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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
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..........
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
New Jersey 13-1086010
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
10 Lafayette Square 14203
Buffalo, New York (Zip Code)
(Address of principal executive offices)
(716) 857-6980
Registrant's telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
Name of each
exchange
Title of each class on which registered
Common Stock, $1 Par Value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (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 as of November 30, 1994.
Common stock, $1 par value, outstanding as of November 30, 1994:
37,337,056 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for the Annual
Meeting of Shareholders to be held February 16, 1995, 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, 1994
TABLE OF CONTENTS
Page
GLOSSARY OF TERMS 3
PART I
ITEM 1. BUSINESS
COMPANY AND SUBSIDIARIES 6
RATES AND REGULATION 7
UTILITY OPERATION 8
PIPELINE AND STORAGE 14
SELECTED STATISTICS OF THE SYSTEM'S REGULATED OPERATIONS 16
EXPLORATION AND PRODUCTION 17
OTHER NONREGULATED 19
COMPETITION 19
CAPITAL EXPENDITURES 22
ENVIRONMENTAL MATTERS 22
MISCELLANEOUS 22
EXECUTIVE OFFICERS OF THE COMPANY 23
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES 24
EXPLORATION AND PRODUCTION ACTIVITIES 24
ITEM 3. LEGAL PROCEEDINGS
PARAGON/TGX PROCEEDINGS 27
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 30
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
SHAREHOLDER MATTERS 31
ITEM 6. SELECTED FINANCIAL DATA 32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 52
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 95
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 95
ITEM 11. EXECUTIVE COMPENSATION 95
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT 95
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 95
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K 96
SIGNATURES 101
GLOSSARY OF TERMS
The following terms 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 - National Fuel Gas Company.
Condensate - A liquid hydrocarbon recovered at 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 the Holding Company Act,
was organized under the laws of the State of New Jersey in 1902. The Company
is engaged in the business of owning and holding all of the securities of the
subsidiary companies identified below. All references to years in this report
are to the Company's fiscal year ended September 30 unless otherwise noted.
The System constitutes an integrated natural gas operation and consists
of operations which are regulated as to their rates and operations which are
not so regulated. The Regulated Operations fall 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 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.
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.
Distribution Corporation, a New York corporation, is a public utility
that sells natural gas and provides gas transportation service 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 principal metropolitan areas
served are Buffalo, Niagara Falls and Jamestown, New York, and Erie and
Sharon, Pennsylvania.
Supply Corporation, a Pennsylvania corporation, is engaged in the
transportation and storage of natural gas for System and nonaffiliated
companies. Supply Corporation owns and operates an integrated gas pipeline
system extending from southwestern Pennsylvania to the New York-Canadian
border at the Niagara River. Supply Corporation owns and operates 30
underground storage fields in its operating area and four additional
underground storage fields are operated jointly with certain major interstate
pipeline companies.
ITEM 1. BUSINESS (Continued)
Seneca, a Pennsylvania corporation, 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, for the most part, sold to
purchasers located in the vicinity of its wells. In addition, Seneca is
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, 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, operates a sawmill and kiln in
Kane, Pennsylvania.
Data-Track, a New York corporation, provides collection services for the
subsidiaries of the Company, particularly Distribution Corporation, primarily
through the issuance of collection notices.
Leidy Hub, a New York corporation, is a partner in the Ellisburg-Leidy
Northeast Hub Company, which operates a natural gas market area hub in
northeastern Pennsylvania serving the consuming regions of the Northeast,
Mid-Atlantic and Canada. 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 are subject to regulation by the 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-System transactions and limitations on diversification.
Distribution Corporation is subject to regulation by 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 modernization of the Holding Company Act. The SEC has deemed that a
reexamination of the need for, and role of, a federal holding company statute
is necessary in light of recent utility and regulatory developments. The
Company is unable to predict, at this time, what type of modernization may
occur as a result of this reexamination and therefore what the impact will be
on the Company.
ITEM 1. BUSINESS (Continued)
UTILITY OPERATION
Gas Sales and Transportation
The System's Utility Operation is conducted solely through Distribution
Corporation. Substantially all of its sales are requirements sales (i.e.,
sales that vary and are not subject 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 accounted for approximately 52% of System
operating income before income taxes. Information regarding the results of
operations for the Utility Operation can be found in "Management's Discussion
and Analysis of Financial Condition and Results of Operations," on pages 33 to
51 of this report.
On average, 97% of Distribution Corporation's retail customers use gas
for space heating, which makes throughput, for the most part,
weather-sensitive. In Distribution Corporation's 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
tempered by a weather normalization clause that the PSC has authorized in
Distribution Corporation's New York retail jurisdiction. This WNC 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
Northeast and with other companies providing gas storage service. The System
has some unique characteristics which enhance its competitive position. Its
service area, which is located adjacent to Canada 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
production based on price and deliverability.
To compete in this environment, Seneca acts as operator on most
prospects, sheds risk 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 EXPENDITURES
A discussion of capital expenditures by business segment is included in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," on pages 33 to 51 of this report.
ENVIRONMENTAL MATTERS
Supply Corporation is 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. Supply Corporation voluntarily agreed to re-plug 30 wells
which were believed to be venting small amounts of natural gas to the
atmosphere. Twenty-seven of those wells have been plugged, at a cost of
approximately $3.1 million, and the other 3 have been found not 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 natural 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 additional discussion of environmental matters involving the
Company, see Note G - "Commitment and Contingencies" on pages 77 to 79 of this
report.
MISCELLANEOUS
The System had 3,148 regular employees at September 30, 1994, a decrease
of 5.4% from the 3,329 employed at September 30, 1993.
Agreements covering employees in collective bargaining units in the
State of New York were renegotiated in calendar 1994 and are scheduled to
expire in calendar 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 calendar 1996.
