United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
Annual Report Pursuant to Section 13 or 15(d) of
The Securities Exchange Act of 1934
For the Fiscal Year Ended September 30, 19971998
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
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Securities registered pursuant to Section 12(b) of the Act:
Name of each
exchange
Title of each class on which registered
Common Stock, $1 Par Value, and New York Stock Exchange
Common Stock Purchase Rights
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ X ]
The aggregate market value of the voting stock held by nonaffiliates of
the registrant amounted to $1,707,884,000$1,686,072,000 as of November 30, 1997.1998.
Common Stock, $1 Par Value, outstanding as of November 30, 1997:
38,216,9101998:
38,537,997 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Annual Report to Shareholders for 19971998 are
incorporated by reference into Part I of this report. Portions of the
registrant's definitive Proxy Statement for the Annual Meeting of Shareholders
to be held February 26, 199818, 1999 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, 19971998
Table of Contents Page
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Part I
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Item 1. Business
The Company and its Subsidiaries 19
Rates and Regulation 2120
The Utility Segment 21
The Pipeline and Storage Segment 2221
The Exploration and Production Segment 22
The International Segment 22
The Other Nonregulated Segment 2322
Sources and Availability of Raw Materials 2322
Competition 23
Seasonality 2524
Capital Expenditures 2524
Environmental Matters 25
Miscellaneous 25
Executive Officers of the Company 2625
Item 2. Properties
General Information on Facilities 2726
Exploration and Production Activities 27
Item 3. Legal Proceedings 28
Item 4. Submission of Matters to a Vote of Security Holders 28
Part II
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Item 5. Market for the Registrant's Common Stock and Related
Shareholder Matters 2928
Item 6. Selected Financial Data 3029
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 3130
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk 4955
Item 8. Financial Statements and Supplementary Data 4955
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 7886
Part III
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Item 10. Directors and Executive Officers of the Registrant 7886
Item 11. Executive Compensation 7886
Item 12. Security Ownership of Certain Beneficial Owners and
Management 7886
Item 13. Certain Relationships and Related Transactions 7886
Part IV
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Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 7987
Signatures 8290
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This combined Annual Report to Shareholders/Form 10-K contains "forward-looking
statements" as defined by the Private Securities Litigation Reform Act of 1995.
Forward-looking statements should be read with the cautionary statements
included in this combined Annual Report to Shareholders/Form 10-K at Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" (MD&A), under the heading "Safe Harbor for Forward-Looking
Statements." Forward-looking statements are all statements other than statements
of historical fact, including, without limitation, those statements that are
designated with a "1" following the statement, as well as those statements that
are identified by the use of the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts," "projects," and similar expressions.
PART I
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ITEM 1 Business
The Company and its Subsidiaries
National Fuel Gas Company (the Company or Registrant), a registered holding
company under the Public Utility Holding Company Act of 1935, as amended (the
Holding Company Act), was organized under the laws of the State of New Jersey in
1902. The Company is engaged in the business of owning and holding securities
issued by its subsidiary companies. Except as otherwise indicated below, the
Company owns all of the outstanding securities of its subsidiaries. Reference to
"the Company" in this report means the Registrant or the Registrant and its
subsidiaries collectively, as appropriate in the context of the disclosure.
The Company is an integrated natural gas operationa diversified energy company consisting of threefive major
business segments:
1. The Utility segment is carried out by National Fuel Gas Distribution
Corporation (Distribution Corporation), a New York corporation. Distribution
Corporation sells natural gas and provides natural gas transportation services
through a local distribution system located in western New York and northwestern
Pennsylvania (principal metropolitan areas: Buffalo, Niagara Falls and
Jamestown, New York; Erie and Sharon, Pennsylvania).
2. The Pipeline and Storage segment is carried out by National Fuel Gas Supply
Corporation (Supply Corporation), a Pennsylvania corporation, and by Seneca
Independence Pipeline Company (SIP), a Delaware corporation. Supply Corporation
provides interstate natural gas transportation and storage services for
affiliated and nonaffiliated companies through (i) an integrated gas pipeline
system extending from southwestern Pennsylvania to the New York-Canadian border
at the Niagara River, and (ii) 3029 underground natural gas storage fields owned
and operated by Supply Corporation and four other underground natural gas
storage fields operated jointly with various major interstate gas pipeline
companies. SIP has agreed to purchase, upon receipt of regulatory approval, a one-third general partnership interest in Independence
Pipeline Company (Independence), a Delaware general partnership. Independence,
after receipt of regulatory approvals and upon securing sufficient customer
interest, plans to construct and operate the Independence Pipeline, a 370-mile
interstate pipeline system which would transport about 900,000 dekatherms per
day (Dth/day) of natural gas from Defiance, Ohio to Leidy, Pennsylvania.
3. The Exploration and Production segment is carried out by Seneca Resources
Corporation (Seneca), a Pennsylvania corporation, and in California, by Seneca's
wholly-owned subsidiary, HarCor Energy, Inc. (HarCor), a Delaware corporation.
Seneca is engaged in the exploration for, and the development and purchase of,
natural gas and oil reserves in the Gulf Coast of Texas, Louisiana, and Alabama,
in California, in Wyoming, and in the Appalachian region of the United States.
4. The Other NonregulatedInternational segment is carried out by the following
subsidiaries:
* Horizon Energy Development, Inc.
(Horizon), a New York corporation formed in 1995 to engage in foreign and
domestic energy projects through investmentinvestments as a sole or partialsubstantial owner in
various business entities. These entities including Beheer-en-
Beleggingsmaatschappijinclude Horizon Energy Holdings, Inc.,
a New York corporation, which owns 100% of Horizon Energy Development B.V.
(Horizon B.V.) (formerly known as Beheer-en-Beleggingsmaatschappij Bruwabel
B.V. (Bruwabel),). Horizon B.V. is a Dutch company whose principal asset is an equity investment inassets are majority
ownership of (i) Severoceske Teplarny,teplarny, a.s. (SCT), a company with district
heating and power generation operations located in the northern part of the
Czech Republic. Bruwabel also ownsRepublic; (ii) Prvni severozapadni teplarenska, a.s. (PSZT), a wholesale
power and operates an additional district heating plantcompany that is located in close proximity to SCT;
and (iii) Teplarna Kromeriz, a.s., a power development groupdistrict heating company located in the
southeast region of the Czech Republic.
5. The Other Nonregulated segment is carried out by the following subsidiaries:
* National Fuel Resources, Inc. (NFR), a New York corporation engaged in the
marketing and brokerage of natural gas and electricity, and the performance of
energy management services for utilities and end-users located in the
northeastern and midwestern United States;
* Upstate Energy, Inc. (Upstate) (formerly known as Niagara Energy Trading
Inc. (NET)), a New York corporation formed in July 1997 to engage in wholesale natural
gas tradingmarketing and other energy-related activities;
* Niagara Independence Marketing Company (NIM), a Delaware corporation, formed in
September 1997 to ownowns a
one-third general partnership interest in DirectLink Gas Marketing Company
(DirectLink), a Delaware general partnership which will engage in natural gas
marketing and related businesses, in part by subscribing for firm transportation
capacity on the Independence Pipeline (see Pipeline and Storage segment
discussion below);
* Leidy Hub, Inc. (Leidy), a New York corporation engaged in providingformed to provide various
natural gas hub services to customers in the northeastern, mid-Atlantic, Chicago
and Los Angeles areas of theeastern United States and Ontario, Canada, through (i)
Leidy'sa 50%
ownership of Ellisburg-Leidy Northeast Hub Company (a Pennsylvania general
partnership) and (ii) Leidy's 14.5% ownership of Enerchange, L.L.C.
(Enerchange) (a Delaware limited liability company which in turn owns
QuickTrade, L.L.C., another Delaware limited liability company);
* Seneca is also engaged in the marketing of timber from its Pennsylvania land
holdings;
* Highland Land & Minerals, Inc. (Highland), a Pennsylvania corporation which
operates a sawmillseveral sawmills and kilnkilns in Kane, Pennsylvania and a sawmill in Kersey, Pennsylvania;
* Data-Track Account Services, Inc. (Data-Track), a New York corporation which
provides collection services (principally issuing collection notices) for the
Company's subsidiaries (principally Distribution Corporation);subsidiaries; and
* Utility Constructors, Inc. (UCI), a Pennsylvania corporation which
discontinued its operations (primarily pipeline construction) in 1995 and whose
affairs are being wound down.
Financial information about each of the Company's business segments can
be found in Item 8 at Note I - Business Segment Information. No single customer,
or group of customers under common control, accounted for more than 10% of the
Company's consolidated revenues in 1997.1998. All references to years in this report
are to the Company's fiscal year ended September 30 unless otherwise noted.
The discussion of the Company's business segments as contained in the
Letter to Shareholders, which is included on pages 4 to 16 of the paper copy of
the Company's combined Annual Report to Shareholders/Form 10-K, is included in
this electronic filing as Exhibit 13 and is incorporated herein by reference.
Rates and Regulation
The Company is subject to regulation by the Securities and Exchange Commission
(SEC) under the broad regulatory provisions of the Holding Company Act,
including provisions relating to issuance of securities, sales and acquisitions
of securities and utility assets, intra-Company transactions and limitations on
diversification. The SEC hasand Congress have recommended legislation to repeal
conditionally the Holding Company Act, in conjunction with legislation which
would allow the various state regulatory commissions to have access to such
books and records of companies in a holding company system as would be necessary
for effective regulation, and allow for federal audit authority and oversight of
affiliate transactions. However, the additional proposed access to Company books
and records by state regulatory commissions would correspondingly increase the
amount of regulatory burden at the state level. In addition, recent SEC rule
changes have reduced the number of applications required to be filed under the
Holding Company Act, exempted some routine financings and expanded
diversification opportunities. The Company is unable to predict at this time
what the ultimate outcome of legislative and/or regulatory changes will be, and
therefore what the impact on the Company might be.1
The Utility segment's rates, services and other matters are regulated
by the Public Service Commission of the State of New York Public Service Commission (PSC) with respect to
services provided within New York, and by the Pennsylvania Public Utility
Commission (PaPUC) with respect to services provided within Pennsylvania. For
additional discussion of the Utility segment's rates and regulation, see Item 7
under the heading "Rate Matters," and Item 8 at Note B-Regulatory Matters.
The Pipeline and Storage segment's rates, services and other matters
are regulated by the Federal Energy Regulatory Commission (FERC). SIP is not
itself regulated by the FERC, but its sole business will be the ownership of an
interest in Independence, whose rates, services and other matters will be
regulated by the FERC. For additional discussion of the Pipeline and Storage
segment's rates and regulation, see Item 7 under the heading "Rate Matters," and
Item 8 at Note B-Regulatory Matters.
The discussion under Item 8 at Note B-Regulatory Matters, includes a
description of the regulatory assets and liabilities reflected on the Company's
consolidated balance sheetsConsolidated Balance Sheets in accordance with applicable accounting standards.
To the extent that the criteria set forth in such accounting standards are not
met by the operations of the Utility segment or the Pipeline and Storage
segment, as the case may be, the related regulatory assets and liabilities would
be eliminated from the Company's consolidated balance sheetsConsolidated Balance Sheets and such accounting
treatment would be discontinued.
In the International segment, rates charged for the sale of thermal
energy and electric energy at the retail level are subject to regulation and
audit in the Czech Republic by the Czech Ministry of Finance. The regulation of
electric energy rates at the retail level indirectly impacts the rates charged
by the International segment for its electric energy sales at the wholesale
level.
In addition, the Company and its subsidiaries are subject to the same
federal, state and local regulations on various subjects as other companies
doing similar business in the same locations.
This report occasionally refers collectively to the Utility segment and
the Pipeline and Storage segment as the Regulated Operations.
The Company's current operations other than the Utility segment and the
Pipeline and Storage segment are not regulated as to prices or rates for
services. Accordingly, this report occasionally refers collectively to the
Exploration and Production segment and the Other Nonregulated segment as the
Nonregulated Operations.
The Utility Segment
The Utility segment contributed approximately 52%115.3% of the Company's operating
income before income taxes in 1997.1998.
Additional discussion of the Utility segment appears in the Letter to
Shareholders contained in this combined Annual Report to Shareholders/Form 10-K,
below under the headings "Sources and Availability of Raw Materials" and
"Competition," in Item 7 "MD&A," and in Item 8 at Notes B-Regulatory Matters,
H-Commitments and Contingencies and I-Business Segment Information.
The Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 31%66.2% of the
Company's operating income before income taxes in 1997.1998.
Supply Corporation currently has service agreements for substantially
all of its firm transportation capacity, which totals approximately 1,8931,943
million cubic feet (MMcf) per day. The Utility segment has contracted for
approximately 1,126 MMcf per day or 59%58% of that capacity until 2003 and
continuing year-to-year thereafter. An additional 25% of thatSupply Corporation's
firm transportation capacity is subject to firm contracts with nonaffiliated
customers until 2003 or later.
Supply Corporation has available for sale to customers approximately
60.962.8 billion cubic feet (Bcf) of firm storage capacity. The Utility segment has
contracted for 26.0 Bcf or 43%41% of that capacity, in service agreements with
remaining initial terms of approximately 65 to 98 years and continuing
year-to-year thereafter: 23.3 Bcf - 65 years; 2.0 Bcf - 98 years and 0.7 Bcf - 76
years. Nonaffiliated customers have contracted for the remaining 34.936.8 Bcf or 57%59%
of firm storage capacity; 12.1 Bcf or 20%19% of total storage capacity is
contracted by nonaffiliated customers until 2003 or later. The primary terms of current firm storage service agreements
representing 23.3 Bcf of Supply Corporation's firm storage capacity contracted
for by nonaffiliated customers expired in 1995. Service continues year-to-year
and can be terminated or reduced by the customer on one year's notice. When such
terminations or reductions occur, Supply Corporation
has been able to remarket
thesuccessful in marketing and obtaining executed contracts for storage
service under firm contracts, at(at discounted rates. Currently, the
Pipelinerates) as it becomes available and Storage segment is actively marketing 3.3 Bcf of available storage
capacity.expects to continue to
do so.1
Independence has filed with the FERC signed precedent agreements
providing for firm transportation service totallingtotaling about 530,000629,000 Dth/day for
ten years, out of total proposed transportation capacity of about 900,000
Dth/day. The customer for 500,000 Dth/day of that total is DirectLink, which is
owned by the sponsors of the Independence Pipeline.Pipeline, including NIM.
Additional discussion of the Pipeline and Storage segment appears in
the Letter to Shareholders contained in this combined Annual Report to
Shareholders/Form 10-K, below under the headings "Sources and Availability of
Raw Materials" and "Competition," Item 7 "MD&A," and Item 8 at Notes
B-Regulatory Matters and I-Business Segment Information.
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 18%incurred an operating loss before income
taxes as a result of the Company'soil and gas asset impairment it recorded in 1998. The
impact of this segment's operating loss in relation to total operating income
before income taxes in 1997.1998 was negative 86.4%.
Additional discussion of the Exploration and Production segment appears
in the Letter to Shareholders contained in this combined Annual Report to
Shareholders/Form 10-K, below under the heading "Competition," Item 7 "MD&A,"
and Item 8 at Notes A-Summary of Significant Accounting Policies, F-Financial
Instruments, I-Business Segment Information, J-Stock Acquisitions and
L-SupplementaryM-Supplementary Information for Oil and Gas Producing Activities.
The International Segment
The International segment contributed approximately 2.0% of the Company's
operating income before income taxes in 1998.
Additional discussion of the International segment appears in the
Letter to Shareholders contained in this combined Annual Report to
Shareholders/Form 10-K, below under the heading "Sources and Availability of Raw
Materials" and "Competition," Item 7 "MD&A," and Item 8 at Notes F-Financial
Instruments, I-Business Segment Information and J-Stock Acquisitions.
The Other Nonregulated Segment
The Other Nonregulated segment reducedcontributed approximately 5.0% of the Company's
operating income before income taxes slightly (less than 1%) in 1997.1998. The impact of the Corporate
operations reduced the
Company'soperation's operating loss in relation to total operating income before income
taxes by approximately 1%in 1998 was negative 2.1%.
Additional discussion of the Other Nonregulated segment appears in the
Letter to Shareholders contained in this combined Annual Report to
Shareholders/Form 10-K, below under the headings "Sources and Availability of
Raw Materials" and "Competition," Item 7 "MD&A," and Item 8 at Notes F-Financial
Instruments and I-Business Segment Information.
Sources and Availability of Raw Materials
Natural gas is the principal raw material for the Utility segment and some of
the subsidiaries in the Other Nonregulated segment, as discussed below. In 1998,
the Utility segment purchased 117.2 Bcf of gas. Gas purchases from various
producers and marketers in the southwestern United States under long-term (two
years or longer) contracts accounted for 71% of these purchases. Purchases of
gas in Canada and the United States on the spot market (contracts of less than a
year) accounted for 24% of the Utility segment's 1998 gas purchases. Gas
purchases from Southern Company Energy Marketing L.P. and Dynegy Marketing and
Trade (both southwest gas under long-term contracts) represented 12% and 20%,
respectively, of total 1998 gas purchases by the Utility segment. No other
producer or marketer provided the Utility segment with 10% or more of its gas
requirements in 1998.
Supply Corporation transports and stores gas owned by its customers,
whose gas originates in the southwestern and Appalachian regions of the United
States Canada and Appalachia.as well as in Canada. SIP, through Independence, proposes to transport
natural gas produced in Canada and in the midwestern United States. Highland and Seneca's timber operations rely to
a large degree upon timber located on Seneca's lands, so that source and
availability are not issues.
The Exploration and Production segment seeks to discover and
produce raw materials (natural gas, oil and hydrocarbon liquids) as described in
the Letter to Shareholders contained in this combined Annual Report to
Shareholders/Form 10-K, Item 7 "MD&A" and Item 8 at Notes I-Business Segment
Information and LM - Supplementary Information for Oil and Gas Producing
Activities.
In 1997,Coal is the Utilityprincipal raw material for the International segment,
constituting 57% of the cost of materials needed to operate the boilers which
produce steam or hot water. Natural gas, oil and limestone combined account for
the remaining 43% of such materials. Coal is purchased 138.8 Bcf of gas. Gas purchasesand delivered directly
from various producersthe Mostecka Uhelna Spolecnost, a.s. mine for Horizon's largest coal-fired
plant under a contract where price and marketers inquantity are renegotiated each year.
Based on the southwestern United States under
long-term (two years or longer) contracts accounted for 74% of these purchases.
