreign
oil.
The electric utility industry is moving toward a more competitive
environment as a result of the Energy Policy Act of 1992 and actions of
various regulatory commissions. It is unclear at this point what impact this
restructuring will have on the natural gas industry.
System companies compete on the basis of price, service, quality and
reliability, product performance and other factors.
Utility Operations
The 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 it is anticipated that, similar to
what was done in the pipeline sector of the natural gas industry, regulators
will require utilities to unbundle their services. The anticipated result is
that utility service will divide into "core" markets consisting of the
traditional residential and commercial customers, as well as customers taking
firm transportation service and "non-core" markets consisting of competitive
commercial and industrial markets. It is anticipated that competition for the
"non-core" market will continue from parties desiring to bypass the System by
selling and/or transporting gas directly to Distribution Corporation's
industrial and commercial customers. Furthermore, the FERC, in its recent
Bypass Policy, appears to be unwilling to shield local distribution companies
from bypass. In addition, competition will exist with fuel oil suppliers and
electric utilities in making retail energy sales. Distribution will attempt
to retain, and if possible expand, its most vulnerable markets, such as the
large industrial market, through favorable rate design, business development
and related efforts. Distribution Corporation continues to (a) develop or
ITEM 1. BUSINESS (Continued)
promote new sources and uses of natural gas and/or new services, rates and
contracts; (b) purchase gas from lowest cost suppliers consistent with
operating and long-term gas supply needs; and (c) emphasize and provide high
quality service to its customers.
Pipeline and Storage Operations
The Pipeline and Storage segment competes for market growth in the
natural gas market with other pipeline companies transporting gas in the
Northeastsegment's volumes transported and with other companies providing gas storage service.stored
may vary materially depending on weather, without materially affecting its
earnings. The System
has some unique characteristics which enhance its competitive position. Its
service area, which is located adjacent to CanadaPipeline and the Northeast United
States, and partially connects the Northeast with the South, Southwest and
Midwest, is advantageous for the provision of increased transportation and
storage service in the future. The Company will continue to evaluate ways to
take advantage of its location to open up new markets and expand existing
ones, especially in the gas storage business. There will, however, be
increased competition to provide services due to a number of recent large
pipeline expansions in the Northeast. Likewise, new storage projects face
competition from existing storage facilities and a number of planned storage
projects which have been announced as a result of Order 636.
Exploration and Production
The Exploration and Production segment competes with other gas and oil
producers and with fuel oil and electricity wholesalers and producers. Seneca
competes with other oil and gas exploration and production companies of
various sizes for leases and drilling rights for exploration and development
prospects, and competes with other producers for markets to sell its
productionStorage segment's rates are based on price and deliverability.
To competea straight
fixed-variable rate design which allows recovery of all fixed costs in this environment, Seneca acts as operatorfixed
monthly reservation charges. Variable charges based on most
prospects, sheds riskvolumes are designed only
to reimburse the variable costs caused by actual transportation or storage of
exploratory efforts through partnerships, 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.
Other Nonregulated
In the Other Nonregulated segment, NFR competes with other gas marketers
and energy management services providers. Leidy Hub competes with other gas
market service providers. Highland competes with other sawmills in
northwestern Pennsylvania, and UCI competes with other pipeline construction
companies in its area of operation. Sources and providers of energy, other
than those described above, do not compete with System companies to any
significant extent.
ITEM 1. BUSINESS (Continued)
CAPITAL EXPENDITURESgas.
Capital Expenditures
A discussion of capital expenditures by business segment is included in "Management's Discussion and Analysis of Financial Condition and Results of
Operations,Item 7
under the heading "Investing Cash Flow," on pages 33 to 51 of this report.
ENVIRONMENTAL MATTERSsubheading "Capital Expenditures."
Environmental Matters
Supply Corporation iswas 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 agreed to re-plug 30replugged 27 wells which were believed to be
venting small amounts of natural gas to the atmosphere. Twenty-sevenIn 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 have been plugged, at a cost of
approximately $3.1 million, and the other 3 have been found notstarted to be venting
gas anymore. There are on-going discussions regarding the NYDEC's
determination that Supply Corporation should also re-plug 37 plugged and
abandoned wells which are not venting any naturalvent gas to the atmosphere.
Re-plugging those additional 37 wells, plus the 3 wells which were formerly
venting small amounts of gas to the atmosphere, would cost an additional
amount of approximately $5.1 million.
For additionalA discussion of environmental matters involving the Company seeis
included in Item 8, Note G - "CommitmentH-Commitments and Contingencies" on pages 77 to 79 of this
report.
MISCELLANEOUSContingencies.
Miscellaneous
The SystemCompany had 3,148 regular2,925 full-time employees at September 30, 1994,1995, a decrease of
5.4%7% from the 3,3293,148 employed at September 30, 1993.1994.
Agreements covering employees in collective bargaining units in the
State of New
York were last renegotiated in calendarOctober 1994 and are scheduled to expire in
calendarFebruary 1998. Agreements covering most employees in collective bargaining units
in the Commonwealth of 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.
System companies haveThe Company has numerous county and municipal franchises under
which they useit uses public roads and certain other rights-of-way and public property
for the location of facilities. System companies haveThe Company has regularly renewed such
franchises at expiration and expectexpects no difficulty in continuing to renew them.
ITEM 1. BUSINESS (Concluded)
EXECUTIVE OFFICERS OF THE COMPANY (1)
Age as of Date Elected
Name 9/30/94 Position To Position
Bernard J. Kennedy 63 Chairman of the Board of
Directors. March 21, 1989
Chief Executive Officer. August 1, 1988
President. January 1, 1987
Director. March 29, 1978
Executive Vice President
and General Counsel from
1976 to 1986.
Chairman of the Board of
certain subsidiariesOfficers of the Company since August 1988.
President and Chief Executive
Officer of Supply Corporation
and an officer of certain
other subsidiaries of the
Company from prior to 1989
until June 1, 1989.
Philip C. Ackerman 50 Director(1)
Age as of Company Position Date Elected
Name 9/30/95 Since 1990 To Position
---- -------- ---------- -----------
Bernard J. Kennedy 64 Chairman of the
Board of Directors. March 21, 1989
Chief Executive
Officer. August 1, 1988
President. January 1, 1987
Director. March 29, 1978
Chairman of the Board
of certain subsidiaries
of the Company. August 1, 1988
Philip C. Ackerman 51 Director. March 16, 1994
Senior Vice President. June 1, 1989
President of
Distribution Corporation. October 1, 1995
President of Seneca. June 1, 1989
Executive Vice President
of Supply Corporation. October 1, 1994
President of Horizon. September 13, 1995
President of certain other
of the Company's
subsidiaries from
prior to 1990.
Richard Hare 57 President of Supply
Corporation. June 1, 1989
Senior Vice President of
Penn-York Energy Corpor-
ation until its merger
into Supply Corporation
on July 1, 1994. June 1, 1989
William J. Hill 65 Director. September 20, 1995
President of
Distribution
Corporation until
October 1, 1995. June 1, 1989
Vice President from July 1,
1980 until June 1, 1989.
President of certain of the
Company's subsidiaries from
prior to 1989.
Richard Hare 56 President of Supply Corporation. June 1, 1989
An executive officer of certain
of the Company's subsidiaries
from prior to 1989.
William J. Hill 64 President of Distribution June 1, 1989
Corporation.
An executive officer of
Distribution Corporation
from prior to 1989.
(1) The Company has been advised that there are no family relationships
among any of the officers listed, and that there is no arrangement or
understanding among any one of them and any other persons pursuant to
which he was elected as an officer.
ITEM 2.2 PROPERTIES
GENERAL INFORMATION ON FACILITIESGeneral Information on Facilities
The investment of the SystemCompany in net property, plant and equipment was $1,542,739,000$1,649.2
million at September 30, 1994.1995. Approximately 80%78% of this investment is in the
System's 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,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 System'sCompany's other business segments. Most of
thisIts net
investment representsin its gas distribution network. These properties
include 14,592network (including 14,666 miles of
pipeline (exclusive of service pipe), whichdistribution pipeline) and its services represent approximately 55%58% and 27%,
respectively, of the Utility Operation's net investment of $787,794,000.$822.8 million.
The Pipeline and Storage segment represents a net investment of $440,810,000$463.6
million in transmission and storage facilities at September 30, 1994.1995.
Transmission pipeline, with a net cost of $132,591,000,$145.1 million, represents 30%31% of this
segment's total net investment and includes 2,7862,778 miles of pipeline required to
move large volumes of gas throughout the System'sits service area. Storage facilities
consist of 34 storage fields, four4 of which are jointly operated with certain
pipeline suppliers, and 512511 miles of pipeline. Included in the storage
facilities net investment is $80,942,000$85.6 million of base gas. The Pipeline and Storage
segment has 31 compressor stations with 72,10073,450 installed compressor horsepower.
The Exploration and Production segment had a net investment in
properties amounting to $295,419,000$340.0 million at September 30, 1994.1995. Of this amount,
Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast
regions was $238,175,000,$285.2 million, and Seneca's net investment in oil and gas
properties in the Appalachian region aggregated $57,244,000.$54.8 million.
During the past five years, the SystemCompany has made significant additions
to plant in order to expand and improve transmission and distribution facilities
for both retail and wholesaletransportation customers and to augment the reserve base of
oil and gas. Net plant has increased $455,276,000,$442.8 million, or 42%37%, since 1989.1990.
The System'sRegulated Operation's facilities provided the capacity to meet the System's 1994its
1995 peak day sendout, including transportation service, of 1,9881,847 MMcf, which
occurred on January 19, 1994.February 5, 1995. Withdrawals from storage provided approximately
47%45% of the requirements on that day.
SystemCompany maps, which are included as Exhibit 99.2in the paper copy of the Company's
combined Annual Report to Shareholders/Form 10-K, are narratively described in
the Appendix to this report.
EXPLORATION AND PRODUCTION ACTIVITIESelectronic 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 System'sCompany's oil and gas producing activities. For a further
discussion of oil and gas producing activities, refer to Note K
- - "SupplementaryL-Supplementary
Information for Oil and Gas Producing Activities," on pages
84 to 88 under Item 8 of this report, and to Exploration and Production on pages 17 to 19
of this report.
ITEM 2. PROPERTIES (Continued)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, 1993, whereas the
reserve disclosures1994, 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 K are reported as of September 30, 1994.
The gas reserves of Supply Corporation reported as of December 31, 1993,
in Forms 2 and 15, were in-house estimates arrived at by qualified Supply
Corporation geologists and engineers.L.
Seneca is not regulated by the FERC, and thus is not required to file
Forms 2 and 15. As discussed in Item 1,
Supply Corporation's exploration and production activities were transferred to
Empire effective January 1, 1994. Subsequently, on July 1, 1994, Empire was
merged into Seneca. Seneca's oil and gas reserves reported in Note KL as of September
30, 1994,1995, were estimated for Senecaby 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 SystemSeneca's records:
Production
For the Year Ended September 30 1994 1993 1992
Average sales price per Mcf of gas $ 2.18 $ 2.20 $ 1.97
Average sales price per barrel of oil $14.86 $16.78 $17.11
Average production (lifting) cost per Mcf
equivalent of gas and oil produced
For the Year Ended September 30 1995 1994 1993
- ------------------------------- ---- ---- ----
Average Sales Price per Mcf of Gas $ 1.67 $ 2.18 $ 2.20
Average Sales Price per Barrel of Oil $16.16 $14.86 $16.78
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ .44 $ .45 $ .54
$ .62
Productive Wells
At September 30, 1994 Gas Oil
Productive Wells - gross 2,153 201
- net 2,013 172
At September 30, 1995 Gas Oil
- --------------------- --- ---
Productive Wells - gross 2,115 257
- net 1,941 202
Developed Andand Undeveloped Acreage
At September 30, 1994
Developed Acreage - gross 568,736
- net 508,753
Undeveloped Acreage - gross 516,743
- net 476,482
ITEM 2. PROPERTIES (Concluded)
At September 30, 1995
- ---------------------
Developed Acreage - gross 595,787
- net 520,849
Undeveloped Acreage - gross 624,085
- net 588,431
Drilling Activity
Productive Dry
For the Year Ended September 30 1994 1993 1992 1994 1993 1992
Net Wells Completed - Exploratory 5 9 5 5 6 5
- Development 7 16 11 1
Productive Dry
------------------ ------------------
For the Year Ended September 30 1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
Net Wells Completed - Exploratory 5 5 9 0 4 6
- Development 6 8 16 0 0 3
3
Present Activities
At September 30, 1994
Wells in Process of Drilling - gross 1
- net 1
At September 30, 1995
- ---------------------
Wells in Process of Drilling - gross 7
- net 6
There are currently no waterflood projects or pressure maintenance
operations of material importance.
ITEM 3. LEGAL PROCEEDINGS
PARAGON/3 Legal Proceedings
Paragon/TGX PROCEEDINGSProceedings
A. New York Litigation
OnSince November 30, 1984, Distribution Corporation commenced an actionhas 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) seeking. Distribution Corporation
sought a declaratory judgment concerning the contract effect of a December 20,
1983 PSC order (the Disapproval Order) which, among other things, disapproved a
1974 gas purchase agreement between Distribution Corporation's predecessor in
interest, Iroquois Gas Corporation, and Paragon (the Paragon Contract).
Paragon/TGX counterclaimed for (i) a declaration that the Disapproval Order did
not affect the Paragon Contract in any way, whatsoever, (ii) approximately $4,400,000$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 has 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 (NGPA).
On the basis of a Memorandum and Order dated December 10, 1988, the
District Court in January 1991 issued a partial summary judgment which
declared that, whereas the Disapproval Order abrogated only the Paragon
Contract's price term, the legal consequence of such abrogation was to render
the Paragon Contract "void and no longer of any force or effect" as of
December 20, 1983.1978.
On December 3, 1991, the U. S.United States Court of Appeals for the Second
Circuit (the Second Circuit) reversed the District Court'sissued an opinion regarding a partial summary
judgment and remanded the case togranted by the District Court for further proceedings.Court. The Second Circuit agreed with the District Courtessentially held that
the Disapproval Order had "voided the Contract's price term," but did not agree that the Paragon
Contract as a whole was "voided by the cancellation of the price term."
Rather, the Second Circuit found 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 $21,874,042$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.
By Order entered March 23, 1992, the District Court granted Distribution
Corporation permission to amend its reply to Paragon/TGX's counterclaims to
allege, among other things, (i) Distribution Corporation's "termination" of
the Paragon Contract by letter effective February 1, 1988; (ii) Paragon's pre-
September 1984 repudiation of the Paragon Contract; and (iii) the PSC's
"primary jurisdiction" to interpret the Disapproval Order as respects "a price
consistent" therewith. With respect to (iii) above, Distribution Corporation
ITEM 3. LEGAL PROCEEDINGS - (Continued)
notes that the New York State Public Service Law provides that no charge for
gas made pursuant to a contract with a New York gas utility shall exceed the
"just and reasonable charge" for such gas. In response to Distribution
Corporation's motion for partial summary judgment in respect of the defense
denominated (ii) above, the District Court, in a Memorandum and Order entered
July 10, 1992, as revised by a Memorandum and Order entered March 1, 1993,
denied Distribution Corporation's summary judgment motion (due to a perceived
question of fact as to the occurrence of a condition precedent to Paragon's
pre-September 1984 contract repudiation), but confirmed Distribution
Corporation's right to assert the repudiation defense upon the trial of the
action.
On January 4, 1993, the District Court entered a non-final order
purportedly responsive to a February 13, 1992 Paragon/TGX motion. The order
purports to declare that, by voiding the Paragon Contract price escalation
mechanism effective December 31, 1983, the PSC's 1983 Disapproval Order
effectively capped the Paragon Contract price, at the lesser, from time to
time, of (i) the 1983 Paragon Contract summer/winter "base prices," or (ii)
the applicable "Natural Gas Ceiling Prices" set forth in 18 CFR paragraph
271.101 Table I. Under date of January 19, 1993 Distribution Corporation
sought rehearing, reargument, reconsideration and clarification of the January
4, 1993 order. On July 12, 1993, the District Court filed a Memorandum and
Order granting in part the January 19, 1993 motion. The July 12, 1993 Order
stated that, while the January 4, 1993 Memorandum and Order did determine that
an obligation on Distribution Corporation's part to pay for gas purchased
pursuant to the gas purchase agreement at the applicable NGPA ceiling price
arose out of the conduct of the parties after the NGPA became effective and
that the Disapproval Order did not relieve Distribution Corporation of such
obligation, it did not determine the just and reasonable price for the gas
pursuant to Public Service Law section 110(4), set a contract price for the
duration of the contract, resolve any defenses presented by Distribution
Corporation, determine whether such obligation continues until the present
time, or rule on any deregulation issues.
Effective January 14, 1994, TGX purportedly effected a partial
assignment of its interest under the Paragon Contract to an unaffiliated
third-party, with whom Distribution Corporation subsequently negotiated
agreements to supersede the terms of the Paragon Contract, prospectively.
These transactions did not materially increase (and potentially may have
decreased) Distribution Corporation's exposure in the New York Litigation.
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...materialfaith . . . 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
ITEM 3. LEGAL PROCEEDINGS - (Continued)
TGX in the conduct of its
business." Distribution Corporation filed a timely reply to Paragon/TGX's
claims.
The parties are awaiting a scheduling orderVarious 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 magistrate
regarding discoveryPSC to
defer, and the trial of this proceeding.
B. Louisiana Litigation
On February 22, 1990, TGX, the purported assignee of the Paragon
Contract, filed a voluntary petition pursuant to Chapter 11 of the United
States Bankruptcy Code in the United States Bankruptcy Court for the Western
District of Louisiana (the Bankruptcy Court). Thereafter TGX commenced a
"turnover" proceeding against Distribution Corporation, premised upon TGX's
December 13, 1991 payment demand described above under "New York Litigation."
Pursuant toultimately recover through rates, a partial settlement agreement between TGX andpayment made
to TGX. Distribution Corporation approvedalso requested the PSC to review the prices
charged by the Bankruptcy Court in August 1992, TGX has
withdrawn the "turnover" proceeding and Distribution Corporation has paid to
TGX $2,940,000 in consideration of, among other things, TGX's release of
Distribution Corporation from the cause of action asserted in the "turnover"
proceeding. TGX is still free to pursue its breach of contract counterclaims
in the New York Litigation. However, the $2,940,000 paid by Distribution
Corporation to TGX will be credited against the amount, if any, which is
ultimately adjudged due TGX and/or Paragon in the New York Litigation.
C. State Commission Proceedings
By its "Order Instituting Proceeding," issued in Case 93-G-0352, et al.,
and effective April 28, 1993, the PSC granted Distribution Corporation
deferral authority in respect of the New York allocable share ($2,006,000) of
the partial settlement payment described above under "Louisiana Litigation"
and instituted a proceeding designed to address Distribution Corporation's
request for recovery authority in respect of that amount. Distribution
Corporation received authority to treat the Pennsylvania allocable share
($934,000) of the partial settlement payment as a gas cost experienced during
the twelve (12) month period ending November 30, 1992.
The PSC proceeding is also expected to address Distribution
Corporation's recovery in New York of gas costs incurred in respect of the
Paragon Contract during the reconciliation period September 1, 1991 through
August 30, 1992. Finally, the PSC proceeding is expected to include the
review of the Paragon Contract in lightcontext of the "just and reasonable" standard of Section
110(4) of the New York Public Service Law.
Under date of October 25, 1994,Law and issue a declaratory order
regarding its findings.
The PSC consolidated the Administrativeproceedings, 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 Judge (ALJ) in
this proceeding issuedSection 110(4)
issues because the PSC determined there was no "properly reviewable contract"
that had been filed with it.
In September 1995, Distribution Corporation filed a recommended decision (RD). The RD seemingly
recommends thatpetition with
the maximum price Paragon/TGX should be authorized to receive
for gas delivered in respectNew York Supreme Court (Albany County, Special Term) seeking judicial review
of the contract should be $3.714 per Mcf. The
ALJ noted thatPSC's May 1995 order regarding the dismissal of Distribution
Corporation might owe approximately $9.6 million
moreCorporation's petition for a declaratory order.
ITEM 4 Submission of Matters to Paragon/TGX under this scenario. The ALJ also found that payments
previously made by Distribution Corporation were prudent and reasonable.
Nonetheless, he recommended that Distribution Corporation be allowed to
recover from ratepayers only one-halfa Vote of the $2,006,000 payment referred to
ITEM 3 LEGAL PROCEEDINGS - (Concluded)
above and one-half of future amounts that might be paid to Paragon/TGX. The
ALJ's recommendations are not binding on the PSC or the courts. All parties
to the proceedings have taken exception to various portions of the RD. The
PSC is expected to issue its decision in this proceeding during 1995.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSSecurity Holders
No matter was submitted to a vote of security holders during the fourth quarter
of 1994.
1995.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER
MATTERS5 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"Capitalization and Note J -
"MarketK- Market for
Common Stock and Related Shareholder Matters (unaudited)," on
pages 67 to 71 and 83, respectively, under Item 8 of this
report,Form 10-K, and reference is made thereto.