System companies have numerous county and municipal franchises under
which they use public roads and certain other rights-of-way and public
property for the location of facilities. System companies have regularly
renewed such franchises at expiration and expect 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 subsidiaries 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 March 16, 1994
Senior Vice President. 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. PROPERTIES
GENERAL INFORMATION ON FACILITIES
The investment of the System in net property, plant and equipment was
$1,542,739,000 at September 30, 1994. Approximately 80% of this investment is
in the System's Utility and Pipeline and Storage segments, which are primarily
located in western New York and western Pennsylvania. The remaining
investment in property, plant and equipment is mainly in the Exploration and
Production Segment, which is primarily located in the Gulf Coast,
southwestern, western and Appalachian regions of the United States.
The Utility Operation has the largest net investment in property, plant
and equipment, compared with the System's other business segments. Most of
this net investment represents its gas distribution network. These properties
include 14,592 miles of pipeline (exclusive of service pipe), which represent
approximately 55% of the Utility Operation's net investment of $787,794,000.
The Pipeline and Storage segment represents a net investment of
$440,810,000 in transmission and storage facilities at September 30, 1994.
Transmission pipeline, with a net cost of $132,591,000, represents 30% of this
segment's total net investment and includes 2,786 miles of pipeline required
to move large volumes of gas throughout the System's service area. Storage
facilities consist of 34 storage fields, four of which are jointly operated
with certain pipeline suppliers, and 512 miles of pipeline. Included in the
storage facilities net investment is $80,942,000 of base gas. The Pipeline
and Storage segment has 31 compressor stations with 72,100 installed
compressor horsepower.
The Exploration and Production segment had a net investment in
properties amounting to $295,419,000 at September 30, 1994. Of this amount,
Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast
regions was $238,175,000, and Seneca's net investment in oil and gas
properties in the Appalachian region aggregated $57,244,000.
During the past five years, the System has made significant additions to
plant in order to expand and improve transmission and distribution facilities
for both retail and wholesale customers and to augment the reserve base of oil
and gas. Net plant has increased $455,276,000, or 42%, since 1989.
The System's facilities provided the capacity to meet the System's 1994
peak day sendout, including transportation service, of 1,988 MMcf, which
occurred on January 19, 1994. Withdrawals from storage provided approximately
47% of the requirements on that day.
System maps are included as Exhibit 99.2 to this report.
EXPLORATION AND PRODUCTION ACTIVITIES
The information that follows is disclosed in accordance with SEC
regulations, and relates to the System's oil and gas producing activities.
For a further discussion of oil and gas producing activities, refer to Note K
- - "Supplementary Information for Oil and Gas Producing Activities," on pages
84 to 88 of this report, and to Exploration and Production on pages 17 to 19
of this report.
ITEM 2. PROPERTIES (Continued)
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 disclosures included 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. 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 K as of
September 30, 1994, were estimated for Seneca by independent petroleum
engineers from Ralph E. Davis, Inc.
The following is a summary of certain oil and gas information taken from
System 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 $ .45 $ .54 $ .62
Productive Wells
At September 30, 1994 Gas Oil
Productive Wells - gross 2,153 201
- net 2,013 172
Developed And 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)
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 3 3
Present Activities
At September 30, 1994
Wells in Process of Drilling - gross 1
- net 1
There are currently no waterflood projects or pressure maintenance
operations of material importance.
ITEM 3. LEGAL PROCEEDINGS
PARAGON/TGX PROCEEDINGS
A. New York Litigation
On November 30, 1984, Distribution Corporation commenced an action
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 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 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, 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.
On December 3, 1991 the U. S. Court of Appeals for the Second Circuit
(the Second Circuit) reversed the District Court's partial summary judgment
and remanded the case to the District Court for further proceedings. The
Second Circuit agreed with the District Court 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.
In a letter dated December 13, 1991, TGX demanded that Distribution
Corporation pay it $21,874,042 (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...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 order from the magistrate
regarding discovery 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 to a partial settlement agreement between TGX and Distribution
Corporation, approved 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 light of the "just and reasonable" standard
of the New York Public Service Law.
Under date of October 25, 1994, the Administrative Law Judge (ALJ) in
this proceeding issued a recommended decision (RD). The RD seemingly
recommends that the maximum price Paragon/TGX should be authorized to receive
for gas delivered in respect of the contract should be $3.714 per Mcf. The
ALJ noted that Distribution Corporation might owe approximately $9.6 million
more 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-half 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 HOLDERS
No matter was submitted to a vote of security holders during the fourth
quarter of 1994.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER
MATTERS
Information regarding the market for the Registrant's common stock and
related shareholder matters appears in Note D - "Capitalization" and Note J -
"Market for Common Stock and Related Shareholder Matters (unaudited)," on
pages 67 to 71 and 83, respectively, of this report, and reference is made
thereto.
ITEM 6. SELECTED FINANCIAL DATA
Year Ended September 30 1994 1993 1992 1991 1990
SUMMARY OF OPERATIONS (Thousands)
Operating Revenues $1,141,324 $1,020,382 $920,450 $865,131 $892,009
Operating Expenses:
Purchased Gas 497,687 409,005 363,690 364,246 415,052
Operation Expense and Maintenance 291,390 283,230 263,084 245,253 227,593
Property, Franchise and Other
Taxes 103,788 95,393 89,158 83,095 75,846
Depreciation, Depletion and
Amortization 74,764 69,425 55,726 50,805 43,740
Income Taxes - Net 47,792 41,046 35,231 23,285 27,480
1,015,421 898,099 806,889 766,684 789,711
Operating Income 125,903 122,283 113,561 98,447 102,298
Other Income 3,656 4,833 5,790 11,793 7,483
Income Before Interest Charges 129,559 127,116 119,351 110,240 109,781
Interest Charges 47,124 51,899 59,041 61,250 57,783
Income Before Cumulative Effect 82,435 75,217 60,310 48,990 51,998
Cumulative Effect of Changes in
Accounting 3,237 - - - -
Net Income Available for Common
Stock $ 85,672 $ 75,217 $ 60,310 $ 48,990 $ 51,998
PER COMMON SHARE DATA
Earnings $2.32* $2.15 $1.94 $1.63 $1.83
Dividends Declared $1.56 $1.52 $1.48 $1.44 $1.38
Dividends Paid $1.55 $1.51 $1.47 $1.43 $1.36
Dividend Rate at Year-End $1.58 $1.54 $1.50 $1.46 $1.42
NUMBER OF COMMON SHAREHOLDERS AT
YEAR-END 22,465 22,893 23,218 22,662 22,203
PROPERTY, PLANT AND EQUIPMENT (Thousands)
Regulated:
Utility Operation $1,036,225 $ 983,417 $ 929,601 $ 871,102 $ 813,736
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 1,294,739
Nonregulated:
Exploration and Production 464,725 415,642 378,815 353,090 323,132
Other 24,938 21,237 15,170 8,202 7,196
489,663 436,879 393,985 361,292 330,328
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 623,517 561,433 502,007 458,763 418,893
Net Plant $1,542,739 $1,478,003 $1,416,382 $1,313,751 $1,206,390
TOTAL ASSETS (Thousands) $1,981,657 $1,801,540 $1,760,830 $1,560,834 $1,436,687
CAPITALIZATION (Thousands)
Common Stock Equity $ 780,288 $ 736,245 $ 632,333 $ 542,109 $ 484,044
Long-Term Debt, Net of Current
Portion 462,500 478,417 479,500 442,071 397,350
Total Capitalization $1,242,788 $1,214,662 $1,111,833 $ 984,180 $ 881,394
* Includes Cumulative Effect of Changes in Accounting of $.09. See Notes A and F
to Consolidated Financial Statements.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
For a graph of "The Revenue Dollar - 1994" see graph A. in the Appendix to
this report.