Purchases ofcurrent extraction rate, this mine has proven reserves through
2030. Natural gas in Canada under long-term contracts, purchases of gas in Canadais imported by the Czech Republic government from Russia and
the United States onNorth Sea and is transported through the spot market (contracts of less than a year)government-owned pipeline system
and purchasespurchased by the International segment from Appalachian producers accounted for 3%, 21% and 2%, respectively,two of the Utility segment's 1997eight regional gas
purchases. Gasdistribution companies. Oil is also imported. This segment purchases oil from
Vastar
Resources, Inc.domestic and Natural Gas Clearinghouse (both southwest gas under
long-term contracts) represented 14% and 21%, respectively, of total 1997 gas
purchases by the Utility segment. No other producer or marketer provided the
Utility segment with 10% or more of its gas requirements in 1997.foreign refineries.
The Other Nonregulated segment needs natural gas for its marketing and
Leidy's hub services, but is relatively indifferent as to the source. Highland and Seneca's
timber operations rely to a large degree upon timber located on Seneca's lands,
so that source and availability are not issues.
Competition
Competition in the natural gas industry exists among providers of natural gas,
as well as between natural gas and other sources of energy. The continuing
deregulation of the natural gas industry should enhance the competitive position
of natural gas relative to other energy sources by removing some of the
regulatory impediments to adding customers and responding to market forces.1 In
addition, the environmental advantages of natural gas compared with other fuels
should increase the role of natural gas as an energy source.1 Moreover, natural
gas is abundantly available in North America, which makes it a dependable
alternative to imported oil.
The electric industry is moving toward a more competitive environment
as a result of the Federal Energy Policy Act of 1992 and initiatives undertaken
by the FERC and various states. It is unclear at this point what impact this
restructuring will have on the Company.1
The Company competes on the basis of price, service and reliability,
product performance and other factors. Sources and providers of energy, other
than those described under this "Competition" heading, do not compete with the
Company to any significant extent.
Competition: The Utility Segment
The changes precipitated by the FERC's restructuring of the gas industry in
Order No. 636 are redefining the roles of the gas utility industry and the state
regulatory commissions. The PSC issued an orderState restructuring initiatives are under way, with
regulators in 1995 providingboth New York and Pennsylvania promoting retail competition for
natural gas supply purchases. However, the Utility segmentsegment's traditional
distribution function remains largely unchanged. For further discussion of state
restructuring initiatives refer to implement unbundling of its services. The Utility segment has
implemented most ofItem 7 under the provisions contained in the PSC's 1995 order, and now
offers unbundled, flexible services to its residential, commercial and
industrial customers. At present, these provisions are not advantageous to the
residential customers because of high cost and the resulting lack of interest by
gas marketers in offering residential gas sales. In large part, the high cost is
due to the significant customer protections required of utilities which are then
passed along in rates. Such protections include sufficient contracts to
purchase, transport and store natural gas in the event that it is needed by
residential customers.heading "Rate Matters."
Competition for large-volume customers continues with local producers
or pipeline companies attempting to sell or transport gas directly to end-users
located within the Utility segment's service territories (i.e., bypass). In
addition, competition continues with fuel oil suppliers, and may increase with
electric utilities making retail energy sales.1
The Utility segment is now better able to compete, through its
unbundled flexible services, in its most vulnerable markets (the large
commercial and industrial markets). The Utility segment continues to (i) develop
or promote new sources and uses of natural gas and/or new services, rates and
contracts and (ii) emphasize and provide high quality service to its customers.
Competition: The Pipeline and Storage Segment
Supply Corporation competes for market growth in the natural gas market with
other pipeline companies transporting gas in the northeastern United States and
with other companies providing gas storage services. Supply CorporatonCorporation has some
unique characteristics which enhance its competitive position. Its facilities
are located adjacent to Canada and the northeastern United States, and provide
part of the link between gas-consuming regions of the eastern United States and
gas-producing regions of Canada and the southwestern, southern and midwestern
regions of the United States. This location offers the opportunity for increased
transportation and storage services in the future.1
SIP, through Independence, is competing for customers with other
proposed pipeline projects which would bring natural gas from the Chicago area
to the growing Northeast and Mid-Atlantic U.S. markets. In combination with
expansion projects of Transcontinental Gas Pipe Line Corporation and ANR
Pipeline Company, Independence intends to provide the least-cost path for this
service and will access the storage and market hub at Leidy, Pennsylvania.1 It
is likely that not all of the proposed pipelines will go forward, and that the
first project built will have an advantage over other proposed projects.1
Independence is attempting to be the first of the proposed projects approved by
the FERC and the first built.1 Independence will also create opportunities for
increased transportation and storage services by Supply Corporation.1
Competition: The Exploration and Production Segment
The Exploration and Production segment competes with other gas and oil producers
and marketers with respect to its sales of oil and gas. The Exploration and
Production segment also competes, by competitive bidding and otherwise, with
other oil and gas exploration and production companies of various sizes for
leases and drilling rights for exploration and development prospects.
To compete in this environment, the Exploration and Production segment
originates and acts as operator on most prospects, minimizes risk of exploratory
efforts through partnership-type arrangements, applies the latest technology for
both exploratory studies and drilling operations and focuses on market niches
that suit its size, operating expertise and financial criteria.
Competition: The International Segment
Horizon competes with other entities seeking to develop foreign and domestic
energy projects. Horizon, through SCT and PSZT, faces competition in the sales
of thermal energy to large industrial customers. Currently, electric energy
sales are made to local distribution companies. The Czech Ministry of Finance
has announced plans to privatize the local distribution companies. While it is
expected that these plans will increase competition at the retail level of the
electric energy market, it is unclear at this point what impact this
privatization will have on the wholesale electric energy market.1 Both SCT and
PSZT sell electricity at the wholesale level.
Competition: The Other Nonregulated Segment
In the Other Nonregulated segment, NFR, NETUpstate and NIM, through DirectLink,
compete with other marketers and energy management services providers. Leidy
competes with other natural gas hub service providers. Highland competes with
other sawmills in northwestern Pennsylvania. Horizon competes with other entities
seeking to develop foreign and domestic energy projects.
Seasonality
Variations in weather conditions can materially affect the volume of gas
delivered by the Utility segment, as virtually all of its residential and
commercial customers use gas for space heating. The effect on the Utility
segment in New York is mitigated by a weather normalization clause which is
designed to adjust the rates of retail customers to reflect the impact of
deviations from normal weather. Weather that is more than 2.2% warmer than
normal results in a surcharge being added to customers' current bills, while
weather that is more than 2.2% colder than normal results in a refund being
credited to customers' current bills. In the International segment, district
heating operations in the Czech Republic are also subject to the seasonality of
weather.
Volumes transported and stored by Supply Corporation may vary
materially depending on weather, without materially affecting its earnings.
Supply Corporation's rates are based on a straight fixed-variable rate design
which allows recovery of all fixed costs in fixed monthly reservation charges.
Variable charges based on volumes are designed only to reimburse the variable
costs caused by actual transportation or storage of gas.
Capital Expenditures
A discussion of capital expenditures by business segment is included in Item 7
under the heading "Investing Cash Flow," subheading "Capital Expenditures.Expenditures and
Other Investing Activities."
Environmental Matters
A discussion of material environmental matters involving the Company is included
in Item 8, Note H-Commitments and Contingencies.
Miscellaneous
The Company had 2,524a total of 3,944 full-time employees at September 30, 1997, a decrease1998,
2,554 employees in all of 11.2%its U.S. operations and 1,390 employees in its
International segment. This is an increase of 56% from the 2,8432,524 total employed
at September 30, 1996.1997. Most of the increase (1,356 employees) occurred in the
International segment.
Agreements covering employees in collective bargaining units in New
York were renegotiated in November 1997, effective December 1997, and are
scheduled to expire in February 2001. Agreements covering most employees in
collective bargaining units in Pennsylvania were renegotiated early, effective
April
and May 1996,November 1998, and are scheduled to expire in April and May 1999.2003.
The Company has numerous county and municipal franchises under which it uses
public roads and certain other rights-of-way and public property for the
location of facilities. TheWhen necessary, the Company has regularly renewedrenews such franchises at
expiration and expects no difficulty in continuing to renew them.1
franchises.
Executive Officers of the Company*Company(1)
Age as of Current Company Date Elected To
Name 9/30/9798 Positions Current Positions
---- --------- --------------- -----------------
Bernard J. Kennedy 6667 Chairman of the
Board of Directors. March 21, 1989
Chief Executive
Officer. August 1, 1988
President. January 1, 1987
Director. March 29, 1978
Philip C. Ackerman 5354 Director. March 16, 1994
Senior Vice President. June 1, 1989
President of
Distribution Corporation. October 1, 1995
Executive Vice President
of Supply Corporation. October 1, 1994
President of Horizon. September 13, 1995
President of certain
other subsidiaries of
the Company from prior
to 1992.1993.
Age as of Current Company Date Elected To
Name 9/30/98 Positions Current Positions
---- --------- --------------- -----------------
Richard Hare 5960 President of Supply
Corporation. June 1, 1989
Senior Vice President of
Penn-York Energy Corpor-
ation until its merger
into Supply Corporation
on July 1, 1994. June 1, 1989
President of SIP. September 22, 1997
James A. Beck 5051 President of Seneca. October 1, 1996**1996(2)
President of NET.Upstate. July 18, 1997
President of NIM. September 22, 1997
President of Highland. March 11, 1998
Joseph P. Pawlowski 5657 Treasurer. December 11, 1980
Senior Vice President of
Distribution Corporation. February 20, 1992
Treasurer of
Distribution Corporation. January 1, 1981
Treasurer of
Supply Corporation. June 1, 1985
Secretary of
Supply Corporation. October 1, 1995
Treasurer of SIP. September 22, 1997
Officer of certain other
subsidiaries of the
Company from prior
to 1992.1993.
Gerald T. Wehrlin 5960 Controller. December 11, 1980
Senior Vice President of
Distribution Corporation. April 1, 1991
Controller of Seneca. September 1, 1981
Secretary and Treasurer
of Leidy. September 1, 1993
Vice President
of Horizon. February 21, 1997 ***1997(3)
Officer of certain other
subsidiaries of the
Company from prior to
1992.
Age as of Current Company Date Elected To
Name 9/30/97 Positions Current Positions
---- --------- --------------- -----------------
1993.
Walter E. DeForest 5657 Senior Vice President of
Distribution Corporation. August 1, 1993
President of Leidy. September 1, 1993
Bruce H. Hale 4849 Senior Vice President of February 21, 1997,
Supply Corporation. and from February
21, 1992 through
December 31,
1992.****1992(4)
Vice President of Horizon. September 13, 1995
Age as of Current Company Date Elected To
Name 9/30/98 Positions Current Positions
---- --------- --------------- -----------------
Dennis J. Seeley 5455 Senior Vice President of
Distribution Corporation. February 21, 1997
and from April 1,
1991 through
February 18,
1993 *****1993(5)
David F. Smith 4445 Senior Vice President of
Distribution Corporation. January 1, 1993
Secretary of
Distribution Corporation. June 20, 1986
Officer of certain other
subsidiaries of the
Company from prior
to 1992.1993.
*(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.
**(2) Vice President of Seneca from January 1, 1994 through April 30, 1995,
Executive Vice President of Seneca from May 1, 1995 through September
30, 1996.
***(3) Secretary and Treasurer of Horizon from September 13, 1995 through
February 21, 1997.
****(4) Senior Vice President of Distribution Corporation from April 1, 1991
through February 20, 1992, and again from January 1, 1993 through
February 21, 1997.
*****(5) Senior Vice President of Supply Corporation from January 1, 1993 through
February 21, 1997.
ITEM 2 PROPERTIES
General Information on Facilities
The investment of the Company in net property, plant and equipment was $1,819.4
million$2.2
billion at September 30, 1997.1998. Approximately 74%61% of this investment is in the
Utility and Pipeline and Storage segments, which are primarily located in
western New York and western Pennsylvania. The remaining investment in property,
plant and equipment is mainly in the Exploration and Production segment (28%),
which is primarily located in the Gulf Coast, southwestern, western and
Appalachian regions of the United States.States, and in the International segment (9%)
which is located in the Czech Republic. During the past five years, the Company
has made significant additions to plant in order to expand and improve
transmission and distribution facilities for both retail and transportation
customers, and to augment the reserve base of oil and gas.gas, and to purchase district
heating and power generation facilities in the Czech Republic. Net plant has
increased $403.0$767.3 million, or 28%52%, since 1992.1993.
The Utility segment has the largest net investment in property, plant
and equipment, compared with the Company's other business segments. Its net
investment in its gas distribution network (including 14,76214,784 miles of
distribution pipeline) and its services represent approximately 58% and 28%,
respectively, of the Utility segment's net investment of $899.2$906.8 million.
The Pipeline and Storage segment represents a net investment of $450.9$461.0
million in transmission and storage facilities at September 30, 1997.1998.
Transmission pipeline, with a net cost of $145.1$145.7 million, represents 32% of this
segment's total net investment and includes 2,6772,646 miles of pipeline required to
move large volumes of gas throughout its service area. Storage facilities
consist of 3433 storage fields, 4 of which are jointly operated with certain
pipeline suppliers, and 494490 miles of pipeline. IncludedNet investment in the storage
facilities net investment is $82.1includes $88.6 million of gas stored underground-noncurrent,
representing the cost of the gas required to maintain pressure levels for normal
operating purposes as well as gas maintained for system balancing and other
purposes, including that needed for no-notice transportation service. The
Pipeline and Storage segment has 31 compressor stations with 70,550 installed
compressor horsepower.
The Exploration and Production segment had a net investment in
properties amounting to $443.2$638.9 million at September 30, 1997.1998. Of this amount,
Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast
regions was $388.7$592.9 million, and Seneca's net investment in oil and gas
properties in the Appalachian region aggregated $45.5$46.0 million.
The Regulated Operations'International segment had a net investment in properties amounting
to $202.6 million at September 30, 1998. PSZT's net investment in district
heating and electric generation facilities was $145.7 million; SCT's net
investment in district heating and electric generation facilities was $55.9
million; and Teplarna Kromeriz's net investment in district heating facilities
was approximately $1.0 million.
The Utility and Pipeline and Storage segments' facilities provided the
capacity to meet its 1997fiscal 1998 peak day sendout, including transportation
service, of 2,0471,727 MMcf, which occurred on January 17,December 31, 1997. Withdrawals from
storage provided approximately 41%33% of the requirements on that day.
Company maps, which are included on pagesthe inside front cover and on page
1 and 2 of the paper copy of thethis combined Annual Report to Shareholders/Form 10-K,
are narratively described in the Appendix to this electronic filing and are
incorporated herein by reference.
Exploration and Production Activities
The information that follows is disclosed in accordance with SEC regulations,
and relates to the Company's oil and gas producing activities. A further
discussion of oil and gas producing activities is included in Item 8, Note
L-SupplementaryM-Supplementary Information for Oil and Gas Producing Activities. Note LM sets
forth proved developed and undeveloped reserve information for Seneca. Seneca's
oil and gas reserves reported in Note M as of September 30, 1998, were estimated
by Seneca's qualified geologists and engineers and were audited by independent
petroleum engineers from Ralph E. Davis, Inc. Seneca reports its oil and gas
reserve information, on an annual basis, to the Energy Information
Administration (EIA). The basis of reporting Seneca's reserves to the EIA is
identical to that reported in Note M.
Supply Corporation holds reserves (not included in Note M) related to
held for future use storage wells. Information on such reserves is included on
Supply Corporation's Form 2 "Annual Report of Natural Gas Companies" filed with
the FERC.
Seneca is not regulated by the FERC, and thus is not required to file
Form 2. Seneca's oil and gas reserves reported in Note L as of September 30,
1997, were estimated by Seneca's qualified geologists and engineers and were
audited by independent petroleum engineers from Ralph E. Davis, Inc.
The following is a summary of certain oil and gas information taken
from Seneca's records:
Production
For the Year Ended September 30 1998 1997 1996 1995
- ------------------------------- ---- ---- ----
Average Sales Price per Mcf of GasGas* $ 2.45 $ 2.60 $ 2.35 $ 1.67
Average Sales Price per Barrel of OilOil* $12.15 $20.63 $19.50 $16.16
Average Production (Lifting) Cost per Mcf
Equivalent of Gas and Oil Produced $ 0.45 $ 0.35 $ 0.31
$ 0.44*Prices do not reflect gains or losses from hedging activities.
Productive Wells
At September 30, 19971998 Gas Oil
- --------------------- --- ---
Productive Wells - gross 1,806 2691,925 877
- net 1,718 221
1,821 833
Developed and Undeveloped Acreage
At September 30, 19971998
- ---------------------
Developed Acreage - gross 612,932639,768
- net 538,368558,501
Undeveloped Acreage - gross 886,398926,587
- net 682,520701,241
Drilling Activity
Productive Dry
----------------------------------- ------------------
For the Year Ended September 30 1998 1997 1996 19951998 1997 1996
1995- ------------------------------- ---- ---- ---- ---- ---- ----
Net Wells Completed - Exploratory 10.72 4.21 4.22 4.324.97 3.49 7.35
0.27
- Development 14.11 1.84 8.02 6.162.00 1.60 0 0
Present Activities
At September 30, 19971998
- --------------------------------------------------------------------------------------------------
Wells in Process of Drilling - gross 11.0018.00
- net 7.23
There are currently no14.22
South Lost Hills Waterflood Program
In Seneca's South Lost Hills Field (acquired in 1998 as part of the HarCor and
Bakersfield Energy Resources, Inc. acquisitions) a waterflood projects orproject was
initiated in 1996 on Ellis lease in the Diatomite reservior for pressure
maintenance operationsand recovery enhancement purposes. Currently there are 29 injectors
and 86 producers in the program. The total injection and production from this
waterflood project are 10,000 barrels of material importance.water per day and 400 barrels of oil
per day, respectively. Expansion of the current project is being evaluated by a
reservior simulation program.
ITEM 3 Legal Proceedings
None
ITEM 4 Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter
of 1997.1998.
PART II
-------
ITEM 5 Market for the Registrant's Common Stock and Related Shareholder
Matters
Information regarding the market for the Registrant's common stock and related
shareholder matters appears in Note D-Capitalization and Note K-MarketL-Market for
Common Stock and Related Shareholder Matters (unaudited), under Item 8 of this
combined Annual Report to Shareholders/Form 10-K, and reference is made thereto.