ITEM 6 Selected Financial Data
ITEM 6. SELECTED FINANCIAL DATA
Year Ended September 30 1995 1994 1993 1992 1991
1990- ----------------------- ---- ---- ---- ---- ----
SUMMARY OF OPERATIONSSummary of Operations (Thousands)
Operating Revenues $975,496 $1,141,324 $1,020,382 $920,450 $865,131
$892,009-------- ---------- ---------- -------- --------
Operating Expenses:
Purchased Gas 351,094 497,687 409,005 363,690 364,246
415,052
Operation Expense and Maintenance 292,505 291,390 283,230 263,084 245,253 227,593
Property, Franchise and Other
Taxes 91,837 103,788 95,393 89,158 83,095
75,846
Depreciation, Depletion and
Amortization 71,782 74,764 69,425 55,726 50,805
43,740
Income Taxes - Net 43,879 47,792 41,046 35,231 23,285
27,480-------- ---------- ---------- -------- --------
851,097 1,015,421 898,099 806,889 766,684
789,711-------- ---------- ---------- -------- --------
Operating Income 124,399 125,903 122,283 113,561 98,447
102,298
Other Income 5,378 3,656 4,833 5,790 11,793
7,483-------- ---------- ---------- -------- --------
Income Before Interest Charges 129,777 129,559 127,116 119,351 110,240
109,781
Interest Charges 53,883 47,124 51,899 59,041 61,250
57,783-------- ---------- ---------- -------- --------
Income Before Cumulative Effect 75,894 82,435 75,217 60,310 48,990 51,998
Cumulative Effect of Changes in
Accounting - 3,237 - - -
--------- ---------- ---------- -------- --------
Net Income Available for Common
Stock $ 75,894 $ 85,672 $ 75,217 $ 60,310 $ 48,990
$ 51,998
PER COMMON SHARE DATA======== ========== ========== ======== ========
Per Common Share Data
Earnings $2.03 $2.32* $2.15 $1.94 $1.63
$1.83
Dividends Declared $1.60 $1.56 $1.52 $1.48 $1.44
$1.38
Dividends Paid $1.59 $1.55 $1.51 $1.47 $1.43
$1.36
Dividend Rate at Year-End $1.62 $1.58 $1.54 $1.50 $1.46
$1.42
NUMBER OF COMMON SHAREHOLDERS AT
YEAR-ENDNumber of Common Shareholders at
Year-End 21,429 22,465 22,893 23,218 22,662
22,203
PROPERTY, PLANT AND EQUIPMENT======== ========== ========== ======== ========
Net Property, Plant and Equipment (Thousands)
Regulated:
Utility Operation $1,036,225 $ 983,417822,764 $ 929,601787,794 $ 871,102754,466 $ 813,736719,755 $ 678,933
Pipeline and Storage 640,124 618,917 594,580 539,904 481,003
1,676,349 1,602,334 1,524,181 1,411,006 1,294,739463,647 443,622 436,547 423,383 380,008
---------- ---------- ---------- ---------- ----------
1,286,411 1,231,416 1,191,013 1,143,138 1,058,941
---------- ---------- ---------- ---------- ----------
Nonregulated:
Exploration and Production 464,725 415,642 378,815 353,090 323,132339,950 295,418 273,470 261,446 248,787
Other 24,938 21,237 15,170 8,202 7,196
489,663 436,879 393,985 361,292 330,32822,690 18,579 16,209 11,670 5,896
---------- ---------- ---------- ---------- ----------
362,640 313,997 289,679 273,116 254,683
---------- ---------- ---------- ---------- ----------
Corporate 244 223 223 216 216
Gross Plant 2,166,256 2,039,436 1,918,389 1,772,514 1,625,283
Accumulated Depreciation,
Depletion and Amortization 623,517 561,433 502,007 458,763 418,893131 137 122 128 127
---------- ---------- ---------- ---------- ----------
Total Net Plant $1,542,739 $1,478,003$1,649,182 $1,545,550 $1,480,814 $1,416,382 $1,313,751
$1,206,390
TOTAL ASSETS========== ========== ========== ========== ==========
Total Assets (Thousands) $2,038,302 $1,981,657 $1,801,540 $1,760,830 $1,560,834
$1,436,687
CAPITALIZATION========== ========== ========== ========== ==========
Capitalization (Thousands)
Common Stock Equity $ 800,588 $ 780,288 $ 736,245 $ 632,333 $ 542,109
$ 484,044
Long-Term Debt, Net of Current
Portion 474,000 462,500 478,417 479,500 442,071
397,350---------- ---------- ---------- ---------- ----------
Total Capitalization $1,274,588 $1,242,788 $1,214,662 $1,111,833 $ 984,180
$ 881,394
========== ========== ========== ========== ==========
* Includes1994 includes Cumulative Effect of Changes in Accounting of $.09. See Notes A
and FG to Consolidated Financial Statements.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
For a graph7 Management's Discussion and Analysis of "The Revenue Dollar - 1994" see graph A. in the Appendix to
this report.Financial Condition and
Results of Operations
1994Results of Operations
1995 Compared with 1993.1994
National Fuel's consolidated earnings were $85.7$75.9 million, or $2.32$2.03 per common share, in 1994.1995.
This included $3.2compares with earnings of $82.4 million, or $.09$2.23 per common share related toin 1994
(before the cumulative effect of the mandated changes in accounting for income
taxes and post-employment benefits, (as adoptedwhich added a net $3.2 million, or $0.09 per
common share of earnings in accordance1994).
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
Financial Accounting Standards Board's (FASB) Statementsproject 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 Financial Accounting Standards (SFAS) No. 109equipment, 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 No. 112, respectively).
Earnings before thesean 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 changes amounted tofor 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
of approximately 10% over 1993 earnings of $75.2 million. Onmillion and a per-common-share basis, earnings before the accounting changes were $2.23 for
1994, up 4% increase
from 1993 earnings per common share of $2.15. Share amounts reflect a greater
number of weighted average shares outstanding in the current year,1994, principally because of
the sale of 2.5 million shares of common stock in May 1993.
Earnings growthThe earnings increase in 1994 was primarily dueattributable to higher earnings in
the Company's nonregulated
operations.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's successes have continued
in 1994, withsegment as a result of record oil and gas production, more than compensating for
a decline in oil and gas prices. Earnings from Other Nonregulated operations
increased because of the improved performance ofFurthermore, the Company's natural gas
marketing, pipeline construction and timber operations.
Earnings from the Company's regulated operations in total, increased in
1994.had improved earnings.
The Utility Operation's earnings were upincreased slightly
over last year
because of higher throughput due to colder weather as well as Stateand the impact of rate increases in New York Public
Service Commission (PSC) and
Pennsylvania Public Utility Commission (PaPUC)
authorization to earn a return on increased capital investment. ThePennsylvania. These increases were partly offset by an earnings decrease in the
Pipeline and Storage segment's earnings decreased in 1994 compared with 1993,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 boostedincreased 1993 earnings.
Operating Revenues
Year Ended September 30 (in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
Utility Operation
Retail Revenues:
Residential $ 569,603 $ 677,068 $ 613,039
Commercial 137,869 177,249 156,851
Industrial 18,269 31,096 31,609
- -----------------------------------------------------------------------------
725,741 885,413 801,499
Off-System Sales 18,255 6,930 945
Transportation 37,183 34,419 30,213
Other 4,885 4,911 3,961
- -----------------------------------------------------------------------------
786,064 931,673 836,618
- -----------------------------------------------------------------------------
Pipeline and Storage
Wholesale Revenues - - 444,142
Storage Service 59,826 58,971 41,041
Transportation 88,766 90,416 45,313
Other 15,995 3,734 4,072
- -----------------------------------------------------------------------------
164,587 153,121 534,568
- -----------------------------------------------------------------------------
Exploration and Production 56,232 70,261 58,636
Other Nonregulated 57,075 72,036 42,099
- -----------------------------------------------------------------------------
113,307 142,297 100,735
- -----------------------------------------------------------------------------
Less: Intersegment Revenues 88,462 85,767 451,539
- -----------------------------------------------------------------------------
Total Operating Revenues $ 975,496 $1,141,324 $1,020,382
=============================================================================
Operating Income (Loss) Before Income
Taxes
Year Ended September 30 (in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
Utility Operation $ 83,774 $ 90,584 $ 86,690
Pipeline and Storage 67,884 62,302 67,375
Exploration and Production 16,404 21,767 12,980
Other Nonregulated 3,021 2,505 (986)
Corporate (2,805) (3,463) (2,730)
- -----------------------------------------------------------------------------
Total Operating Income Before Income
Taxes $168,278 $173,695 $163,329
=============================================================================
System Natural Gas Volumes
Year Ended September 30 (in billion cubic feet) 1995 1994 1993
- -------------------------------------------------------------------------
Regulated Gas Sales
Residential 79.9 90.6 86.9
Commercial 22.2 26.9 25.6
Industrial 4.8 6.5 6.5
Wholesale * - - 118.7
Off-System 9.4 3.3 0.3
- -------------------------------------------------------------------------
116.3 127.3 238.0
- -------------------------------------------------------------------------
Nonregulated Gas Sales
Gas Sales for Resale 0.4 0.3 -
Production (in equivalent billion cubic feet) 25.4 29.5 24.9
- -------------------------------------------------------------------------
25.8 29.8 24.9
- -------------------------------------------------------------------------
Total Gas Sales 142.1 157.1 262.9
- -------------------------------------------------------------------------
Transportation
Utility Operation 52.8 52.2 48.9
Pipeline and Storage * 290.8 296.6 138.6
Nonregulated 2.5 1.4 -
- -------------------------------------------------------------------------
346.1 350.2 187.5
- -------------------------------------------------------------------------
Marketing Volumes 18.8 18.2 7.3
- -------------------------------------------------------------------------
Less Intersegment Volumes:
Transportation 154.2 164.8 40.1
Production 5.0 2.5 4.3
Gas Sales - 0.1 112.2
- -------------------------------------------------------------------------
159.2 167.4 156.6
- -------------------------------------------------------------------------
Total System Natural Gas Volumes 347.8 358.1 301.1
=========================================================================
* The elimination of wholesale volumes, as well as the increase in
transportation volumes from 1993 to 1994 reflects Supply Corporation's
adoption of FERC Order 636, effective on August 1, 1993.
Utility Operation
Operating Revenues
1995 Compared with 1992. Earnings were $75.21994
Operating revenues decreased $145.6 million in 1993, up $14.9
million, or 25%, over 1992 earnings1995 compared with 1994. This
decrease reflects the recovery of $60.3 million. Earnings per common
share in 1993 were $2.15, an 11% increase from the $1.94 earned in 1992. Share
amounts reflect a greater number of weighted average shares outstanding in
1993, principallydecreased gas costs mainly because of lower
gas sales of 11.0 billion cubic feet (Bcf) as well as a 15% decline in the
saleaverage cost of 2.5 million sharespurchased gas.
The decline in residential and commercial gas sales of common stock15.4 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 May 1993its jurisdictions, has a mechanism whereby
it has the opportunity to recover certain costs and September 1992.
The earnings increase in 1993 resulted from improvements in both the
Pipeline and Storage and Exploration and Production segments' earnings which,
in the aggregate, more than offsetretain a decline in the earningsportion of the
Utility
Operation and the Company's Other Nonregulated operations. New rates, coupled
with a change in rate design, were the major reasons for the Pipeline and
Storage segment's improved results, while increased natural gas production and
higher prices improved the Exploration and Production segment's performance.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Operating Income (Loss)
Before Income Taxes
Year Ended September 30 (in thousands) 1994 1993 1992
Utility Operation $ 90,584 $ 86,690 $ 90,025
Pipeline and Storage 62,302 67,375 49,796
Exploration and
Production 21,767 12,980 7,021
Other Nonregulated 2,505 (986) 4,229
24,272 11,994 11,250
Corporate (3,463) (2,730) (2,279)
Total Operating Income
Before Income Taxes $173,695 $163,329 $148,792
Operating Revenues
Year Ended September 30 (in thousands) 1994 1993 1992
Utility Operation
Retail Revenues:
Residential $ 677,068 $ 613,039 $533,908
Commercial 177,249 156,851 139,662
Industrial 31,096 31,609 35,985
885,413 801,499 709,555
Off-System Sales 6,930 945 -
Transportation 34,419 30,213 27,424
Other 4,911 3,961 3,685
931,673 836,618 740,664
Pipeline and Storage
Wholesale Revenues - 444,142 425,931
Storage Service 58,971 41,041 36,064
Transportation 90,416 45,313 33,821
Other 3,734 4,072 3,054
153,121 534,568 498,870
Exploration and
Production 70,261 58,636 36,303
Other Nonregulated 72,036 42,099 47,479
142,297 100,735 83,782
Less: Intersegment
Revenues 85,767 451,539 402,866
Total Operating Revenues $1,141,324 $1,020,382 $920,450
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
UTILITY OPERATION
Operating Revenuesmargin on these off-system sales.
1994 Compared with 1993.1993
Operating revenues increased $95.1 million in 1994 compared with 1993. This
increase reflects recovery of increased gas costs mainly due to higher throughput,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.
Distribution Corporation, in each of its jurisdictions, has
a mechanism whereby it has the opportunity to recover certain costsHigher residential and retain
a portion of the margin on these off-system sales.
Higher retailcommercial sales of 5 billion cubic feet (Bcf)5.0 Bcf resulted primarily
from weather in Distribution Corporation's service territory that was, on
average, 6.5% colder than lastthe prior year.
Operating Income
1995 Compared with 1994
Operating income before income taxes decreased $6.8 million in 1995 compared
with 1994. This decrease reflects the lower gas sales, discussed above, coupled
with higher operating expenses. Although industrialDistribution Corporation received
general rate increases in New York and Pennsylvania in July 1994 and December
1994, respectively, the weather related reduction in volumes sold, remained level
when compared with last year, they reflected a 2.5 Bcf switch from sales to
transportation service, offset by increased gas sales to a new cogeneration
customer.
Transportation throughput was up 3.3 Bcf mainly because of the above noted
2.5 Bcf switch, as well as a similar switch from sales to transportation
service by commercial customers of .4 Bcf. In addition, there was increased
transportation of 2 Bcf to large- and small-volume industrial customers. The
shut-down of three industrial customers and the bypass of National Fuel's
pipeline system by three customersespecially in
the Pennsylvania jurisdiction, partially
offsetnegatively impacted margins. In both
jurisdictions, lower normalized usage per residential and commercial account
than was established in the total increaseratemaking 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 approximately 1.6 Bcf. Rates that go intothe 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 DecemberNew York preserved pretax operating income of
$8.2 million as weather, overall, was warmer than normal for the period of
October 1994 inthrough May 1995. Since the Pennsylvania rate jurisdiction compensate fordoes not
have a WNC, uncontrollable weather variations directly impact pretax operating
income and earnings. In the loss
of throughput related to these customers.
1993 Compared with 1992. Operating revenue increased $96 millionPennsylvania service territory, weather was 14.2%
warmer than last year and 5.8% warmer than normal. The warmer weather in 19931995
compared with 1992, although throughput remained relatively unchanged. The
flow-through of higher gas costs, as well as rate increases in the New York
rate jurisdiction in both July 19921994 had a negative impact on pretax operating income and 1993, and a rate increase inearnings
for the Pennsylvania rate jurisdiction effective in December 1991, resulted in
increased revenues. Weather-sensitive residential throughput increased 2.1 Bcf
as a result of weather that was, on average, 1.9% colder than last year in
Distribution Corporation's service territory. Combined industrial and end-user
transportation throughput decreased 2.4 Bcf as a result of the bankruptcy of a
major customer in Pennsylvania and a decrease in boiler fuel sales. These
declines were partially mitigated by a significant increase attributable to a
full year's throughput for a cogeneration project that came on line in May 1992.
Operating Incomejurisdiction.
1994 Compared with 1993.1993
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.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
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 addition, in periods of colder than normal weather, the
WNC benefits Distribution Corporation's New York customers. In 1994, the WNC in New York resulted in a benefit to customers of $5.8
million. 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 9.6% colder than lastthe
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.
1993 Compared with 1992. Operating income before income taxes decreased $3.3
million in 1993 compared with 1992. This decline reflects the impact of lower
average gas use per residential account in the New York rate jurisdiction
compared with that imputed in rates resulting in a lower margin on gas sales
which was not adequate to cover the increase in operating expenses. This
problem was remedied by reflecting a lower usage per account in Distribution
Corporation's rates that went into effect on July 23, 1993, in New York. In
1993, the WNC in New York preserved pretax operating income of $1.2 million and
earnings per share of $.02. In the Pennsylvania service territory, weather was
2.5% colder in 1993 than 1992, although it was 5.4% warmer than normal. This
colder weather had a positive impact on pretax operating income and earnings
for the Pennsylvania rate jurisdiction.
Degree Days
Percent Colder
(Warmer) Than
Year Ended September 30 Normal Actual Normal Last Year
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%
1992: Buffalo 6,778 6,644 (2.0%) 15.9%
Erie 6,556 5,983 (8.7%) 13.1%
Degree Days
Percent Colder
(Warmer) Than
Year Ended September 30 Normal Actual Normal Last Year
- ------------------------------------------------------------------------------
1995: Buffalo 6,693 6,181 (7.6%) (11.4%)
Erie 6,128 5,773 (5.8%) (14.2%)
- ----------------------------------------------------------------------------
1994: Buffalo 6,710 6,975 3.9% 3.6%
Erie 6,202 6,726 8.4% 9.6%
- ---------------------------------------------------------------------------
1993: Buffalo 6,723 6,730 0.1% 1.3%
Erie 6,484 6,135 (5.4%) 2.5%
- ---------------------------------------------------------------------------
Purchased Gas.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.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
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 $3.74$3.19 per thousand cubic feet (Mcf) in 1994,1995, a decrease of 3%15% from the
average cost of $3.84$3.74 per Mcf in 1993.1994. The average cost of purchased gas in 19931994
was 22% higher3% lower than the $3.15$3.84 per Mcf in 1992.
System Throughput
(billion cubic feet)
Year Ended September 30 1994 1993 1992
Utility Operation
Retail Sales:
Residential 90.6 86.9 84.8
Commercial 26.9 25.6 25.9
Industrial 6.5 6.5 9.1
124.0 119.0 119.8
Transportation-
End-Users 52.2 48.9 48.7
176.2 167.9 168.51993.
Pipeline and Storage
Wholesale SalesOperating 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 - 118.7 130.3
Transportation 295.3 138.6 157.0
295.3 257.3 287.3
Less Intersegment Throughput:
Sales - 112.2 122.0
Transportation 164.2 40.1 33.2
164.2 152.3 155.2
Total System Throughput 307.3 272.9 300.6
PIPELINE AND STORAGE
Operating RevenuesQuarterly
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 1993.1993
Operating revenues decreased $381.4 million in 1994 compared with 1993. This
decline reflects Supply Corporation's restructured operations under the Federal Energy Regulatory Commission's (FERC)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, thusservices. Thus the recovery of purchased gas
costs has been eliminated from Supply Corporation's revenues.
1993Operating Income
1995 Compared with 1992.1994
Operating revenuesincome before income taxes increased $35.7$5.6 million in 19931995 compared
with 1992, despite a 30 Bcf decline1994. This increase reflects the increase in throughput. New rates that
became effectiveoperating revenues discussed
above, offset in July 1992, subject to refund, significantly increased
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
revenues in 1993. Supply Corporation filed a Stipulationpart by higher operating expense and Agreement (the
Settlement) with the FERC on October 15, 1993, respecting these new rates. As a
result of the Settlement, Supply Corporation reversed approximately $15 million
of its previously accrued refund provision. Approximately $2.8 million of the
amount reversed related to 1992. Additionally, as the Settlement included full
recovery of Supply Corporation's portion of the net periodic post-retirement
benefit costs under SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions." Supply Corporation recorded $3.6 million of
related post-retirement benefit expense. These adjustments relate to rates that
were in effect since July 1, 1992, subject to refund. The change to the
straight fixed-variable (SFV) rate design mandated by Order 636, which provides
for recovery of Supply Corporation's fixed costs in the demand, or reservation
charge, contributed additional revenues of approximately $2.7 million for August
and September 1993 when compared to Supply Corporation's former rate design.
All of these items were reflected in earningsrecording, in the
fourth quarter of 1993.
Operating Income1995, 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 1993.1993
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. The favorable SettlementA 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 SFVstraight 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.
Throughput increased 38 Bcf in 1994
Exploration and can be attributed to increased
utilization of Supply Corporation's Canadian gas transportation facilities, the
expanded capacity of these facilities and weather that was colder than last
year. However, because of the SFV rate design, the increase in throughput did
not have a significant impact on pretax operating income.
1993Production
Operating Revenues
1995 Compared with 1992.1994
Operating income before income taxes increased $17.6revenues decreased $14.0 million in 19931995 compared with 1992.1994. This
increasedecrease 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 mainlydown 291,000 barrels, or 28%. This drop reflects natural
depletion and lower condensate production related to decreased gas production.
Although the result of
higherweighted 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 discussed above, which were partly offset by higher gas costs
and operation and maintenance (O & M) expenses, primarily for labor and employee
benefits.
EXPLORATION AND PRODUCTION
Operating Revenuesduring 1995.
1994 Compared with 1993.1993
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
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Gulf Coast Region and 17% and 24%,
respectively, for all geographic regions combined.
Systemwide, theThe weighted average price received for gas and oil production in 1994
was $2.18as compared to 1993 decreased $0.02 per Mcf and $14.86$1.92 per barrel (bbl),
respectively. This is a decline
of $.02 per Mcf in gas prices and $1.92 per bbl in oil prices compared with
1993. Nonetheless, efforts to stabilize prices through hedging
activities contributed approximately $1.6 million of operating revenues for the
year.
At
present, Seneca's goal is to hedge approximately 60% of its Gulf Coast gas and
oil production.
Production Volumes
Year Ended September 30 1995 1994 1993
- ----------------------------------------------------------
Gas Production
(million cubic feet)
Gulf Coast 14,294 16,296 12,134
West Coast 840 706 1,059
Appalachia 5,808 6,271 6,681
- -----------------------------------------------------------
20,942 23,273 19,874
===========================================================
Oil Production
(thousands of barrels)
Gulf Coast 287 615 387
West Coast 433 404 431
Appalachia 19 11 13
- -----------------------------------------------------------
739 1,030 831
===========================================================
Weighted Average Prices
Year Ended September 30 1995 1994 1993
- ----------------------------------------------------------
Weighted Average Gas Price/Mcf
Gulf Coast $1.56 $2.03 $1.99
West Coast $1.33 $1.58 $1.62
Appalachia $2.01 $2.65 $2.67
Weighted Average Price $1.67 $2.18 $2.20
- ------------------------------------------------------------
Weighted Average Oil Price/bbl
Gulf Coast $16.94 $15.54 $17.84
West Coast $15.66 $13.79 $15.76
Appalachia $15.72 $15.92 $18.81
Weighted Average Price $16.16 $14.86 $16.78
Operating Income
1995 Compared with 1992.1994
Operating revenues increased $22.3income before income taxes decreased $5.4 million in 19931995 compared
with 1992.1994. This increasedecrease 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 also primarily attributable to Seneca's
Gulf Coast operations. Natural gas production from the Gulf Coast operations
increased 217% to 12.1 Bcf from 3.8 Bcf in 1992. In total, from all geographic
areas, production rose by 7.8 Bcf to 19.9 Bcf. Lower natural gas production was
realized from Appalachian and West Coast properties. Systemwide, the average
price received for gas production in 1993 was $2.20 per Mcf, an increasea result of $.23
per Mcf from $1.97 per Mcf in 1992. Oil production (mainly condensate from gas
wells) also increased in 1993 by 188,000 bbls compared with 1992. Systemwide,
the average price received for oil production in 1993 was $16.78 per bbl, a
decrease of $.33 per bbl from $17.11 per bbl in 1992.