Results of Operations
1994 Compared with 1993. National Fuel's consolidated earnings were $85.7
million, or $2.32 per common share, in 1994. This included $3.2 million, or
$.09 per common share, related to the cumulative effect of the mandated changes
in accounting for income taxes and post-employment benefits (as adopted in
accordance with the Financial Accounting Standards Board's (FASB) Statements of
Financial Accounting Standards (SFAS) No. 109 and No. 112, respectively).
Earnings before these accounting changes amounted to $82.4 million, an increase
of approximately 10% over 1993 earnings of $75.2 million. On a
per-common-share basis, earnings before the accounting changes were $2.23 for
1994, up 4% from 1993 earnings of $2.15. Share amounts reflect a greater
number of weighted average shares outstanding in the current year, principally
because of the sale of 2.5 million shares of common stock in May 1993.
Earnings growth in 1994 was primarily due to the Company's nonregulated
operations. The Exploration and Production segment's successes have continued
in 1994, with 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 of the Company's natural gas
marketing, pipeline construction and timber operations.
Earnings from the Company's regulated operations, in total, increased in
1994. The Utility Operation's earnings were up slightly over last year because
of higher throughput due to colder weather, as well as State of New York Public
Service Commission (PSC) and Pennsylvania Public Utility Commission (PaPUC)
authorization to earn a return on increased capital investment. The Pipeline
and Storage segment's earnings decreased in 1994 compared with 1993, 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 boosted 1993 earnings.
1993 Compared with 1992. Earnings were $75.2 million in 1993, up $14.9
million, or 25%, over 1992 earnings 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, principally because of the sale of 2.5 million shares of common stock in
each of May 1993 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 offset a decline in the earnings 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 Revenues
1994 Compared with 1993. Operating revenues increased $95.1 million in 1994
compared with 1993. This increase reflects recovery of increased gas costs
mainly due to higher throughput, 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 costs and retain
a portion of the margin on these off-system sales.
Higher retail sales of 5 billion cubic feet (Bcf) resulted primarily from
weather in Distribution Corporation's service territory that was, on average,
6.5% colder than last year. Although industrial 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 customers in the Pennsylvania jurisdiction partially
offset the total increase by approximately 1.6 Bcf. Rates that go into effect
in December 1994 in the Pennsylvania rate jurisdiction compensate for the loss
of throughput related to these customers.
1993 Compared with 1992. Operating revenue increased $96 million in 1993
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 1992 and 1993, and a rate increase in 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 Income
1994 Compared with 1993. Operating income before income taxes increased $3.9
million in 1994 compared with 1993. This increase reflects higher revenues,
discussed above, partly offset by increased operating expenses. The severe
cold weather during January and February 1994 necessitated an unusually high
number of system repairs and related site restoration work, which increased
maintenance expense.
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 last 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%
Purchased Gas. The cost of purchased gas is by far the Company's single largest
operating expense. Annual variations in purchased gas costs can be attributed
directly to changes in gas sales volumes, the price of gas purchased and the
operation of purchased gas adjustment clauses.
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, was $3.74
per thousand cubic feet (Mcf) in 1994, a decrease of 3% from the average cost of
$3.84 per Mcf in 1993. The average cost of purchased gas in 1993 was 22% higher
than the $3.15 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
176.2 167.9 168.5
Pipeline and Storage
Wholesale Sales - 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 Revenues
1994 Compared with 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) Order 636,
which became effective August 1, 1993. Under Order 636, Supply Corporation's
gas purchasing and sales functions were discontinued and replaced with new
transportation and storage services, thus the recovery of purchased gas costs
has been eliminated from Supply Corporation's revenues.
1993 Compared with 1992. Operating revenues increased $35.7 million in 1993
compared with 1992, despite a 30 Bcf decline in throughput. New rates that
became effective 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 Stipulation 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 earnings in the fourth quarter of 1993.
Operating Income
1994 Compared with 1993. Operating income before income taxes decreased $5.1
million in 1994 compared with 1993. This decrease was principally because of
two nonrecurring items reflected in 1993. The favorable 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 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 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.
1993 Compared with 1992. Operating income before income taxes increased $17.6
million in 1993 compared with 1992. This increase was mainly the result of
higher 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 Revenues
1994 Compared with 1993. Operating revenues increased $11.6 million in 1994
compared with 1993. This increase was primarily attributable to Seneca's Gulf
Coast operations and reflects the continued success of both its offshore
drilling program in the Gulf of Mexico and its horizontal drilling program in
central Texas. Gas production and oil production (mainly condensate from gas
wells) hit record levels in 1994 and were up 34% and 59%, respectively, in the
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, the average price received for gas and oil production in 1994
was $2.18 per Mcf and $14.86 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.