On July 1, 1997,1998, the Company issued 700 unregistered shares of Company
common stock to the seven non-employee directors of the Company, 100 shares to
each such director. These shares were issued as partial consideration for the
directors' service as directors during the quarter ended September 30, 1997,1998,
pursuant to the Company's Retainer Policy for Non-Employee Directors. These
transactions were exempt from registration by Section 4(2) of the Securities Act
of 1933, as amended, as transactions not involving any public offering.
ITEM 6 Selected Financial Data
Year Ended September 30: 1998 1997 1996 1995 1994 1993
- ----------------------- ---- ---- ---- ---- ----
Summary of Operations (Thousands)
Operating Revenues $1,248,000 $1,265,812 $1,208,017 $975,496 $1,141,324
$1,020,382---------- ---------- ---------- -------- ---------- ----------
Operating Expenses:
Purchased Gas 441,746 528,610 477,357 351,094 497,687
409,005Fuel Used in Heat and
Electric Generation 37,592 1,489 - - -
Operation and Maintenance 288,026320,014 286,537 309,206 292,505 291,390 283,230
Property, Franchise and Other
Taxes 92,817 100,549 99,456 91,837 103,788
95,393
Depreciation, Depletion and
Amortization 118,880 111,650 98,231 71,782 74,764
69,425Impairment of Oil and Gas
Producing Properties 128,996 - - - -
Income Taxes - Net24,024 68,674 66,321 43,879 47,792
41,046
--------- ------------------- ---------- ---------- -------- ----------
----------1,164,069 1,097,509 1,050,571 851,097 1,015,421
898,099
--------- ------------------- ---------- ---------- -------- ----------
----------
Operating Income 83,931 168,303 157,446 124,399 125,903
122,283
Other Income 35,870 3,196 3,869 5,378 3,656
4,833
--------- ------------------- ---------- ---------- -------- ---------- ----------
Income Before Interest Charges
and Minority Interest in
Foreign Subsidiaries 119,801 171,499 161,315 129,777 129,559
127,116
Interest Charges 85,284 56,811 56,644 53,883 47,124
51,899
--------- ------------------- ---------- ---------- -------- ----------
Minority Interest in Foreign
Subsidiaries (2,213) - - - -
---------- ---------- ---------- -------- ----------
Income Before Cumulative Effect 32,304 114,688 104,671 75,894 82,435 75,217
Cumulative Effect of Changes in
Accounting (9,116) - - - 3,237
-
--------- ------------------ ---------- ---------- -------- ----------
Net Income Available for Common
Stock $114,688 $104,671$ 23,188 $ 114,688 $ 104,671 $ 75,894 $ 85,672
$ 75,217========== ========== ========== ======== ======== ======== ========== ==========
Per Common Share Data
Basic Earnings Per Common Share $0.61** $3.01 $2.78 $2.03 $2.32*
$2.15Diluted Earnings per Common Share $0.60** $2.98 $2.77 $2.03 $2.31*
Dividends Declared $1.77 $1.71 $1.65 $1.60 $1.56
$1.52
Dividends Paid $1.76 $1.70 $1.64 $1.59 $1.55
$1.51
Dividend Rate at Year-End $1.80 $1.74 $1.68 $1.62 $1.58
$1.54
At September 30:
- ---------------
Number of Common Shareholders 23,743 20,267 21,640 21,429 22,465
22,893
====== ================ ========== ========== ======== ========== ==========
Net Property, Plant and Equipment (Thousands)
Regulated:
Utility $ 906,754 $ 889,216 $ 855,161 $ 822,764 $ 787,794
$ 754,466
Pipeline and Storage 460,952 450,865 452,305 463,647 443,622
436,547
---------- ---------- ---------- ---------- ----------
1,340,081 1,307,466 1,286,411 1,231,416 1,191,013
---------- ---------- ---------- ---------- ----------
Nonregulated:
Exploration and Production 638,886 443,164 375,958 339,950 295,418
273,470International 202,590 942 1,274 70 -
Other 36,110 26,167 22,690Nonregulated 38,946 35,168 24,893 22,620 18,579
16,209
---------- ---------- ---------- ---------- ----------
479,274 402,125 362,640 313,997 289,679
---------- ---------- ---------- ---------- ----------
Corporate 9 11 15 131 137 122
---------- ---------- ---------- ---------- ----------
Total Net Plant $2,248,137 $1,819,366 $1,709,606 $1,649,182 $1,545,550 $1,480,814
========== ========== ========== ========== ==========
Total Assets (Thousands) $2,684,459 $2,267,331 $2,149,772 $2,036,823 $1,980,806 $1,801,540
========== ========== ========== ========== ==========
Capitalization (Thousands)
Common Stock Equity $ 890,085 $ 913,704 $ 855,998 $ 800,588 $ 780,288
$ 736,245
Long-Term Debt, Net of Current
Portion 692,669 581,640 574,000 474,000 462,500 478,417
---------- ---------- ---------- ---------- ----------
Total Capitalization $1,582,754 $1,495,344 $1,429,998 $1,274,588 $1,242,788 $1,214,662
========== ========== ========== ========== ==========
* 1994 includes Cumulative Effect of Changes in Accounting of $0.09 (basic and
diluted), which resulted from the adoption of SFAS 109, "Accounting for
Income Taxes" and SFAS 112, "Employers' Accounting for Postemployment
Benefits".Benefits."
** 1998 includes oil and gas asset impairment of ($2.06) basic, ($2.04) diluted
and cumulative effect of a change in depletion methods of ($0.24) basic and
diluted. Refer to further discussion of these items in Notes to Financial
Statements, Note A - Summary of Significant Accounting Policies.
ITEM 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
1998 Compared with 1997
National Fuel's earnings were $23.2 million, or $0.61 per common share ($0.60
per common share on a diluted basis), in 1998. These earnings include a non-cash
impairment of Seneca's oil and gas assets in the amount of $79.1 million (after
tax), as well as the cumulative effect through October 1, 1997, of a change in
depletion methods for Seneca's oil and gas assets which reduced earnings by $9.1
million (after tax). Without these two non-cash items, earnings for the fiscal
year ended September 30, 1998 would have been $111.4 million, or $2.91 per
common share ($2.88 per common share on a diluted basis). This compares with
earnings of $114.7 million, or $3.01 per common share ($2.98 per common share on
a diluted basis), in 1997. The earnings for 1998 also reflect a net $5.0 million
of after tax income from the settlement of the primary issues relating to IRS
audits of years 1977-1994.
The earnings decrease in 1998 was attributable to lower earnings of the
Company's Utility and Exploration and Production segments, offset in part by
higher earnings in the Pipeline and Storage, International (which incurred a
loss in 1997) and Other Nonregulated segments.
Utility earnings decreased as a result of the impact of warmer weather
in 1998 compared with 1997, and the consequent overall lower usage per account.
In addition, the Utility segment incurred interest expense, net of related rate
recovery, in connection with the settlement of the primary issues relating to
the previously referred to settlement of the IRS audits. Partly offsetting these
negative impacts to earnings was the Utility segment's continued decrease in
operation and maintenance (O&M) expense.
In the Exploration and Production segment, earnings are down mainly
because of low oil prices and decreased gas production. In addition, earnings
were impacted as a result of higher interest costs related to Seneca's
acquisition activities in 1998. (Refer to further discussion of acquisition
activities under "Investing Cash Flow," subheading "Exploration and
Production.") These circumstances more than offset the positive contribution to
earnings that resulted from higher oil production, higher gas prices (after
hedging) and Seneca's portion of interest income related to the previously
mentioned settlement of IRS audits.
In the Pipeline and Storage segment, earnings are up mainly due to
Supply Corporation's portion of interest income from the previously mentioned
settlement of IRS audits. Additional income tax expense related to certain
unsettled issues were also recorded. Also contributing to Supply Corporation's
earnings for the year was a buyout of a firm transportation agreement by a
customer in the amount of $2.5 million. However, lower revenue from unbundled
pipeline sales and open access transportation partly offset these positive
earnings.
The International segment realized increases from Horizon's share of
earnings from its two main investments in district heating and power generation
operations located in the Czech Republic. Horizon initially acquired 36.8% of
SCT in 1997, and increased its ownership during 1998 to 82.7% by September 30,
1998. Horizon also invested in PSZT during 1998 and owned an 86.2% interest at
September 30, 1998.
The Other Nonregulated segment's earnings are up mainly because of
higher earnings in the timber operations, offset in part by higher expenses in
the natural gas marketing operations.
Discussion of Asset Impairment and Cumulative Effect of a Change in Depletion
Method
Seneca follows the full-cost method of accounting for its oil and gas
operations. Under this method, capitalized costs are limited by a present worth
calculation of future revenues from oil and gas assets (full-cost ceiling). Due
to significant declines in oil prices in 1998, Seneca's capitalized costs under
the full-cost method of accounting exceeded the full-cost ceiling at March 31,
1998. Seneca was required to recognize an impairment of its oil and gas
producing properties in the quarter ended March 31, 1998. This charge amounted
to $129.0 million (pretax) and reduced net income for 1998 by $79.1 million
($2.06 per common share, basic; $2.04 per common share, diluted).
Seneca changed its method of depletion for oil and gas properties from
the gross revenue method to the units of production method. The new method was
adopted because it provides a better matching of oil and gas revenues and
depletion expense and is the preferable method used by oil and gas producing
companies. Seneca's recent acquisition activities have increased its scope of
operations in relation to National Fuel's operations. Consequently, the change
in method was warranted. The units of production method was applied
retroactively to prior years to determine the cumulative effect through October
1, 1997. This cumulative effect reduced earnings for 1998 by $9.1 million, net
of income tax ($0.24 per common share, basic and diluted). Depletion of oil and
gas properties for 1998 has been computed under the units of production method.
The effect of the change from the gross revenue method to the units of
production method increased net income for 1998 by $1.4 million ($0.04 per
common share, basic and diluted).
1997 Compared with 1996
National Fuel's earnings were $114.7 million, or $3.01 per common share ($2.98
per common share on a diluted basis), in 1997. This compares with earnings of
$104.7 million, or $2.78 per common share ($2.77 per common share on a diluted
basis), in 1996.
The earnings increase in 1997 was attributable to higher earnings of
the Company's Utility and Pipeline and Storage segments, as well as a reduction
in losses of its Other NonregulatedInternational segment, partly offset by lower earnings of the
Exploration and Production segment.segment and a loss in the Other Nonregulated segment
compared with income in 1996.
Utility earnings increased as a result of new rates effective in
October 1996 and lower operation and maintenance(O&M)O&M expense. Partly offsetting these positive impacts to
earnings was warmer weather in 1997 compared with 1996, as well as the inclusion
in 1996 earnings of a downward revision of estimated purchased gas costs for
1995. The Pipeline and Storage segment earnings increase was attributable to
higher revenue from unbundled pipeline sales and open access transportation, as
well as lower O&M expense for the year. In the Other NonregulatedInternational segment, net losses
in 1997 were significantly less than in 1996. The 1996 losses included expenses
associated with the Company's withdrawal from participation in an international
power project. Exploration and Production earnings decreased as a result of
higher operation and depletion expense, which more than offset increased
revenues resulting from increased prices and thea slight increase in production.
1996 Compared with 1995
National Fuel's earnings were $104.7 million, or $2.78 per common share, in
1996. This compares with earnings of $75.9 million, or $2.03 per common share,
in 1995.
The earnings increase in 1996 was attributable to higher earnings of
the Company's Exploration and Production, Utility, and Pipeline and Storage
segments. The Other Nonregulated segment incurred lossessegment's loss in 1996 as compared
with earnings1997 resulted primarily from increased
depletion expenses in 1995.
Exploration and Production earnings increased because of significant
increases in natural gas and oil production combined with higher gas and oil
prices. The earnings increase of the Utility segment reflects the positive
impact of colder weather, new rates that became effective in September 1995 in
both the New York and Pennsylvania jurisdictions, and the results of
management's emphasis on controlling O&M expense. Also, purchased gas cost
adjustments in the Utilitythis segment's New York jurisdiction increased 1996
earnings. The Pipeline and Storage segment's earnings increase was attributable
to a retroactive rate increase combined with the recording of a reserve for a
storage project in 1995. Partly offsetting the increased earnings of the
Pipeline and Storage segment were lower revenuestimber operations related to unbundled pipeline
sales and open access transportation. An early retirement offer to certain
salaried, non-union hourly and union employees of both the Utility and Pipeline
and Storage segments resulted incutting timber
with a reduction to 1996 earnings for both segments.
The 1996 losses of the Other Nonregulated segment were mainly attributable to
withdrawal from an international power project.higher cost.
Operating Revenues
Year Ended September 30 (Thousands)(thousands) 1998 1997 1996 1995
- -----------------------------------------------------------------------------
Utility
Retail Revenues:
Residential $ 612,647 $ 709,968 $ 678,395
$569,603
Commercial 123,807 167,338 165,824
137,869
Industrial 18,068 22,412 25,648
18,269
- -----------------------------------------------------------------------------
754,522 899,718 869,867
725,741- -----------------------------------------------------------------------------
Off-System Sales 44,479 43,857 30,907
18,255
Transportation 62,844 49,285 49,180
37,183
Other 9,335 (1,494) 4,372
4,885
- -----------------------------------------------------------------------------
871,180 991,366 954,326 786,064
- -----------------------------------------------------------------------------
Pipeline and Storage
Storage Service 63,505 64,221 67,975
59,826
Transportation 94,347 92,858 92,401
88,766
Other 13,131 15,615 16,177
15,995
- -----------------------------------------------------------------------------
170,983 172,694 176,553 164,587
- -----------------------------------------------------------------------------
Exploration and Production 124,272 119,260 114,462
56,232- -----------------------------------------------------------------------------
International 76,259 1,910 286
- -----------------------------------------------------------------------------
Other Nonregulated 83,915 68,930 57,075
- -----------------------------------------------------------------------------
203,175 183,392 113,307106,527 82,005 68,644
- -----------------------------------------------------------------------------
Less: Intersegment Revenues 101,221 101,423 106,254 88,462
- -----------------------------------------------------------------------------
Total Operating Revenues $1,248,000 $1,265,812 $1,208,017 $975,496
=============================================================================
Operating Income (Loss) Before Income
Taxes
Year Ended September 30 (Thousands)(thousands) 1998 1997 1996
1995
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Utility $124,482 $123,856 $115,257 $ 83,774
Pipeline and Storage 71,510 73,523 72,914 67,884
Exploration and Production (93,266) 42,694 46,408
16,404International 2,136 (2,987) (14,281)
Other Nonregulated (743) (8,581) 3,0215,347 2,244 5,700
Corporate (2,254) (2,353) (2,231)
(2,805)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Income Before Income
Taxes $107,955 $236,977 $223,767
$168,278
===========================================================================================================================================================
System Natural Gas Volumes
Year Ended September 30 (billion cubic feet) 1998 1997 1996
1995
- -------------------------------------------------------------------------
RegulatedUtility Gas Sales
Residential 71.7 85.7 90.7
79.9
Commercial 16.4 22.6 24.9
22.2
Industrial 4.3 5.1 6.0
4.8
Off-System 16.2 14.1 11.1
9.4
- -------------------------------------------------------------------------
108.6 127.5 132.7
116.3
- -------------------------------------------------------------------------
NonregulatedNon-Utility Gas Sales
Gas Sales for Resale - - 0.4
Production (equivalent billion cubic feet) 52.2 50.0 49.2 25.4
- -------------------------------------------------------------------------
50.0 49.2 25.8
- -------------------------------------------------------------------------
Total Gas Sales 160.8 177.5 181.9 142.1
- -------------------------------------------------------------------------
Transportation
Utility 59.660.4 57.9 58.2 52.8
Pipeline and Storage 309.3313.1 300.3 325.0
290.8
Nonregulated 0.8 0.5 0.6
2.5
- -------------------------------------------------------------------------
369.4374.3 358.7 383.8 346.1
- -------------------------------------------------------------------------
Marketing Volumes 26.4 21.0 20.2 18.8
- -------------------------------------------------------------------------
Less Intra and Intersegment Volumes:
Transportation 160.4140.8 151.9 157.7
154.2
Production 4.1 4.3 4.8 5.0
Gas Sales - - 0.8
Marketing -
Marketing - 0.1
- - -------------------------------------------------------------------------
164.7144.9 156.2 163.4 159.2
- -------------------------------------------------------------------------
Total System Natural Gas Volumes 403.2416.6 401.0 422.5 347.8
=========================================================================
Utility
Operating Revenues
1998 Compared with 1997
Operating revenues for the Utility segment decreased $120.2 million in 1998
compared with 1997. This decrease primarily reflects the recovery of lower gas
costs which resulted from a decrease in gas sales (an 18.9 billion cubic feet
(Bcf) decrease for 1998) and a decrease in the average cost of purchased gas
(see discussion of purchased gas below under the heading "Purchased Gas"). While
the decrease in gas sales also reflects, in part, the migration of certain
retail customers to transportation service in both the New York and Pennsylvania
jurisdictions as a result of new aggregator services, the major reason for the
decrease stems from warmer weather which was on average 13.8% warmer than the
prior year (see Degree Days table below). The switch to new aggregator services
is discussed further in the "Rate Matters" section that follows.
As of September 30, 1998, Distribution Corporation's 1996 rate
settlement with the State of New York Public Service Commission (PSC) expired.
As part of this rate settlement, Distribution Corporation had put into effect a
$7.2 million annual base rate increase in its New York jurisdiction on October
1, 1997. However, this rate settlement also provided that earnings above a 12%
return on equity (determined on a cumulative basis over the three years ended
September 30, 1998) are to be shared equally between shareholders and customers.
As a result of this sharing mechanism, Distribution Corporation has determined
that the refund due customers is $10.7 million (of which $7.7 million was
recorded in 1998 and $3.0 million was recorded in 1997). These amounts are
included as a reduction of other operating revenues in 1998 and 1997,
respectively.
Also as part of the 1996 rate settlement, Distribution Corporation
was allowed to utilize certain refunds from upstream pipeline companies and
certain credits (referred to as the "refund pool") to offset certain specific
expense items. In September 1998, Distribution Corporation recognized $7.9
million of the refund pool as other operating revenue and recorded an equal
amount of O&M expense in accordance with the settlement agreement.
In addition, 1998 other operating revenues include $6.0 million of
revenue recorded in Distribution Corporation's New York jurisdiction related to
the previously mentioned recent settlement of IRS audits. This $6.0 million
represents the rate recovery (through the above noted refund pool) of interest
expense as allowed by the 1996 rate settlement with the PSC.