Production Volumes
Year Ended September 30 1994 1993 1992
Gas Production
(million cubic feet)
Gulf Coast 16,296 12,134 3,828
West Coast 706 1,059 1,234
Appalachia 6,271 6,681 7,008
23,273 19,874 12,070
Oil Production
(thousands of barrels)
Gulf Coast 615 387 172
West Coast 404 431 454
Appalachia 11 13 17
1,030 831 643
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Operating Incomedecreased production.
1994 Compared with 1993.1993
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 basicallysubstantially 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.
1993Other Nonregulated
Operating Revenues
1995 Compared with 1992.1994
Operating income before income taxes increased $6revenues decreased $15.0 million in 19931995 compared with 1992.1994. This
increase was alsodecrease 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 increaseCompany's gas marketing subsidiary, largely because of lower natural
gas prices in operating revenues, discussed above, partly offset by increases in
depletion and O & M expenses. The increase in O & M expenses is related to the
increased production activity in the Gulf Coast operations. Additionally, a
charge to O & M expense of $2.3 million was recorded in the fourth quarter of
1993 for work performed on Appalachian wells.
OTHER NONREGULATED
Operating Revenues1995 compared with 1994.
1994 Compared with 1993.1993
Operating revenues increased $29.9 million in 1994 compared with 1993. This
increase is almost entirely due to higher revenues from NFR the Company's gas marketing subsidiary, as its gas marketing
volumes more than doubled to 18.2 Bcf in 1994 from 7.3 Bcf in 1993.
1993Operating Income
1995 Compared with 1992.1994
Operating revenues decreased $5.4income before income taxes increased $0.5 million in 19931995 compared
with 1992.1994. This decline reflected lower revenues fromincrease 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 Company'sdiscontinuance of its pipeline construction
subsidiary, partly offset by higher revenues
from NFR. UCI had an exceptionally productive year in 1992, completing several
projects in Virginia and New York for nonaffiliated pipeline companies that were
expanding their systems. The lack of large projects in 1993 negatively impacted
UCI's revenues. NFR's revenues increased in 1993, as gas marketing volumes
increased to 7.3 Bcf from 5.4 Bcf in 1992.
Operating Incomeoperations.
1994 Compared with 1993.1993
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.
1993 Compared with 1992. Operating income before incomeIncome Taxes, Other Income and Interest Charges
Income Taxes
Income taxes decreased $5.2
million in 1993 compared with 1992. This decline was mainly the result of the
lack of a contribution by UCI to operating income before income taxes. The lack
of large projects, coupled with tight margins contributed to poor performance in
1993. This more than offset the increase in NFR's operating income before
income taxes resulting from increased marketing activities.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
INCOME TAXES, OTHER INCOME AND INTEREST CHARGES
Income Taxes. Income taxes increased in 1994 and 1993,1995, mainly because of increasesa decrease in pretax income.
The opposite was true in 1994 as income as well as higher income tax rates. In addition, thetaxes increased because of an increase
in incomepretax income. Income taxes in 1994 reflects1995 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 down fromand $2.6
million in 1993. These credits are a direct reduction of income tax expense.
Other Income.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 and $1 million in 1994 and
1993, respectively.1994. A portion of the decrease
in 1994 and 1993 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.
Other income also decreased in 1993 because of lower income associated with
funds used during construction by the Pipeline and Storage segment resulting
from lower construction balances. The decreases in 1993 were partly offset by
higher interest income on temporary cash investments related to the proceeds
from the September 1992 issuance of 2.5 million shares of common stock.
Interest Charges.Charges
Interest on long-term debt increased $4.2 million in 1995 and decreased $1.8
million and $1.4
millionin 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 and 1993, respectively. This
was mainly due to refinancing activities, whereby higher-interest long-term debt
was replaced with lower-interest long-term debt and with equity.debt.
Other interest charges decreased $3 million and $5.7increased $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
and
1993, respectively. The declines in both 1994 and 1993 reflectreflects lower interest on short-term borrowings because of lower average
amounts outstanding. A lower
weighted average interest rateoutstanding, offset in 1993 also contributed to the decline in
short-term interest. However, 1994 reflectspart by an increase in the weighted average
interest rate.
1995 OUTLOOK
The coming year will be one of transition for the Company as it works
through the impact of the FERC's Order 636 on the state level. As a result,
1995 earnings are expected to be lower than the record earnings of 1994.
However, management continues to believe that the integrated strength of the
Company places it on a course for growth in 1996Capital Resources and beyond.
When reviewing 1994 earnings it is important to note that $.09 per share
was due to the cumulative effect of mandated accounting changes which will not
recur in 1995. In addition, allowed returns on pipeline equity are expected to
decrease as a result of allegedly lower risks associated with that business.
Supply Corporation, therefore, anticipates a lower return on equity for rates to
become effective in 1995. Further, in the Utility Operation, Distribution
Corporation saw its allowed return on equity in its New York rate jurisdiction
fall from 12.0% to 10.7% in July. The Company expects allowed returns on equity
at the state level to increase in future years as a result of the state
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
commission recognition of increased risks under the FERC's Order 636, as well as
the rise in interest rates. Nevertheless, such a rise will not significantly
benefit 1995 earnings.
Our Exploration and Production segment, and our Other Nonregulated
operations should increase their earnings contribution in 1995. However, the
current low prices received for natural gas production will temper the increase
and, therefore, it is unlikely that increased contributions for our nonregulated
operations will cause consolidated earnings to increase in 1995.
CAPITAL RESOURCES AND LIQUIDITYLiquidity
The primary sources and uses of cash during the last three years are summarized
in the following condensed statement of cash flows:
Sources and (Uses) of Cash
Year Ended September 30 (in millions) 1995 1994 1993
- -----------------------------------------------------------------
Provided by Operating Activities $173.5 $199.2 $123.7
Capital Expenditures (182.8) (135.1) (131.9)
Short-Term Debt, Net Change 35.1 (84.3) (30.2)
Long-Term Debt, Net Change 4.0 80.1 (51.1)
Issuance of Common Stock 2.5 9.1 78.8
Common Dividends (59.2) (57.2) (52.2)
All Other-Net 10.6 3.6 0.2
- ------------------------------------------------------------------
Net Increase (Decrease) in Cash
and Temporary Cash Investments $(16.3) $ 15.4 $(62.7)
==================================================================
Operating Cash Year Ended September 30 (in millions) 1994 1993 1992
Provided by Operating Activities $199.2 $123.7 $ 93.0
Capital Expenditures (135.1) (131.9) (157.9)
Short-Term Debt (84.3) (30.2) 20.5
Long-Term Debt, Net Change 80.1 (51.1) 74.3
Issuance of Common Stock 9.1 78.8 73.7
Common Dividends (57.2) (52.2) (45.6)
All Other-Net 3.6 .2 (2.1)
Net Increase (Decrease) in Cash
and Temporary Cash Investments $ 15.4 $(62.7) $ 55.9
OPERATING CASH FLOWFlow
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 in accordance with SFAS 109 and SFAS 112, respectively.benefits.
Cash provided by operating activities in the Utility Operation and
Pipeline and Storage segment may vary substantially from year to year because of
fluctuations in weather, 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.
For a graph of "Book Value Per Common Share" see graph B. in the Appendix
of this report.
Net cash provided by operating activities totalled $199.2$173.5 million in
1994,
an increase1995, a decrease of $75.5$25.7 million compared with the $123.7$199.2 million provided by
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
operating activities in 1993.1994. This increase reflected higherdecrease reflects lower revenues and earnings
in the Exploration and Production segment, mainly from its Gulf Coast
operations. Theoperations, coupled with lower payable balances. This was partly offset by
higher cash flow from the Utility Operation hadbecause of an over-recovery of gas
costs, an increase in cash flow from operations
mainly because Distribution Corporation had over-recovered purchased gas costs
at September 30, 1994, while it was in an under-recovery position at September
30, 1993. In addition, the Pipeline and Storage segment had an increase in
upstream pipeline companysupplier refunds received during the year, a reduction in
1994, thus increasing its cash
flow from operations.
INVESTING CASH FLOWstored gas inventory, and a decrease in receivable balances.
Investing Cash Flow
Capital Expenditures.Expenditures
Capital expenditures totalled $138.3$182.8 million in 1994.1995. The table below presents
these expenditures by business segment:
Year Ended September 30 (in millions) 1994 Percentage
Utility Operation $ 61.7 44.6%
Pipeline and Storage 20.5 14.8
Exploration and Production 52.5* 38.0
Other Nonregulated 3.6 2.6
$138.3* 100%
* Includes noncash acquisition of $3.2 million in a stock-for-asset swap.
1995
Year Ended September 30 (in millions) Amount Percentage
- -----------------------------------------------------------------------
Utility Operation $ 64.8 35.4%
Pipeline and Storage 38.7 21.2
Exploration and Production 69.7 38.1
Other Nonregulated 9.6 5.3
- --------------------------------------------------------------------
$182.8 100.0%
====================================================================
Most of the Utility Operation's capital expenditures were for the
replacement of mains and main extensions, as well as for the replacement of
service lines and, to a minor extent, the installation of new services.
Pipeline and Storage capital expenditures included an increase in
compression at two locations, other additions, improvements and replacements to
the Company's transmission and storage systems.
The majority of the Exploration and Production segment's capital
expenditures were made for the exploration for and development of oil and gas
properties located offshore in the Gulf of Mexico, and in Seneca's Northeast
Clay Field in central Texas. As a result of activity in the Gulf Coast Region,
reserves included 93.4 Bcf of new gas reserves and 1.1 million barrels of new
oil reserves at September 30, 1994. In addition, capital expenditures in the
Appalachian Region included $3.2 million for the acquisition of natural gas
production assets in exchange for Company common stock. This acquisition added
approximately 3 Bcf of gas reserves.
Other Nonregulated capital expenditures included approximately $5.0
million in connection with its link with the Empire State Pipeline at Grand
Island, New York and approximately $5.1 million related to compressor engine
emission controls necessary to comply with the Clean Air Amendments of 1990. In
addition, capital expenditures were made for additions, improvements and
replacements to this segment's transmission and storage systems.
The Exploration and Production segment spent approximately $49.0
million on its offshore program in the Gulf of Mexico, including offshore lease
acquisitions and drilling expenditures. Lease acquisitions included a 30%
working interest in an oil and gas field in West Delta Blocks 31 and 32. The
majority of offshore drilling expenditures were spent on West Cameron 552, West
Cameron 522, West Delta 17 and Vermillion 252.
Approximately $21.0 million was spent on the Exploration and Production
segment's onshore program, including horizontal onshore drilling in central
Texas and the acquisition of a 240-acre oil field located in the Silverthread
Field in California.
Other Nonregulated capital expenditures consisted primarily of
timberland and equipment purchases.
The Company's estimated capital expenditures for the next three years
are:
Year Ended September 30 (in millions) 1995 1996 1997
Utility Operation $ 63.6 $ 59.1 $ 58.1
Pipeline and Storage 38.0 17.6 18.3
Exploration and Production 74.3 78.2 80.8
Other Nonregulated 7.1 1.2 1.3
$183.0 $156.1 $158.5
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Year Ended September 30 (in millions) 1996 1997 1998
- --------------------------------------------------------------------
Utility Operation $ 60.7 $ 58.9 $ 57.9
Pipeline and Storage 21.5 20.5 20.5
Exploration and Production 90.4 91.3 95.0
Other Nonregulated 0.3 0.3 0.3
- --------------------------------------------------------------------
$172.9 $171.0 $173.7
====================================================================
Estimated expenditures for the Utility Operation during the next three
years will be concentrated in the areas of main replacements and extensions,
service line replacements and, to a minor extent, the installation of new
services.
Included inEstimated expenditures for the Pipeline and Storage segment's capital expenditures for
1995 is approximately $5.6 million tosegment in 1996
will be spent in connection with several
expansion projects, the most significant of which is a link with the Empire
State Pipeline at Grand Island, New York. This will greatly increase the
reliability, flexibility and efficiency of service to the Company's service
territoryconcentrated in the areas northreconditioning of Buffalostorage wells and to Grand Island, New York.
Also included in the 1995 capital expenditures is approximately $4.3
million for compressor engine emission controls necessary to comply with the
standards of the Clean Air Act Amendments of 1990 (the Act). Approximately $.6
million of capital expenditures were incurred in 1994 to comply with the Act.
The Company does not anticipate incurring significant additional capital
expenditures to comply with the current standards of the Act. However, changes
in standards may require additional expenditures in the future. Management
expects that all related capital expenditures will be recoverable through rates.
Significant capital expenditures related to Supply Corporation's Laurel
Fields Storage Project (which is pending the FERC's approval) are not expected
to be incurred until 1996. Since the timing of expenditures related to this
project are not finalized, the preceding table does not include significant
amounts for this project. Laurel Fields is a 19 Bcf underground natural gas
storage development project, which entails the development of Supply
Corporation's Callen Run (a depleted gas field) and expansion of its Limestone
Storage Field. Filings with the FERC were made in June 1994 to implement this
project. An "open season" was held in August 1994 to identify prospective
customers for this project. Precedent agreements are currently being negotiated
with interested customers. On November 4, 1994, a proposal was sent to the FERC
to divide the project into two phases. Phase I would encompass the expansion of
the Limestone Storage Field to accommodate approximately 7 Bcfreplacement
of storage and phase II would consist of the development of the Callen Run Storage Field. The
potential cost of the project is approximately $200 million.
For a graph of "Capital Expenditures" see graph C. in the Appendix to this
report.transmission lines.
Estimated capital expenditures in 19951996 for the Exploration and
Production segment are approximately 40%30% higher than capital spending in 19941995 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, evaluating reserve acquisitions and significantly expanding exploration
activities. Capital expenditures for Other Nonregulated operations
will primarily be used for timberland.
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
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
facilities and the expansion of transmission line capacities. TheWhile 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 regulatedCompany's other business
segments depends, to a large degree, upon market conditions coupled withconditions. Expenditures in the
Regulated Operations are also dependent on adequate rate relief.
Other.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
$2.3$4.0 million of cash was received during fiscal 1995 related to the sale of
certain gas reserves in the firstGulf 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 1994,1995, approximately $6.2 million
of cash was received related to the fiscal 1993 sale of Seneca's interestUCI'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 its Alberta,
Canada, gas reserves.
FINANCING CASH FLOWforeign and domestic
energy projects, including foreign utility companies and exempt wholesale
generators of electricity. The SEC authorized the Company (through Horizon and
intermediate companies) to invest up to an aggregate of $150.0 million through
December 2001 in such activities. On September 15, 1995, the Company acquired
500 shares of Horizon $1 par common stock for $1.0 million. Currently, Horizon
is considering investment opportunities in eastern Europe, South America and
Asia, and is the controlling partner in Sceptre Power Company, a partnership
which includes a team with considerable experience in developing such energy
projects.
Financing Cash Flow
In order to meet the Company's capital requirements, cash from external sources
must periodically be obtained through short-term bank loans and commercial
paper, as well as through issuances of long-term debt and equity securities. The
Company expects these traditional sources of cash to continue to supplement its
internally generated cash during the next several years.
On JulyMay 1, 1994,1995, the Company redeemed $19.9retired $55.0 million remaining outstanding
principal amount of 9-1/2% debentures due July 1, 2019, for $21.36.07% medium-term
notes and $20.0 million including redemption premium.of 6.10% medium-term notes, both of which matured on
that date.
On July 14, 1994,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$50.0 million of 7.375%
medium-term notes due July 1999, at an interest rate of 7.25%. Also on July 14, 1994, the Company
issued $50 million of medium-term notes due July 2024, at an interest rate of
8.48%. These latter notes are callable beginning July 1999.in June 2025. After reflecting underwriting discounts and
commissions, the combined proceeds to the Company of
these two issuances amounted to $99.4$49.3 million.
TheOn 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 were used to reduce
outstanding short-term borrowings.the Company amounted to $49.8 million.
The Company's embedded cost of long-term debt was 7.3% at both
September 30, 19941995 and 1993.1994.
At September 30, 1994,1995, the Company has registered under the Securities
Act of 1933, as amended, and Exchange Commission
(SEC)has authority remaining under a shelf registration filed in March 1993the Public Utility Holding
Company Act of 1935, as amended, to issue and sell up to $220$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.
For a graph of "Embedded Cost of Long-Term Debt" see graph D. in the
Appendix to this report.
Consolidated short-term debt decreased $84.3increased $35.1 million during 1994.1995. 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, and NFR, is engaged in certain natural gas and
crude oil price swap
agreements and in the gas futures market as a means of
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued) hedging a portion of the market risk associated with
fluctuations in the market price of natural gas and crude oil. These price swap
agreements are not held for trading purposes. During 1995, Seneca utilized
natural gas and crude oil swap agreements with notional amounts of 16.3
equivalent Bcf and 711,000 equivalent bbl, respectively. This activity resulted
in net revenues of approximately $7.0 million.
At September 30, 1995, Seneca had natural gas swap agreements
outstanding with a notional amount of approximately 23.8 equivalent Bcf at
prices ranging from $1.70 per Mcf to $2.16 per Mcf. Seneca also had crude oil
swap agreements outstanding at September 30, 1995 with a notional amount of
1,780,000 equivalent bbl at prices ranging from $17.40 per bbl to $19.00 per
bbl. In addition, the Company has SEC authority to enter into certain interest
rate swap agreements. For further discussion, see disclosure in Note F -
Financial Instruments under "Financialthe heading "Derivative Financial Instruments" in
Note A - SummaryItem 8 of Significant
Accounting Policies.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, none ofneither this litigation nor
these other regulatory matters are expected to materially change the Company's
present liquidity position.
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 long-term debt, at September 30, 1994, the Company would have been
permitted to issue up to a maximum of $434.5 million in additional long-term
unsecured indebtedness, subject to maturity and long-term interest rates. In
addition, at September 30, 1994, the Company had regulatory authorizations and
unused short-term credit lines that would have permitted it to borrow an
additional $287.5 million of short-term debt.
For a graph of "Capitalization Ratios" see graph E. in the Appendix to this
report.
RATE MATTERSRate 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 or 8.9%,
with a
requested return on equity of 12.85%. New rates are expected to become
effective in August orIn September 1995. On November 17, 1994, Distribution
Corporation presented the PSC staff with a preliminary proposal for a multi-year
settlement.
In August 1993, Distribution Corporation filed in its New York jurisdiction
a request for an annual rate increase of $55.4 million, or 8.5%, with a return
on equity of 12.16%. Included in the requested rate increase was an initial
amount of $24.9 million for the recovery of transition costs arising from the
FERC's Order 636, which represented 3.8% of the total 8.5% requested increase.
On July 19, 1994,1995, the PSC issued an order
authorizing a base rate increase of $11.1$14.2 million or 1.7%, with a return on equity of
10.7%10.4%. In addition, the
PSC authorized recovery of transition costs arising from the FERC's Order 636
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
of up to $11 million annually from sales customers through the monthly Gas
Adjustment Clause (GAC). Distribution Corporation will defer, for recovery in
future periods, any amounts that may exceed the $11 million annual amount. NewThe new rates became effective July 24, 1994.
The recoveryas of transition costs from transportation customers in New York
remains unresolved. The PSC has postponed its decision on transportation
customers' allocable share of transition costs pending further consideration of
the issue in a generic restructuring case (the Generic Case) which began in
October 1993. The PSC staff's position in the Generic Case is that
transportation customers should be assigned a per-unit charge that is equal to
50% of the per-unit charge being collected from sales customers for gas supply
realignment (GSR) costs and stranded costs. The PSC has authorized Distribution
Corporation's continued deferral of transition costs relating to transportation
customers until resolution in the Generic Case. At September 30, 1994, deferred
transition costs related to transportation customers amounted to approximately
$2 million.
In July 1993, in connection with a previously approved two-year settlement,20, 1995.
Pennsylvania Jurisdiction
On March 15, 1995, Distribution Corporation received PSC approvalfiled in its Pennsylvania
jurisdiction a request for the second year of the
settlement. The approval was for aan annual rate increase of $13.3$22.0 million or 2.1%,
forwith a
return on equity of 13.25%. In September 1995, the 12-month period ended July 31, 1994.
ThisPennsylvania Public Utility
Commission (PaPUC) approved a settlement authorizing a base rate increase went into effectof
$6.0 million with no specified rate of return on July 23, 1993.
Pennsylvania Jurisdictionequity. 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$16.0 million or 6.8%, 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 or 2.0 %, with a return on equity of 11.0% and without a WNC. New rates are scheduled to become effective as of December 7, 1994.
In March 1993, Distribution Corporation filed with the PaPUC for an annual
rate increase in its Pennsylvania jurisdiction of $33.4 million, or 16.2%, with
a return on equity of 12.4%. Included in the requested rate increase was an
initial amount of $8.2 million for the recovery of transition costs arising from
the FERC's Order 636. On December 1, 1993, an order was issued by the PaPUC
authorizing an annual rate increase of $11.4 million, or 4.9%, exclusive of
transition costs. The
new rates became effective as of December 1, 1993.
The PaPUC's December 1, 1993 order also addressed certain issues concerning
recovery of GSR costs and stranded costs resulting from the implementation of
the FERC's Order 636. Under this order, Distribution Corporation began
collecting, effective December 1, 1993, GSR and stranded costs from its
customers through a separate surcharge. Distribution Corporation is allowed to
update this surcharge on a quarterly basis. Distribution Corporation is
recovering under-recovered purchased gas transition costs from its Pennsylvania
sales customers through its gas cost recovery rates.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)7, 1994.