1993 Compared with 1992. Operating revenues increased $22.3 million in 1993
compared with 1992. This increase 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 increase 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 Income
1994 Compared with 1993. Operating income before income taxes increased $8.8
million in 1994 compared with 1993. This increase reflects the higher revenues
discussed above, partly offset by higher depletion expense which is directly
related to higher revenues. O & M expense remained basically 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.
1993 Compared with 1992. Operating income before income taxes increased $6
million in 1993 compared with 1992. This increase was also the result of the
increase 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 Revenues
1994 Compared with 1993. Operating revenues increased $29.9 million in 1994
compared with 1993. This increase is almost entirely due to higher revenues
from NFR, 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.
1993 Compared with 1992. Operating revenues decreased $5.4 million in 1993
compared with 1992. This decline reflected lower revenues from UCI, the
Company's 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 Income
1994 Compared with 1993. Operating income before income taxes increased $3.5
million in 1994 compared with 1993. This increase is due to the improved
performance of UCI, which, although still operating at a loss, had higher
margins than in 1993. In addition, the improved performance of NFR and the
Company's timber operations enhanced operating income before income taxes of
this segment.
1993 Compared with 1992. Operating income before 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, mainly because of
increases in pretax income as well as higher income tax rates. In addition, the
increase in income taxes in 1994 reflects lower Section 29 nonconventional fuel
tax credits. These credits, which relate to production from qualified gas
wells, decreased to $1.7 million in 1994, down from $2.6 million in 1993. These
credits are a direct reduction of income tax expense.
Other Income. Other income decreased $1.2 million and $1 million in 1994 and
1993, respectively. 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. Interest on long-term debt decreased $1.8 million and $1.4
million 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.
Other interest charges decreased $3 million and $5.7 million in 1994 and
1993, respectively. The declines in both 1994 and 1993 reflect lower interest
on short-term borrowings because of lower average amounts outstanding. A lower
weighted average interest rate in 1993 also contributed to the decline in
short-term interest. However, 1994 reflects 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 1996 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 LIQUIDITY
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) 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 FLOW
Internally generated cash from operating activities consists of net income
available for common stock, adjusted for noncash expenses, noncash income and
changes in operating assets and liabilities. Noncash items include
depreciation, depletion and amortization, deferred income taxes and allowance
for funds used during construction. In 1994, noncash items also included the
cumulative effect of required changes in accounting for income taxes and
post-employment benefits in accordance with SFAS 109 and SFAS 112, respectively.
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 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 million in 1994,
an increase of $75.5 million compared with the $123.7 million provided by
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
operating activities in 1993. This increase reflected higher revenues and
earnings in the Exploration and Production segment, mainly from its Gulf Coast
operations. The Utility Operation had 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 company refunds received in 1994, thus increasing its cash
flow from operations.
INVESTING CASH FLOW
Capital Expenditures. Capital expenditures totalled $138.3 million in 1994.
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.
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 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 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)
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 in the Pipeline and Storage segment's capital expenditures for
1995 is approximately $5.6 million to 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
territory in the areas north of Buffalo 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 Bcf 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.
Estimated capital expenditures in 1995 for the Exploration and Production
segment are approximately 40% higher than capital spending in 1994 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. The magnitude of
future capital expenditures in the regulated segments depends, to a large
degree, upon market conditions coupled with adequate rate relief.
Other. Cash received on the sale of the Company's investment in property, plant
and equipment is reflected as a cash flow from investing activities.
Approximately $2.3 million of cash was received in the first quarter of fiscal
1994, related to the fiscal 1993 sale of Seneca's interest in its Alberta,
Canada, gas reserves.
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 July 1, 1994, the Company redeemed $19.9 million remaining outstanding
principal amount of 9-1/2% debentures due July 1, 2019, for $21.3 million,
including redemption premium.
On July 14, 1994, the Company issued $50 million of 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. After reflecting
underwriting discounts and commissions, the combined proceeds to the Company of
these two issuances amounted to $99.4 million. The proceeds were used to reduce
outstanding short-term borrowings.
The Company's embedded cost of long-term debt was 7.3% at both September
30, 1994 and 1993.
At September 30, 1994, the Company has Securities and Exchange Commission
(SEC) authority remaining under a shelf registration filed in March 1993 to
issue and sell up to $220 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 $84.3 million during 1994. 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, 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. In addition, the Company has SEC authority
to enter into interest rate swap agreements. For further discussion, see
disclosure under "Financial Instruments" in Note A - Summary of Significant
Accounting Policies.
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 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 MATTERS
Utility Operation
New York Jurisdiction
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 or 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, the PSC issued an order authorizing a base rate increase
of $11.1 million, or 1.7%, with a return on equity of 10.7%. 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. New
rates became effective July 24, 1994.
The recovery 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,
Distribution Corporation received PSC approval for the second year of the
settlement. The approval was for a rate increase of $13.3 million, or 2.1%,
for the 12-month period ended July 31, 1994.
This rate increase went into effect on July 23, 1993.
Pennsylvania Jurisdiction
On March 8, 1994, Distribution Corporation filed in its Pennsylvania
jurisdiction a request for an annual rate increase of $16 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)
General rate increases 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 change 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 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, regulators are expected to focus
on increased utility efficiency.
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, the mechanisms
would allow the PSC to administer financial penalties or rewards determined by
the utility's ability to meet or exceed 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. The more significant ones, 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. It is expected that the PSC will issue an order
addressing key issues 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.
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.
Distribution Corporation is working closely with the state regulatory
commissions to resolve the complexities of industry restructuring.
Pipeline and Storage
For a discussion of Supply Corporation's gathering rates, refer to Note B -
Regulatory Matters.
On October 31, 1994, Supply Corporation filed for an annual rate increase
of $21 million, with a requested return on equity of 12.6%. This rate case was
filed as a result of the FERC's order issued on October 28, 1994, rejecting
Supply Corporation's rate case filed on September 30, 1994. 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 by Penn-York
(Penn-York was merged into Supply Corporation effective July 1, 1994).