1997 Compared with 1996
Operating revenues increased $37.0 million in 1997 compared with 1996. Despite
lower gas sales volumes for residential, commercial and industrial customers (mainly due to weather that was, on average, 5.6% warmer than
the prior year), revenues increased primarily because of the pass through of
increased gas costs higher off-system
sales and thea general base rate increase of $7.2 million in
Distribution Corporation's New York jurisdiction effective October 1, 1996. Gas
costs were up due to a 7% increase in the average costs of purchased gas (see
discussion of purchased gas below under the heading "Purchased Gas"). The increase in
off-system sales reflects the continued emphasis by Distribution Corporation to
utilize available capacity on various upstream pipelines. While off-system sales
contributed to the revenue increase, the margins on such sales, after sharing
with customers, are minimal. Other
operating revenues in 1997 were reduced by a $3.0 million cumulative refund provision to
the Utility's customers for a 50% sharing of earnings over a predetermined amount12% return on
equity as discussed above.
Operating Income
1998 Compared with 1997
Operating income before income taxes for the Utility segment increased $0.6
million in accordance1998 compared with 1997. Excluding the $6.0 million of rate recovery
of interest expense related to the IRS audits, as noted above (this rate
recovery is offset 100% by interest expense, included below the operating income
line), the Utility segment's pretax operating income decreased $5.4 million for
the year ended September 30, 1998. The decrease in operating income before
income taxes resulted primarily from the negative impact of warmer weather and
the related decrease in normalized gas usage per customer account. Partly
offsetting this decrease in operating income before income taxes, the Utility
segment experienced a decrease in O&M expense. This decrease is a result of
management's continued emphasis on controlling costs. Also contributing to this
decrease, 1997 O&M expense included $0.9 million of expenses associated with an
early retirement offer to certain Pennsylvania operating union employees in
1997.
In October 1998, the Company announced an early retirement offer to
certain salaried, non-union hourly and union employees of Distribution
Corporation. The estimated expense to be recorded by the Utility segment in 1999
related to this offer is $4.3 million to $4.7 million.1
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
settlementjurisdiction. In addition, in periods of July 1996.
1996 Compared with 1995
Operating revenues increased $168.3 million in 1996 compared with 1995. This
increase reflects general rate increases incolder than normal weather, the WNC
benefits Distribution Corporation's New York and Pennsylvania rate
jurisdictions, effective in September 1995, pass through of increased gas costs,
higher transportation volumes and higher off-system sales. The base rate
increases amounted to $14.2 million and $6.0 millioncustomers. In 1998, the WNC in New
York preserved pretax operating income of $12.1 million as weather, overall, was
warmer than normal for the period of October 1997 through May 1998. Since the
Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather
variations directly impact pretax operating income and earnings. In the
Pennsylvania respectively.service territory, weather was 15.7% warmer than 1997 and 13.4%
warmer than normal. The recovery of increased gas costs was due to
higher gas sales volumes (mainly due toPennsylvania jurisdiction's warmer weather that was, on average, 16.7%
colder than 1995 as well as a 25% increase in the average cost of purchased gas
(see discussion of purchased gas below under the heading "Purchased Gas").
Higher transportation volumes due to colder weather, new customers and increases
in production at various manufacturing facilities also contributed to higher1998
compared with 1997 lowered pretax operating revenues. The increase in off-system sales reflects the continued
utilization of Distribution Corporation's available capacity on various upstream
pipelines. As noted above, the margins on such sales are minimal.
Operating Incomeincome by approximately $6.2
million.
1997 Compared with 1996
Operating income before income taxes increased $8.6 million in 1997 compared
with 1996. The increase resulted primarily from the increases in 1997 revenue
discussed above, combined with lower O&M expenseexpense. These items were partly offset
by certain purchased gas costs adjustments, totallingtotaling $4.2 million, associated
with lost and unaccounted-for gas in theDistribution Corporation's New York
Division of Distribution Corporationjurisdiction that lowered purchased gas expense in 1996. O&M expense decreased
primarily as a result of an early retirement offer to certain salaried,
non-union hourly and union employees of Distribution Corporation that was
effective October 1, 1996. The 1996 results included expenses for this
retirement offer of $6.4 million. TheO&M expense in 1997 results includeincluded $0.9 million of
operating expenses associated with anexpense for the 1997 early retirement offer to certain Pennsylvania operating union employees in
1997.mentioned above. O&M expense also
decreased as a result of management's continued emphasis on controlling costs.
The impact of weather on Distribution Corporation's New York rate
jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New
York, which covers the eight-month period from October through May, has had a
stabilizing effect on pre-tax operating income and earnings for the New York
rate jurisdiction. In addition, in periods of colder than normal weather, the
WNC benefits Distribution Corporation's New York customers.
In 1997, the WNC in New York resulted in a benefit to customers of $0.2
million as weather, overall, was colder than normal for the period of October
1996 through May 1997. Since
the Pennsylvania rate jurisdiction does not have a
WNC, uncontrollable weather variations directly impact pre-tax operating income
and earnings. In the Pennsylvania service territory, weather in 1997
was 5.5% warmer than last year1996 and 2.8% colder than normal. The Pennsylvania
jurisdiction's warmer weather in 1997 compared with 1996 lowered pre-taxpretax
operating income by approximately $3.2 million.
1996 Compared with 1995
Operating income before income taxes increased $31.5 million in 1996 compared
with 1995. The increase reflects higher gas revenue, as discussed above. It also
reflects certain purchased gas cost adjustments associated with lost and
unaccounted-for gas in Distribution Corporation's New York jurisdiction having a
net impact of reducing purchased gas expense by $4.2 million. Partly offsetting
the above increases was the impact of an early retirement offer to certain
salaried, non-union hourly and union employees of Distribution Corporation
resulting in additional operating expenses in the Utility segment of $6.4
million in 1996. This offer was undertaken as a means to reduce future costs.
In 1996, the WNC in New York resulted in a benefit to customers of
$10.6 million as weather, overall, was colder than normal for the period of
October 1995 through May 1996. In the Pennsylvania service territory, weather in
1996 was 17.1% colder than in 1995 and 8.1% colder than normal. The colder
weather in 1996 compared with 1995 had a positive impact on the Pennsylvania
rate jurisdiction's pre-tax operating income of approximately $7.6 million.
Degree Days
Percent (Warmer) Colder
in 1997-----------------------
Than
-----------------------
Year Ended September 30 Normal Actual Normal 1996Prior Year
- -------------------------------------------------------------------------------
1998: Buffalo 6,689 5,914 (11.6%) (12.9%)
Erie 6,223 5,389 (13.4%) (15.7%)
- -------------------------------------------------------------------------------
1997: Buffalo 6,690 6,793 1.5% (5.7%)
Erie 6,223 6,395 2.8% (5.5%)
- -------------------------------------------------------------------------------
1996: Buffalo 6,728 7,203 7.1% 16.5%
Erie 6,258 6,764 8.1% 17.1%
- -------------------------------------------------------------------------------
1995: Buffalo 6,693 6,181 (7.6%) (11.4%)
Erie 6,128 5,774 (5.8%) (14.2%)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------
Purchased Gas
The cost of purchased gas is by far the Company's single largest operating
expense. Annual variations in purchased gas costs can be attributed directly to
changes in gas sales volumes, the price of gas purchased and the operation of
purchased gas adjustment clauses.
Currently, Distribution Corporation has contracted for long-term firm
transportation capacity with Supply Corporation and six other upstream pipeline
companies, for long-term gas supplies with a combination of producers and
marketers and for storage service with Supply Corporation and three
nonaffiliated companies. In addition, Distribution Corporation can satisfy a
portion of its gas requirements through spot market purchases. Changes in
wellhead prices have a direct impact on the cost of purchased gas. Distribution
Corporation's average cost of purchased gas, including the cost of
transportation and storage, was $4.26$4.13 per thousand cubic feet (Mcf) in 1997, an
increase1998, a
decrease of 7%3% from the average cost of $3.98$4.26 per Mcf in 1996.1997. The average cost
of purchased gas in 19961997 was 25%7% higher than the $3.19$3.98 per Mcf in 1995.1996.
Pipeline and Storage
Operating Revenues
1998 Compared with 1997
Operating revenues decreased $1.7 million in 1998 compared with 1997. The
decrease resulted primarily from lower revenues from unbundled pipeline sales
and open access transportation (a decrease of $2.1 million), lower storage
service revenues (a decrease of $0.7 million), and lower cashout revenue (a cash
resolution of a gas imbalance whereby a customer pays Supply Corporation for gas
it receives in excess of amounts delivered into Supply Corporation's system by
the customer's shipper). Cashout revenues decreased by $1.1 million. However,
there is no earnings impact as cashout revenue is offset by an equal amount of
purchased gas expense. These decreases were partially offset by an increase in
transportation demand charges (approximately $1.8 million) stemming from the
1998 Niagara Expansion Project (see further discussion under "Investing Cash
Flow," subheading "Pipeline and Storage").
Transportation volumes in this segment increased 12.8 Bcf. Generally,
volume fluctuations do not have a significant impact on earnings as a result of
Supply Corporation's straight fixed-variable (SFV) rate design. However, as
mentioned above, the increase in capacity stemming from the 1998 Niagara
Expansion Project contributed to higher demand charge revenue.
1997 Compared with 1996
Operating revenues decreased $3.9 million in 1997 compared with 1996. As
discussed below,The 1996
revenues reflected a rate increase which was retroactive to June 1, 1995. The
retroactive rates added approximately $2.0 million to revenues in 1996 that
related to 1995. The corresponding decrease in 1997 primarily impacted storage
service revenues, which decreased by $3.8 million. In addition to the
retroactive rate impact, storage service revenues decreased as a result of
customers opting for more flexible services at discounted rates. A slight
increase in transportation revenues primarily reflects an increase in surcharge
adjustments. Other operating revenues decreased slightly as higher revenues from
unbundled pipeline sales and open access transportation (an increase of $3.3
million) was more than offset by lower cashout revenue (a cash
resolutiondecrease of a gas imbalance whereby a customer pays Supply Corporation$3.7
million).
Operating Income
1998 Compared with 1997
Operating income before income taxes for gas
it receives in excess of amounts delivered into Supply Corporation's system by
the customer's shipper). Cashout revenue decreased by $3.7 million. However,
there is no earnings impact as cashout revenue is offset by an equal amount of
purchased gas expense.
While transportation volumes in thisPipeline and Storage segment
decreased 15.7 Bcf,$2.0 million in 1998 compared with 1997. As discussed above, the
decrease in volumes did not have a significant impact on earnings as a result of
Supply Corporation's straight fixed-variable (SFV) rate design.
1996 Compared with 1995
Operating revenues increased $12.0 million in 1996 compared with 1995. Higher
transportation and storage revenues reflect the impact of a $6.0 million rate
increase effective on April 1, 1996 retroactiveis primarily attributable to June 1, 1995. The retroactive
rates added approximately $2.0 million to revenues in 1996 that relate to 1995.
Higher volumes of gas transported as well as certain surcharge adjustments also
increased revenues in 1996. Other operating revenues increased only slightly,
but include an increase of approximately $4.6 million related to cashoutlower revenue mostly offset by a decrease of approximately $4.4 million related tofrom unbundled pipeline
sales and open access transportation.
Operating Incometransportation and lower storage service revenues, offset
in part by higher transportation demand charges. There also was an increase in
O&M expense resulting primarily from the establishment of reserves for
preliminary survey and investigation costs associated with the 1999 Niagara
Expansion and Green Canyon projects. The 1999 Niagara Expansion project is
discussed further under "Investing Cash Flow," subheading "Pipeline and
Storage". The reserve related to the Green Canyon project (a natural gas
gathering project offshore and onshore Louisiana) was established due to the
lack of interest at this time by potential customers. Certain of these costs for
which reserves have been established may be recovered at a future date.1 In
addition, Supply Corporation recognized a base gas loss at its Zoar Storage
Field. In total, these three items amounted to $3.7 million. Partially
offsetting these increases in O&M expense was the reversal of a portion of a
reserve set up in a prior period for the Laurel Fields Storage Project. The
Pipeline and Storage segment was able to recapture approximately $1.0 million by
selling preliminary engineering, survey, environmental and archeological
information from the Laurel Fields Storage Project to the Independence Pipeline
Company (the Independence Pipeline project is discussed further under "Investing
Cash Flow," subheading "Pipeline and Storage"). Another decrease to O&M expense
stems from the fact that 1997 O&M expense included $1.0 million of expenses
associated with an early retirement offer to certain Pennsylvania operating
union employees.
In October 1998, the Company announced an early retirement offer to
certain salaried, non-union hourly and union employees of Supply Corporation.
The estimated expense to be recorded by the Pipeline and Storage segment in 1999
related to this offer is $0.7 million to $1.0 million.
1997 Compared with 1996
Operating income before income taxes increased $0.6 million in 1997 compared
with 1996. This slight increase primarily reflects lower O&M expenses (including
labor) combined with higher revenues related to unbundled pipeline sales and
open access transportation. The cost of an early retirement offer to certain
Pennsylvania operating union employees in 1997 resulted in $1.0 million of
additional operating expenses. However, such expenses were $0.8 million less
than the expenses associated with thea 1996 early retirement offer, as discussed
below.offer. Partly
offsetting these increases was the retroactive rate effect recorded in 1996 and
lower storage service revenues, as discussed above.
1996Exploration and Production
Operating Revenues
1998 Compared with 19951997
Operating income before income taxesrevenues increased $5.0 million in 19961998 compared with 1995. This1997. The main
reason for the increase reflectswas the $4.9 million in revenues related to the gas
processing plant that was acquired as part of the HarCor and Bakersfield Energy
Resources (BER) acquisitions in 1998 (see further discussion of these
acquisitions under "Investing Cash Flow," subheading "Exploration and
Production"). While this gas processing plant contributed a large amount of
revenue, increase discussed abovethis revenue was basically offset by an equal amount of expense.
Gas production revenues, net of hedging activities, decreased $1.1
million as a result of decreased production, offset in part by higher gas prices
(after hedging) (the weighted average gas price after hedging increased $0.09
per Mcf). Refer to the tables below for production and price information. The
gas production declines were mainly due to the shut-in of production during the
Gulf hurricane season and tropical storms, as well as the recordingexpected decline in
production of a $3.7 million reserveWest Cameron 552 and delays in drilling due to lack of rig
availability in the fourth quarterfirst half of 1995 for
previously deferred preliminary survey and investigation charges for a storage
project. Partly offsetting the year. Oil production revenues, net of
hedging activities, were basically even with the prior year as increased
production was offset by lower oil prices (after hedging). The weighted average
oil price after hedging decreased $4.92 per barrel (bbl). The increase in oil
production was mainly the impactresult of higher operating
expenses, including an early retirement offer to certain salaried, non-union
hourly and union employees of Supply Corporation resulting in additional
operating expensesWest Coast production from the properties
acquired in the PipelineWhittier, HarCor and Storage segment of $1.8 million in 1996.
This offer was undertaken as a means to reduce future costs.
Exploration and Production
Operating RevenuesBER acquisitions.
1997 Compared with 1996
Operating revenues increased $4.8 million in 1997 compared with 1996. Gas
production revenues, net of hedging activities, increased $9.4$2.2 million as a
result of higher prices (after hedging) (the weighted average gas price after
hedging increased $0.25$0.07 per Mcf) slightly offset by decreased natural gas
production. Oil production revenues, net of hedging activities, increased $5.3$2.8
million as a result of increases in oil production and prices.offset in part by lower oil
prices (after hedging). The weighted average oil price increased $1.13after hedging decreased
$0.06 per barrel (bbl) (See tables below).bbl. The increase in oil production iswas the result of a full year of
production in 1997 at Vermilion 252 compared with only seven months in 1996.
Partly offsettingRefer to tables below for production and price information.
Production Volumes
Year Ended September 30 1998 1997 1996
- ---------------------------------------------------------------
Gas Production
(million cubic feet)
Gulf Coast 29,461 32,377 32,355
West Coast 2,146 1,135 990
Appalachia 4,867 5,074 5,422
- ---------------------------------------------------------------
36,474 38,586 38,767
===============================================================
Oil Production
(thousands of barrels)
Gulf Coast 1,228 1,404 1,195
West Coast 1,376 490 533
Appalachia 10 8 14
- ---------------------------------------------------------------
2,614 1,902 1,742
===============================================================
Average Prices
Year Ended September 30 1998 1997 1996
- ---------------------------------------------------------------
Average Gas Price/Mcf
Gulf Coast $2.40 $2.60 $2.33
West Coast $2.14 $1.79 $1.25
Appalachia $2.88 $2.79 $2.65
Weighted Average $2.45 $2.60 $2.35
Weighted Average After Hedging $2.27 $2.18 $2.11
- ---------------------------------------------------------------
Average Oil Price/bbl
Gulf Coast $14.69 $21.37 $20.45
West Coast* $ 9.85 $18.49 $17.41
Appalachia $16.80 $21.28 $18.43
Weighted Average $12.15 $20.63 $19.50
Weighted Average After Hedging $13.03 $17.95 $18.01
- --------------------------------------------------------------
*1998 includes high gravity oil which generally sells for a lower price.
Seneca utilizes price swap agreements to manage a portion of the increasemarket
risk associated with fluctuations in gas and oil revenue was the recognitionprice of a pre-tax loss on hedging of approximately $21.5 million compared
with a pre-tax loss of $11.8 million in 1996. Gains or losses on hedging
activities are offset by lower or higher prices received for actual natural gas and crude oil production.oil.
Refer to further discussion of the Company'sthese hedging activities under "Financing Cash Flow""Market Risk
Sensitive Instruments" and in Note F - Financial Instruments in Item 8 of this
report.
1996 Compared with 1995
Operating revenues increased $58.2 million in 1996 compared with 1995. Gas
revenues increased $56.2 million as a result of an 85% increase in natural gas
productionThe following summarizes Seneca's settlements under price swap
agreements during 1998, 1997 and an increase in the weighted average gas price of $0.68 per Mcf.
Oil revenues increased $22.0 million as a result of production, which was more
than twice the prior year, and an increase in the weighted average oil price of
$3.34 per bbl (See tables below). In 1995, natural gas and oil production was
delayed when prices were low in order to preserve the value received for
reserves. Increased production reflects offshore finds at West Cameron 552 and
Vermilion 252 and the acquisition of West Delta Block 30 in September 1995, as
well as production from the 1995 Hamp Lease acquisition in California. Partly
offsetting the above increases in gas and oil revenues was the recognition of a
pre-tax loss on hedging of approximately $11.8 million in 1996 compared with a
pre-tax gain of $6.9 million in 1995. Refer to further discussion of the
Company's hedging activities under "Financing Cash Flow" and in Note F -
Financial Instruments in Item 8 of this report.