General rate increases in both the New York and Pennsylvania
jurisdictions do not reflect the recovery of purchased gas costs. Such costs are
recovered through operation of the purchased gas adjustment clauses.
State Regulatory Environment
The seeds of changeChanges 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 it is anticipated that, similar to what was done in the pipeline sector of the
natural gas industry, regulators will requireare requiring utilities to unbundle their
services. The anticipated result is that utility
service will divide into "core" markets consistingDetails of the typical residential
and commercial customers, as well as customers taking firm transportation
service and the "non-core" markets consisting of competitive commercial and
industrial markets. It is anticipated that non-core services will be lightly
regulated and, with respect to core customers, regulatorsthese recent developments are expected to focus
on increased utility efficiency.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
has
proposed several customer service performance incentives in its New York rate
case filed in October 1994. If these incentives are accepted,In its September 1995 order concerning the mechanisms
would allowOctober
1994 rate filing, the PSC adopted incentive mechanisms that will allow it to
administer financial penalties or rewards determined by the utility'sDistribution Corporation's ability to
meet or exceedmaintain required performance levels. The
proposed 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 ones,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. ItIn 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
addressing key issuesadopting 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 unbundling, rate design and the extent of state
regulation. Implementation will likely be achieved by each utility on a case-by-case basis.published gas cost index.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Pennsylvania
Settlement Guidelines. This proceeding is intended to develop orders
addressing specific rules of procedure to accomplish settlement of complex
proceedings, including rate cases.
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 is working closely withhas expressed its support for,
and participated in, the state regulatory
commissions to resolvedrafting of many of the complexitiesproposals. However,
Distribution Corporation cannot determine the outcome of industry restructuring.these proceedings at
this time.
Pipeline and Storage
For a discussion of Supply Corporation's gathering rates, refer to Note B -
Regulatory Matters.Matters in Item 8 of this report.
On October 31, 1994, Supply Corporation filed for an annual rate
increase of $21$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 rate case was
filed as a result of the FERC's order issued on October 28, 1994, rejectingsettlement in principle will increase Supply Corporation's
rate case filedrevenues by approximately $6.4 million annually from current levels, with a
return on September 30, 1994.equity of 11.3%. The FERC rejected
the September 30, 1994 filing because it disagreed with the proposed method of
rolling-in rates for the storage service previously offered byformer Penn-York (Penn-York wasEnergy Corporation (Penn-York)
services, which were merged into Supply Corporation effective July 1, 1994).
On December 30, 1993,1994, will
be rolled-in for ratemaking purposes. Approximately two-thirds of the FERC issued an order approving, with slight
modificationformer
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 Settlement, whichterminations 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 October 15, 1993,
respecting two Supply Corporation rate proceedings. As modified, the Settlement
provided forNovember 6, 1995.
Approval is expected in early calendar year 1996 and rates that produced annual revenues of approximately $125 million
between Julyare expected to
become effective retroactive to June 1, 1992, and July 31, 1993. Rates for the period beginning August
1, 1993, reflect reduced costs after restructuring plus certain settlement
concessions, and will produce revenues of approximately $121 million annually.
As a result of the Settlement, Supply Corporation refunded to its customers
$13.6 million, including interest, during the second quarter of 1994.
OTHER MATTERS1995.
Other Matters
Environmental Matters.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.
Distribution Corporation has been identified by the Environmental
Protection Agency or the New York State Department of Environmental Conservation
(DEC) as one of a number of companies that are considered to be potentially
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
responsible parties (PRPs) with respect to several waste disposal sites in New
York that were operated by unrelated third parties. These 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 be dependent on
such factors as the remediation plan selected, the extent of site contamination,
the number of additional PRPs at each site and the portion attributed, if any,
to Distribution Corporation. Distribution Corporation's estimated share of the
clean-up costs has been accrued for four of these sites.
One of these four sites was formerly used for a manufactured gas plant.
Distribution Corporation is currently involved in litigation regarding this
site. The current owner of the site has submitted a claim against Distribution
Corporation for contribution of a share of approximately $1.6 million of
removal/remediation costs that have been incurred. It is anticipated that
future remedial costs will be incurred and on the basis of a Record of Decision
issued by the DEC, as amended on September 19, 1994, the estimated future
remedial costs for the site are approximately $5.7 million. Management believes
that the ultimate outcome of these matters will not have a material impact on
the financial condition, results of operations or cash flows of the Company.
Distribution Corporation has incurred clean-up costs at two additional
sites in New York and one site in Pennsylvania related to former manufactured
gas plant sites. Supply Corporation is involved in a remediation program of
certain of its measuring and regulating stations in Pennsylvania. Estimated
clean-up costs have been accrued for 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. The CompanyDistribution Corporation has
estimated that clean-up costs related to the above notedseveral former manufactured gas plant
sites and several other waste disposal sites are in the range of $6.7$8.1 million to
$10.1$9.5 million. At September 30, 1994, the Company1995, Distribution Corporation has recorded the
minimum liability of $6.7$8.1 million. The Company is currently not aware of any
material additional exposure to environmental liabilities. However, adverse
changes in environmental regulations or other factors could impact the Company.
In New York, Distribution Corporation has received approval from the PSC to
defer and amortize both former manufactured gas and non-manufactured gasis recovering 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 and Supply Corporation expectexpects to recover such costs in rates, as the PaPUC
and the FERC, respectively, havehas allowed recovery of other environmental clean-up costs in rate cases. Accordingly,For
further discussion, see disclosure in Note H - Commitments and Contingencies
under the Consolidated Balance Sheets at September 30, 1994, include related regulatory
assetsheading "Environmental Matters" in Item 8 of this report.
Accounting for Stock Based Compensation
In October 1995, the amountFinancial Accounting Standards Board issued SFAS 123,
"Accounting for Stock Based Compensation," which establishes a fair value based
method of approximately $7.3 million, $.6 millionaccounting for employee stock options or similar equity instruments
and encourages all companies to adopt that method of which relates
to costs that have already been incurred.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.Inflation
Although the rate of inflation has been relatively low over the past few years,
and thus has benefited both the Company and its
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Concluded) 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 DATAFinancial Statements and Supplementary Data
Index to Financial Statements
- -----------------------------
Page
----
Financial Statements:
Report of Independent Accountants 5330
Consolidated Statements of Income and Earnings Reinvested
in the Business, three years ended September 30, 1994 541995 31
Consolidated Balance Sheets at September 30, 1995 and 1994 and 1993 55 - 5632-33
Consolidated Statement of Cash Flows, three years ended
September 30, 1994 571995 34
Notes to Consolidated Financial Statements 58 - 8835-58
Financial Statement Schedules:
For the three years ended September 30, 1994
V -Property, Plant and Equipment 89 and 91
VI -Accumulated Depreciation, Depletion
and Amortization of Property, Plant
and Equipment 90 - 91
VIII-Valuation1995
II-Valuation and Qualifying Accounts and Reserves 92
IX -Short-Term Borrowings 93
X -Supplementary Income Statement Information 9459
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 IJ - "QuarterlyQuarterly Financial Data
(unaudited)" and Note KL - "SupplementarySupplementary Information Forfor Oil and Gas Producing
Activities," appears on page 82 and pages 84 to 88, respectively, ofunder this report,Item, and reference is made thereto.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)Report of Management
- --------------------
Management is responsible for the preparation and integrity of the Company's
financial statements. The financial statements have been prepared in accordance
with generally accepted accounting principles consistently applied, and
necessarily include some amounts that are based on management's best estimates
and judgment.
The Company maintains a system of internal accounting and
administrative controls and an ongoing program of internal audits that
management believes provide reasonable assurance that assets are safeguarded and
that transactions are properly recorded and executed in accordance with
management's authorization. The Company's financial statements have been
examined by our independent accountants, Price Waterhouse LLP, which also
conducts a review of internal controls to the extent required by generally
accepted auditing standards.
The Audit Committee of the Board of Directors, composed solely of
outside directors, meets with management, internal auditors and Price Waterhouse
LLP to review planned audit scope and results and to discuss other matters
affecting internal accounting controls and financial reporting. The independent
accountants have direct access to the Audit Committee and periodically meet with
it without management representatives present.
Report of Independent Accountants
To the Board of Directors
and Shareholders of
National Fuel Gas Company
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of
National Fuel Gas Company and its subsidiaries at September 30, 19941995 and 1993,1994,
and the results of their operations and their cash flows for each of the three
years in the period ended September 30, 1994,1995, 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 FG 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 28, 199427, 1995
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
Year Ended September 30
1994 1993 1992
(Thousands of Dollars)
INCOME
Operating Revenues $1,141,324 $1,020,382 $920,450
Operating Expenses
Purchased Gas 497,687 409,005 363,690
Operation Expense 260,411 258,918 240,645
Maintenance 30,979 24,312 22,439
Property, Franchise and Other Taxes 103,788 95,393 89,158
Depreciation, Depletion and Amortization 74,764 69,425 55,726
Income Taxes - Net 47,792 41,046 35,231
1,015,421 898,099 806,889
Operating Income 125,903 122,283 113,561
Other Income 3,656 4,833 5,790
Income Before Interest Charges 129,559 127,116 119,351
Interest Charges
Interest on Long-Term Debt 36,699 38,507 39,949
Other Interest 10,425 13,392 19,092
47,124 51,899 59,041
Income Before Cumulative Effect 82,435 75,217 60,310
Cumulative Effect of Changes in
Accounting 3,237 - -
Net Income Available for Common Stock 85,672 75,217 60,310
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year 335,907 314,334 301,066
421,579 389,551 361,376
Dividends on Common Stock 57,725 53,644 47,042
Balance at End of Year $ 363,854 $ 335,907 $314,334
Earnings Per Common Share
Income Before Cumulative Effect $2.23 $2.15 $1.94
Cumulative Effect of Changes in
Accounting .09 - -
Net Income Available for Common Stock $2.32 $2.15 $1.94
Weighted Average Common Shares Outstanding 37,046,249 34,938,722 31,152,635
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
Year Ended September 30 (Thousands of Dollars) 1995 1994 1993
---- ---- ----
Income
Operating Revenues $ 975,496 $1,141,324 $1,020,382
---------- ---------- ----------
Operating Expenses
Purchased Gas 351,094 497,687 409,005
Operation Expense 266,786 260,411 258,918
Maintenance 25,719 30,979 24,312
Property, Franchise and Other Taxes 91,837 103,788 95,393
Depreciation, Depletion and Amortization 71,782 74,764 69,425
Income Taxes - Net 43,879 47,792 41,046
---------- ---------- ----------
851,097 1,015,421 898,099
---------- ---------- ----------
Operating Income 124,399 125,903 122,283
Other Income 5,378 3,656 4,833
---------- ---------- ----------
Income Before Interest Charges 129,777 129,559 127,116
---------- ---------- ----------
Interest Charges
Interest on Long-Term Debt 40,896 36,699 38,507
Other Interest 12,987 10,425 13,392
---------- ---------- ----------
53,883 47,124 51,899
---------- ---------- ----------
Income Before Cumulative Effect 75,894 82,435 75,217
Cumulative Effect of Changes in
Accounting - 3,237 -
---------- ---------- ----------
Net Income Available for Common Stock 75,894 85,672 75,217
Earnings Reinvested in the Business
Balance at Beginning of Year 363,854 335,907 314,334
---------- ---------- ----------
439,748 421,579 389,551
Dividends on Common Stock 59,625 57,725 53,644
---------- ---------- ----------
Balance at End of Year $ 380,123 $ 363,854 $ 335,907
========== ========== ==========
Earnings Per Common Share
Income Before Cumulative Effect $2.03 $2.23 $2.15
Cumulative Effect of Changes in
Accounting - .09 -
---------- ---------- ----------
Net Income Available for Common Stock $2.03 $2.32 $2.15
========== ========== ==========
Weighted Average Common Shares Outstanding 37,396,875 37,046,249 34,938,722
========== ========== ==========
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
National Fuel Gas Company
Consolidated Balance Sheets
At September 30
1994 1993
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment $2,166,256 $2,039,436
Less - Accumulated Depreciation, Depletion
and Amortization 623,517 561,433
1,542,739 1,478,003
Current Assets
Cash and Temporary Cash Investments 29,016 13,595
Receivables - Net 95,993 86,957
Unbilled Utility Revenue 17,311 27,210
Gas Stored Underground 34,711 22,120
Materials and Supplies - at average cost 23,796 20,848
Unrecovered Purchased Gas Costs - 20,772
Prepayments 20,111 17,094
220,938 208,596
Other Assets
Recoverable Future Taxes 99,742 -
Unamortized Debt Expense 28,396 28,735
Other Regulatory Assets 47,737 43,644
Deferred Charges 15,796 21,255
Other 26,309 21,307
217,980 114,941
$1,981,657 $1,801,540
National Fuel Gas Company
Consolidated Balance Sheets
At September 30 (Thousands of Dollars) 1995 1994
---- ----
Assets
Property, Plant and Equipment $2,322,335 $2,169,067
Less - Accumulated Depreciation,
Depletion and Amortization 673,153 623,517
---------- ----------
1,649,182 1,545,550
---------- ----------
Current Assets
Cash and Temporary Cash Investments 12,757 29,016
Receivables - Net 75,933 95,494
Unbilled Utility Revenue 20,838 17,311
Gas Stored Underground 25,589 31,900
Materials and Supplies - at average cost 24,374 23,796
Prepayments 29,753 20,609
---------- ----------
189,244 218,126
---------- ----------
Other Assets
Recoverable Future Taxes 94,053 99,742
Unamortized Debt Expense 26,976 28,396
Other Regulatory Assets 37,040 47,737
Deferred Charges 8,653 15,797
Other 33,154 26,309
---------- ----------
199,876 217,981
---------- ----------
$2,038,302 $1,981,657
========== ==========
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
National Fuel Gas Company
Consolidated Balance Sheets
At September 30
1994 1993
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 100,000,000 Shares; Issued and
Outstanding - 37,278,409 Shares and 36,661,008
Shares, Respectively $ 37,278 $ 36,661
Paid In Capital 379,156 363,677
Earnings Reinvested in the Business 363,854 335,907
Total Common Stock Equity 780,288 736,245
Long-Term Debt, Net of Current Portion 462,500 478,417
Total Capitalization 1,242,788 1,214,662
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 112,500 196,800
Current Portion of Long-Term Debt 96,000 -
Accounts Payable 66,667 42,893
Amounts Payable to Customers 38,714 40,776
Other Accruals and Current Liabilities 61,368 69,523
375,249 349,992
Deferred Credits
Accumulated Deferred Income Taxes 273,560 188,793
Taxes Refundable to Customers 31,688 -
Unamortized Investment Tax Credit 14,057 14,743
Other Deferred Credits 44,315 33,350
363,620 236,886
Commitments and Contingencies - -
$1,981,657 $1,801,540
National Fuel Gas Company
Consolidated Balance Sheets
At September 30 (Thousands of Dollars) 1995 1994
---- ----
Capitalization and Liabilities
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 100,000,000 Shares; Issued and
Outstanding - 37,434,363 Shares and 37,278,409
Shares, Respectively $ 37,434 $ 37,278
Paid In Capital 383,031 379,156
Earnings Reinvested in the Business 380,123 363,854
---------- ----------
Total Common Stock Equity 800,588 780,288
Long-Term Debt, Net of Current Portion 474,000 462,500
---------- ----------
Total Capitalization 1,274,588 1,242,788
---------- ----------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 147,600 112,500
Current Portion of Long-Term Debt 88,500 96,000
Accounts Payable 53,842 68,293
Amounts Payable to Customers 51,001 38,714
Other Accruals and Current Liabilities 52,118 59,742
---------- ----------
393,061 375,249
---------- ----------
Deferred Credits
Accumulated Deferred Income Taxes 288,763 273,560
Taxes Refundable to Customers 23,080 31,688
Unamortized Investment Tax Credit 13,380 14,057
Other Deferred Credits 45,430 44,315
---------- ----------
370,653 363,620
---------- ----------
Commitments and Contingencies - -
---------- ----------
$2,038,302 $1,981,657
========== ==========
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
National Fuel Gas Company
Consolidated Statement of Cash Flows
Year Ended September 30 1994 1993 1992
(Thousands of Dollars) 1995 1994 1993
---- ---- ----
OPERATING ACTIVITIESOperating Activities
Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217 $ 60,310
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Effect of Noncash Adjustments:
Cumulative Effect of Changes in Accounting - (3,237) - -
Depreciation, Depletion and Amortization 71,782 74,764 69,425 55,726
Deferred Income Taxes 8,452 4,853 16,919
14,125
Other 275 5,780 5,574 2,997
167,832 167,135 133,158
Change in:
Receivables and Unbilled Utility Revenue 16,034 863 (21,531) (12,074)
Gas Stored Underground and Materials and Supplies 5,733 (15,539) 7,156 (5,221)
Unrecovered Purchased Gas Costs - 20,772 (7,739)
(7,703)
Prepayments (9,144) (3,017) (1,489)
2,862
Accounts Payable (14,451) 23,774 (2,579) 4,349
Amounts Payable to Customers 12,287 (2,062) (18,808) (6,728)
Other Accruals and Current Liabilities (1,305) 3,072 15,249 15,704
Other Assets and Liabilities - Net 7,903 3,534 (13,691)
(31,359)-------- -------- --------
Net Cash Provided by Operating Activities 173,460 199,229 123,703
92,988
INVESTING ACTIVITIES-------- -------- --------
Investing Activities
Capital Expenditures (182,826) (135,084) (131,926)
(157,856)
Other 10,646 3,586 225
(2,052)-------- -------- --------
Net Cash Used in Investing Activities (172,180) (131,498) (131,701)
(159,908)
FINANCING ACTIVITIES-------- -------- --------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper 35,100 (84,300) (30,200) 20,500
Proceeds from Issuance of Long-Term Debt 100,000 100,000 129,000 251,000
Reduction of Long-Term Debt (96,000) (19,917) (180,083) (176,729)
Proceeds from Issuance of Common Stock 2,555 9,064 78,822 73,728
Dividends Paid on Common Stock (59,194) (57,157) (52,224)
(45,634)-------- -------- --------
Net Cash Provided by (Used In)Used in Financing Activities (17,539) (52,310) (54,685)
122,865-------- -------- --------
Net Increase (Decrease) in Cash and
Temporary Cash Investments (16,259) 15,421 (62,683) 55,945
Cash and Temporary Cash Investments at Beginning of Year 29,016 13,595 76,278
20,333-------- -------- --------
Cash and Temporary Cash Investments at End of Year $ 12,757 $ 29,016 $ 13,595
$ 76,278======== ======== ========
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)National Fuel Gas Company
Notes to Consolidated Financial Statements
Note A - Summary of Significant Accounting Policies
Principles of Consolidation.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. Reclassification.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.Regulation
Two of the Company's principal subsidiaries, National Fuel Gas
Distribution Corporation (Distribution Corporation) and National Fuel Gas Supply
Corporation, (Supply Corporation) are subject to regulation by state and federal authorities having
jurisdiction. The Company accounts for these
regulated operations in accordance with Statement of Financial Accounting
Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of
Regulation." This statement sets forth the application ofDistribution Corporation and Supply Corporation have accounting
policies which conform to generally accepted accounting principles, for those companies whose ratesas applied
to regulated enterprises, and are established by or are
subject to approval by an independent third-party regulator. Under SFAS 71,
regulated companies defer costs as assets on the balance sheet (regulatory
assets) when these costs have been or are expected to be allowed in the
ratesetting process in a period different from the period in which the costs
would be charged to expense by an unregulated company. These deferred
regulatory assets are then flowed through the income statement in the period in
which the same amounts are recovered in revenues through rates.
Costs deferred in accordance with SFAS 71 include "Recoverable Future
Taxes," "Unamortized Debt Expense"the accounting requirements
and "Other Regulatory Assets." Referratemaking practices of the regulatory authorities. Reference is made to
the
separate Income Taxes and Unamortized Debt Expense sections of this Note B for further discussion. Otherdiscussion of regulatory assets are shown below:
At September 30 (in thousands) 1994 1993
Pension and Post-Retirement
Benefit Costs (Note F) $17,199 $ 8,125
Order 636 Transition Costs*
(Note B) 8,417 200
Deferred Contract Reformation
Costs (Note B) 7,736 24,862
Environmental Clean-up (Note G) 7,310 4,873
All Other 7,075 5,584
$47,737 $43,644
* Exclusive of amounts being collected through gas costs. Such amounts are
included in unrecovered purchased gas costs.
Revenues.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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Unrecovered Purchased Gas Costs and Refunds.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.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.purposes as well as gas volumes
maintained for system balancing purposes, including those needed for no-notice
transportation service.
Maintenance and repairs of property and replacements of minor items of
property are charged directly to maintenance expense. The original cost of the
regulated subsidiaries' property, plant and equipment retired, and the cost of
removal less salvage, are charged to accumulated depreciation.
Oil and gas exploration and development costs are capitalized under the
full-cost method of accounting as prescribed by the Securities and Exchange
Commission (SEC). All costs directly associated with property acquisition,
exploration and development activities are capitalized, with the principal
limitation that such capitalized amounts not exceed the present value of
estimated future net revenues from the production of proved gas and oil reserves
plus the lower of cost or market of unevaluated properties, net of related
income tax effect. The present value of estimated future net revenues was
computed based on end-of-year prices adjusted for contracted price changes. At
September 30, 1995, Seneca did not experience an impairment of its oil and gas
assets under the SEC full cost accounting rules. There are certain factors,
including price declines, which could cause an impairment of Seneca's oil and
gas assets.
Depreciation, Depletion and Amortization.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 $75,686,000$73.1 million in 1995, $75.7 million
in 1994
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
$70,629,000and $70.6 million in 1993, and $56,506,000 in 1992, and were equivalent to 3.5% in 1995, 3.9% in
1994 and 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and equipment for
those years.