On December 30, 1993, the FERC issued an order approving, with slight
modification the Settlement, which was filed with the FERC on October 15, 1993,
respecting two Supply Corporation rate proceedings. As modified, the Settlement
provided for rates that produced annual revenues of approximately $125 million
between July 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 MATTERS
Environmental Matters. The Company is subject to various federal, state and
local laws and regulations relating to the protection of the environment. The
Company has established procedures for on-going evaluation of its operations to
identify potential environmental exposures and assure compliance with regulatory
policies and procedures.
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 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 Company has estimated that clean-up costs
related to the above noted sites are in the range of $6.7 million to $10.1
million. At September 30, 1994, the Company has recorded the minimum liability
of $6.7 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 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 expect to recover
such costs in rates, as the PaPUC and the FERC, respectively, have allowed
recovery of other environmental clean-up costs in rate cases. Accordingly, the
Consolidated Balance Sheets at September 30, 1994, include related regulatory
assets in the amount of approximately $7.3 million, $.6 million of which relates
to costs that have already been incurred.
Effects of Inflation. Although the rate of inflation has been relatively low
over the past few years, and thus has benefited both the Company and its
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 DATA
Index to Financial Statements
Page
Financial Statements:
Report of Independent Accountants 53
Consolidated Statements of Income and
Earnings Reinvested in the Business,
three years ended September 30, 1994 54
Consolidated Balance Sheets at
September 30, 1994 and 1993 55 - 56
Consolidated Statement of Cash Flows,
three years ended September 30, 1994 57
Notes to Consolidated Financial
Statements 58 - 88
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-Valuation and Qualifying Accounts
and Reserves 92
IX -Short-Term Borrowings 93
X -Supplementary Income Statement Information 94
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 I - "Quarterly Financial Data
(unaudited)" and Note K - "Supplementary Information For Oil and Gas Producing
Activities," appears on page 82 and pages 84 to 88, respectively, of this
report, and reference is made thereto.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Report of Independent Accountants
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,
1994 and 1993, and the results of their operations and their cash flows for
each of the three years in the period ended September 30, 1994, 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 F 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, 1994
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
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
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
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)
OPERATING ACTIVITIES
Net Income Available for Common Stock $ 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 74,764 69,425 55,726
Deferred Income Taxes 4,853 16,919 14,125
Other 5,780 5,574 2,997
167,832 167,135 133,158
Change in:
Receivables and Unbilled Utility Revenue 863 (21,531) (12,074)
Gas Stored Underground and Materials and Supplies (15,539) 7,156 (5,221)
Unrecovered Purchased Gas Costs 20,772 (7,739) (7,703)
Prepayments (3,017) (1,489) 2,862
Accounts Payable 23,774 (2,579) 4,349
Amounts Payable to Customers (2,062) (18,808) (6,728)
Other Accruals and Current Liabilities 3,072 15,249 15,704
Other Assets and Liabilities - Net 3,534 (13,691) (31,359)
Net Cash Provided by Operating Activities 199,229 123,703 92,988
INVESTING ACTIVITIES
Capital Expenditures (135,084) (131,926) (157,856)
Other 3,586 225 (2,052)
Net Cash Used in Investing Activities (131,498) (131,701) (159,908)
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial
Paper (84,300) (30,200) 20,500
Proceeds from Issuance of Long-Term Debt 100,000 129,000 251,000
Reduction of Long-Term Debt (19,917) (180,083) (176,729)
Proceeds from Issuance of Common Stock 9,064 78,822 73,728
Dividends Paid on Common Stock (57,157) (52,224) (45,634)
Net Cash Provided by (Used In)
Financing Activities (52,310) (54,685) 122,865
Net Increase (Decrease) in Cash and
Temporary Cash Investments 15,421 (62,683) 55,945
Cash and Temporary Cash Investments at Beginning of Year 13,595 76,278 20,333
Cash and Temporary Cash Investments at End of Year $ 29,016 $ 13,595 $ 76,278
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note A - Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the
accounts of the Company and its subsidiaries, all of which are wholly-owned.
All significant intercompany balances and transactions have been eliminated
where appropriate.
Reclassification. Certain prior year amounts have been reclassified to conform
with current year presentation.
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 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 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" and "Other Regulatory Assets." Refer to the
separate Income Taxes and Unamortized Debt Expense sections of this Note for
further discussion. Other 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. 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. Distribution Corporation's rate
schedules contain clauses that permit adjustment of revenues to reflect price
changes from the cost of purchased gas included in base rates. Differences
between amounts currently recoverable and actual adjustment clause revenues, as
well as other price changes and pipeline and storage company refunds not yet
includable in adjustment clause rates, are deferred and accounted for as either
unrecovered purchased gas costs or amounts payable to customers.
Supply Corporation collects revenues subject to refund if rates in effect
are pending a final rate case determination by the Federal Energy Regulatory
Commission (FERC). Estimated rate refund liabilities are recorded which
reflect management's current estimate as to the ultimate outcome of each rate
case.
Property, Plant and Equipment. The principal assets, consisting primarily of
gas plant in service, are recorded at the historical cost when originally
devoted to service in the regulated businesses, as required by regulatory
authorities. Such cost includes an Allowance for Funds Used During
Construction (AFUDC), which is defined in applicable regulatory systems of
accounts as the net cost of borrowed funds used for construction purposes and a
reasonable rate on other funds when so used. The rates used in the calculation
of AFUDC are determined in accordance with guidelines established by regulatory
authorities.
Included in property, plant and equipment is the cost of gas stored
underground - noncurrent, representing the volume of gas required to maintain
pressure levels for normal operating purposes.
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.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization are computed by application of either the straight-line method or
the gross revenue method, in amounts sufficient to recover costs over the
estimated service lives of property in service, and for oil and gas properties,
over the period of estimated gross revenues from proved reserves. The costs of
unevaluated oil and gas properties are excluded from this calculation. The
provisions for depreciation, depletion and amortization, including amounts
capitalized or charged to other operating accounts, were $75,686,000 in 1994,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
$70,629,000 in 1993 and $56,506,000 in 1992, and were equivalent to 3.9% in
1994, 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and
equipment for those years.