Production Volumes1996:
Year Ended September 30 (thousands of dollars) 1998 1997 1996
1995
- ------------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Production
(million cubic feet)
Gulf Coast 32,377 32,355 14,294
West Coast 1,135 990 840
Appalachia 5,074 5,422 5,808Price Swap Agreements:
Notional Quantities - -----------------------------------------------------------
38,586 38,767 20,942
===========================================================Equivalent Bcf 26.4 24.9 23.0
Gain (Loss) ($6,375) ($16,387) ($9,231)
Crude Oil Production
(thousands of barrels)
Gulf Coast 1,404 1,195 287
West Coast 490 533 433
Appalachia 8 14 19Price Swap Agreements:
Notional Quantities - -----------------------------------------------------------
1,902 1,742 739
===========================================================
Weighted Average Prices*
Year Ended September 30 1997 1996 1995Equivalent bbls 901,000 1,371,500 1,071,000
Gain (Loss) $2,299 ($5,090) ($2,606)
- -----------------------------------------------------------
Weighted Average Gas Price/Mcf
Gulf Coast $2.60 $2.33 $1.56
West Coast $1.79 $1.25 $1.33
Appalachia $2.79 $2.65 $2.01
Weighted Average Price $2.60 $2.35 $1.67
- -----------------------------------------------------------
Weighted Average Oil Price/bbl
Gulf Coast $21.37 $20.45 $16.94
West Coast $18.49 $17.41 $15.66
Appalachia $21.28 $18.43 $15.72
Weighted Average Price $20.63 $19.50 $16.16
*Weighted average prices do not reflect gains or losses from hedging activities.-------------------------------------------------------------------------------
Operating Income
1998 Compared with 1997
The Exploration and Production segment experienced an operating loss before
taxes of $93.3 million compared with operating income before taxes of $42.7
million in 1997, a negative variation of $136.0 million. Excluding the $129.0
million non-cash impairment of this segment's oil and gas assets, as discussed
previously, this segment had operating income before taxes of $35.7 million, a
decrease of $7.0 million compared with the prior year. This decrease resulted
from lower gas production revenues, net of hedging, as discussed above and
higher lease operating expense. The increase in lease operating expenses stems
from the additional operating costs of the Whittier, HarCor and BER properties.
As previously discussed, Seneca changed its method of depletion for oil and gas
producing properties from the gross revenue method to the units of production
method. Depletion of oil and gas properties for 1998 has been computed under the
units of production method which resulted in depletion expense that was $2.3
million less than it would have been under the gross revenue method.
1997 Compared with 1996
Operating income before income taxes decreased $3.7 million in 1997 compared
with 1996. This decrease reflects higher depletion expense and higher operating
expenses (lease operating expenses, salary expenses and production taxes) due to
increased activities, which more than offset the increase in revenues, discussed
above.
1996International
Operating Revenues
1998 Compared with 19951997
Operating income before income taxesrevenues increased $30.0$74.3 million in 19961998 compared with 1995. This1997. The
increase primarily reflects 100% of the higher operating revenues discussed above,
partly offsetof SCT and PSZT for 1998.
Horizon acquired a 34% equity interest in SCT in April 1997, subsequently
increasing that interest to 36.8% by higher depletion expenseSeptember 30, 1997 (and thus accounted for
its investment in SCT under the equity method in 1997). During 1998, Horizon
increased its ownership in SCT to 82.7% as of September 30, 1998. In February
1998, Horizon acquired a 75.3% equity interest in PSZT and higher operating expenses (lease
operating expensessubsequently
increased its ownership interest to 86.2% as of September 30, 1998. The
consolidation method was used to account for the investments in SCT and production taxes) due to increased production.
Other Nonregulated
OperatingPSZT
during 1998.
Heating and Electric Sales of SCT and PSZT
Year Ended September 30, 1998 (thousands of dollars)
Volumes Revenues
----------------------------------------- --------
Heating Sales 6,870,921 Gigajoules*(6.5 Bcf Equivalent) $47,953
Electricity Sales 763,823 Megawatt hours $22,772
*Gigajoules = one billion joules. A joule is a unit of energy.
1997 Compared with 1996
Operating revenues increased $15.0$1.6 million in 1997 compared with 1996. This
increase represents twelve months of operations in 1997 of Teplarna Kromeriz, a
small district heating plant located in the Czech Republic. There were only
three months of reported operations in 1996.
Operating Income
1998 Compared with 1997
Operating income before income taxes for the International segment increased
$5.1 million in 1998 compared with 1997. The current year reflects 100% of the
revenues and pretax operating income of SCT as well as 100% of the revenues and
pretax operating income of PSZT for February through September 1998. The
minority interests in SCT and PSZT are shown separately on the Consolidated
Statement of Income after operating results. In 1997, Horizon had a 36.8% equity
interest in SCT and thus recorded its share of SCT's operating results below the
operating income line in "Other Income."
Because of the change in the nature of operations of the International
segment during the past year, operating income comparisons between the current
period and prior periods may not be meaningful. Future revenues from district
heating operations are expected to fluctuate with changes in weather.1 The
Company expects that rates charged for the sale of thermal energy and electric
energy at the retail level will be subject to regulation and audit in the Czech
Republic by the Czech Ministry of Finance.1
1997 Compared with 1996
Operating losses before income taxes for the International segment decreased
from $14.3 million in 1996 to $3.0 million in 1997. This decrease in operating
losses relates primarily to $9.0 million of nonrecurring expenses incurred in
1996 by Horizon, relating to its withdrawal from participation in an
international power project in August 1996. In 1997, Horizon sold its right to
this power project for approximately $2.8 million, including cash proceeds and
the assumption of certain liabilities by the purchaser.
Other Nonregulated
Operating Revenues
1998 Compared with 1997
Operating revenues increased $24.5 million in 1998 compared with 1997. This
increase reflects higher operating revenues from NFR, the Company's gas
marketing subsidiary, and the Company's timber operations. NFR's operating
revenues increased because of an increase in marketing volumes. Partially
offsetting this, NFR recognized a pretax gain on exchange-traded futures and
options of approximately $1.3 million in 1998 compared to a pretax gain of
approximately $1.7 million in 1997. Refer to further discussion of the Company's
hedging activities under "Market Risk Sensitive Instruments" and in Note F -
Financial Instruments in Item 8 of this report. Operating revenues for the
timber operations increased as a result of higher timber sales by Seneca and
increased lumber sales resulting from Highland's purchase in 1998 of two new
lumber mills. Highland also had a full year of production from the mill it
purchased in January 1997.
1997 Compared with 1996
Operating revenues increased $13.4 million in 1997 compared with 1996. The
increase primarily reflects higher operating revenues from NFR the Company's
gas marketing subsidiary, and Highland, the Company's sawmill and timber
subsidiary.Highland.
NFR's operating revenues increased largely because of higher natural gas prices
and an increase in marketing volumes. Also, NFR recognized a pre-taxpretax gain on
exchange-traded futures contractsand options of approximately $1.4$1.7 million during 1997
compared to a pre-taxpretax gain of approximately $1.0 million in 1996. Refer to
further discussion of the Company's hedging activities under "Financing Cash Flow""Market Risk
Sensitive Instruments" and in Note F - Financial Instruments in Item 8 of this
report. Highland's operating revenues increased as a result of increased lumber
sales resulting from the operation of a new lumber mill beginning in January
1997.
1996Operating Income
1998 Compared with 19951997
Operating revenuesincome before income taxes increased $11.9$3.1 million in 19961998 compared
with 1995. The1997. This increase primarily reflects higher operating revenuesresulted from NFR, largely because
of higher natural gas prices and an increase in marketing volumes. Also, NFR
recognized a pre-tax gain on futures contractspretax operating income
from the timber operations due to increased revenues discussed above offset in
part by lower pretax operating income of approximately $1.0 million
during 1996 compared to a pre-tax gain of approximately $0.2 million in 1995.
Offsetting thisNFR. NFR's increase was a decrease in operating
revenuesrevenue noted above was substantially offset by increased gas costs. In
addition, NFR had an increase in O&M expense, resulting from UCI, the
Company's discontinued pipeline construction subsidiary.
Operating Incomeexpansion of its
customer base into new market areas.
1997 Compared with 1996
The Other Nonregulated segment experienced an operating lossOperating income before income taxes of $0.7decreased $3.5 million in 1997 as compared
with an operating1996. This decrease was principally due to a pretax loss before income taxes
of $8.6 million in 1996. The decrease in operating loss relates primarily to
expenses incurred in the prior year by Horizon, the Company's foreign and
domestic energy projects subsidiary, relating to its withdrawal from
participation in an international power project in August 1996. In 1997, Horizon
sold its rights to this power project for approximately $2.8 million, including
cash proceeds and the assumptiontimber
operations as a result of certain liabilities by the purchaser. As
discussed below, the entire project was written off in 1996. Partly offsetting
the lower losses of Horizon was increased depletion expenses in this segment's
timber operationsexpense related to cutting timber
with a higher cost.
1996 Compared with 1995
The Other Nonregulated segment experienced an operating loss before income taxes
of $8.6 million in 1996 compared with operating income before income taxes of
$3.0 million in 1995. Expenses incurred by Horizon were the main factors in this
decrease. In August 1996, Horizon withdrew from participation in the development
of a 151 megawatt power plant near Kabirwala, Punjab Province, in east-central
Pakistan (Kabirwala Project). As a result of this withdrawal, certain
pre-operating costs were charged to earnings. Total pre-tax charges in 1996
associated with the Kabirwala Project were approximately $9.0 million. UCI also
experienced a significant decrease in operating income before income taxes as a
result of discontinuing its pipeline construction operations late in 1995. NFR
experienced an increase in operating income before income taxes based primarily
on increased volumes marketed.
Income Taxes, Other Income and Interest Charges
Income Taxes
Income taxes decreased $44.7 million in 1998 primarily as a result of a decrease
in pretax income. Income taxes increased $2.4 million and $22.4 million in 1997 and 1996,
respectively, mainly becauseprimarily as a
result of an increase in pre-taxpretax income. For further discussion of income taxes,
refer to Note C Income Taxes in Item 8 of this report.
Other Income
Other income increased $32.7 million in 1998 and decreased $0.7 million in 1997.
The 1998 increase in other income is primarily due to $18.5 million of interest
income which resulted from the current year settlement of IRS audits. The 1998
increase is also due to a gain, net of hedging, of $5.1 million associated with
U.S. dollar denominated debt carried on the balance sheet of PSZT (see further
discussion regarding this PSZT debt in Note D - Capitalization and $1.5Note F -
Financial Instruments in Item 8 of this report), as well as $1.3 million of
interest income on temporary cash investments of SCT and PSZT. In addition,
other income in 19971998 increased from a buyout of a firm transportation agreement
by a Pipeline and 1996,
respectively.Storage segment customer in the amount of $2.5 million.
The 1997 decrease resulted, in part, from certain nonrecurring items
recorded in 1996 for Supply Corporation, including a gain on disposition of
property, as well as interest income related to a retroactive rate settlement.
In addition, the 1997 decrease reflects losses from Leidy Hub's equity
investment in various gas hub partnerships and losses from Horizon's equity
investment in Severoceske Teplarny, a.s. (SCT).SCT. The SCT losses relate to the period April 1997 (when Horizon
made its initial equity investment in SCT) through September 30, 1997. Since SCT
is a heating utility, it typically experiences losses during the summer months.
The 1996 decrease resulted
primarily because 1995 included a gain of $2.5 million recorded by UCI on the
sale of its pipeline construction equipment. This was partly offset by the
nonrecurring items, noted above, that were recorded in 1996.
Interest Charges
Interest on long-term debt increased $11.0 million in 1998 and $1.3 million in
1997; however, it did not
change significantly in 1996 compared with 1995.1997. The increase in 1998 and 1997 can be attributed to a higher average amount
of long-term debt outstanding, in 1997,
offset slightly by a lower average interest rate.
Although there was a higher
average amount ofIn 1998, long-term debt outstanding in 1996 comparedbalances grew significantly as a result of the stock
acquisitions of SCT, PSZT and HarCor combined with 1995, this
was almost completely offset by a lower average interest rate.the Whittier and BER asset
purchases. These acquisitions and asset purchases are discussed further under
"Investing Cash Flow," subheadings "International" and "Exploration and
Production."
Other interest charges increased $17.5 million in 1998 and decreased
$1.1 million in 19971997. The increase in 1998 resulted primarily from interest
expense related to the previously mentioned settlement of IRS audits (total
interest expense related to the IRS audits amounted to $11.7 million). In
addition, the increase in other interest for 1998 resulted from an increase in
the average amount of short-term debt outstanding. Short-term debt was initially
utilized to fund the acquisition activities in the International and increased
$2.8 millionExploration
and Production segments, as mentioned above, until a portion was replaced with
long-term debt in 1996.May 1998. Furthermore, short-term debt was used to repay the
long-term debt that matured in 1998. The decrease in 1997 resulted primarily
from lower interest expense on Amounts Payable to Customers offset in part by
higher interest on short-term borrowings because of higher average amounts
outstanding.
The increase in 1996 resulted primarily from a higher average balance of
outstanding short-term borrowings offset partly by a lower weighted average
interest rate on such borrowings. Additionally, 1996 experienced an increase in
interest expense as a result of higher interest on Amounts Payable to Customers.
Capital Resources and Liquidity
The primary sources and uses of cash during the last three years are summarized
in the following condensed statement of cash flows:
Sources (Uses) of Cash
Year Ended September 30 (in millions) 1998 1997 1996
1995
- ------------------------------------------------------------------------------------------------------------------------------------------
Provided by Operating Activities $253.0 $294.7 $168.5
$174.4
Capital Expenditures (393.2) (214.0) (171.6)
(182.8)Investment in Subsidiaries,
Net of Cash Acquired (112.0) (21.1) -
Other Investing Activities 2.1 1.4 (1.4)
Short-Term Debt, Net Change 229.4 (107.3) 52.1 35.1
Long-Term Debt, Net Change 94.9 98.2 11.2 3.1
Issuance of Common Stock 7.9 7.1 9.0
2.5
Common Stock Dividends (67.0) (64.3) (61.2)
(59.2)
Investment in Unconsolidated
Foreign Subsidiary (21.1)Dividends Paid to Minority
Interest (0.3) - -
Other Investing Activities 1.4 (1.4) 10.6Effect of Exchange Rates on Cash 1.6 - ---------------------------------------------------------------------
- ----------------------------------------------------------------------
Net Increase (Decrease) in Cash
and Temporary Cash Investments $16.4 $(5.3) $6.6
$(16.3)
==========================================================================================================================================
Operating Cash Flow
Internally generated cash from operating activities consists of net income
available for common stock, adjusted for noncash expenses, noncash income and
changes in operating assets and liabilities. Noncash items include the
cumulative effect of a change in accounting for depletion, the impairment of oil
and gas producing properties, depreciation, depletion and amortization, deferred
income taxes, minority interest in foreign subsidiaries and allowance for funds
used during construction.
Cash provided by operating activities in the Utility and Pipeline and
Storage segments may vary substantially from year to year because of the impact
of rate cases. In the Utility segment, supplier refunds, over- or
under-recovered purchased gas costs and weather also significantly impact cash
flow. The Company considers supplier refunds and over-recovered purchased gas
costs as a substitute for short-term borrowings. The impact of weather on cash
flow is tempered in the Utility segment's New York rate jurisdiction by its WNC
and in the Pipeline and Storage segment by Supply Corporation's SFV rate design.
Net cash provided by operating activities totalled $294.7totaled $253.0 million in
1997, an increase1998, a decrease of $126.2$41.7 million compared with the $168.5$294.7 million provided by
operating activities in 1996.1997. The majority of this increasedecrease occurred in the
Utility segment. The Utility segment asexperienced a result of an increasedecrease in cash receipts
from gas sales and transportation service (sales were down mainly due to warmer
weather) and an increase in interest payments (primarily related to the recent
settlement of IRS audits). Also, the Utility segment received a netlarge refund
from an upstream pipeline company in 1997 which did not recur in 1998. A portion
of this refund was passed back to customers in 1998. These decreases to cash
were partially offset by lower cash payments for gas purchases.
The Exploration and Production segment experienced a decrease in cash
provided by operating activities. Lower cash receipts from the sale of oil and
gas combined with higher operating costs (primarily due to the Whittier, HarCor
and BER acquisitions) were partially offset by interest income resulting from
the aforementioned IRS settlement, a decrease in cash outlays for hedging
transactions as well as a decrease in cash outlays for federal taxes.
Partly offsetting the decreases discussed above, the International and
Pipeline and Storage segments experienced increases in cash provided by
operating activities. The International segment benefitted from the results of
operations of SCT and PSZT while the Pipeline and Storage segment experienced an
increase in cash provided by operating activities primarily because of interest
income resulting from the aforementioned IRS settlement combined with cash
received as refunds from upstream
pipelines, and lower O&M costs. Lower O&Ma customer resulting from a buyout of a firm transportation
agreement. Higher operating costs partially offset the increases to cash
provided by operating activities in the Pipeline and Storage segment also contributed to the increase as did an increase in cash receipts
from gas and oil sales in the Exploration and Production segment.
Investing Cash Flow
Capital Expenditures and Other Investing Activities
Capital expenditures represent the Company's additions to property, plant and
equipment and are exclusive of equity investments in corporations (stock
acquisitions) and/or partnerships. Such investments are treated separately in
the Statement of Cash Flows and discussed further in the segment discussion
below.
The Company's cash outlay for capital expenditures totalled $214.0and other investments totaled
$520.7 million in 1997. Noncash capital expenditures totalled $12.3 million in the
Other Nonregulated segment and related to Seneca's issuance of long-term notes
to third parties in exchange for land and timber.1998. The table below presents these capital expenditures and
other investments by business segment:
Year Ended September 30, 1998 (in millions)
1997
- ----------------------------------------------------------------------------------------
Total Capital
Expenditures
Capital Other and Other
Expenditures Investments Investments
------------ ----------- -----------
Utility $ 66.950.7 $ - $ 50.7
Pipeline and Storage 22.623.7 5.5 29.2
Exploration and Production 120.3293.9 32.6(1) 326.5
International 14.7 89.4(2) 104.1
Other Nonregulated 16.510.2 - ---------------------------------------------
$226.3
=============================================
Most10.2
------ ------ ------
$393.2 $127.5 $520.7
====== ====== ======
(1) Investment, net of cash acquired = $29.8 million.