Gas Stored Underground - Current.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 1994,1995, 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 $19,300,000$19.2 million at September 30,
1994.1995.
Unamortized Debt Expense.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.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 SFASStatement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109). The adoption of SFAS 109, which
changed the Company's method of accounting for income taxes from the deferred method to an asset and liability
approach. Previously, deferred taxes were provided for the tax effects of
timing differences between financial reporting purposes and tax reporting
purposes except where not permitted by regulatory authorities. The asset and
liability approach requires the recognition of deferred tax liabilities and
assets for the expected future tax consequences attributable to temporary
differences between the carrying amounts of assets and liabilities and their
tax bases. In addition, such deferred tax assets and liabilities will be
adjusted for the effects of enacted changes in tax laws and rates.taxes. The cumulative effect of
this change increased net income for the fiscal year ended September 30, 1994 by
$3,826,000$3.8 million as a result of the reduction in deferred income taxes associated
with the Company's nonregulated operations.
The effect on the recorded deferred income taxes
associated with rate-regulated activities was to reclassify a portion to a
regulatory liability since such amounts are expected to be refundable to
customers under regulatory procedures. This liability amounted to $31,688,000
at September 30, 1994.
In addition, under SFAS 109, the Company is required to recognize additional
deferred taxes for timing differences on which deferred tax treatment was not
permitted by regulatory authorities. The recognition of these deferred tax
balances had no effect on earnings due to the recording of corresponding
regulatory assets representing future amounts collectible from customers in the
ratemaking process. 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 amounted to $99,742,000 at September 30, 1994.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Financial Instruments. In October 1994, the Financial Accounting Standards
Board (FASB) issued SFAS 119, "Disclosure about Derivative Financial Instruments
The Company, in its Exploration and Fair Value of Financial Instruments" (SFAS 119). This
statement requires disclosures about amounts, nature, and terms of derivative
financial instruments. It also requires that a distinction be made between
financial instruments held or issued for trading purposes and those held or
issued for purposes other than trading. The Company's disclosure is in
accordance with the provisions of SFAS 119.
Seneca Resources Corporation (Seneca) has entered into certainProduction 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. These agreements are
not held for trading purposes. The price swap agreements call for Seneca to
receive monthly payments from (or make payments to) other parties based upon
the differential between a fixed and a variable price as specified by the
agreement. At September 30, 1994, Seneca had natural gas price swap agreements
which run through December 1996 and have an aggregate notional amount of
approximately 16.2 billion cubic feet (Bcf) of natural gas equivalent. In
October 1994, Seneca entered into natural gas price swap agreements for an
additional aggregate notional amount of approximately 3.6 Bcf of natural gas
equivalent. These agreements cover the period from March 1995 through February
1996. Seneca also had crude oil price swap agreements at September 30, 1994,
which run through September 1997 and have an aggregate notional amount of
773,000 barrels of crude oil equivalent. 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, whichparties. Reference is when the
underlying hedged commodity transaction occurs.
National Fuel Resources, Inc. (NFR) participates in the natural gas futures
marketmade to lock in natural gas prices to decrease volatility related to
fluctuations in market prices. Futures are not heldNote F - Financial Instruments, for trading purposes. At
September 30, 1994, NFR had short positions on futures amounting to
approximately 1.1 Bcffurther
discussion of natural gas. It also had long positions on futures
amounting to approximately .1 Bcf of natural gas. Gains or losses resulting
from changes in the market value of these transactions are deferred until the
hedged commodity transaction occurs, at which point they are reflected in
operating revenues on the Consolidated Statement of Income.
Seneca and NFR are at risk in the event of nonperformance by counterparties
on natural gas and crude oil price swap agreements and natural gas futures,
respectively, but Seneca and NFR do not anticipate nonperformance by any of
these counterparties.
The Company currently has authorization from the SEC to enter into interest
rate swap agreements and certain other derivative instruments up to a notional
amount of $350,000,000. Currently, no such agreements are outstanding.financial instruments.
Consolidated Statement of Cash Flows.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 1992 was $46,183,000,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
$48,282,000 and $58,530,000,$48.3 million, respectively. Net income taxes
paid in 1995, 1994 and 1993 were $34.6 million, $37.6 million and 1992 were $37,573,000, $19,872,000 and $15,282,000,$19.9 million,
respectively.
In December 1993, the Company entered into a non-cash investing
activity whereby it issued 108,396 shares of Company common stock to Empire Exploration,
Inc. (Empire), which in turn exchanged those shares for $3,184,000$3.2 million of
natural gas production assets, $167,000 of other current assets and $280,000 of cash.
On July 1, 1994, Empire was merged into Seneca.assets.
Earnings Per Common Share.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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)New Accounting Pronouncement
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" (SFAS 121). This statement establishes accounting
standards for the impairment of long-lived assets, certain identifiable
intangibles and goodwill related to those assets to be held and used and for
long-lived assets and certain identifiable intangibles to be disposed of.
Essentially, SFAS 121 requires review of these assets for impairment whenever
events or changes in circumstances indicate that the carrying amount may not be
recoverable. SFAS 121 also requires that a rate-regulated enterprise recognize
an impairment for the amount of costs excluded when a regulator excludes all or
part of a cost from an enterprise's rate base or when regulatory assets are no
longer probable of recovery. The Company has adopted SFAS 121 with no impact on
its results of operations for 1995.
Note B - Regulatory Matters
Regulatory Assets and Liabilities
Distribution Corporation and Supply Corporation have incurred various costs and
received various credits which have been reflected as regulatory assets and
liabilities on the Company's consolidated balance sheets. Accounting for such
costs and credits as regulatory assets and liabilities is in accordance with
SFAS 71, "Accounting for the Effect of Certain Types of Regulation" (SFAS 71).
This statement sets forth the application of generally accepted accounting
principles for those companies whose rates are established by or are subject to
approval by an independent third-party regulator. Under SFAS 71, regulated
companies defer costs and credits on the balance sheet as regulatory assets and
liabilities when it is probable that those costs and credits will be allowed in
the ratesetting process in a period different from the period in which they
would have been reflected in income by an unregulated company. These deferred
regulatory assets and liabilities are then flowed through the income statement
in the period in which the same amounts are reflected in rates. Distribution
Corporation and Supply Corporation have recorded the following regulatory assets
and liabilities:
At September 30 (in thousands) 1995 1994
---- ----
Regulatory Assets:
Recoverable Future Taxes (Note C) $ 94,053 $ 99,742
Unamortized Debt Expense (Note A) 22,035 23,751
Pension and Post-Retirement Benefit Costs (Note G) 18,412 17,199
Order 636 Transition Costs* 12,358 8,417
Environmental Clean-up (Note H) 7,475 7,310
Other (1,205) 14,811
-------- --------
Total Regulatory Assets 153,128 171,230
-------- --------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) 51,001 38,714
Taxes Refundable to Customers (Note C) 23,080 31,688
Other 8,628 9,513
-------- --------
Total Regulatory Liabilities 82,709 79,915
-------- --------
Net Regulatory Position $ 70,419 $ 91,315
======== ========
* Exclusive of amounts being collected through gas costs. Such amounts are
included in unrecovered purchased gas costs or amounts payable to customers.
If for any reason, including deregulation, a change in the method of
regulation, or a change in competitive environment, Distribution Corporation
and/or Supply Corporation ceases to meet the criteria for application of SFAS 71
for all or part of their operations, the regulatory assets and liabilities
related to those portions ceasing to meet such criteria would be eliminated from
the balance sheet and included in income of the period in which the
discontinuance of SFAS 71 occurs. Such amounts would be classified as an
extraordinary item. Distribution Corporation and Supply Corporation are not
currently facing a requirement to discontinue SFAS 71.
Order 636 Transition Costs.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.
AtAs of September 30, 1994,1995, Distribution Corporation's estimate of its
exposure to outstanding transition cost claims is in the range of $4,600,000$7.1 million
to $80,700,000.$71.0 million. The majority of theseestimated maximum exposure is declining as transition
costs relate to gas supply realignment
(GSR) costsare incurred and stranded costs and is exclusive of any potential stranded costs
related to production plant or gathering facilities which pipeline companies,
including Supply Corporation, may file for at a future date, and any potential
GSR costs claimed by an upstream supplier, which are subject to the outcome of
its bankruptcy and FERC proceedings.paid. At September 30, 1994, the Company1995, Distribution Corporation has
recorded the minimum liability and corresponding regulatory asset of $4,600,000.$7.1
million.
Distribution Corporation has authorization from the State of New York Public
Service Commission (PSC) to recover up to $11,000,000 annually ofis currently recovering transition costs from
its sales customers in New York throughand its sales and transportation customers in
Pennsylvania. Recovery of the monthly Gas Adjustment
Clause (GAC). Distribution Corporation will defer, for recovery in future
periods, any amounts that may exceed the $11,000,000 annual amount.
The recoveryallocable portion of transition costs fromrelated to
Distribution Corporation's transportation customers in New York remains unresolved. The PSC has postponed its decision on transportation
customers' allocable share of transition costs pending further considerationis expected to
begin upon the Public Service Commission of the issueState of New York's (PSC)
acceptance of a compliance filing made in a generic restructuring case (the Generic Case) which began in
October 1993. The PSC staff's position inNovember 1995. It is expected that the
Generic Case is that
transportation customers shouldcompliance filing will be assigned a per-unit charge that is equal to
50%accepted by the Spring of the per-unit charge being collected from sales customers for GSR and
stranded costs. The PSC has authorized Distribution Corporation's continued
deferral of transition costs relating to transportation customers until
resolution in the Generic Case. At September 30, 1994, deferred transition
costs related to transportation customers amounted to $2,031,000.
In its Pennsylvania jurisdiction, Distribution Corporation is recovering GSR
and stranded costs from its customers through a separate surcharge. At
September 30, 1994, Distribution Corporation had deferred GSR and stranded
costs of $900,000. Distribution Corporation will recover these costs through a
true-up mechanism whereby it is allowed to update its surcharge on a quarterly
basis. Distribution Corporation is recovering under-recovered purchased gas
transition costs from its Pennsylvania sales customers through its gas cost
recovery rates.1996.
Distribution Corporation will continue to actively challenge relevant
FERC filings made by the upstream pipeline companies to ensure the eligibility and
prudency of all transition cost claims. This industrywide issue will
potentially involve years of rate proceedings before the FERC, state
commissions and the courts. Management believes that any transition
costs resulting from the implementation of Order 636 which have been determined
to
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
be both eligible and prudently incurred should be fully recoverable from
the
respective customers of Supply Corporation and Distribution Corporation.customers.
Gathering Rates.Rates
Supply Corporation has approximately $19,000,000$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. Currently, Supply Corporation has a gathering rate in place under an interim
settlement with customers and local producers. In its
restructuring orders, the FERC has directed Supply Corporation to fully unbundle
its gathering rate
effective July 1, 1995. Supply Corporation submitted an offer of settlement
(the Settlement) which if approved would provide for a ten-year transition to
fully unbundle rates beginning July 1, 1995. Comments on the Settlement have
been filed by the parties. Such comments were generally favorable. However,
opposition came largely from offsystem customers claiming that they should not
have any cost responsibility for the production and gathering plant becausecost 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 not necessary to provide service to them. The Settlement currently awaits a
FERC decision. The FERC has, however, also directedexpected early in calendar 1996. If approved, it will permit Supply
Corporation to file
a fully unbundled rate by December 31, 1994, that would become immediately
effective on July 1, 1995. Supply Corporation has requested an extensionrecover its investment in production and gathering plant,
as well as its gathering cost of the December deadline to April 28, 1995, since approval of the Settlement in
the meantime would make further filings unnecessary.
Contract Reformation Issues. As a result of the FERC's Orders 436 and 528
issued in October 1985 and November 1990, respectively, pipeline companies have
made, and have agreed to make, payments to producers in exchange for
reformation of the price and/or take-or-pay provisions of their long-term
wellhead gas supply arrangements, also referred to as contract reformation
costs (CRC). The Company is currently recovering from its customers
substantially all CRC billed to it.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)service.
Note C - Income Taxes
Deferred tax liabilities (assets) were comprised of the following:
At September 30, 1994 (in thousands) Accumulated Deferred
Deferred Income Taxes
Income Taxes Current*
Deferred Tax Liabilities:
Excess of Tax Over Book Depreciation $174,006 $ -
Exploration and Intangible Well
Drilling Costs 78,224 -
Other 64,181 -
Total Deferred Tax Liabilities 316,411 -
Deferred Tax Assets:
Deferred Investment Tax Credits (8,388) -
Overheads Capitalized for Tax Purposes (9,238) -
Provisions for Rate Contingencies and
Refunds - (686)
Unrecovered Purchased Gas Costs - (3,762)
Other (25,225) -
Total Deferred Tax Assets (42,851) (4,448)
Total Net Deferred Income Taxes $273,560 $( 4,448)
* Included on the Consolidated Balance Sheets in "Other Accruals and
Current Liabilities."
The components of federal and state income taxes included in the Consolidated
Statement of Income are as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Expenses:
Current Income Taxes -
Federal $36,630 $21,148 $17,680
State 6,309 2,979 3,426
Deferred Income Taxes 4,853 16,919 14,125
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Operating Expenses:
Current Income Taxes -
Federal $30,522 $36,630 $21,148
State 4,905 6,309 2,979
Deferred Income Taxes 8,452 4,853 16,919
------- ------ ------
43,879 47,792 41,046 35,231
Other Income:
Deferred Investment Tax Credit (672) (682) (693) (706)
Cumulative Effect of Changes in Accounting:
Adoption of SFAS 109 - (3,826) -
Tax Effect of Adoption of SFAS 112 - (425) -
------- ------ ------
Total Income Taxes $43,207 $42,859 $40,353
======= ======= =======
Prior to the adoption of SFAS 109 (3,826) - -
Tax Effectin 1994, deferred income tax expense
resulted from timing differences between the recognition of Adoptionrevenues and
expenses for income tax and financial reporting purposes except where not
permitted by regulatory authorities. The sources of SFAS 112 (425) - -
Total Income Taxes $42,859 $40,353 $34,525these timing differences and
the related income tax effect of each are as follows:
Year Ended September 30 (in thousands) 1993
----
Unrecovered Purchased Gas Costs $11,641
Excess of Tax Over Book Depreciation 6,717
Exploration and Intangible Well Drilling Costs 7,377
Revenue Refunds Payable to Customers (2,994)
Debt Retirement Costs 3,780
Tax Credit Carryforward (2,608)
Miscellaneous (6,994)
-------
Total Deferred Income Taxes $16,919
=======
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Total income taxes as reported differ from the amounts that were
computed by applying the federal income tax rate to income before income taxes.
The following is a reconciliation of this difference:
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217
Total Income Taxes 43,207 42,859 40,353
-------- -------- --------
Income Before Income Taxes $119,101 $128,531 $115,570
======== ======== ========
Income Tax Expense, Computed at
Statutory Rate of 35% in 1995 and 1994
and 34.75% in 1993 $41,685 $ 44,986 $40,161
Increase (Reduction) in Taxes Resulting from:
Current State Income Taxes 3,188 4,101 1,944
Depreciation 2,397 2,174 2,221
Production Tax Credits (899) (1,658) (2,608)
Adoption of SFAS 109 - (3,826) -
Miscellaneous (3,164) (2,918) (1,365)
------- ------- ------
Total Income Taxes $43,207 $42,859 $40,353
======= ======= =======
Significant components of the Company's deferred tax liabilities and
assets were as follows:
At September 30 (in thousands) 1995 1994
------------------------- -------------------------
Accumulated Deferred Accumulated Deferred
Deferred Income Taxes Deferred Income Taxes
Income Taxes Current* Income Taxes Current*
------------ ------------ ------------ ------------
Deferred Tax Liabilities:
Excess of Tax Over Book Depreciation $185,595 $ - $ 174,006 $ -
Exploration and Intangible Well
Drilling Costs 84,380 - 78,224 -
Other 67,831 - 64,181 -
-------- ------- --------- -------
Total Deferred Tax Liabilities 337,806 - 316,411 -
======== ======= ========= =======
Deferred Tax Assets:
Deferred Investment Tax Credits (7,860) - (8,388) -
Overheads Capitalized for Tax Purposes (11,766) - (9,238) -
Unrecovered Purchased Gas Costs - (8,322) - (4,448)
Other (29,417) - (25,225) -
-------- ------- --------- -------
Total Deferred Tax Assets (49,043) (8,322) (42,851) (4,448)
======== ======= ========= =======
Total Net Deferred Income Taxes $288,763 $(8,322) $ 273,560 $(4,448)
======== ======= ========= =======
* Included on the Consolidated Balance Sheets in "Other Accruals and Current
Liabilities."
SFAS 109 requires the recognition of regulatory liabilities
representing the reduction of previously recorded deferred income taxes
associated with rate-regulated activities that are expected to be refundable to
customers. These amounted to $23.1 million and $31.7 million at September 30,
(in thousands)1995 and 1994, 1993 1992
Net Income Available for Common Stock $ 85,672 $ 75,217 $60,310
Total Income Taxes 42,859 40,353 34,525
Income Before Income Taxes $128,531 $115,570 $94,835
Income Tax Expense, Computed at
Statutory Rate of 35% in 1994
and 34.75% in 1993 and 34% in 1992 $ 44,986 $40,161 $32,244
Increase (Reduction) in Taxes Resulting from:
Current State Income Taxes 4,101 1,944 2,261
Depreciation 2,174 2,221 1,893
Production Tax Credits (1,658) (2,608) (520)
Adoption ofrespectively. Also, SFAS 109 (3,826) - -
Miscellaneous (2,918) (1,365) (1,353)
Total Income Taxes $42,859 $40,353 $34,525requires 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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note D - Capitalization
Summary of Changes in Common Stock Equity
Earnings
Paid Reinvested
Common Stock In in the
(in thousands) Shares Amount Capital Business
------ ------ ------- ----------
Balance at September 30, 1992 33,856 $33,856 $284,143 $314,334
Net Income Available for Common Stock 75,217
Dividends Declared on Common Stock
($1.52 Per Share) (53,644)
Common Stock Issued:
Sale of Common Stock 2,500 2,500 71,425
Stock Options and Stock Award Plans 50 50 832
401(k) Plans 115 115 3,423
Customer Stock Purchase Plan 140 140 4,101
Common Stock Issuance Costs (247)
------ ------- -------- --------
Balance at September 30, 1993 36,661 36,661 363,677 335,907
Net Income Available for Common Stock 85,672
Dividends Declared on Common Stock
($1.56 Per Share) (57,725)
Common Stock Issued:
Acquisition of Natural Gas
Production Assets 108 108 3,523
Stock Options and Stock Award Plans 164 164 1,163
401(k) Plans 136 136 4,234
Customer Stock Purchase Plan 209 209 6,559
------ ------- -------- --------
Balance at September 30, 1994 37,278 37,278 379,156 363,854
Net Income Available for Common Stock 75,894
Dividends Declared on Common Stock
($1.60 Per Share) (59,625)
Common Stock Issued:
Stock Options and Stock Award Plans 22 22 377
401(k) Plans 88 88 2,310
Customer Stock Purchase Plan 46 46 1,188
------ ------- --------
Balance at September 30, 1995 37,434 $37,434 $383,031 $380,123*
====== ======= ======== =========
* The availability of consolidated earnings reinvested in the business for
dividends payable in cash is limited under terms of the indentures covering
long-term debt. At September 30, 1995, $305.7 million of accumulated earnings
was free of such limitations.
Common Stock.Stock
The Company issued 2,500,000has various plans which allow shareholders, customers and employees
to purchase shares of Company common stock in each of
May 1993 and September 1992.stock. The shares issued in May 1993 were sold to the
public at a price of $30.50 per share, and the net proceeds to the Company
after underwriting discounts and commissions were $29.57 per share, or
$73,925,000. The shares issued in September 1992 were sold to the public at a
price of $27.625 per share, and the net proceeds to the Company after
underwriting discounts and commissions were $26.715 per share, or $66,787,500.
Through the Company's Dividend Reinvestment and Stock
Purchase Plan (DRP),
holders of shares of the Company's common stock mayallows shareholders to reinvest cash dividends and/or make cash
investments in the Company's common stock of the Company. In 1994 and
1993, open market shares were utilized for issuance under the DRP. In 1992,
65,015 new shares as well as open market shares were issued under the DRP.
Under the Company's section 401(k) plans, the Company issued 136,100 shares,
115,300 shares and 108,700 shares of common stock during 1994, 1993 and 1992,
respectively.stock. The Company's Customer Stock Purchase Plan (CSPP)
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, the shares purchased
under the
CSPPthese plans are either original issue shares purchased directly from the
Company or shares purchased on the open market by an agent.
The Company issued 208,990 shares,
139,986 shares and 156,607 shares of common stock under the CSPP during 1994,
1993 and 1992, respectively.
Effective March 17, 1992, after having received shareholder approval, the
Company amended its Restated Certificate of Incorporation, as amended, to
change the designation of its authorized and issued common stock from shares
having no par value to shares having a par value of $1 per share. Accordingly,
$214,461,000 was transferred from Common Stock to Paid In Capital. This change
eliminated unnecessary additional qualification and licensing fees incurred by
the Company in certain states as a result of having no par value common stock.
This change has no effect on the rights and privileges of Company stockholders.
Stock Options and Stock Award Plans.Plans
The Company's 1993 Award and Option Plan (1993 Plan) provides for the issuance
of incentive stock options, nonqualified stock options, stock appreciation
rights, restricted stock, performance units and performance shares to key
employees. The 1983 Incentive Stock Option Plan (1983 Plan) provided for the
issuance of incentive stock options to key employees, and the 1984 Stock Plan
(1984 Plan) provided for awards of restricted stock, nonqualified stock options
and stock appreciation rights to key employees. Stock options under all three
plans have exercise prices equal to the average market price of Company common
stock on the date of grant, and generally no option is exercisable less than one
year or more than ten years after the date of each grant.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
In 1993, the authorized maximum number of shares of common stock under the
1983 Plan and 1984 Plan was reached, and therefore no further options or
restricted stock have been awarded under these plans. Under the 1993 Plan, the
maximum number of shares of common stock available for option grants and stock
awards is 1,600,000 shares. Stock options
outstanding do not have a materially dilutive effect on earnings per common
share.