Gas Stored Underground - Current. Gas stored is carried at cost, on a last-in,
first-out (LIFO) basis. Under present regulatory practice, the liquidation of
a LIFO layer is reflected in future gas cost adjustment clauses. Based upon
the average price of spot market gas purchased in September 1994, 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 at September 30, 1994.
Unamortized Debt Expense. Costs associated with the issuance of debt by the
Company are deferred and amortized over the lives of the related issues. Costs
associated with the reacquisition of debt related to rate-regulated
subsidiaries are deferred and amortized over the remaining life of the issue or
the life of the replacement debt in order to match regulatory treatment.
Income Taxes. The Company and its wholly-owned subsidiaries file a
consolidated federal income tax return. Prior to its repeal in 1986,
Investment Tax Credit was either reflected currently in income or deferred and
amortized to income over the estimated useful lives of the related property, as
required by regulatory authorities having jurisdiction.
On October 1, 1993, the Company adopted SFAS 109, "Accounting for Income
Taxes" (SFAS 109). The adoption of SFAS 109 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.
The cumulative effect of this change increased net income by $3,826,000 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 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 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 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, which is when the
underlying hedged commodity transaction occurs.
National Fuel Resources, Inc. (NFR) participates in the natural gas futures
market to lock in natural gas prices to decrease volatility related to
fluctuations in market prices. Futures are not held for trading purposes. At
September 30, 1994, NFR had short positions on futures amounting to
approximately 1.1 Bcf 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.
Consolidated Statement of Cash Flows. For purposes of the Consolidated
Statement of Cash Flows, the Company considers all highly liquid debt
instruments purchased with a maturity of generally three months or less to be
cash equivalents. Interest paid in 1994, 1993 and 1992 was $46,183,000,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
$48,282,000 and $58,530,000, respectively. Net income taxes paid in 1994, 1993
and 1992 were $37,573,000, $19,872,000 and $15,282,000, 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 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.
Earnings Per Common Share. Earnings per common share are calculated using the
weighted average number of shares outstanding during each fiscal year. Common
stock equivalents in the form of stock options do not have a material dilutive
effect on earnings per common share.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note B - Regulatory Matters
Order 636 Transition Costs. As a result of the industrywide restructuring
under the FERC's Order 636, Distribution Corporation is incurring transition
costs billed by Supply Corporation and other upstream pipeline companies.
At September 30, 1994, Distribution Corporation's estimate of its exposure
to outstanding transition cost claims is in the range of $4,600,000 to
$80,700,000. The majority of these costs relate to gas supply realignment
(GSR) costs 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. At September 30, 1994, the Company has
recorded the minimum liability and corresponding regulatory asset of $4,600,000.
Distribution Corporation has authorization from the State of New York Public
Service Commission (PSC) to recover up to $11,000,000 annually of transition
costs from sales customers in New York through 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 recovery 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 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.
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.
Gathering Rates. Supply Corporation has approximately $19,000,000 of
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 because it
is not necessary to provide service to them. The Settlement currently awaits a
FERC decision. The FERC has, however, also directed 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 extension 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)
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
47,792 41,046 35,231
Other Income:
Deferred Investment Tax Credit (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 $42,859 $40,353 $34,525
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) 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 of SFAS 109 (3,826) - -
Miscellaneous (2,918) (1,365) (1,353)
Total Income Taxes $42,859 $40,353 $34,525
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note D - Capitalization
Common Stock. The Company issued 2,500,000 shares of common stock in each of
May 1993 and September 1992. 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 may reinvest cash dividends
and/or make cash investments in the 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.
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. At the discretion of the Company, the shares purchased under the
CSPP are 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. 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 shares
were surrendered and/or cancelled during 1994, 1993 and 1992, respectively.
As of September 30, 1994, a total of 286,308 shares of restricted stock had
been awarded under the 1984 Plan and 1993 Plan, since inception. Restrictions
have lapsed respecting 148,814 of these shares. Of the remaining 137,494
shares of restricted stock, 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. 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)
Redeemable Preferred Stock. As of September 30, 1994, 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. 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
* 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 in 1996, none in 1997, $50,000,000 in 1998 and
$50,000,000 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.
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, the Company issued $50,000,000
of 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. After reflecting
underwriting discounts and commissions, the combined proceeds to the Company of
these issuances amounted to $99,415,500. 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. The Company has authority remaining under this shelf
registration to issue and sell up to $220,000,000 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 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.
The Company may also issue as much as $150,000,000 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 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. 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 available for borrowing
under the discretionary lines of credit is correspondingly reduced. No
borrowings under this arrangement were outstanding at September 30, 1994. The
arrangement expires on September 20, 1995, and the Company expects to renew or
replace all or most of this arrangement before then.
At September 30, 1994, the Company had outstanding notes payable to banks
and commercial paper of $102,500,000 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, respectively.
The weighted average interest rate on notes payable to banks was 5.13% and
3.29% at September 30, 1994 and 1993, respectively. The weighted average
interest rate on commercial paper was 5.09% and 3.32% at September 30, 1994 and
1993, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note F - Retirement Plan and Other Post-Employment Benefits
Retirement Plan. The Company has a tax-qualified, noncontributory,
defined-benefit retirement plan (Plan) that covers substantially all employees
of the Company. The Plan uses years of service, age at retirement and earnings
of employees to determine benefits.
The Company's policy is to fund at least an amount necessary to satisfy the
minimum funding requirements of applicable laws and regulations and not more
than the maximum amount deductible for federal income tax purposes. Plan
funding is subject to annual review by management and its consulting actuary.
Plan assets primarily consist of equity and fixed income investments and units
in commingled funds. A plan amendment was adopted which provided for an early
retirement window program which is 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 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
The projected benefit obligation was determined using an assumed discount
rate of 8.5% in 1994, 7.75% in 1993 and 8.5% in 1992. 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)
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)
Other Post-Retirement 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
in equity securities and municipal bonds.
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 in 1994 compared with the costs based on cash
payments for retiree health care and life insurance benefits of $5,974,000 and
$4,945,000 in 1993 and 1992, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
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
The weighted-average assumed discount rate used in determining the
accumulated post-retirement benefit obligation was 8.5% in 1994. The average
assumed annual rate of salary increase for the applicable life insurance plans
was 5%.