(2) Investments, net of cash acquired = $82.2 million.
Utility
The majority of the Utility segment's capital expenditures were made for the replacement of
mains and main extensions, as well as for the replacement of service lineslines.
Pipeline and to a minor extent, the installation of new services.Storage
The bulkmajority of the Pipeline and Storage segment's capital expenditures were made for
additions, improvements and replacements to this segment's transmission and
storage systems. Approximately $4.2 million was spent on the 1998 Niagara
Expansion Project. As part of this expansion, Supply Corporation began
transportation service for an additional 25,000 Dth per day in November 1997. In
November 1998, Supply Corporation began transportation service for an additional
23,000 Dth per day of firm winter only capacity. As there has not been much
interest in further expansion in this area at this time, the Company established
a reserve in March 1998 for approximately $1.7 million (pretax) related to
preliminary survey and investigation costs associated with the proposed 1999
Niagara Expansion Project.
Seneca Independence Pipeline Company (SIP) made a $5.5 million
investment in 1998 representing a one-third general partnership interest in
Independence Pipeline Company, a Delaware general partnership. This investment
was financed with short-term borrowings. Independence Pipeline Company intends
to build a 370 mile natural gas pipeline from Defiance, Ohio to Leidy,
Pennsylvania at an estimated cost of $675 million.1 If the Independence Pipeline
Project is not constructed, SIP's share of the development costs (including
SIP's investment in Independence Pipeline Company) is estimated not to exceed
$6.0 million to $8.0 million.1
Exploration and Production
In March 1998, Seneca acquired properties in the Midway-Sunset and North Lost
Hills Field in the San Joaquin Basin of California from the Whittier Trust
Company for approximately $141.0 million. This acquisition is included in the
Exploration and Production capital expenditure amount in the table above.
In May and June 1998, Seneca acquired the oil and gas properties
located in the South Lost Hills Field in the San Joaquin Valley near
Bakersfield, California, that were owned 75% by HarCor and 25% by BER. These
properties produce gas and high gravity oil, include a gas processing plant and
associated pipelines, and provide opportunities for additional drilling and
development.1
The acquisition of HarCor's portion of these properties was completed
in May 1998 through a tender offer (an offer of $2.00 per share) for the
outstanding shares of HarCor. Approximately 95% of the outstanding shares of
HarCor common stock were tendered in accordance with the tender offer. The
common stock that was not purchased pursuant to the tender offer was converted
into the right to receive $2.00 per share. The cost of the tender offer and
subsequent conversion of the remaining shares of HarCor was approximately $32.6
million. The stock acquisition resulted in the assumption of approximately $64.7
million of long-term debt at the date of acquisition (refer to Note D -
Capitalization in Item 8 of this report).
The acquisition of BER's portion of these properties was completed in
June 1998 through an asset purchase. The purchase price was approximately $30.0
million. This acquisition is included in the Exploration and Production capital
expenditure amount in the table above.
The acquisitions of Whittier, HarCor and BER were initially financed
using short-term borrowings. Subsequently, approximately $120 million of
short-term borrowings were replaced with long-term borrowings. These
acquisitions complement the Exploration and Production segment's reserve mix,
bringing its new reserve base to approximately 725 Bcf equivalent, of which 55%
is oil and 45% is gas.
Other Exploration and Production segment spentcapital expenditures
included approximately $96.6$98.6 million on itsthe offshore program in the Gulf of
Mexico, including offshore drilling expenditures, geological expendituresoffshore construction and
lease acquisitions.acquisition costs. Offshore exploratory and development drilling was concentrated on Ship Shoal 258,
Vermilion 225, High
Island 194, Main Pass 256, Main Pass 257, West Cameron 182,
West Delta 30,179, High Island A354, High Island A356, Vermilion 309, Eugene Island 47
and South Marsh Island 122. Offshore construction occurred primarily at West
Cameron 540 and Vermilion 309, Galveston 210, High Island A364309. Lease acquisition costs resulted from successful
bidding on fourteen state of Texas and High Island 179. Offshorethree federal lease acquisitionstracts in the Gulf of
Mexico combined with the acquisition of a 50% interest in Vermilion 253.
The remaining $24.3 million capital expenditures included South Marsh Island
122, Mustang Island 796onshore
drilling and 818 in Texas state waters and Eugene Island 9 and 91construction costs for wells located in Louisiana, state waters. Other offshore acquisitions included East Cameron 36,
Visca Knowl 564, Oxy-High Island A356, Barrett-High Island A364 and Shell-High
Island 179.
Approximately $23.7 million was spent on the Exploration and Production
segment's onshore program, including horizontal drilling in central Texas and
developmentalCalifornia as well as onshore geological and exploratory drillinggeophysical costs, including the
purchase of certain 3-D seismic data.
International
In fiscal 1998, Horizon acquired additional shares of SCT thereby increasing its
equity interest in California.SCT to 82.7% as of September 30, 1998. The cost of acquiring
these additional shares was approximately $24.9 million. This stock acquisition
resulted in the assumption of approximately $5.1 million of long-term debt at
the date of acquisition (refer to Note D - Capitalization in Item 8 of this
report).
In addition, acquisitions
included leasesFebruary 1998, Horizon acquired a 75.3% equity interest in CaliforniaPSZT and
Wyoming.subsequently increased its ownership interest to 86.2% as of September 30, 1998.
The cost of acquiring the shares of PSZT was approximately $64.5 million. This
stock acquisition resulted in the assumption of approximately $59.2 million of
long-term debt (refer to Note D - Capitalization in Item 8 of this report) and
$4.3 million of short-term debt at the date of acquisition.
Short-term borrowings were initially used to finance the acquisition
costs of SCT and PSZT. Subsequently, approximately $80 million of short-term
borrowings were replaced with long-term borrowings.
The bulk of the International segment capital expenditures were made by
PSZT for the reconstruction of boilers at its heating plant to comply with
stricter clean air standards. Short-term borrowings and cash from operations
were used to finance these capital expenditures.
Other Nonregulated
Other Nonregulated capital expenditures consisted primarily of timberland purchases.timber purchases
by the northeast division of Seneca as well as equipment purchases by Highland
for its existing sawmill and kiln operations and the purchase of two new
sawmills in Pennsylvania. The capital expenditures also included the purchase of
furniture, equipment and computer hardware and software for NFR's gas marketing
operations.
Other Investing Activities
Other cash provided by or used in investing activities primarily reflects cash
received on the sale of various subsidiaries investments in property, plant and
equipment, cash received on the sale of the Company's interest in Enerchange,
L.L.C., a natural gas hub partnership, and cash used to make an initial
investment in Independence Pipeline Company.
Estimated Capital Expenditures and Other Investments
The Company's estimated capital expenditures for the next three years are:1
Year Ended September 30 (in millions) 1998 1999 2000 2001
- --------------------------------------------------------------------
Utility $51.9 $56.9 $55.9$48.9 $47.9 $46.9
Pipeline and Storage 28.027.0 20.5 20.5
Exploration and Production 132.2 143.9 139.692.0 126.1 128.8
International 35.6 5.8 5.5
Other Nonregulated 0.3 0.3 0.30.9 0.8 0.8
- --------------------------------------------------------------------
$212.4 $221.6 $216.3$204.4 $201.1 $202.5
====================================================================
Estimated capital expenditures for the Utility segment during the next
three years will be concentrated in the areas of main improvements, replacements
and extensions, service line replacements and, to a minor extent, the
installation of new services.1
Estimated capital expenditures for the Pipeline and Storage segment in
1998 will be concentrated in the reconditioning of storage wells and the
replacement of storage and transmission lines.1
Approximately $6.4 million is included in
the 1998 budget for the Niagara Expansion Project, which would provide
approximately 25,000 Dekatherms (Dth) per day of firm year-round capacity and
23,000 Dth per day of firm winter only capacity from the Niagara Falls, New York
import point to interconnections at Leidy and Wharton, Pennsylvania.1
Supply Corporation began transportation service for the additional 25,000 Dth
per day in November 1997 and has filed for Federal Energy Regulatory Commission
(FERC) approval concerning the 23,000 Dth per day expansion of firm winter only
capacity. Supply Corporation anticipates receiving such FERC approval by April
or May of 1998.1
Supply Corporation also has a proposed 1999 Niagara Expansion Project
(1999 Expansion), which would expand transportation capacity from the Canadian
border at Niagara Falls, New York, to Leidy, Pennsylvania. Given the uncertain
status of the 1999 Expansion, no amount has been included in the 1998 or 1999
budget as the timing of the "go ahead" for the 1999 Expansion will depend on
several factors, including signed precedent agreements and FERC approval.1 A
timetable has not been set for filing with the FERC.
Estimated capital expenditures in 19981999 for the Exploration and
Production segment are approximately 10.0% highersignificantly lower than capital spending in 19971998 as the
Company sees significant opportunities for growth in this segment.1 These
expenditures will be directed mainly toward developing Seneca'sfocusing on managing existing properties and reducing debt
balances.1 The 1999 budget includes approximately $23.1 million for development
drilling, facilities construction and recompletions related to the properties
acquired in the HarCor, Whittier and BER acquisitions. Approximately $34.0
million has been budgeted for offshore exploratory drilling, development
drilling and onshore prospects, reservefacilities construction. The budget also includes $5.8 million for
lease acquisitions and significantly expanding exploration
activities.1 Approximately 75% of these$12.6 million for geological and geophysical
expenditures.
Estimated capital expenditures for the International segment will be
directed offshore.1concentrated in the process of reconstructing boilers at the heating plant of
PSZT to comply with certain clean air standards mandated by the Czech Republic
government. Approximately $33.0 million is budgeted for this reconstruction.
The Company's other investments in 1999 will be concentrated in the
Pipeline and Storage segment and the International segment. In November 1997,the Pipeline and
Storage segment, the Company signed a letter of intent with the
Whittier Trust Companyplans to purchase for cash propertiesinvest an additional $5.0 - $10.0 million
in the Midway-SunsetIndependence Pipeline Company.1 Additional spending in 1999 and Lost Hills fieldbeyond
would depend on such factors as Federal Energy Regulatory Commission (FERC)
approval and customer interest in the San Joaquin Basin of California. This potential
acquisition will complementproject.1 In the Exploration and Production segment's reserve
mix, bringing its new potential reserve base to 58% oil and 42% gas.1 This
potential acquisition would also provide the Exploration and ProductionInternational segment, with the opportunity to continue its focus of growth by increasing its
activities in the domestic onshore areas.1 The purchase price of these
propertiesit
is expected to be in the range of $130that SCT will spend approximately $6.0 million to $150 million and is
dependent upon various factors, including acceptance by Trust participants and
swappingincrease its
equity investment in one of certain Coalinga field properties for additional properties in the
Midway-Sunset fields.1its subsidiaries.1
The Company anticipates financing this purchase with
long-term debt.1 No amount for this potential acquisition has been included in
the estimatedcontinuously evaluates capital expenditure table above.
The Company's capital expenditure program is under continuous review.expenditures and other
investments. The amounts are subject to modification for opportunities such as
the acquisition of attractive oil and gas properties, timber or storage
facilities and the expansion of transmission line capacities. While the majority
of capital expenditures in the Utility segment are necessitated by the continued
need for replacement and upgrading of mains and service lines, the magnitude of
future capital expenditures or other investments in the Company's other business
segments depends, to a large degree, upon market conditions.1
Investment in Unconsolidated Foreign Subsidiary
In 1997, Horizon's wholly owned subsidiary, Bruwabel, acquired a 36.8% equity
interest in SCT. SCT is a company with district heating and power generation
operations located in the northern part of the Czech Republic. For calendar
1996, SCT reported profits of approximately $5.0 million. Bruwabel paid $22.0
million, including legal and finders fees, for its 36.8% equity interest.
Bruwabel received a dividend of $0.9 million from its investment in SCT during
1997.
In December 1997, Bruwabel acquired an additional 34% equity interest
in SCT for approximately $22.0 million, thus raising its total ownership to
70.8%. As such, Bruwabel will begin to consolidate SCT into its financial
statements during the first quarter of 1998. The acquisition was financed with
short-term borrowings.
Bruwabel's investment in SCT is valued in Czech Korunas, and as such,
this investment is subject to currency exchange risk when the Czech Korunas are
translated into U.S. Dollars. During 1997, the Czech Koruna devalued in
relation to the U.S. Dollar, resulting in a negative adjustment to stockholders
equity in the amount of approximately $2.0 million. This amount is reported as a
Cumulative Translation Adjustment in Common Stock Equity on the Consolidated
Balance Sheet. If the Czech Koruna increases in value in relation to the U.S.
Dollar, the $2.0 million Cumulative Translation Adjustment could reverse and
potentially become a positive adjustment to Common Stock Equity. Management
cannot predict whether the Czech Koruna will increase or decrease in value
against the U.S. Dollar.1
Other Investing Activities
Other cash provided by or used in investing activities reflects cash received on
the sale of the Company's investment in property, plant and equipment and cash
used for other investments.
In June 1997, the Company announced its intention to join as an equal
partner in the Independence Pipeline Project, which is designed to bring gas
from Defiance, Ohio to Leidy, Pennsylvania and is expected to cost $675
million.1 The Independence Pipeline Project as filed with the FERC will consist
of approximately 370 miles of 36-inch diameter pipe with an initial capacity of
approximately 900,000 Dth per day. In September 1997, the Company formed a new
subsidiary, Seneca Independence Pipeline Company (SIP), which has agreed to
purchase, upon receipt of regulatory approval, a one-third general partnership
interest in Independence Pipeline Company, a Delaware general partnership. If
the Independence Pipeline Project is not constructed, SIP's share of the
development costs is estimated not to exceed $6.0 million to $8.0 million.1 It
is expected that SIP will invest approximately $6.8 million in the partnership
during 1998.1 SIP will most likely use short-term borrowings for the projected
investments in 1998.1
In November 1996, Supply Corporation entered into a Memorandum of
Understanding (the MOU) with Green Canyon Gathering Company, a subsidiary of El
Paso Energy, regarding a project to develop, construct, finance, own and operate
natural gas gathering and processing facilities offshore and onshore Louisiana,
at an estimated total cost of about $200 million.1 The MOU has been amended
several times since then, and currently provides for the parties to (i) share
past and future development costs for the Project through December 31, 1998, and
(ii) negotiate toward definitive agreements to form one or more 50-50 entities
and to finance, develop, build, own and operate the Project. The FERC ruled in
March 1997 that most of the Project would be jurisdictional, so additional
regulatory filings would be necessary to construct and operate the Project. The
parties will prepare and make those filings whenever justified by customer
demand. If the MOU expires without any additional filings at the FERC, Supply
Corporation's share of the development costs through December 31, 1998 is
unlikely to exceed $1.2 million, of which Supply Corporation had paid about $0.9
million as of September 30, 1997.1 These paid costs are recorded in Deferred
Charges on the Consolidated Balance Sheet at September 30, 1997. Supply
Corporation is currently using short-term borrowings to finance the Project.
Financing Cash Flow
In order to meet the Company's capital requirements, cash from external sources
must periodically be obtained through short-term bank loans and commercial
paper, as well as through issuances of long-term debt and equity securities. The
Company expects these traditional sources of cash to continue to supplement its
internally generated cash during the next several years.1
In August 1997,May 1998, the Company issued $100.0$200.0 million of 6.214%6.303% medium-term
notes due in August 2027.May 2008. After reflecting underwriting discounts and commissions,
the net proceeds to the Company amounted to $99.5$198.8 million. Such proceeds were
used to reduce short-term borrowings.
In November 1997,borrowings arising from acquisition activities in the
Company retired $50.0 million of 6.42%
medium-term notes. Short-term borrowings were used to retire these notes.International and Exploration and Production segments.
The Company's embedded cost of long-term debt was 6.9% and 7.0% at September 30,
19971998 and 1996, respectively.1997.
Consolidated short-term debt decreased $107.3increased $233.9 million during 1997.1998
($229.4 million after reflecting $4.5 million of short-term borrowings assumed
as part of the PSZT acquisition and subsequently repaid). The Company continues
to consider short-term bank loans and commercial paper important sources of cash
for temporarily financing capital expenditures gas-
in-storageand investments in corporations
and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs,
exploration and development expenditures and other working capital needs. In
addition, the Company considers supplier refunds and over-recovered purchased
gas costs as a substitute for short-term debt. Fluctuations in these items can
have a significant impact on the amount and timing of short-term debt.
At September 30, 1998, the Company had authorization from the SEC under
a shelf registration filed pursuant to the Securities Act of 1933, to issue and
sell up to $200.0 million of debentures and/or medium-term notes. In March 1998,
the Company obtained authorization from the SEC, under the Public Utility
Holding Company Act of 1935, to issue, in the aggregate, long-term debt
securities and equity securities amounting to $2.0 billion during the order's
authorization periods, which extends to December 31, 2002.
The Company's present liquidity positionindenture contains covenants which limit, among other
things, the incurrence of funded debt. Funded debt basically is believed to be adequate to
satisfy known demands.1 Underindebtedness
maturing more than one year after the date of issuance. Because of the
impairment of oil and gas producing properties recorded by the Company in March
1998, these covenants will restrict the Company's covenants contained in its indenture
covering its long-term debt, as amended, the Company would have been permittedability to issue upadditional
funded debt, with certain exceptions, until at least the third quarter of fiscal
1999.1 This will not, however, limit the Company's issuance of funded debt to
a maximum of approximately $504.0 million in additional long-term
unsecured indebtedness atrefund existing funded debt.
The Company has adequate financing resources available to meet expected
operating and capital requirements.1 At September 30, 1997, in light of then current long-term
interest rates. In addition, at September 30, 1997,1998, the Company had
regulatory authorizations and unused short-term credit lines that would have
permitted it to borrow an additional $507.6$423.7 million of short-term debt.
The amounts and timing of the issuance and sale of debt and/or equity
securities will depend on market conditions, regulatory authorizations and the
requirements of the Company.1
The Company, through Seneca, has entered into certain price swap
agreements to manage a portion of the market risk associated with fluctuations
in the market price of natural gas and crude oil. These price swap agreements
are not held for trading purposes. During 1997, Seneca utilized natural gas and
crude oil price swap agreements with notional amounts of 24.9 equivalent Bcf and
1,371,500 equivalent bbl, respectively. These hedging activities resulted in the
recognition of a pre-tax loss of approximately $21.5 million. This loss was
offset by higher prices received for actual natural gas and crude oil
production.