Transactions involving option shares for all three plans are summarized
as follows:
Number of
Shares Subject Option Price
to Option Per Share
Outstanding at
September 30, 1991 516,260 $13.19 to $23.81
Granted in 1992 206,500 $23.88
Exercised in 1992* (100,664) $13.19 to $23.81
Forfeited in 1992 (4,000) $23.81
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
Shares Exercisable at
September 30, 1994 895,337
Shares Reserved for
Future Grant at
September 30, 1994 1,159,072
*In connection with exercising these options, 18,088, 36,797 and 35,532
Number of
Shares Subject Option Price
to Option Per Share
- ----------------------------------------------------------------------
Outstanding at
September 30, 1992 618,096 $15.59 to $23.88
Granted in 1993 416,500 $25.19 and $31.50
Exercised in 1993* (78,750) $15.59 to $23.88
- ----------------------------------------------------------------------
Outstanding at
September 30, 1993 955,846 $15.59 to $31.50
Granted in 1994 272,000 $31.63
Exercised in 1994* (60,509) $18.00 to $25.19
- ----------------------------------------------------------------------
Outstanding at
September 30, 1994 1,167,337 $15.59 to $31.63
Granted in 1995 362,100 $27.94
Forfeited in 1995 (11,532) $25.19 to $31.63
Exercised in 1995* (17,615) $15.59 to $23.88
- ----------------------------------------------------------------------
Outstanding at
September 30, 1995 1,500,290 $18.00 to $31.63
======================================================================
Shares Exercisable at
September 30, 1995 1,138,190
Shares Reserved for
Future Grant at
September 30, 1995 795,148
- -------------------------------------------------------------------------
* In connection with exercising these options, 3,192, 18,088 and 36,797 shares
were surrendered and/or canceled during 1995, 1994 and 1993, respectively.
On October 4, 1995, an additional 140,000 stock option shares were
surrendered and/or cancelled during 1994, 1993 and 1992, respectively.
Asgranted at an option price per share of September 30, 1994, a total of 286,308$28.56.
During 1995, 8,000 shares of restricted stock had
beenwere 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
137,494145,494 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
approximately one-fourth of such shares on
each January 2, 1999 through 2002. Restrictions on 8,000 shares will lapse
respecting approximately one-fourth of such shares on each January 2, 2000 through 2003.
Restrictions on 113,494
shares will lapse respecting approximately one-sixth of such shares on each
January 2, 1996 through 2001. Restrictions on 8,000 shares will lapse respecting approximately 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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)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.Stock
As of September 30, 1994,1995, there were 3,200,000 shares of $25 par value
Cumulative Preferred Stock authorized but unissued.
Summary of Changes in Common Stock Equity
Earnings
Paid Reinvested
Common Stock In in the
(in thousands) Shares Amount Capital Business
Balance at September 30, 1991 30,926 $241,043 $301,066
Net Income Available for Common Stock 60,310
Dividends Declared on Common Stock
($1.48 Per Share) (47,042)
Transfer from Common Stock to
Paid In Capital (214,461) $214,461
Common Stock Issued:
Sale of Common Stock 2,500 2,500 64,288
DRP, Incentive Compensation Plans
and 401(k) Plans 273 3,314 3,065
CSPP 157 1,460 2,614
Common Stock Issuance Costs (285)
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
Incentive Compensation Plans
and 401(k) Plans 165 165 4,255
CSPP 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
Incentive Compensation Plans
and 401(k) Plans 300 300 5,397
CSPP 209 209 6,559
Balance at September 30, 1994 37,278 $ 37,278 $379,156 $363,854*
* 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, 1994, $289,470,000 of accumulated earnings
was free of such limitations. However, substantially all of this amount has
been reinvested in the business.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Long-Term Debt.Debt
The outstanding long-term debt is as follows:
At September 30 (in thousands) 1994 1993
Debentures:
7-3/4% due February 2004 $125,000 $125,000
9-1/2% due July 2019 - 19,917
Medium-Term Notes:
6.07% due May 1995 55,000 55,000
6.10% due May 1995 20,000 20,000
6.10% due June 1995 1,000 1,000
9.32% due June 1995 20,000 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
7.25% due July 1999 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 -
558,500 478,417
Less Current Portion 96,000 -
$462,500 $478,417
At September 30 (in thousands) 1995 1994
---- ----
Debentures:
7-3/4% due February 2004 $125,000 $125,000
Medium-Term Notes:
6.07% due May 1995 - 55,000
6.10% due May 1995 - 20,000
6.10% due June 1995 - 1,000
9.32% due June 1995 - 20,000
8.875% due December 1995 20,000 20,000
8.90% due December 1995 38,500 38,500
4.53% due September 1996 30,000 30,000
6.42% due November 1997 50,000 50,000
6.08% due July 1998 50,000 -
7.25% due July 1999 50,000 50,000
6.60% due February 2000 50,000 50,000
7.395% due March 2023 49,000 49,000
8.48% due July 2024* 50,000 50,000
7.375% due June 2025 50,000 -
-------- --------
562,500 558,500
Less Current Portion 88,500 96,000
-------- --------
$474,000 $462,500
======== ========
* Callable beginning July 1999.
The aggregate principal amounts of long-term debt maturing for the next
five years, including amounts classified as Current Portion of Long-Term Debt,
are: $96,000,000 in 1995, $88,500,000$88.5 million in 1996, none in 1997, $50,000,000$100.0 million in 1998, $50.0 million
in 1999 and $50,000,000$50.0 million in 1999.
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, is $541,327,000 and
$513,107,000 at September 30, 1994 and 1993, respectively. Such value is not
intended to reflect principal amounts that the Company will ultimately be
required to repay.2000.
During 1994, the Company redeemed $19,917,000 remaining outstanding
principal amount of 9-1/2% debentures due July 1, 2019, for $21,337,000,
including redemption premium. Also during 1994,1995, the Company issued $50,000,000an aggregate $100.0 million of
medium-term notes. In June 1995, $50.0 million of 7.375% medium-term notes due
July 1999, at an interest rate of 7.25% and
$50,000,000 of medium-term notes due July 2024, at an interest rate of 8.48%.
The 8.48% notes are callable beginning July 1999.in June 2025 were issued. After reflecting underwriting discounts and
commissions, the combined proceeds to the Company of
these issuancesfrom this issuance amounted to $99,415,500. The$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 were used to reduce
outstanding short-term borrowings.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
In March 1993, the Company filed a shelf registration with the SEC for
$350,000,000 of debentures and/or medium-term notes that became effective on
March 30, 1993.from this issuance amounted to $49.8 million.
The Company has authority remaining under thisa shelf registration and has
authority under the Public Utility Holding Company Act of 1935, as amended, to
issue and sell up to $220,000,000$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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
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 pipeline
construction 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 $400,000,000$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 through 1995.throughout 1996.
The Company may also issue as much as $150,000,000$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 $400,000,000$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 $105,000,000.$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 $400,000,000$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, 1994.1995. The arrangement expires on September 20, 1995,19, 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 $102,500,000$102.5 million and $10,000,000, respectively. At
September 30, 1993, the Company had outstanding notes payable to banks and
commercial paper of $125,800,000 and $71,000,000,$10.0 million, respectively.
The weighted average interest rate on notes payable to banks was 5.13%6.15%
and 3.29%5.13% at September 30, 19941995 and 1993,1994, respectively. The weighted average
interest rate on commercial paper was 5.09%5.85% and 3.32%5.09% at September 30, 19941995 and
1993,1994, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note F - Financial Instruments
Fair Values
The fair market value of the Company's long-term debt is estimated based on
quoted market prices of similar issues having the same remaining maturities,
redemption terms and credit ratings. Based on these criteria, the fair market
value of long-term debt, including current portion, was as follows:
At September 30 (in thousands) 1995 1994
---------------------- ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
Long-Term Debt $562,500 $570,236 $558,500 $541,327
======== ======== ======== ========
The fair value amounts are not intended to reflect principal amounts that the
Company will ultimately be required to pay.
Temporary cash investments, notes payable to banks and commercial paper
are stated at amounts which approximate their fair value due to the short-term
maturities of those financial instruments. Investments in life insurance are
stated at their cash surrender values as discussed below.
Investments
Other assets consist principally of cash surrender values of insurance
contracts. The cash surrender values of these insurance contracts amounted to
$28.2 million and $21.3 million at September 30, 1995 and 1994, respectively.
The insurance contracts were established as a funding mechanism for various
benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company, in its Exploration and Production operations, has entered into
certain price swap agreements that effectively hedge a portion of the market
risk associated with fluctuations in the price of natural gas and crude oil.
These agreements are not held for trading purposes. The price swap agreements
call for the Company to receive monthly payments from (or make payment to) other
parties based upon the difference between a fixed and a variable price as
specified by the agreement. The variable price is either a crude oil price
quoted on the New York Mercantile Exchange or a quoted natural gas price in
"Inside FERC."
The following summarizes the Company's activity under swap agreements
during 1995 and 1994:
Year Ended September 30 1995 1994
--------------- -------------
Natural Gas Swap Agreements:
Notional Amount - Equivalent
Billion Cubic Feet (Bcf) 16.3 8.0
Fixed Prices per Thousand Cubic
Feet (Mcf) $1.73 - $2.38 $2.16 - $2.38
Variable Prices per Mcf $1.35 - $1.76 $1.44 - $2.44
Gain $7,157,000 $1,986,000
Crude Oil Swap Agreements:
Notional Amount - Equivalent
Barrels (bbl) 711,000 -
Fixed Prices per bbl $16.68 - $19.60 -
Variable Prices per bbl $17.16 - $19.89 -
Loss $(221,000) -
The Company had the following swap agreements outstanding at September
30, 1995:
Natural Gas Swap Agreements:
Notional Amount
Fiscal Year (Equivalent Bcf) Fixed Price per Mcf
----------- ---------------- -------------------
1996 17.6 $1.70 - $2.16
1997 3.9 $1.70 - $1.98
1997 1.7 (1)
1998 0.6 (1)
----
23.8
====
Crude Oil Swap Agreements:
Notional Amount
Fiscal Year (Equivalent bbl) Fixed Price per bbl
----------- ---------------- -------------------
1996 946,000 $17.40 - $19.00
1997 738,000 $17.40 - $18.33
1998 96,000 $18.31
---------
1,780,000
=========
(1) Price to be set according to market prices at a future date.
Gains or losses from these price swap agreements are reflected in
operating revenues on the Consolidated Statement of Income at the time of
settlement with the other parties. Based upon the September 30, 1995 variable
prices of these price swap agreements, there is an unrecognized gain of
approximately $6.7 million. The actual gain or loss realized upon settlement of
these price swap agreements will depend upon the variable price at the time of
settlement.
The Company has SEC authority to enter into interest rate swaps
associated with short-term and long-term borrowings up to a notional amount of
$350.0 million. However, within this combined limitation, the Company may only
enter into interest rate swaps associated with short-term borrowings up to a
notional amount of $200.0 million. No such agreements were entered into in 1995
and none are currently outstanding.
Credit Risk
Credit risk relates to the risk of loss that the Company would incur as a result
of nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company is at risk in the event of nonperformance by
counterparties on investments, such as temporary cash investments and cash
surrender values of insurance contracts, and on its derivative financial
instruments. The counterparties to the Company's investments and derivative
financial instruments are investment grade financial institutions. Furthermore,
the Company has guarantees from counterparty affiliates on a large portion of
its derivative financial instruments. Accordingly, the Company does not
anticipate any material impact to its financial position, results of operations
or cash flow as a result of nonperformance by counterparties.
Note G - Retirement Plan and Other Post-Employment Benefits
Retirement Plan.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. AIn 1994, a plan amendment was adopted which provided for
an early retirement window program which iswas accounted for under the rules
prescribed by SFAS 88, "Employers' Accounting for Settlements and Curtailments
of Defined Benefit Plans and for Termination Benefits." For ratemaking purposes,
pension expense equals the amount funded less amounts capitalized. Since Plan
funding has not been required in recent years, the Company deferred the pension
expense associated with its regulated subsidiaries. The amounts deferred are
expected to be recovered in rates as contributions are made to the Plan. The
actuarial valuation funding report for the 1996 Plan year indicates that a
contribution to the Plan is required. Rate recovery for the Distribution
Corporation portion of pension costs began with rates that went into effect on
September 20, 1995 and September 27, 1995 in New York and Pennsylvania,
respectively.
The components of net periodic pension expense were as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Service Cost for Benefits Earned
During the Period $10,441 $ 9,181 $ 8,816
Interest Cost on Projected Benefit Obligation 26,532 24,258 22,446
Actual Return on Plan Assets (16,212) (35,657) (37,107)
Net Amortization and Deferral (16,603) 4,287 7,077
Early Retirement Window 2,855 - -
Net Periodic Pension Cost 7,013 2,069 1,232
Deferred for Regulatory Purposes (6,875) (2,012) (1,192)
Pension Cost Recognized in
Consolidated Statement of Income $ 138 $ 57 $ 40
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Service Cost $ 9,680 $10,441 $ 9,181
Interest Cost 28,338 26,532 24,258
Actual Return on Plan Assets (47,591) (16,212) (35,657)
Net Amortization and Deferral 13,570 (16,603) 4,287
Early Retirement Window - 2,855 -
------- ------- -------
Net Periodic Pension Cost 3,997 7,013 2,069
Deferred for Regulatory Purposes (3,848) (6,875) (2,012)
------- ------- -------
Pension Cost Recognized in
Consolidated Statement of Income $ 149 $ 138 $ 57
======= ======= =======
The projected benefit obligation was determined using an assumed
discount rate of 8% in 1995, 8.5% in 1994 and 7.75% in 1993 and 8.5% in 1992.1993. 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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)In 1995, in
addition to the decrease in the discount rate from 8.5% to 8%, the mortality
assumption was changed by using a more current mortality table and rates of
assumed retirement were revised to more accurately reflect actual retirement
experience. The effect of the discount rate change was to increase the projected
benefit obligation (PBO) by $22.8 million. The effect of the mortality and
retirement rate changes was to increase the PBO by $15.4 million.
A reconciliation of the Plan's funded status as determined by the
Company's consulting actuary is presented in the following table:
At September 30 (in thousands) 1994 1993
Actuarial Present Value of:
Vested Benefit Obligation $245,095 $241,676
Accumulated Benefit Obligation $282,340 $278,843
Projected Benefit Obligation $342,050 $346,634
Plan Assets at Fair Value 370,150 369,920
Plan Assets in Excess of
Projected Benefit Obligation 28,100 23,286
Unrecognized Net Asset (37,502) (42,688)
Unrecognized Prior Service Cost 13,339 14,418
Unrecognized Net Gain (19,959) (4,025)
Pension Liability (16,022) (9,009)
Deferred for Regulatory Purposes 15,001 8,126
Pension Liability Recognized on Consolidated
Balance Sheets $ (1,021) $ (883)
At September 30 (in thousands) 1995 1994
---- ----
Actuarial Present Value of:
Vested Benefit Obligation $287,470 $245,095
======== ========
Accumulated Benefit Obligation $333,597 $282,340
======== ========
Projected Benefit Obligation $404,157 $342,050
Plan Assets at Fair Value 399,608 370,150
-------- --------
Funded Status (4,549) 28,100
Unrecognized Net Asset (33,335) (37,502)
Unrecognized Prior Service Cost 12,446 13,339
Unrecognized Net Loss (Gain) 5,419 (19,959)
-------- --------
Pension Liability (20,019) (16,022)
Deferred for Regulatory Purposes 18,849 15,001
-------- --------
Pension Liability Recognized on Consolidated
Balance Sheets $ (1,170) $ (1,021)
======== ========
Other Post-Retirement Benefits.Benefits
In addition to providing retirement plan benefits, the Company currently provides health
care and life insurance benefits for substantially all retired employees under a
post-retirement benefit plan (Post-Retirement Plan).
The Company has 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. The Company's current policy is to invest Post-Retirement Plan assets primarily inconsist of equity securities and
municipal bonds.fixed income investments and money market funds.
The Company has elected to amortize the initial accumulated liability
(transition obligation)
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 $23,530,000$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 $5,974,000 and
$4,945,000$6.0 million in 1993 and 1992, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)1993.
The components of net periodic post-retirement benefit cost were as
follows:
Year Ended September 30 (in thousands) 1994
Service Cost $ 3,974
Interest Cost 13,714
Expected Return on Post-Retirement Plan Assets (1,035)
Amortization of Transition Obligation 8,628
Net Periodic Post-Retirement Benefit Cost 25,281
Deferred for Regulatory Purposes, Net (1,751)
Post-Retirement Benefit Cost
Recognized in Consolidated Statement of Income $ 23,530
Year Ended September 30 (in thousands) 1995 1994
---- ----
Service Cost $ 3,394 $ 3,974
Interest Cost 13,027 13,714
Actual Return on Post-Retirement Plan Assets (4,613) (1,035)
Net Amortization and Deferral 8,739 8,628
------- -------
Net Periodic Post-Retirement Benefit Cost 20,547 25,281
Deferred for Regulatory Purposes, Net 3,853 (1,751)
------- -------
Post-Retirement Benefit Cost
Recognized in Consolidated Statement of Income $24,400 $23,530
======= =======
The weighted-average assumed discount rate used in determining the
accumulated post-retirement benefit obligation was 8% in 1995 and 8.5% in 1994.
The average assumed annual rate of salary increase for the applicable life
insurance plans was 5%. for both years. The expected long-term rate of return on
Post-Retirement Plan assets was 8.5% for both years.
The annual rate of increase in the per capita cost of covered medical
care benefits for the active participants and medical plans available to new
retirees was assumed to be 13% for 1994;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 t
oto be 14% for 1994.1994 and 10% for 1995. This rate was
assumed to decrease gradually to 5.5% by the year 20032005 and remain level
thereafter. The annual rate increase in the per capita Medicare Part B
Reimbursement was assumed to be 12.3% in 1994, 12.2% in 1995, 12% for 1996 and
5.5% for each year after 1996. In 1995, in addition to the decrease in the
discount rate from 8.5% to 8%, there were plan changes to the prescription drug
and life insurance post-retirement benefits. The effect of
the discount rate change was to increase the accumulated post-retirement benefit
obligation (APBO) by $25.8 million. The net effect of the plan changes was to
reduce the APBO by $6.4 million.
A reconciliation of the Post-Retirement Plan's funded status as
determined by the Company's consulting actuary is in the following table:
At September 30 (in thousands) 1994
Accumulated Post-Retirement
Benefit Obligation $ 155,976
Fair Value of Post-Retirement
Plan Assets 29,035
Accumulated Benefit Obligation in excess
of Plan Assets (126,941)
Unrecognized Transition Obligation 156,210
Unrecognized Net (Gain)/Loss (31,776)
Post-Retirement Liability (2,507)
Deferred for Regulatory Purposes, Net 1,751
Post-Retirement Benefit Liability Recognized
on Consolidated Balance Sheets $ (756)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
At September 30 (in thousands) 1995 1994
---- ----
Accumulated Post-Retirement Benefit Obligation:
Inactives $ 76,272 $ 63,934
Actives Fully Eligible 36,223 31,983
Actives Not Yet Fully Eligible 70,620 60,059
-------- --------
183,115 155,976
Fair Value of Post-Retirement Plan Assets 48,678 29,035
-------- --------
Funded Status (134,437) (126,941)
Unrecognized Transition Obligation 141,561 156,210
Unrecognized Net Gain (8,930) (31,776)
-------- --------
Post-Retirement Liability (1,806) (2,507)
Deferred for Regulatory Purposes, Net (2,102) 1,751
--------- --------
Post-Retirement Benefit Liability Recognized
on Consolidated Balance Sheets $ (3,908) $ (756)
======== ========
The health care cost trend rate assumptions used to calculate the per
capita cost of covered medical care benefits have a significant effect on the
amounts reported. If the health care cost trend rates were increased by 1% in
each year, the accumulated post-retirement benefit obligationAPBO as of October 1, 1993,1994, would be increased by $26,600,000.$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 19941995 by $3,100,000.$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.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. Essentially, the new standard required the
Company to change its accountingThe Consolidated
Statement of Income for significant post-employment benefits from
the "pay-as-you-go" (cash) to the accrual basis. The only significant
post-employment benefit that the Company has relates to workers' compensation.
In the Company's regulated operations, workers' compensation is recovered in
rates on1994 includes a cash basis and is not material. Workers' compensation claims
related to the Company's nonregulated operations at September 30, 1994, is
approximately $1,014,000 ($589,000charge of $0.6 million, net of income
taxes) using a discount rate
of 8.5%. As required by SFAS 112, the adoption of the standard is reflected on
the Consolidated Statement of Incometaxes, as a cumulative effect of a change in accounting principle.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note GH - Commitments and Contingencies
Leases. System companies haveLeases
The Company has entered into lease agreements, principally for the use of office
space, business machines, transportation and construction 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 $17,190,000$16.3 million in 1995,
$17.2 million in 1994 $16,864,000and $16.9 million in 1993 and $17,570,000 in 1992.1993. At September 30, 1994,1995, the
future minimum payments under the Company's lease agreements for the next five
years are: $13,075,000 in 1995, $9,779,000$13.9 million in 1996, $6,959,000$10.9 million in 1997, $5,021,000$7.6 million in 1998,
$5.1 million in 1999 and $3,650,000$3.6 million in 1999.2000. The future minimum lease payments
attributable to later years is $6,059,000.$9.7 million.
Obligations Under Firm Contracts.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, 1994,1995, the projected aggregate amounts of
such required future payments, based on current FERC-approved rates and current
indices, where applicable, are approximately $88,600,000, $12,500,000$97.7 million, $12.7 million and
$6,900,000$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, 1994,1995, total gross costs
incurred under these contracts, including commodity charges on actual quantities
shipped, purchased and stored, amounted to $347,100,000.$270.7 million.