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; 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
o be 14% for 1994. This rate was assumed to decrease gradually to
5.5% by the year 2003 and remain level thereafter.
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)
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 obligation as of October 1, 1993,
would be increased by $26,600,000. This 1% change would also increase the
aggregate of the service and interest cost components of net periodic
post-retirement benefit cost for 1994 by $3,100,000.
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 PSC and the Pennsylvania Public Utility
Commission (PaPUC) and FERC authorization, respectively.
Post-Employment Benefits. In November 1992, the FASB issued SFAS 112,
"Employers' Accounting for Postemployment Benefits" (SFAS 112), which
establishes standards of financial accounting and reporting for benefits, such
as salary continuation, severance pay, workers' compensation and other
disability-related benefits, provided to former or inactive employees
subsequent to employment but prior to retirement. The Company adopted SFAS 112
in the fourth quarter of 1994. Essentially, the new standard required the
Company to change its accounting 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 on 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 ($589,000 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 Income as a cumulative effect of a change in
accounting principle.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note G - Commitments and Contingencies
Leases. System companies have 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 in 1994, $16,864,000 in 1993 and $17,570,000 in 1992.
At September 30, 1994, the future minimum payments under the Company's lease
agreements for the next five years are: $13,075,000 in 1995, $9,779,000 in
1996, $6,959,000 in 1997, $5,021,000 in 1998 and $3,650,000 in 1999. The
future minimum lease payments attributable to later years is $6,059,000.
Obligations Under Firm Contracts. Distribution Corporation has agreements with
five nonaffiliated upstream pipeline companies that provide for the
availability of needed pipeline transportation capacity for periods that extend
through 2004. These agreements provide for payment of a demand or reservation
charge, at FERC-approved rates, for contracted capacity. Distribution
Corporation has various gas purchase agreements with nonaffiliated gas
producers that require payment of fixed monthly charges. These charges are
tied to various indices. These agreements have an average term of six years.
Additionally, Distribution Corporation has agreements with two nonaffiliated
companies for gas storage services through 2004 that require payment of a
demand charge, at FERC-approved rates, for contracted storage. At September
30, 1994, 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 and $6,900,000 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, total gross costs incurred
under these contracts, including commodity charges on actual quantities
shipped, purchased and stored, amounted to $347,100,000.
Environmental Matters. The Company is subject to various federal, state and
local laws and regulations relating to the protection of the environment. The
Company has established procedures for the on-going evaluation of its
operations to identify potential environmental exposures and assure compliance
with regulatory policies and procedures.
Distribution Corporation has 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 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
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
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 $1,600,000 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 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 Company has estimated that clean-up costs
related to the above noted sites are in the range of $6,700,000 to $10,100,000.
At September 30, 1994, the Company has recorded the minimum liability of
$6,700,000. 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
expect to recover such costs in rates, as the PaPUC and the FERC, respectively,
have allowed recovery of other environmental clean-up costs in rate cases.
Accordingly, the Consolidated Balance Sheets at September 30, 1994, include
related regulatory assets in the amount of approximately $7,300,000, $600,000
of which relates to costs that have already been incurred.
The Company has begun a program to comply with 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 are affected by the nitrogen oxide emission standards of the Act.
Supply Corporation incurred capital expenditures for emission controls of
approximately $623,000 in 1994 and expects to incur approximately $4,300,000 in
1995. 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. 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 H - Business Segment Information
The System 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.
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. Pipeline and Storage operations are regulated by the FERC and
are carried out by Supply Corporation. In 1994, 52% 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 southwestern, western and
Appalachian regions of the United States. Utility Constructors, Inc. is
engaged in the Company's pipeline construction operations, Highland Land &
Minerals, Inc. is engaged 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.
The data presented in the tables below reflect the Company's regulated and
nonregulated business segments for the years ended September 30, 1994, 1993 and
1992. 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 and deferred charges.
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
* 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)
Note I - 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, 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. As
discussed in Note F - 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
* Includes Cumulative Effect of Changes in Accounting as discussed above.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
Note J - Market for Common Stock and
Related Shareholder Matters (unaudited)
At September 30, 1994, there were 22,465 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, 1993 and 1994, 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)
Note K - 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
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, consist of
individually insignificant oil and gas leases still early in their primary
terms and individually insignificant unproved perpetual oil and gas rights.
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)
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's 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 Developed and
Undeveloped Reserves:
Beginning 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
Revisions 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 11,437
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(Continued)
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)
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
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
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)
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, 1994
Reserve for Doubtful
Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055
Year Ended September 30, 1993
Reserve for Doubtful
Accounts $ 5,900 $ 8,713 $ - $8,874 $ 5,739
Year Ended September 30, 1992
Reserve for Doubtful
Accounts $ 5,876 $ 9,723 $ - $9,699 $ 5,900
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 borrowings 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 notes 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 DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item concerning the directors of the
Company is omitted pursuant to Instruction G of Form 10-K since the Company's
definitive Proxy Statement for its February 16, 1995 Annual Meeting of
Shareholders will be filed with the SEC not later than 120 days after
September 30, 1994. The information provided in such definitive Proxy
Statement is incorporated herein by reference.
Information concerning the Company's executive officers can be found in
Part I, Item 1, of this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is omitted pursuant to Instruction
G of Form 10-K since the Company's definitive Proxy Statement for its February
16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later
than 120 days after September 30, 1994. The information provided in such
definitive Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is omitted pursuant to Instruction
G of Form 10-K since the Company's definitive Proxy Statement for its February
16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later
than 120 days after September 30, 1994. The information provided in such
definitive Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
At September 30, 1994, the Company knows of no relationships or
transactions required to be disclosed pursuant to Item 404 of Regulation S-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statement Schedules
All financial statement schedules filed as part of this report
are included in Item 8 and reference is made to the index on
page 52 of this report.
(b) Reports on Form 8-K
None
(c) Exhibits.