At September 30, 1997, Seneca had natural gas price swap agreements
outstanding with a notional amount of approximately 36.3 equivalent Bcf at
prices ranging from $1.77 per Mcf to $2.55 per Mcf. The weighted average fixed
price of these swap agreements is approximately $2.15 per Mcf. Seneca also had
crude oil price swap agreements outstanding at September 30, 1997 with a
notional amount of 1,026,000 equivalent bbl at prices ranging from $17.50 per
bbl to $20.56 per bbl. The weighted average fixed price of these swap agreements
is approximately $18.96 per bbl.
The Company, through NFR, participates in the natural gas futures
market to manage a portion of the market risk associated with fluctuations in
the price of natural gas. Such futures are not held for trading purposes. During
1997, NFR recognized a pre-tax gain of approximately $1.4 million related to
such futures contracts. Since these futures contracts qualify and have been
designated as hedges, any gains or losses resulting from market price changes
are substantially offset by the related commodity transaction.
At September 30, 1997, NFR had long positions in the futures market
amounting to a notional amount of 7.4 Bcf at prices ranging from $2.04 per Mcf
to $3.49 per Mcf. The weighted average contract price of these futures contracts
is approximately $2.61 per Mcf. NFR had short positions in the futures market
amounting to a notional amount of 2.3 Bcf at prices ranging from $2.06 per Mcf
to $3.61 per Mcf. The weighted average contract price of these futures contracts
is approximately $2.97 per Mcf.
In addition, the Company has SEC authority to enter into certain
interest rate swap agreements. For further discussion of the Company's
derivative financial instruments, see disclosure in Note F - Financial
Instruments under the heading "Derivative Financial Instruments" in Item 8 of
this report.
The Company's credit risk is the risk of loss that the Company would
incur as a result of nonperformance by counterparties pursuant to the terms of
their contractual obligations related to investments, such as temporary cash
investments, cash surrender values of insurance contracts, and derivative
financial instruments. The Company does not anticipate any material impact to
its financial position, results of operations or cash flow as a result of
nonperformance by counterparties.1 See further discussion in Note F-Financial
Instruments under the heading "Credit Risk" in Item 8 of this report.
The Company is involved in litigation arising in the normal course of
its business. In addition to the regulatory matters discussed in Note B -
Regulatory Matters, in Item 8 of this report, the Company is involved in other
regulatory matters arising in the normal course of business that involve rate
base, cost of service and purchased gas cost issues. While the resolution of
such litigation or other regulatory matters could have a material effect on
earnings and cash flows in the year of resolution, neither thissuch litigation nor
these other regulatory matters are expected to materially change the Company's
present liquidity position nor have a material adverse effect on the financial
condition of the Company at this time.1
Market Risk Sensitive Instruments
Energy Commodity Price Risk
Certain of the Company's nonregulated subsidiaries (primarily Seneca and NFR)
utilize various derivative financial instruments (derivatives), including price
swap agreements and exchange-traded futures and options, as part of the
Company's overall energy commodity price risk management strategy. Under this
strategy, the Company manages a portion of the market risk associated with
fluctuations in the price of natural gas and crude oil, thereby providing more
stability to operating results. The derivatives entered into by the Company's
nonregulated subsidiaries are not held for trading purposes. These subsidiaries
have operating procedures in place that are administered by experienced
management to monitor compliance with their risk management policies.
The following tables disclose natural gas and crude oil price swap
information by expected maturity dates for agreements in which Seneca receives a
fixed price in exchange for paying a variable price as quoted in "Inside FERC"
or on the New York Mercantile Exchange. Notional amounts (quantities) are used
to calculate the contractual payments to be exchanged under the contract. The
tables do not reflect the earnings impact of the physical transactions that are
expected to offset the financial gains and losses arising from the use of the
price swap agreements. The weighted average variable prices represent the prices
as of September 30, 1998. At September 30, 1998, Seneca had not entered into any
natural gas price swap agreements extending beyond 2000 nor had it entered into
any crude oil price swap agreements extending beyond 1999.
Natural Gas Price Swap Agreements
- ---------------------------------
Expected
Maturity Dates
--------------
1999 2000 Total
---- ---- -----
Notional Quantities (Equivalent Bcf) 18.7 3.1 21.8
Weighted Average Fixed Rate (per Mcf) $2.34 $2.37 $2.34
Weighted Average Variable Rate (per Mcf) $1.66 $1.66 $1.66
Crude Oil Price Swap Agreements
- -------------------------------
Expected
Maturity Dates
--------------
1999
----
Notional Quantities (Equivalent bbls) 135,000
Weighted Average Fixed Rate (per bbl) $19.86
Weighted Average Variable Rate (per bbl) $14.97
At September 30, 1998, Seneca would have had to pay the respective
counterparties to its natural gas price swap agreements an aggregate of
approximately $1.4 million to terminate the natural gas price swap agreements
outstanding at that date. Seneca would have received an aggregate of
approximately $0.4 million from the counterparties to its crude oil price swap
agreements to terminate the crude oil price swap agreements outstanding at
September 30, 1998.
The Company is exposed to credit risk on the price swap agreements that
Seneca has entered into. Credit risk relates to the risk of loss that the
Company would incur as a result of nonperformance by counterparties pursuant to
the terms of their contractual obligations. To mitigate such credit risk, before
entering into a price swap agreement with a new counterparty, management
performs a credit check and prepares a report indicating the results of the
credit investigation. This report must be approved by Seneca's board of
directors after which a Master Swap Agreement is executed between Seneca and the
counterparty. On an ongoing basis, periodic reports are prepared by management
to monitor counterparty credit exposure. Considering the procedures in place,
the Company does not anticipate any material impact to its financial position,
results of operations, or cash flows as a result of nonperformance by
counterparties.1
The following table discloses the net notional quantities, weighted
average contract prices and weighted average settlement prices by expected
maturity date for exchange-traded futures contracts utilized to manage natural
gas price risk. These futures contracts have been entered into by NFR. The table
does not reflect the earnings impact of the physical transactions that are
expected to offset the financial gains and losses arising from the use of the
futures contracts. At September 30, 1998, NFR held no futures contracts with
maturity dates extending beyond 2000.
Exchange-Traded Futures Contracts
- ---------------------------------
Expected
Maturity Dates
--------------
1999 2000 Total
---- ---- -----
Contract Volumes Purchased (Equivalent Bcf) 11.1 3.2 14.3
Weighted Average Contract Price
(per Mcf) $2.50 $2.58 $2.52
Weighted Average Settlement Price
(per Mcf) $2.59 $2.55 $2.58
The following table discloses the net notional quantities and weighted
average strike prices by expected maturity dates for exchange-traded options
utilized to manage natural gas price risk. These options have been entered into
by NFR. The table does not reflect the earnings impact of the physical
transactions that would offset any financial gains or losses that might arise if
an option were to be exercised. At September 30, 1998, NFR held no options with
maturity dates extending beyond 1999.
Exchange-Traded Options
- -----------------------
Expected
Maturity Dates
--------------
1999
----
Option Volumes Purchased (Sold)(Equivalent Bcf) (2.3)
Weighted Average Strike Price
(per Mcf) $2.91
At September 30, 1998, NFR would have received approximately $0.4
million to settle the exchange-traded futures outstanding at that date. NFR had
an unrealized gain of approximately $0.1 million related to its exchange-traded
options outstanding at September 30, 1998. This unrealized gain consisted mostly
of premiums received on the exchange-traded options it had sold.
Exchange Rate Risk
Horizon's investment in the Czech Republic is valued in Czech korunas, and as
such, this investment is subject to currency exchange risk when the Czech
korunas are translated into U.S. dollars. During 1998, the Czech koruna
increased in value in relation to the U.S. dollar, resulting in a $9.4 million
positive adjustment to the Cumulative Translation Adjustment. Further valuation
changes to the Czech koruna would result in corresponding positive or negative
adjustments to the Cumulative Translation Adjustment. Management cannot predict
whether the Czech koruna will increase or decrease in value against the U.S.
dollar.1
PSZT had U.S. dollar denominated debt in the amount of $50.6 million at
September 30, 1998. Since the functional currency of PSZT is the Czech koruna
and this debt had to be repaid in U.S. dollars, a change in exchange rates
between the Czech koruna and the U.S. dollar would increase or decrease the
amount of Czech koruna required to repay the debt, resulting in a corresponding
gain or loss to be recognized in the income statement. From the acquisition of
PSZT in February 1998 through September 30, 1998, PSZT recognized a pretax gain
of approximately $7.2 million, which is included in Other Income in the
Consolidated Statement of Income. To eliminate future exchange rate risk on the
U.S. dollar denominated debt, PSZT bought a $50.6 million U.S. dollar forward
contract at an exchange rate of 31.54 CZK per dollar on September 3, 1998. The
purpose of the forward contract was to hedge against the exchange rate risk
associated with the U.S. dollar denominated debt. At September 30, 1998, the
fair value of this forward contract was $(2.1) million, representing the loss on
the contract as of September 30, 1998. The loss was recorded as an accrued
liability on the Consolidated Balance Sheets with the offset being Other Income
in the Consolidated Statement of Income. Upon maturing on December 3, 1998, the
final loss recognized on this forward contract was $2.0 million. With the
maturity of this forward contract, PSZT simultaneously converted the $50.6
million of U.S. dollar denominated debt into a loan denominated in CZK, thus
eliminating further exchange rate risk.
Interest Rate Risk
The Company's exposure to interest rate risk primarily consists of short-term
debt instruments. At September 30, 1998, this included short-term bank loans and
commercial paper totaling $326.3 million. The interest rate on the short-term
bank loans and commercial paper approximated 5.6%.
The following table presents the principal cash repayments and related
weighted average interest rates by expected maturity date for the Company's
long-term fixed rate debt as well as the other debt of certain of the Company's
subsidiaries. The interest rates for the variable rate debt are based on those
in effect at September 30, 1998:
Principal Amounts by
Expected Maturity Dates
-----------------------------------------------------
(millions of dollars) 1999 2000 2001 2002 2003 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
National Fuel Gas Company
Long-Term Fixed Rate Debt $150 $50 $- $- $- $574 $774
Weighted Average Interest
Rate Paid 6.1% 6.6% -% -% -% 7.0% 6.8%
Fair Value = $830.5 million
HarCor
Long-Term Fixed Rate Debt $62.6 $- $- $- $- $- $62.6
Weighted Average Interest
Rate Paid 14.9% -% -% -% -% -% 14.9%
Fair Value = $62.6 million
PSZT
Long-Term Fixed Rate Debt $- $9.9 $- $- $- $- $9.9
Weighted Average Interest
Rate Paid -% 13.0% -% -% -% -% 13.0%
Fair Value = $9.9 million
Long-Term Variable Rate
Debt $- $7.6 $10.1 $10.1 $10.1 $12.7 $50.6
Weighted Average Interest
Rate Paid -% 8.0% 8.0% 8.0% 8.0% 8.0% 8.0%
Fair Value = $50.6 million
SCT
Long-Term Variable Rate
Debt $0.5 $0.5 $0.5 $0.6 $0.7 $1.7 $4.5
Weighted Average Interest
Rate Paid 14.7% 14.7% 14.7% 14.7% 14.7% 14.7% 14.7%
Fair Value = $4.5 million
Other Notes
Long-Term Debt* $3.8 $2.4 $1.8 $- $- $- $8.0
Weighted Average Interest
Rate Paid 7.1% 7.4% 6.9% -% -% -% 7.1%
Fair Value = $8.0 million
*$0.4 million is variable rate debt; $7.6 million is fixed rate debt.
Rate Matters
Utility
New York Jurisdiction
In November 1995, Distribution Corporation filed in its New York jurisdiction a
request for an annual rate increase of $28.9 million with a requested return on
equity of 11.5%. A two-year settlement (the 1996 settlement) with the parties in
this rate proceeding was approved by the Public Service Commission of the State of New York Public Service
Commission (PSC). Effective October 1, 1996 and October 1, 1997, Distribution
Corporation received annual base rate increases of $7.2 million. TheAs part of the
1996 settlement, did not specify a
rate of return on equity. Generally, earnings above a 12% return on equity (excluding certain items
and determined on a cumulative basis over the three years ending September 30,
1998) willare to be shared equally between shareholders and ratepayers.customers. As a result
of this sharing mechanism, Distribution Corporation has determined that the
refund due customers as of September 30, 1998 is $10.7 million (of which $7.7
million was recorded an estimated cumulative refund provision to its customers ofin 1998 and $3.0 million ($2.0was recorded in 1997).
On October 21, 1998, the PSC approved a rate plan for Distribution
Corporation for the period beginning October 1, 1998 and ending September 30,
2000. The plan is the result of a settlement agreement entered into by
Distribution Corporation, Staff for the PSC (Staff), Multiple Intervenors (an
advocate for large industrial customers) and the State Consumer Protection
Board. Under the plan, Distribution Corporation's rates are reduced by $7.2
million, after-tax) duringor 1.1%. In addition, customers will receive up to $6.0 million in bill
credits, disbursed volumetrically over the fourth quartertwo year term, reflecting a
pre-determined share of 1997.excess earnings under the 1996 settlement described
above. The finalremaining amount, owed to customers, if any, will not be known untilpassed back to customers as
determined by the conclusionPSC. An allowed return on equity of 12%, above which 50% of
additional earnings are shared with the settlement period.
In June 1997,customers, is maintained from the 1996
settlement. Finally, the rate plan also provides that $7.2 million of 1999
revenues will be set aside in a special reserve to be applied against
Distribution Corporation's incremental costs resulting from the PSC's gas
restructuring effort further described below.
On November 3, 1998, the PSC issued an order requiring jurisdictional
utilities to file plans to offer heating customers a fixed price service option
forPolicy Statement Concerning the
coming winter heating season. The order also directed----------------------------------
Future of the utilities to
submit proposals for increased supply diversity with a view toward fostering
price stability. In August 1997, Distribution Corporation filedNatural Gas Industry in its New York jurisdictionState and Order Terminating
- --------------------------------------------------------------------------------
Capacity Assignment (Policy Statement). The Policy Statement sets forth the
- --------------------
PSC's "vision" on "how best to ensure a plan to comply with the PSC's order and the PSC subsequently
approved the plan in October 1997. The fixed price service option that was
approved gives heating customers the opportunity to be guaranteed a fixed unit
pricecompetitive market for natural gas duringin
New York." That vision includes the billing period of December 1997 through April
1998. The option was made available on a first-come, first-served basis to a
maximum of 100,000 heating customers. Approximately 11,000 heating customers
chose the fixed price service option, which will fix the monthly gas adjustment
at $.13832 per hundred cubic feet, which is 20% less than the average gas
adjustment experienced during the 1996 - 1997 heating season. However, this rate
is higher thanfollowing goals:
(1) Effective competition in the gas adjustment experienced duringsupply market for retail
customers;
(2) Downward pressure on customer gas prices;
(3) Increased customer choice of gas suppliers and service options;
(4) A provider of last resort (not necessarily the 1995 - 1996 heating
season. Distribution Corporation lockedutility)
(5) Continuation of reliable service and maintenance of operations
procedures that treat all participants fairly;
(6) Sufficient and accurate information for customers to use in commodity prices for approximately
30%making
informed decisions;
(7) The availability of information that permits adequate oversight of
the New York jurisdiction's planned purchases during the periodmarket to ensure fair competition; and
(8) Coordination of November 1997 through March 1998. Other components of heating customers rates
will remain unchanged.
New York'sFederal and State policies affecting gas industry restructuring effort continues to develop at a
slow pace. As of the end of September 1997, 14,000 small volume customers across
the state chose aggregator services over their utility. In Distribution
Corporation's service territory, 1,500 small volume customers (out of over
500,000) are purchasing gas from eight aggregators, for a total annual load of
just over 1 Bcf. At the urging of the PSC, Distribution Corporation began to
offer storage release service to aggregators on June 27, 1997. Currently,
Distribution's is the only actual release storage service availablesupply
and distribution in New York State.
Whether aggregators findThe Policy Statement provides that the most effective way to establish
a competitive market in gas supply is "for local distribution companies to cease
selling gas." The PSC hopes to accomplish that objective over a three-to-seven
year transition period, taking into account "statutory requirements" and the
individual needs of each local distribution company (LDC). The Policy Statement
directs Staff to schedule "discussions" with each LDC on an "individualized plan
that would effectuate our vision." In preparation for negotiations, LDCs will be
required to address issues such as a strategy to hold new capacity contracts to
a minimum, a long-term rate plan with a goal of reducing or freezing rates, and
a plan for further unbundling. In addition, Staff will hold collaborative
sessions with multiple parties to discuss generic issues including reliability
and market power regulation.
The PSC's Order Terminating Capacity Assignment, included with the
----------------------------------------
Policy Statement, directs the state's LDCs to file proposed tariffs, by no later
than February 1, 1999, revising the current requirement that suppliers take
assignment of an allocation of upstream capacity for each customer that elects
to purchase gas from a supplier other than the LDC. Although the order states
that the so-called "mandatory assignment" feature of aggregation service attractive enoughis
terminated effective April 1, 1999, LDCs are permitted to increase
marketing activity remainsshow that their
individual circumstances may warrant continuation of the requirement. The order
also recognizes that LDCs with intermediate pipelines, like Distribution
Corporation, could present "unique cost and reliability issues which require
further consideration." The order provides that to the extent all or part of an
LDC's mandatory assignment authority is indeed terminated, there will be seen.
a
reasonable opportunity to recover stranded costs.1
Distribution Corporation plans to work cooperatively with the PSC to
develop a plan which maximizes customer choice options while preserving
reliability and the Distribution Corporation's financial objectives.1 Toward
that end, Distribution Corporation believes that it must remain a merchant. At
this time, current laws provide that LDCs are obligated to provide merchant
service to qualified applicants. While the outcome of these PSC proceedings
cannot be determined, the Company believes that changes, if any, will be
implemented incrementally over a number of years.1
On April 3, 1998, Distribution Corporation filed comments in a PSC
generic proceeding addressing gas transportation rates for electric generators.
This case arose in response to concerns by the PSC regarding the effects of gas
transportation costs on electric rates ultimately paid by the retail customers.
Distribution Corporation argued, among other things, that the current rate
setting policy, established in 1991, should remain unchanged for LDCs facing
competitive bypass threats. On September 24, 1998, the PSC issued a proposal for
a "basic gas-for-electric-generation-service tariff" developed by Staff based on
its own analysis and input received from interested parties. The proposal sets a
minimum rate based on presumed costs and allows additional charges for
incremental costs and, to a minor extent, market factors. Numerous parties,
including Distribution Corporation, filed comments on October 27, 1998 opposing
the Staff proposal or recommending significant changes. Staff's proposal, if
adopted, may diminish Distribution Corporation's ability to capture future
gas-fired generation load opportunities.1 It would not, however, affect existing
contracts with generation customers.