Environmental Matters.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 identifieddesignated by the Environmental Protection
Agency or the New York State 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
that are considered to be potentially responsible
parties (PRPs)PRPs with respect to several waste disposal sites in New York
thatwhich were operated by unrelated third parties. TheseThe 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
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Corporation with
respect to the remediation of these sites will be dependentdepend 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, attributed, if any, attributed to Distribution
Corporation. Distribution Corporation's estimated share of the clean-up costs
has been accrued for fourtwo of these sites.
One of these four sites was formerly used for a manufactured gas plant.
Distribution Corporation is currently involved in litigation regarding this
site. The current owner of the site has submitted a claim against Distribution
Corporation for contribution of a share of approximately $1,600,000 of
removal/remediation costs that have been incurred. It is anticipated that
future remedial costs will be incurred and on the basis of a Record of Decision
issued by the DEC, as amended on September 19, 1994, the estimated future
remedial costs for the site are approximately $5,700,000. Management believes
that the ultimate outcome of these matters will not have a material impact on
the financial condition, results of operations or cash flows of the Company.
Distribution Corporation has incurred clean-up costs at two additional sites
in New York and one site in Pennsylvania related to former manufactured gas
plant sites. Supply Corporation is involved in a remediation program of
certain of its measuring and regulating stations in Pennsylvania. Estimated
clean-up costs have been accrued for 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. The CompanyDistribution Corporation has
estimated that clean-up costs related to all of the above noted sites are in the
range of $6,700,000$8.1 million to $10,100,000.$9.5 million. At September 30, 1994, the Company1995, Distribution
Corporation has recorded the minimum liability of $6,700,000.$8.1 million. The Company is
currently not aware of any material additional exposure to environmental
liabilities. However, adverse changes in environmental regulations or other
factors could impact the Company.
In New York, Distribution Corporation has received approval from the
PSC to defer and amortize both former manufactured gas and non-manufactured gas
plant site investigation and remediation costs over a three-year period for each
site. These costs are then included in rate cases for recovery through base
rates. Distribution Corporation is currently recovering such costs in this
manner. In Pennsylvania, Distribution Corporation and Supply Corporation
expectexpects to recover such costs
in rates as the PaPUC and the FERC, respectively,
havehas allowed recovery of other environmental clean-up costs
in rate cases. Accordingly, the Consolidated Balance Sheets at September 30,
1994,1995, include related regulatory assets in the amount of approximately $7,300,000, $600,000
of which relates to costs that have already been incurred.$7.5
million.
The Company has begun a program to complyis in compliance with the current standards of the Clean
Air Act Amendments of 1990 (the Act). This program focuses on emission controls for Supply Corporation's compressor stations
in New York and Pennsylvania. These
facilities arePennsylvania were affected by the nitrogen oxide emission
standards of the Act. Supply Corporation incurred capital expenditures for
emission controls of approximately $623,000$0.6 million in 1994 and expects$5.1 million in 1995
to incur approximately $4,300,000 in
1995.bring its emission controls into compliance with the Act. The Company does
not anticipate incurring significant additional capital
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
expenditures to comply
with the current standards of the Act, however, changes
in the standards may require additional expenditures in the future. Management
expects that all related capital expenditures will be recoverable through rates.
Other.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 HI - Business Segment Information
The SystemCompany 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 pipeline
construction operations, sawmill and dry kiln
operations, natural gas marketing operations, and natural gas market area hub operations.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
1994, 52%1995, 48% of Supply Corporation's revenue was from affiliated companies, mainly
Distribution Corporation.
Seneca is engaged in exploration for, and development and purchase of,
oil and natural gas reserves in the Gulf Coast, and the southwestern, western
and Appalachian regions of the United States. Seneca's production is, for the
most part, sold to purchasers located in the vicinity of its wells. Highland
Land & Minerals, Inc. operates a sawmill and dry kiln operation in Pennsylvania.
NFR is engaged in the marketing and brokerage of natural gas and performs energy
management services for utilities and end-users in the northeastern United
States markets. Leidy Hub, Inc. is engaged in the
Company's natural gas hub operations, providing services to customers in the
northeastern, mid-Atlantic, Chicago and Los Angeles areas of the United States
and Ontario, Canada. Horizon Energy Development, Inc. was formed in 1995 to
engage in foreign and domestic energy projects. Utility Constructors, Inc.
iswas engaged in the Company's pipeline construction operations Highland Land &
Minerals, Inc. is engagedprior to the
discontinuance of its operations in the Company's sawmill and dry kiln operations, NFR
is engaged in the Company's natural gas marketing operations and Leidy Hub,
Inc. is engaged in the Company's natural gas market area hub opreations.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
1993 and 1992.1993. 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 deferred charges.cash surrender values of
insurance contracts.
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Operating Revenues
Regulated:
Utility Operation $ 786,064 $ 931,673 $ 836,618
Pipeline and Storage 164,587 153,121 534,568
---------- ---------- ----------
950,651 1,084,794 1,371,186
---------- ---------- ----------
Nonregulated:
Exploration and Production 56,232 70,261 58,636
Other 57,075 72,036 42,099
---------- ---------- ----------
113,307 142,297 100,735
---------- ---------- ----------
Intersegment Revenues* (88,462) (85,767) (451,539)
---------- ---------- ----------
$ 975,496 $1,141,324 $1,020,382
========== ========== ==========
Operating Income (Loss) Before
Income Taxes
Regulated:
Utility Operation $ 83,774 $ 90,584 $ 86,690
Pipeline and Storage 67,884 62,302 67,375
---------- -------- --------
151,658 152,886 154,065
---------- -------- --------
Nonregulated:
Exploration and Production 16,404 21,767 12,980
Other 3,021 2,505 (986)
---------- -------- --------
19,425 24,272 11,994
---------- -------- --------
Corporate (2,805) (3,463) (2,730)
---------- -------- --------
$ 168,278 $173,695 $163,329
========== ======== ========
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Revenues
Regulated:
Utility Operation $ 931,673 $ 836,618 $ 740,664
Pipeline and Storage 153,121 534,568 498,870
1,084,794 1,371,186 1,239,534
Nonregulated:
Exploration and Production 70,261 58,636 36,303
Other 72,036 42,099 47,479
142,297 100,735 83,782
Intersegment Revenues* (85,767) (451,539) (402,866)
$1,141,324 $1,020,382 $ 920,450
Operating Income (Loss)
Before Income Taxes
Regulated:
Utility Operation $ 90,584 $ 86,690 $ 90,025
Pipeline and Storage 62,302 67,375 49,796
152,886 154,065 139,821
Nonregulated:
Exploration and Production 21,767 12,980 7,021
Other 2,505 (986) 4,229
24,272 11,994 11,250
Corporate (3,463) (2,730) (2,279)
$ 173,695 $ 163,329 $ 148,792
Identifiable Assets
At September 30
Regulated:
Utility Operation $1,106,053 $ 961,990 $ 874,101
Pipeline and Storage** 498,798 491,291 495,626
1,604,851 1,453,281 1,369,727
Nonregulated:
Exploration and Production** 311,037 290,346 271,444
Other 33,357 27,867 27,808
344,394 318,213 299,252
Corporate 32,412 30,046 91,851
$1,981,657 $1,801,540 $1,760,830
Identifiable Assets
At September 30 (in thousands)
Regulated:
Utility Operation $1,100,236 $1,106,053 $ 961,990
Pipeline and Storage 512,546 498,798 491,291
---------- ---------- ----------
1,612,782 1,604,851 1,453,281
---------- ---------- ----------
Nonregulated:
Exploration and Production 351,262 311,037 290,346
Other 33,734 33,357 27,867
---------- ---------- ----------
384,996 344,394 318,213
---------- ---------- ----------
Corporate 40,524 32,412 30,046
---------- ---------- ----------
$2,038,302 $1,981,657 $1,801,540
========== ========== ==========
* Represents revenue primarily from Pipeline and Storage to Utility Operation.
** Prior year amounts have been reclassified to eliminate an intersegment
receivable and to conform with current year presentation.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Year Ended September 30 (in thousands) 1994 1993 1992
Depreciation, Depletion and
Amortization
Regulated:
Utility Operation $ 28,216 $ 27,137 $ 25,001
Pipeline and Storage 17,516 16,347 16,202
45,732 43,484 41,203
Nonregulated:
Exploration and Production 27,496 24,249 13,257
Other 1,530 1,686 1,260
29,026 25,935 14,517
Corporate 6 6 6
$ 74,764 $ 69,425 $ 55,726
Capital Expenditures
Regulated:
Utility Operation $ 61,715 $ 61,803 $ 65,650
Pipeline and Storage 20,472 27,420 58,646
82,187 89,223 124,296
Nonregulated:
Exploration and Production 52,458 36,473 26,328
Other 3,603 6,229 7,225
56,061 42,702 33,553
Corporate 20 1 7
$138,268 $131,926 $ 157,856
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Depreciation, Depletion and Amortization
Regulated:
Utility Operation $ 30,052 $ 28,216 $27,137
Pipeline and Storage 19,320 17,516 16,347
-------- -------- -------
49,372 45,732 43,484
-------- -------- -------
Nonregulated:
Exploration and Production 21,201 27,496 24,249
Other 1,203 1,530 1,686
-------- -------- -------
22,404 29,026 25,935
-------- -------- -------
Corporate 6 6 6
-------- -------- -------
$ 71,782 $ 74,764 $69,425
======== ======== =======
Capital Expenditures
Regulated:
Utility Operation $ 64,844 $ 61,715 $ 61,803
Pipeline and Storage 38,678 20,472 27,420
-------- -------- --------
103,522 82,187 89,223
-------- -------- --------
Nonregulated:
Exploration and Production 69,741 52,458 36,473
Other 9,563 3,603 6,229
-------- -------- --------
79,304 56,061 42,702
-------- -------- --------
Corporate - 20 1
-------- -------- --------
$182,826 $138,268 $131,926
======== ======== ========
Note IJ - Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all
adjustments necessary for a fair statement of the results of operations for such
periods. Earnings per common share are calculated using the weighted average
number of shares outstanding during each quarter. The total of all quarters may
differ from the earnings per common share shown on the Consolidated Statement of
Income, which is based on the weighted average number of shares outstanding for
the entire fiscal year. Because of the seasonal nature of the Company's heating
business, there are substantial variations in operations reported on a quarterly
basis.
Financial data for the quarters ended December 31, 1994, March 31,
1995, and June 30, 1995 have been restated to reflect the application of a final
rule issued by the FERC in September 1995, which addresses and clarifies
financial reporting aspects of the current practices for unbundled pipeline
sales and open access transportation.
Financial data for the quarter ended September 30, 1995 reflects the
recording of $4.3 million and $3.7 million of operating expenses by Distribution
Corporation and Supply Corporation, respectively. Distribution Corporation
recognized an additional $4.3 million of gas cost expense as a result of the
annual reconciliation of gas costs in its New York jurisdiction, which is
performed in August of each year. This reconciliation determined an amount of
lost and unaccounted-for gas in excess of that allowed to be recovered by the
PSC. Supply Corporation recorded a reserve in the amount of $3.7 million for
previously deferred preliminary survey and investigation charges related to a
storage project.
Financial data for the quarters ended December 31, 1993 and September
30, 1994, reflect the Company's adoption of SFAS 109 and SFAS 112, respectively.
As discussed in Note A - Summary of Significant Accounting Policies, the Company
adopted SFAS 109 during the quarter ended December 31, 1993. The cumulative
effect of this change increased net income by $3,826,000.$3.8 million. As discussed in Note
FG - 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 $589,000.
Income Net Income Earnings
Before Available for Per
Quarter Operating Operating Cumulative Common Common
Ended Revenues Income Effect Stock Share
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*
1993 (in thousands, except earnings per common share)
12/31/92 $294,220 $38,452 $25,941 $25,941 $ .77
3/31/93 $391,790 $57,195 $45,160 $45,160 $1.33
6/30/93 $185,525 $14,993 $ 3,228 $ 3,228 $ .09
9/30/93 $148,847 $11,643 $ 888 $ 888 $ .02$0.6 million.
Income Net Income Earnings
Before Available for Per
Quarter Operating Operating Cumulative Common Common
Ended Revenues Income Effect Stock Share
------- --------- --------- ---------- ------------- --------
1995 (in thousands, except earnings per common share)
- -------------------------------------------------------------------------------------
12/31/94
- As Previously Reported $271,548 $38,578 $25,861 $25,861 $ .69
- As Restated $279,332 $43,288 $30,571 $30,571 $ .82
3/31/95
- As Previously Reported $376,680 $55,197 $42,047 $42,047 $1.12
- As Restated $378,762 $56,457 $43,307 $43,307 $1.16
6/30/95
- As Previously Reported $191,480 $17,789 $ 7,783 $ 7,783 $ .21
- As Restated $193,461 $18,987 $ 8,981 $ 8,981 $ .24
9/30/95 $123,941 $ 5,667 $(6,965) $(6,965) $(.19)
1994 (in thousands, except earnings per common share)
- -------------------------------------------------------------------------------------
12/31/93 $310,131 $38,745 $27,800 $31,626* $ .86 *
3/31/94 $473,722 $54,686 $43,839 $43,839 $1.18
6/30/94 $216,281 $19,782 $ 9,833 $ 9,833 $ .26
9/30/94 $141,190 $12,690 $ 963 $ 374* $ .01 *
* Includes Cumulative Effect of Changes in Accounting as discussed above.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note JK - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 1994,1995, there were 22,46521,429 holders of National Fuel Gas Company
common stock. The market for the common stock is the New York Stock Exchange.
Information related to restrictions on the payment of dividends can be found
in Note D - Capitalization. The quarterly price ranges and quarterly dividends
declared for the fiscal years ended September 30, 19931994 and 1994,1995, are shown
below:
Price Range Dividends
Quarter Ended High Low Declared
1993
12/31/92 $30-1/2 $24-5/8 $.375
3/31/93 $33-1/2 $29-1/4 $.375
6/30/93 $33-1/2 $28-3/4 $.385
9/30/93 $36-7/8 $32-1/4 $.385
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
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Price Range Dividends
Quarter Ended High Low Declared
- ------------- ---- --- ---------
1994
----
12/31/93 $36-5/8 $32-1/2 $.385
3/31/94 $36-1/4 $29-7/8 $.385
6/30/94 $32-7/8 $28-3/8 $.395
9/30/94 $31-7/8 $28-7/8 $.395
1995
----
12/31/94 $30 $25-1/4 $.395
3/31/95 $28-1/2 $25 $.395
6/30/95 $30-3/4 $27-1/2 $.405
9/30/95 $29-5/8 $26-1/2 $.405
Note KL - Supplementary Information for Oil and Gas Producing Activities
The following supplementary information is presented in accordance with SFAS 69,
"Disclosures about Oil and Gas Producing Activities," and related SEC accounting
rules.
Capitalized Costs Relating to Oil and Gas Producing Activities
At September 30 (in thousands) 1994 1993
Capitalized Costs Subject to Amortization $442,224 $399,781
Capitalized Acquisition Costs Excluded
from Amortization 16,636 15,849
458,860 415,630
Less - Accumulated Depreciation, Depletion
and Amortization 167,592 145,553
$291,268 $270,077
Capitalized Costs Relating to Oil and Gas Producing Activities
At September 30 (in thousands) 1995 1994
---- ----
Capitalized Costs Subject to Amortization $495,802 $442,224
Capitalized Acquisition Costs Excluded
from Amortization 28,565 16,636
-------- --------
524,367 458,860
Less - Accumulated Depreciation, Depletion
and Amortization 188,241 167,592
-------- --------
$336,126 $291,268
======== ========
Certain costs excluded from amortization represent unevaluated
properties that require additional drilling to determine the existence of oil
and gas reserves. The remaining costs, incurred during and prior to 1994,1995,
consist of individually insignificant oil and gas leases still early in their
primary terms and individually insignificant unproved perpetual oil and gas
rights.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Property Acquisition Costs $25,305 $ 8,215 $ 9,027
Exploration Costs 18,588 17,855 10,140
Development Costs 25,161 25,102 16,258
Other 559 259 25
------- ------- -------
$69,613 $51,431 $35,450
======= ======= =======
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Costs Incurred in Oil and Gas Property Acquisition, Exploration
and Development Activities
Year Ended September 30 (in thousands) 1994 1993 1992
Property Acquisition Costs $ 8,215 $ 9,027 $ 5,260
Exploration Costs 17,855 10,140 4,552
Development Costs 25,102 16,258 11,172
Other 259 25 3,284
$51,431 $35,450 $24,268
Results of Operations for Producing Activities
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Revenues:
Natural Gas (includes revenues from sales
to affiliates of $5,456, $11,474 and
$10,945, respectively) $50,803 $43,679 $24,022
Oil, Condensate and Other Liquids 15,307 13,943 10,974
Total Operating Revenues 66,110 57,622 34,996
Production/Lifting Costs 13,177 13,452 9,828
Depreciation, Depletion and Amortization
($.41, $.42 and $.37, respectively, per
dollar of operating revenues) 26,992 23,995 13,049
Income Tax Expense 7,907 4,311 3,874
Results of Operations for Producing Activities
(excluding corporate overheads and
interest charges) $18,034 $15,864 $ 8,245
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Results of Operations for Producing Activities
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Operating Revenues:
Natural Gas (includes revenues from sales
to affiliates of $8,650, $5,456 and
$11,474, respectively) $34,849 $50,803 $43,679
Oil, Condensate and Other Liquids 11,948 15,307 13,943
------- ------- -------
Total Operating Revenues 46,797 66,110 57,622
Production/Lifting Costs 11,215 13,177 13,452
Depreciation, Depletion and Amortization
($0.44, $0.41 and $0.42, respectively, per
dollar of operating revenues) 20,528 26,992 23,995
Income Tax Expense 4,301 7,907 4,311
------- ------- -------
Results of Operations for Producing
Activities (excluding corporate overheads
and interest charges) $10,753 $18,034 $15,864
======= ======= =======
Reserve Quantity Information (unaudited)
The Company's proved oil and gas reserves are located in the United States. The
estimated quantities of proved reserves disclosed in the table below are based
upon estimates by the Company'squalified Company geologists and engineers and are audited by
independent petroleum engineers. Such estimates are inherently imprecise and may
be subject to substantial revisions.
Gas Oil
Year Ended MMcf Mbbl
September 30 1994 1993 1992 1994 1993 1992
Proved Developedrevisions as a result of numerous factors including,
but not limited to, additional development activity, evolving production
history, and Undeveloped Reserves:
Beginningcontinual reassessment of Year 175,051 179,811 176,772 18,519 19,805 20,316
Extensions and
Discoveries 94,733 26,416 21,645 1,666 1,713 270
Revisionsthe viability of Previous Estimates (2,075) (3,962) (3,391) (1,660) (1,995) (85)
Production (23,273) (19,874)(12,070) (1,030) (831) (643)
Sales of Minerals in Place (32) (7,401) (3,377) - (173) (53)
Purchases of Minerals
in Place and Other 3,043 61 232 - - -
End of Year 247,447 175,051 179,811 17,495 18,519 19,805
Proved Developed Reserves:
Beginning of Year 134,712 126,176 131,035 10,801 11,437 12,210
End of Year 179,291 134,712 126,176 10,110 10,801 11,437production under varying
economic conditions.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Gas Oil
Year Ended MMcf Mbbl
-------------------------- ----------------------
September 30 1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
Proved Developed and
Undeveloped Reserves:
Beginning of Year 247,447 175,051 179,811 17,495 18,519 19,805
Extensions and
Discoveries 9,912 94,733 26,416 3,863 1,666 1,713
Revisions of
Previous Estimates (21,046) (2,075) (3,962) (60) (1,660) (1,995)
Production (20,942) (23,273) (19,874) (739) (1,030) (831)
Sales of Minerals in
Place (4,685) (32) (7,401) (474) - (173)
Purchases of Minerals
in Place and Other 10,773 3,043 61 2,780 - -
------- ------- ------- ------ ------ ------
End of Year 221,459 247,447 175,051 22,865 17,495 18,519
======= ======= ======= ====== ====== ======
Proved Developed Reserves:
Beginning of Year 179,291 134,712 126,176 10,110 10,801 11,437
======= ======= ======= ====== ====== ======
End of Year 162,504 179,291 134,712 14,937 10,110 10,801
======= ======= ======= ====== ====== ======
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (unaudited)
The Company cautions that the following presentation of the standardized measure
of discounted future net cash flows is intended to be neither a measure of the
fair market value of the Company's oil and gas properties, nor an estimate of
the present value of actual future cash flows to be obtained as a result of
their development and production. It is based upon subjective estimates of
proved reserves only and attributes no value to categories of reserves other
than proved reserves, such as probable or possible reserves, or to unproved
acreage. Furthermore, it is based on year-end prices and costs adjusted only for
existing contractual changes, and it assumes an arbitrary discount rate of 10%.
Thus, it gives no effect to future price and cost changes certain to occur under
the widely fluctuating political and economic conditions of today's world.
The standardized measure is intended instead to provide a somewhat
better means for comparing the value of the Company's proved reserves at a given
time with those of other oil- and gas-producing companies than is provided by a
simple comparison of raw proved reserve quantities.