Exhibit
Number Description of Exhibits
3(i) Articles of Incorporation:
* Restated Certificate of Incorporation of National Fuel Gas
Company, dated March 15, 1985 (Exhibit 10-OO, Form 10-K
for fiscal year ended September 30, 1991)
* 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)
* 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)
3(ii) By-Laws:
3.1 National Fuel Gas Company By-Laws as amended through June
9, 1994
(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), 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)
* 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)
(10) Material Contracts:
(ii) (B) Contracts upon which Registrant's business is substantially
dependent:
10.1 Service Agreement with Columbia Gas Transmission
Corporation under Rate Schedule FTS, dated November 1,
1993 and executed February 13, 1994.
10.2 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)
10.3 Service Agreement with Columbia Gas Transmission
Corporation under Rate Schedule SST, dated November 1,
1993 and executed February 13, 1994.
* Gas Transportation Agreement with Tennessee Gas Pipeline
Company under rate schedule FT-A (Zone 4), dated September
1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1993)
* Gas Transportation Agreement with Tennessee Gas Pipeline
Company under rate schedule FT-A (Zone 5), dated September
1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended
September 30, 1993)
* Service Agreement with Texas Eastern Transmission
Corporation under rate schedule CDS, dated June 1, 1993
(Exhibit 10.3, Form 10-K for fiscal year ended September
30, 1993)
* Service Agreement with Texas Eastern Transmission
Corporation under rate schedule FT-1, dated June 1, 1993
(Exhibit 10.4, Form 10-K for fiscal year ended September
30, 1993)
* 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)
* 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)
(iii) Compensatory plans for officers:
10.4 Employment Agreement, dated September 17, 1981, with
Bernard J. Kennedy.
* National Fuel Gas Company 1983 Incentive Stock Option
Plan, as amended and restated through February 18, 1993.
(Exhibit 10.2, Form 10-Q for the quarterly period ended
March 31, 1993)
* 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)
* National Fuel Gas Company 1993 Award and Option Plan,
dated February 18, 1993. (Exhibit 10.1, Form 10-Q for the
quarterly period ended March 31, 1993)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
* Change in Control Agreement, dated May 1, 1992, with
Philip C. Ackerman. (Exhibit EX-10.4, Form 10-K for
fiscal year ended September 30, 1992)
* Change in Control Agreement, dated May 1, 1992, with
Richard Hare. (Exhibit EX-10.5, Form 10-K for fiscal year
ended September 30, 1992)
* Change in Control Agreement, dated May 1, 1992 with
William J. Hill. (Exhibit EX-10.6, Form 10-K for fiscal
year ended September 30, 1992)
* Agreement, dated August 1, 1989, with Richard Hare.
(Exhibit 10-Q, Form 10-K for fiscal year ended
September 30, 1989)
* 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.
10.8 National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan as amended and restated through
February 17, 1994
10.9 Split Dollar Death Benefits Agreement dated April 1, 1991
with Richard Hare (errata).
10.10 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, Form
10-K for fiscal year ended September 30, 1991)
* Executive Death Benefits Agreement dated August 28, 1991
with Bernard J. 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)
* Summary of Annual at Risk Compensation Incentive Program
(Exhibit 10.10, Form 10-K for fiscal year ended September
30, 1993)
* Excerpts of Minutes from the National Fuel Gas Company
Board of Directors Meeting of December 5, 1991. (Exhibit
10-UU, Form 10-K for fiscal year ended September 30, 1991)
(12) Computation of Ratio of Earnings to Fixed Charges
(21) Subsidiaries of the Registrant:
See Item 1 of Part I of this Annual Report on Form 10-K
Consents of Experts and Counsel:
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
(27) Financial Data Schedule
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 herein by reference as indicated.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
NATIONAL FUEL GAS COMPANY
(Registrant)
By/s/B. J. Kennedy
B. J. Kennedy
Chairman of the Board, President
Date December 22, 1994 and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title
/s/ B. J. Kennedy Chairman of the Board,
B. J. Kennedy President, Chief Executive
Officer and Director
Date December 22, 1994
/s/ P. C. Ackerman Senior Vice President, Principal
P. C. Ackerman Financial Officer and Director
Date December 22, 1994
/s/ J. M. Brown Director
J. M. Brown
Date December 22, 1994
/s/ D. N. Campbell Director
D. N. Campbell
Date December 22, 1994
/s/ L. F. Kahl Director
L. F. Kahl
Date December 22, 1994
/s/ B. S. Lee Director
B. S. Lee
Date December 22, 1994
/s/ E. T. Mann Director
E. T. Mann
Date December 22, 1994
/s/ L. Rochwarger Director
L. Rochwarger
Date December 22, 1994
/s/ G. H. Schofield Director
G. H. Schofield
Date December 22, 1994
/s/ J. P. Pawlowski Treasurer and Principal
J. P. Pawlowski Accounting Officer
Date December 22, 1994
/s/ R. M. DiValerio Secretary
R. M. DiValerio
Date December 22, 1994
/s/ G. T. Wehrlin Controller
G. T. Wehrlin
Date December 22, 1994
APPENDIX TO ITEM 2 - PROPERTIES
Three maps outlining the System's operating areas at September 30, 1994,
are inlcuded in the paper format version of this Form 10-K as exhibit
99.2 and are not included in this electronic filing. The first map
identifies the System's Utility Operating area (i.e., Distribution
Corporation's service area). The second map identified the System'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 - 1994
Two pie graphs detailing the revenue dollar in 1994; where it came from
and where it went to, broken down as follows:
Where it came from:
$ .592 Residential Sales
.182 Commercial and Industrial Sales
.060 Transportaion Revenues
.053 Oil and Gas Revenues
.044 Natural Gas Marketing Revenues
.034 Storage Service Revenues
.035 Other Revenues
$1.000 Total
Where it went to:
$ .435 Gas Purchased
.165 Wages, Including Benefits
.128 Taxes
.091 Other Materials and Services
.065 Depreciation
.051 Dividends - Common Stock
.041 Interest
.024 Reinvested in the Business
$1.000 Total
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION - GRAPHS (Concluded)
B. Book Value Per Common Share
A bar graph detailing book value per common share (dollars) for the years
1990 through 1994, broken down as follows:
1990 - $16.97
1991 - 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 $138.3
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 1990
through 1994, 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