Year Ended September 30 (in thousands) 1994 1993 1992
Future Cash Inflows $705,874 $689,198 $772,017
Less:
Future Production and Development Costs 252,901 240,417 217,654
Future Income Tax Expense at
Applicable Statutory Rate 131,060 132,528 159,888
Future Net Cash Flows 321,913 316,253 394,475
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 106,647 106,598 154,184
Standardized Measure of Discounted Future
Net Cash Flows $215,266 $209,655 $240,291
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Future Cash Inflows $738,711 $705,874 $689,198
Less:
Future Production and Development Costs 272,268 252,901 240,417
Future Income Tax Expense at
Applicable Statutory Rate 129,055 131,060 132,528
-------- -------- --------
Future Net Cash Flows 337,388 321,913 316,253
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 92,120 106,647 106,598
-------- -------- --------
Standardized Measure of Discounted Future
Net Cash Flows $245,268 $215,266 $209,655
======== ======== ========
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Year Ended September 30 (in thousands) 1995 1994 1993
---- ---- ----
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $209,655 $240,291 $183,512
Sales, Net of Production Costs (52,933) (44,170) (25,168)
Net Changes in Prices, Net of
Production Costs (48,149) (52,266) 41,322
Purchases of Minerals in Place 2,793 61 398
Sales of Minerals in Place (29) (7,286) (6,454)
Extensions and Discoveries 96,134 61,476 38,874
Changes in Estimated Future
Development Costs (36,466) (30,555) (15,186)
Previously Estimated Development
Costs Incurred 22,941 30,888 17,793
Net Change in Income Taxes at
Applicable Statutory Rate 3,098 5,476 (11,662)
Revisions of Previous Quantity
Estimates (11,042) (25,891) (8,893)
Accretion of Discount and Other 29,264 31,631 25,755
Standardized Measure of Discounted
Future Net Cash Flows at End 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
======== ======== ========
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA
(Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE V - Property, Plant and Equipment (Note 1)
(THOUSANDS OF DOLLARS)
Balance at Balance at
Beginning of Additions Other Charges End of
Classification Period at Cost Retirements Add (Deduct) Period
Year Ended September 30, 1994
Utility
Operation $ 983,417 $ 59,652 $ 6,844 $ - $1,036,225
Pipeline and
Storage (Note 2) 618,917 20,380 4,132 4,959 640,124
Exploration and
Production 415,642 52,181 3,098 - 464,725
Other Nonregulated 21,237 4,033 332 - 24,938
Corporate 223 21 - - 244
$2,039,436 $136,267 $14,406 $4,959 $2,166,256
Year Ended September 30, 1993
Utility
Operation $ 929,601 $ 60,001 $6,185 $ - $ 983,417
Pipeline and
Storage (Note 2) 594,580 27,004 2,667 - 618,917
Exploration and
Production 378,815 37,145 318 - 415,642
Other Nonregulated 15,170 6,235 168 - 21,237
Corporate 223 - - - 223
$1,918,389 $130,385 $9,338 $ - $2,039,436
Year Ended September 30, 1992
Utility
Operation $ 871,102 $ 64,624 $ 6,125 $ - $ 929,601
Pipeline and
Storage (Note 2) 539,904 58,210 3,534 - 594,580
Exploration and
Production 353,090 25,769 44 - 378,815
Other Nonregulated 8,202 7,222 254 - 15,170
Corporate 216 7 - - 223
$1,772,514 $155,832 $ 9,957 $ - $1,918,389
Notes to Schedule V and VI appear on page 91 of this report.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA
(Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE VI - Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment
(THOUSANDS OF DOLLARS)
Additions
Balance at Charged to
Beginning Costs and Balance at
of Expenses Other Changes End of
Description Period (Note 3) Retirements Add (Deduct) Period
Year Ended September 30, 1994
Utility
Operation $228,951 $28,270 $ 8,790 $ - $248,431
Pipeline and
Storage 185,181 18,436 4,304 - 199,313
Exploration and
Production 142,172 27,443 308 - 169,307
Other Nonregulated 5,028 1,531 200 - 6,359
Corporate 101 6 - - 107
$561,433 $75,686 $13,602 $ - $623,517
Year Ended September 30, 1993
Utility
Operation $209,846 $27,209 $ 8,104 $ - $228,951
Pipeline and
Storage 171,197 17,479 3,495 - 185,181
Exploration and
Production 117,369 24,250 119 672 142,172
Other Nonregulated 3,500 1,685 157 - 5,028
Corporate 95 6 - - 101
$502,007 $70,629 $11,875 $ 672 $561,433
Year Ended September 30, 1992
Utility
Operation $192,169 $25,076 $ 7,399 $ - $209,846
Pipeline and
Storage 159,896 16,900 5,599 - 171,197
Exploration and
Production 104,303 13,264 - (198) 117,369
Other Nonregulated 2,306 1,260 66 - 3,500
Corporate 89 6 - - 95
$458,763 $56,506 $13,064 $ (198) $502,007
Notes to Schedule V and VI appear on page 91 of this report.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA
(Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
Notes to Schedules V and VI:
(1) Because of the variety of properties and the large number of
depreciation rates utilized by System companies, it is considered
impractical to set forth the rates used in computing provisions.
However, the total provisions for depreciation, depletion and
amortization of System property, plant and equipment for the three
years ended September 30, 1994, including amounts charged to accounts
other than depreciation, depletion and amortization expense, were
equivalent to approximately 3.9% in 1994, 3.8% in 1993 and 3.3% in
1992 of average depreciable property, plant and equipment for the
respective years.
(2) Includes gas stored underground costing $80,942,000 at September 30,
1994, and $75,983,000 at September 30, 1993 and 1992. The cost of gas
stored underground in the amount of $4,959,000 was transferred to
property, plant and equipment from deferred changes in 1994.
(3) Additions Charged to Costs and Expenses differs from Depreciation,
Depletion and Amortization (D,D & A) as reported in the Consolidated
Statement of Income, due to D,D & A provisions charged to other income
and expense accounts.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA
(Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE VIII - Valuation and Qualifying Accounts and Reserves
(THOUSANDS OF DOLLARS)
Schedule II - Valuation and Qualifying Accounts
(in thousands)
------------
Additions
----------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other Deductions End of
Description of Period Expenses Accounts (Note) Period
- ----------- ---------- ---------- ---------- ---------- ----------
Year Ended September 30, 1995
- -----------------------------
Reserve for Doubtful
Accounts $ 5,055 $15,187 $ - $14,318 $5,924
======= ======= ====== ====== ======
Year Ended September 30, 1994
- -----------------------------
Reserve for Doubtful
Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055
======= ======= ====== ======= =======
Year Ended September 30, 1993
- -----------------------------
Reserve for Doubtful
Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055
Year Ended September 30, 1993
Reserve for Doubtful
Accounts $ 5,900 $ 8,713 $ - $8,874 $ 5,739
Year Ended September 30, 1992
Reserve for Doubtful
Accounts $ 5,876 $ 9,723 $ - $9,699 $ 5,900 $ 8,713 $ - $8,874 $ 5,739
======= ======= ====== ====== =======
Note - Amounts represent net accounts receivable written-off.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA
(Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE IX - Short-Term Borrowings
(THOUSANDS OF DOLLARS)
Maximum Average Weighted
Balance at Weighted Amount Amount Average
Category End of Average Outstanding Outstanding Interest
of Aggregate Period Interest During the During the Rate During
Short-Term September 30 Rate Period Period the Period
Borrowings (Note 1) (Note 2) (Note 3) (Note 4) (Note 5)
Year 1994
Bank Loans $102,500 5.13% $ 182,100 $107,907 3.75%
Commercial Paper $ 10,000 5.09% $ 76,000 $ 42,000 3.67%
Year 1993
Bank Loans $125,800 3.29% $ 217,000 $115,159 3.58%
Commercial Paper $ 71,000 3.32% $ 128,000 $ 87,427 3.56%
Year 1992
Bank Loans $149,100 3.60% $ 207,200 $165,191 4.81%
Commercial Paper $127,900 3.52% $ 127,900 $ 84,096 4.62%
Notes:
(1) At September 30, 1992, the Company reclassified $50,000,000 of
short-term borrowings9 Changes in and Disagreements with Accountants on the Consolidated Balance Sheet to "Long-Term
Debt, Net of Current Portion" because the Company, on November 5, 1992,
issued $50,000,000 of medium-term notesAccounting and
used the proceeds to reduce
outstanding short-term borrowings.
(2) The interest rate for bank loans is the weighted average of the rates in
effect at the respective banks at September 30 of each year. The
interest rate for commercial paper is the weighted average of the
discount rate on those commercial paper notes outstanding at September
30 of each year.
(3) Represents the maximum amount outstanding during any month of the period.
(4) Represents the average amount outstanding on a daily basis.
(5) Represents the weighted average interest rate on a daily basis.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA
(Concluded)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE X - Supplementary Income Statement Information
(THOUSANDS OF DOLLARS)
Charged to Costs and Expenses
Item Year Ended September 30 1994 1993 1992
1. Maintenance and Repairs $30,979 $24,312 $22,439
2. Depreciation and Amortization of
Intangible Assets, Preoperating Costs
and Similar Deferrals (1) (1) (1)
3. Taxes, other than Payroll and Income Taxes:
Gross Receipts Taxes $53,271 $48,876 $44,400
Real and Other Property Taxes 35,287 33,216 31,320
Other 7,017 5,500 6,127
$95,575 $87,592 $81,847
4. Royalties (1) (1) (1)
5. Advertising Costs (1) (1) (1)
Note (1) Amount is not in excess of one percent of total operating revenues as
reported in the Consolidated Statements of Income and Earnings
Reinvested in the Business.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSUREFinancial Disclosure
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT10 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 16, 199515, 1996 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after September 30, 1994.1995. 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 COMPENSATION11 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 16, 199515,
1996 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1994.1995. The information provided in such definitive
Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT12 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 16, 199515,
1996 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1994.1995. The information provided in such definitive
Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS13 Certain Relationships and Related Transactions
At September 30, 1994,1995, 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 FORM14 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
to the index on
page 52 of this report.thereto.
(b) Reports on Form 8-K
None
(c) Exhibits.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)
*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
(Exhibit A-3 in File No. 70-7334)
*3.2 Certificate of Amendment of Restated Certificate of
Incorporation of National Fuel Gas Company, dated
February 22, 1988 (Exhibit B-5 in File No. 70-7478)
* 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)1992 in File No. 1-3880)
3(ii) By-Laws:
3.1* 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)
* Eighth Supplemental Indenture dated as of July 1, 1989, to
Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit EX-4.3, Form 10-K for fiscal year ended
September 30, 1992) (The Debentures issued thereunder were
redeemed on March 16, 1993, July 7, 1993 and July 1, 1994)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
* 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)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)1993 in
File No. 1-3880)
(10) Material Contracts:
(ii) (B) Contracts upon which Registrant's business is
substantially dependent:
10.1 Service Agreement with Empire State Pipeline under
Rate Schedule FT, dated December 15, 1994.
[Portions of this agreement are subject to a
request for confidential treatment under Rule
24b-2]
10.2 Service Agreement between National Fuel Gas
Distribution Corporation and National Fuel Gas
Supply Corporation under Rate Schedule ESS dated
August 1, 1993
10.3 Service Agreement between National Fuel Gas
Distribution Corporation and National Fuel Gas
Supply Corporation under Rate Schedule ESS dated
September 19, 1995
10.4 Service Agreement between National Fuel Gas
Distribution Corporation and National Fuel Gas
Supply Corporation under Rate Schedule EFT dated
August 1, 1993
10.5 Amendment dated as of May 1, 1995 to Service
Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply
Corporation under Rate Schedule EFT dated August 1,
1993
10.6 Service Agreement with Transcontinental Gas Pipe
Line Corporation under Rate Schedule FT dated
August 1, 1993
10.7 Service Agreement with Transcontinental Gas Pipe
Line Corporation under Rate Schedule FT dated
October 1, 1993
* Service Agreement with Columbia Gas Transmission
Corporation under Rate Schedule FTS, dated November
1, 1993 and executed February 13, 1994.
10.21994
(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.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
10.31994 (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, 1994.1994 (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 scheduleRate Schedule FT-A (Zone 4),
dated September 1, 1993 (Exhibit 10.1, Form 10-K
for fiscal year ended September 30, 1993)1993 in File
No. 1-3880)
* Gas Transportation Agreement with Tennessee Gas
Pipeline Company under rate scheduleRate Schedule FT-A (Zone 5),
dated September 1, 1993 (Exhibit 10.2, Form 10-K
for fiscal year ended September 30, 1993)1993 in File
No. 1-3880)
* Service Agreement with Texas Eastern Transmission
Corporation under rate scheduleRate Schedule CDS, dated June 1,
1993 (Exhibit 10.3, Form 10-K for fiscal year ended
September 30, 1993)1993 in File No. 1-3880)
* Service Agreement with Texas Eastern Transmission
Corporation under rate scheduleRate Schedule FT-1, dated June 1,
1993 (Exhibit 10.4, Form 10-K for fiscal year ended
September 30, 1993)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)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)1993 in File No. 1-3880)
(iii) Compensatory plans for officers:
10.4* Employment Agreement, dated September 17, 1981, with
Bernard J. Kennedy.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, 1993.1993
(Exhibit 10.2, Form 10-Q for the quarterly period ended
March 31, 1993)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)1993
in File No. 1-3880)
* National Fuel Gas Company 1993 Award and Option Plan,
dated February 18, 1993.1993 (Exhibit 10.1, Form 10-Q for
the quarterly period ended March 31, 1993)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)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.Ackerman (Exhibit EX-10.4, Form 10-K for
fiscal year ended September 30, 1992)1992 in File No.
1-3880)
* Change in Control Agreement, dated May 1, 1992, with
Richard Hare.Hare (Exhibit EX-10.5, Form 10-K for fiscal
year ended September 30, 1992)1992 in File No. 1-3880)
* Change in Control Agreement, dated May 1, 1992 with
William J. Hill.Hill (Exhibit EX-10.6, Form 10-K for fiscal
year ended September 30, 1992)1992 in File No. 1-3880)
* Agreement, dated August 1, 1989, with Richard Hare.Hare
(Exhibit 10-Q, Form 10-K for fiscal year ended
September 30, 1989)1989 in File No. 1-3880)
* 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)
10.5 Amendment to Death Benefits Agreement dated March 15, 1994
with Richard Hare.
10.6 Amendment to Death Benefits Agreement dated March 15, 1994
with Philip C. Ackerman.
10.7 National Fuel Gas Company Deferred Compensation Plan,
as amended and restated through May 1, 1994.
10.81994 (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 February 17, 1994
10.9November 1, 1995
* Executive Death Benefits Agreement, dated April 1,
1991, with William J. Hill (Exhibit EX-10.8, Form 10-K
for fiscal year ended September 30, 1992 in File No.
1-3880)
* Split Dollar Death Benefits Agreement, dated April 1,
1991, with Richard Hare (errata).
10.10(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 (errata)
* Eighth Extension to Employment Agreement with Bernard J.
Kennedy, dated September 20, 1991. (Exhibit 10-SS,10.10, Form
10-K for fiscal year ended September 30, 1991)1994 in File
No. 1-3880)
* ExecutiveAmendment 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.Kennedy (Exhibit 10-TT, Form 10-K for fiscal
year ended September 30, 1991)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)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)1993 in File No. 1-3880)
* Excerpts of Minutes from the National Fuel Gas Company
Board of Directors Meeting of December 5, 1991.1991 (Exhibit
10-UU, Form 10-K for fiscal year ended September 30,
1991)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 ScheduleSchedules
(99) Additional Exhibits:
99.1 Report of Ralph E. Davis Associates, Inc.
99.2 System Maps (Not included in EDGAR filing. See
narrative description in the Appendix to this
report.)
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* Incorporated herein by reference as indicated.
SIGNATURESSignatures
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 COMPANYNational Fuel Gas Company
(Registrant)
By/s/---------------------------------
By /s/ B. J. Kennedy
-------------------------------
B. J. Kennedy
Chairman of the Board, President
Date December 22, 199413, 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
DateDate: December 22, 199413, 1995
/s/ P. C. Ackerman Senior Vice President, Principal
P. C. Ackerman Financial Officer and Director
DateDate: December 22, 199413, 1995
/s/ R. T. Brady Director
R. T. Brady
Date: December 13, 1995
/s/ J. M. Brown Director
J. M. Brown
DateDate: December 22, 199413, 1995
/s/ D. N. Campbell Director
D. N. Campbell
DateDate: December 22, 199413, 1995
/s/ W. J. Hill Director
W. J. Hill
Date: December 13, 1995
/s/ L. F. Kahl Director
L. F. Kahl
DateDate: December 22, 1994
13, 1995
/s/ B. S. Lee Director
B. S. Lee
DateDate: December 22, 199413, 1995
/s/ E. T. Mann Director
E. T. Mann
DateDate: December 22, 199413, 1995
/s/ L. Rochwarger Director
L. Rochwarger
DateDate: December 22, 199413, 1995
/s/ G. H. Schofield Director
G. H. Schofield
DateDate: December 22, 199413, 1995
/s/ J. P. Pawlowski Treasurer and
Principal
J. P. Pawlowski Principal Accounting Officer
DateDate: December 22, 199413, 1995
/s/ R.A. M. DiValerioCellino Secretary
R.A. M. DiValerio
DateCellino
Date: December 22, 199413, 1995
/s/ G. T. Wehrlin Controller
G. T. Wehrlin
DateDate: December 22, 199413, 1995
APPENDIX TO ITEM 2 - PROPERTIES
Three maps outlining the System'sCompany's operating areas at September 30, 1994,1995
are inlcudedincluded on page 6 in the paper format version of this the Company's
combined Annual Report to Shareholders/Form 10-K, as exhibit
99.2 andbut are not included in
this electronic filing. The first map identifies the System'sCompany'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 secondthird
map identifiedidentifies the System'sCompany's Pipeline and Storage operating area (i.e.,
Supply Corporation's storage areas and pipelines). The third map identifies the System's Exploration
and Production operating area (i.e., Seneca Resources' operating area).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 19941995
Two pie graphs detailing the revenue dollar in 1994;1995: where it came from
and where it went to, broken down as follows:
Where it came from:
$ .592.581 Residential Sales
.182.178 Commercial, Industrial and IndustrialOff-System Sales
.060 Transportaion.071 Transportation Revenues
.053.048 Oil and Gas Revenues
.044 Natural Gas.042 Marketing Revenues
.034.040 Storage Service Revenues
.035.040 Other Revenues
$1.000 Total
Where it went to:
$ .435.358 Gas Purchased
.165.184 Wages, Including Benefits
.128.138 Taxes
.091.114 Other Materials and Services
.065.073 Depreciation
.051.061 Dividends - Common Stock
.041.055 Interest
.024.017 Reinvested in the Business
$1.000 Total
B. Capital Expenditures
A bar graph detailing capital expenditures (millions of dollars) for the
years 1991 through 1995, broken down as follows:
1991 1992 1993 1994 1995
---- ---- ---- ---- ----
Other Nonregulated $ 1.0 $ 7.2 $ 6.2 $ 3.6 $ 9.6
Pipeline and Storage 58.6 58.7 27.4 20.5 38.7
Exploration and Production 31.7 26.3 36.5 52.5 69.7
Utility Operation 64.9 65.7 61.8 61.7 64.8
------ ------ ------ ------ ------
$156.2 $157.9 $131.9 $138.3 $182.8
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS (Concluded)
B.C. Book Value Per Common Share
A bar graph detailing book value per common share (dollars) for the years
19901991 through 1994, broken down1995, as follows:
1990 - $16.97
1991 - 17.53$17.53
1992 - 18.68
1993 - 20.08
1994 - 20.93
C. Capital Expenditures
A bar graph detailing capital expenditures (millions of dollars) for the
years 1990 through 1994, broken down as follows:
1990 1991 1992 1993 1994
Other Nonregulated $ 2.6 $ 1.0 $ 7.2 $ 6.2 $ 3.6
Pipeline and Storage 42.0 58.6 58.7 27.4 20.5
Exploration and Production 50.8 31.7 26.3 36.5 52.5
Utility Operation 66.1 64.9 65.7 61.8 61.7
$161.5 $156.2 $157.9 $131.9 $138.31995 - 21.39
D. Embedded Cost of Long-Term Debt
A line graph detailing the embedded cost of long-term debt for the years
1990 through 1994, broken down as follows:
Percent
1990 9.4
1991 9.3
1992 8.1
1993 7.3
1994 7.3
E. Capitalization Ratios
A bar graph detailing capitalization (percentage) for the years 19901991
through 1994,1995, broken down as follows:
Debt (%) Equity (%)
1990 56.2 43.8
1991 55.0 45.0
1992 54.5 45.5
1993 47.8 52.2
1994 46.2 53.8
1995 47.0 53.0
Exhibit Index
-------------
3.1 Certificate of Amendment of Restated Certificate of Incorporation of
National Fuel Gas Company, dated March 9, 1987
3.2 Certificate of Amendment of Restated Certificate of Incorporation of
National Fuel Gas Company, dated February 22, 1988
10.1 Service Agreement with Empire State Pipeline under Rate Schedule FT,
dated December 15, 1994. [Portions of this agreement are subject to
a request for confidential treatment under Rule 24b-2]
10.2 Service Agreement between National Fuel Gas Distribution Corporation
and National Fuel Gas Supply Corporation under Rate Schedule ESS
dated August 1, 1993
10.3 Service Agreement between National Fuel Gas Distribution Corporation
and National Fuel Gas Supply Corporation under Rate Schedule ESS
dated September 19, 1995
10.4 Service Agreement between National Fuel Gas Distribution Corporation
and National Fuel Gas Supply Corporation under Rate Schedule EFT
dated August 1, 1993
10.5 Amendment dated as of May 1, 1995 to Service Agreement between
National Fuel Gas Distribution Corporation and National Fuel Gas
Supply Corporation under Rate Schedule EFT dated August 1, 1993
10.6 Service Agreement with Transcontinental Gas Pipe Line Corporation
under Rate Schedule FT dated August 1, 1993
10.7 Service Agreement with Transcontinental Gas Pipe Line Corporation
under Rate Schedule FT dated October 1, 1993
10.8 Amendment to National Fuel Gas Company 1993 Award and Option Plan,
dated October 27, 1995
10.9 Amendment to National Fuel Gas Company Deferred Compensation Plan,
dated September 27, 1995
10.10 National Fuel Gas Company and Participating Subsidiaries Executive
Retirement Plan as amended and restated through November 1, 1995
10.11 Amendment to Death Benefit Agreement of August 28, 1991 with Bernard
J. Kennedy, dated March 15, 1994
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Discussion of the Company's business segments as contained in the
1995 Annual Report and incorporated by reference into this Form 10-K
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
27.1 Financial Data Schedule for 12 months ending September 30, 1995
27.2 Financial Data Schedule for 12 months ending September 30, 1994,
Restated
27.3 Financial Data Schedule for 9 months ending June 30, 1995, Restated
27.4 Financial Data Schedule for 6 months ending March 31, 1995, Restated
27.5 Financial Data Schedule for 3 months ending December 31, 1994,
Restated
99.1 Report of Ralph E. Davis Associates, Inc.