The PSC issued a notice on April 7, 1998 that it is considering the
revision of its regulations governing the operation of the Gas Adjustment Clause
(GAC). As described by the PSC, the revised rules would allow the GAC to more
accurately reflect gas prices. The revised rules would also allow LDCs to
recover risk management costs through the GAC. On June 5, 1998, Distribution
Corporation filed comments in the GAC docket raising several concerns with the
PSC's proposed revisions.
Pennsylvania Jurisdiction
Distribution Corporation currently does not have a rate case on file with the
Pennsylvania Public Utility Commission (PaPUC). Management will continue to
monitor its financial position in the Pennsylvania jurisdiction to determine the
necessity of filing a rate case in the future.
In AprilEffective October 1, 1997, Distribution Corporation filedcommenced a proposal for aPaPUC
approved customer choice pilot program called Energy Select, with the PaPUC. The PaPUC approved
Energy Select in June 1997 and service commenced on October 1, 1997.Select. Energy Select,
which will last one and one-half years,until April 1, 1999, allows approximately 19,000 small
commercial and residential customers of Distribution Corporation in the greater
Sharon, Pennsylvania area to purchase gas supplies from qualified, participating
non-utility suppliers (or marketers) of gas. Distribution Corporation is not a
supplier of gas in this pilot. Under Energy Select, Distribution Corporation
will continue to deliver the gas to the customer's home or business and will
remain responsible for reading customer meters, the safety and maintenance of
its pipeline system and responding to gas emergencies. The
Company's marketing affiliate, NFR is a participating
supplier in Energy Select.
On October 30, 1998, Distribution Corporation filed a System Wide
Energy Select proposal with the PaPUC, requesting an effective date of December
29, 1998. This program proposes to expand the Energy Select pilot program
described above to apply across Distribution Corporation's entire Pennsylvania
service territory. The plan borrows many features of the Energy Select pilot,
but several important changes are proposed. Most significantly, the new program
would include Distribution Corporation as a choice for retail consumers, in
furtherance of Distribution Corporation's objective to remain a merchant. Also
departing from the pilot scheme, Distribution Corporation proposes to undertake
its role as supplier of last resort, and will maintain customer contact by
providing a billing service on its own behalf and, as an option, for
participating suppliers. Finally, the System Wide Energy Select filing proposes
a comprehensive solution for the appropriate disposition of upstream capacity
requirements. If approved, the program would assure traditional levels of supply
and operational reliability while providing an economic means for reduction of
long-term capacity obligations. At this juncture, the Company is not able to
predict the PaPUC's determination on the System Wide Energy Select proposal.
A gas restructuring bill (Senate Bill No. 943) was introduced in the
Pennsylvania General Assembly in 1997 proposing to amend the Public Utility Code
to allow all retail customers, including residential, the ability to choose
their own gas supplier. Senate Bill No. 943 has not yet been enacted into law.
However, in December 1997, the Chairman of the PaPUC convened a collaborative of
gas industry interests to develop a consensus bill using Senate Bill No. 943 as
the starting point. As a member of the utility interest group, Distribution
Corporation is and will continue to be an active participant in the
collaborative.1 The Company is not able to predict the outcome of the bill.
Base rate increasesadjustments in both the New York and Pennsylvania
jurisdictions do not reflect the recovery of purchased gas costs. Such costs are
recovered through operation of the purchased gas adjustment clauses.
State Regulatory Environment
The New York and Pennsylvania regulatory commissions continue to address
restructuringclauses of the
gas industry in response to the FERC's Order 636.
Distribution Corporation is working closely with the state regulatory commissions to resolve issues consistent with Distribution Corporation
objectives. Current proceedings and other regulatory and legislative
developments are discussed below:
New York
Generic Restructuring Proceeding. This proceeding is examining the appropriate
retail or end-use impacts resulting from the FERC's Order 636 pipeline
restructuring. On March 28, 1996, the PSC issued an order directing the state's
local distribution companies (LDCs), including Distribution Corporation, to file
additional tariff amendments regarding this proceeding. On April 30, 1996,
Distribution Corporation submitted a filing, effective May 1, 1996 on a
temporary basis, proposing to amend its services to provide a framework for
small customer aggregation in compliance with the PSC's March 28, 1996 Order
(Distribution Corporation already offers unbundled, flexible service to its
commercial and industrial customers). The changes provide the option for all
customers to choose from whom they want to buy gas, which could be Distribution
Corporation, another utility, or a non-utility supplier or marketer. If a
customer purchases gas from a supplier other than Distribution Corporation, the
supplier would obtain and transport the gas to Distribution Corporation's
pipeline system and Distribution Corporation would then deliver the gas to the
customer. Distribution Corporation would continue to be responsible for
maintaining its pipelines and responding to safety calls, but billing and other
traditional services would be assumed by the alternate supplier. On September
12, 1996, the PSC issued an order approving the April 30, 1996 filing, subject
to additional changes. Further revisions were filed as directed for an effective
date of October 1, 1996. On June 27, 1997, Distribution Corporation's tariff was
further amended to provide unbundled storage capacity to qualified marketers.
Filed and approved in compliance with the PSC's restructuring orders, the
service allows marketers to take release of Distribution Corporation's storage
and transmission capacity in order to serve retail end users through the
aggregation services described above. The service includes, to the extent
necessary, inventory transfers at pre-determined prices.
On September 4, 1997, the PSC issued an order addressing upstream
capacity requirements for LDCs. In the PSC's March 28, 1996 order, the LDCs,
including Distribution Corporation, were authorized to require converting sales
customers (or their marketers) to take an allocation of upstream capacity for up
to a three year period. The PSC stated that prior to the start of the third year
(April 1998), each utility would be required to demonstrate "its efforts to
relieve itself of excess capacity." The PSC further held that "we will address
any issues of stranded costs then." The
September 4, 1997 order implements the third year review by directing the
state's LDCs to, no later than April 1, 1998, submit plans addressing upstream
capacity issues including stranded costs. Distribution Corporation is currently
reviewing its portfolio of upstream capacity consistent with the provisions of
the September 4, 1997 order.
Also, on September 4, 1997, the PSC issued a notice inviting comments
on a report prepared by the PSC Staff for the Department of Public Service
entitled "The Future of the Natural Gas Industry" (Position Paper).
Acknowledging that customer choice has not evolved as expected under the Generic
Restructuring orders, the PSC Staff reaches the "fundamental conclusion" that
"the most effective way to establish a robustly competitive market in gas supply
is to separate the merchant and distribution functions." Toward that end, the
Position Paper sets forth a variety of recommendations addressing issues such as
upstream capacity, rate design, system reliability, market power, customer
communication, social programs and taxes. The PSC Staff believes that a five
year period is necessary for LDCs to transition out of the merchant business. On
November 20, 1997, Distribution Corporation filed initial comments supporting
the PSC Staff's proposal that LDCs exit the merchant function. Additional
comments consistent with Distribution Corporation's objectives were offered on
other issues raised in the Position Paper.
Pennsylvania
The PaPUC has not issued a generic rulemaking for industry restructuring, opting
instead for a case-by-case approach promoting small customer aggregation
programs including Distribution's Energy Select pilot described above. Two
issues dealt with generically, however, are affiliate transactions and supplier
fitness standards, for which the PaPUC adopted policy statements in June 1997.
To the extent required, Distribution Corporation has already implemented
procedures consistent with those policy statements.
On the legislative front, a gas restructuring bill was introduced in
1997 proposing to amend the Public Utility Code to require that LDCs exit the
merchant function in three years. Modeled after the 1996 electric competition
law, House Bill 1068 (introduced in the Senate as S.943) would, if enacted,
provide direct access to competitive markets for all retail gas customers. The
Company is not able to predict the outcome of the bill.
However, it appears that the bill would not become law earlier than 1998.1authorities having jurisdiction.
Pipeline and Storage
On October 31, 1994, Supply Corporation filed for an annualcurrently does not have a rate increase of
$21.0 million,case on file with a requested return on equity of 12.6%. In February 1996,the FERC.
Its last case was settled with the FERC approved a settlement authorizing an annual rate increasein February 1996. As part of approximately
$6.0 million with a return on equity of 11.3%. The new rates were put into
effect on April 1, 1996, retroactive to June 1, 1995. With thisthat
settlement, Supply Corporation agreed not to seek recovery for increased cost of service
until April 1, 1998. Supply Corporation also agreed not to seek recovery of revenues related
to certain terminated service from other storage customers until April 1, 2000, as
long as the terminations were not greater than approximately 30% of the
terminable service. ManagementSupply Corporation has been successful in marketing and
obtaining executed contracts for such terminated storage service (at discounted
rates) and does not anticipate a problem inexpects to continue obtaining executed contracts for additional
terminated storage service as it arises. 1arises.1
Other Matters
Environmental Matters
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for on-going evaluation of its operations to identify potential
environmental exposures and assure compliance with regulatory policies and
procedures.
It is the Company's policy to accrue estimated environmental clean-up costs
(investigation and remediation) when such amounts can reasonably be estimated
and it is probable that the Company will be required to incur such costs.
Distribution Corporation has estimated thatits clean-up costs related to several former
manufactured gas plant sites and several otherthird party waste disposal sites arewill be in the
range of $9.3$12.4 million to $9.9$13.4 million.1 At September 30, 1997,1998, Distribution
Corporation has recorded the minimum liability of $9.3$12.4 million. The ultimate cost to
Distribution Corporation with respect to the remediation of these sites will
depend on such factors as the remediation plan selected, the extent of the site
contamination, the number of additional potentially responsible parties at each
site and the portion, if any, attributed to Distribution Corporation.1 The Company is
currently not aware of any material additional exposure to environmental
liabilities. However, adverse changes in environmental regulations or other
factors could impact the Company.
In New York and Pennsylvania, Distribution Corporation is recovering
site investigation and remediation costs in rates. Accordingly, the Consolidated
Balance Sheet at September 30, 1998 includes related regulatory assets in the
amount of approximately $12.4 million.
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 ongoing evaluation of its operations to identify
potential environmental exposures and assure compliance with regulatory policies
and procedures.
For further discussion see
disclosure inrefer to Note H - Commitments and Contingencies
under the heading "Environmental Matters" in Item 8 of this report.
New Accounting Pronouncements. DuringPronouncements
In June 1997, the Financial Accounting Standards Board (FASB) issued three new accounting pronouncements that will impact the Company: Statement
of Financial Accounting Standards (SFAS) No. 128, "Earnings per
Share"; SFAS 130, "Reporting Comprehensive Income";
(SFAS 130). In June 1998, the FASB issued SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). For a discussion of SFAS 130 and
SFAS 131, "Disclosures
about Segments of an Enterprise133 and Related Information." For further
discussion,their impact on the Company, see disclosure in Note A - Summary of
Significant Accounting Policies in Item 8 of this report.
Year 2000
AsNumerous information technology computer systems, software programs and
semiconductors are not capable of recognizing dates after the millennium approaches,Year 2000 because
such systems use only two digits to refer to a particular year. Such systems may
read dates in the Year 2000 and thereafter as if those dates represent the year
1900 or thereafter and in certain instances, such systems may fail to function
properly.
State of Readiness
The Company is preparing allanticipates that the majority of its computer
systems towill be Year 2000 compliant. Managementready
by March 31, 1999, and that the remaining systems (i.e. primarily those for
which implementation is being deferred until after the 1998-1999 heating season)
will be Year 2000 ready by April 30, 1999.1 Following the completion of an
early-impact analysis study, a formal project manager at the Company was
designated to spearhead the Year 2000 remediation effort. The methodology
adopted by the Company to address the Year 2000 issue is a combination of
methods recommended by respected industry consultants and efforts tailored to
meet the Company's specific needs. The Company's Year 2000 plan addresses five
primary areas.
A. Mainframe Corporate Business Applications Developed and Maintained by the
Company: A detailed plan and impact analysis was conducted in 1996-1997 to
determine the extent of Year 2000 implications on the Company's mainframe-based
computer systems. The remediation and testing in this area are 98 percent
complete and are expected to be fully completed by December 31, 1998.1
B. Personal Computer Business Applications Software Developed and Supported by
the Company: The Company has retained a consulting firm to perform a detailed
impact analysis of the personal computer business application systems supported
by the Company's Information Services Department. The firm is in the process of
finalizingcorrecting Year 2000 problems identified by its analysis. Certain applications
identified by the consulting firm as potentially problematic have been retired
and replaced with Year 2000 compliant applications. The required changes and
testing for these applications are 90 percent complete and are expected to be
finished by March 31, 1999.1
C. Vendor-Supplied Software, Hardware, and Services for Corporate Business
Applications Supported by the Company: This category includes all mainframe
infrastructure products as well as all PC client / server software and hardware.
The Company has sent letters to its vendors asking if their products and
services will continue to perform as expected after January 1, 2000. These
vendors are responsible for approximately 200 products and services associated
with corporate computer applications. The Company has received responses from
all vendors which the Company believes supply critical hardware, software,
date-sensitive embedded chips and related computer services. The Company expects
to complete testing and implementation of the vendor-supplied Year 2000
compliant products and services by April 30, 1999.1
D. Vendor-Supplied Products and Services Used on a comprehensive reviewCorporate Wide Basis: This
category includes the critical products and services that are used by multiple
departments within the Company including all products containing embedded chips
which might be date sensitive. The Company has sent letters to the primary
vendors who provide these products and services to the Company, requesting Year
2000 compliance plans. The Company is monitoring their responses and
incorporating them into the Company's overall Year 2000 project and contingency
plans. The Company expects to complete testing and implementation of its computer systemsthe
products and services of these vendors by March 31, 1999 (reference is made to
the "Risks" section below).1
E. User-Department Maintained Business Applications: The Company uses certain
business software applications that were either built in-house or
vendor-supplied and subsequently maintained by individual departments of the
Company. The scope of such applications includes, but is not limited to,
spreadsheets, databases, vendor provided products and services and embedded
process controls. A corporate wide Year 2000 task force is in place and has
established a process to identify and resolve Year 2000 problems in this area.
This task force meets on a monthly basis to coordinate ongoing activities and
report on the systems that couldproject status. Providers of critical products and services have
been identified and the Company has sent letters requesting their Year 2000
compliance plans. Responses are being monitored and incorporated into the Year
2000 planning of the various departments. All applications and services under
this category are expected to be affected and is developing a conversion plan to resolve the issue.Year 2000 ready by April 30, 1999.1
Cost
The cost of upgrading both vendor supplied and internally developed systems will beand
services is being expensed as incurred. Management estimates that such costscost will
total approximately $2.2 million, of which approximately $1.3 million has been
incurred to date and $0.9 million remains to be spent.1
Risks
The Company's main concern is to ensure the safe and reliable production and
delivery of natural gas and Company-provided services to its customers. Based on
the efforts discussed above, the Company expects to be able to operate its own
facilities without interruption and continue normal operation in Year 2000 and
beyond.1 However, the Company has no control over the systems and services used
by third parties with whom it interfaces. While the Company has placed its major
third parties on notice that the Company expects their products and services to
perform as expected after January 1, 2000, the Company cannot predict with
accuracy the actual adverse consequences to the Company that could result if
such third parties are not Year 2000 compliant.1 The widespread failure of
electric, telecommunication, and upstream gas supply could potentially affect
gas service to utility customers, and the Company is pursuing contingency plans
to avoid such disruptions.
The majority of the devices which control the Company's physical
delivery system are not susceptible to Year 2000 problems because they do not
contain micro-processors. The Company has conducted an extensive review of its
existing micro processors (embedded technology) and is replacing non-Year 2000
compliant hardware. The Company expects to complete these replacements by April
30, 1999.1
Distribution Corporation is subject to regulatory review by both the
PSC and the PaPUC. Both of these regulatory bodies have issued orders concerning
the Year 2000 issue, and both have established dates in 1999 by which
jurisdictional utilities must have taken the necessary steps to ensure that its
critical systems are Year 2000 ready. In the event Distribution Corporation
fails to meet the requirements of those orders, it may be subject to the
imposition of fines or formal enforcement actions by the regulatory bodies.
Contingency Planning
The Company formed its Corporate Year 2000 task force in mid-1997. The primary
function of this group is to: (1) raise awareness of the Year 2000 issue within
the Company, (2) facilitate identification and remediation of Year 2000
potential problems within the Company, and (3) facilitate and develop corporate
contingency plans. The group is comprised of middle to senior level managers and
Company executives. The Company's main thrust at present in contingency planning
is identification and prioritization of the potential risks posed by Year 2000
failures outside of the Company's control. All departments and subsidiaries have
submitted lists of potential risks, which are now being prioritized, in relation
to the overall corporation, in the order of human safety, reliability/delivery
of Company services and administrative services. The Company has existing
disaster/contingency plans to deal with operational gas supply or delivery
problems, loss of the corporate data center, and loss of the corporate customer
telephone centers. These plans are being reviewed to address failures resulting
from Year 2000 problems created or occurring outside of the Company (i.e. loss
of electricity, telephone service, etc.). The Company expects to have its Year
2000 contingency plans completed by mid-September 1999.1 The Company has
selected this date as opposed to one in early 1999 so that the contingency plans
are current and operational and that the Company will be approximately $1.0 million.1able to use them
immediately, if required.1
Effects of Inflation
Although the rate of inflation has been relatively low over the past few years,
and thus has benefited both the Company and its customers, the Company's
operations remain sensitive to increases in the rate of inflation because of its
capital spending and the regulated nature of twoa significant portion of its
major operating
segments.business.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this combined
Annual Report to Shareholders/Form 10-K to make applicable and take advantage of
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995 for any forward-looking statements made by, or on behalf of, the Company.
Forward-looking statements include statements concerning plans, objectives,
goals, strategies, future events or performance, and underlying assumptions and
other statements which are other than statements of historical facts. From time
to time, the Company may publish or otherwise make available forward-looking
statements of this nature. All such subsequent forward-looking statements,
whether written or oral and whether made by or on behalf of the Company, are
also expressly qualified by these cautionary statements. Certain statements
contained herein, including those which are designated with a "1", are
forward-looking statements and accordingly involve risks and uncertainties which
could cause actual results or outcomes to differ materially from those expressed
in the forward-looking statements. The forward-looking statements contained
herein are based on various assumptions, many of which are based, in turn, upon
further assumptions. The Company's expectations, beliefs and projections are
expressed in good faith and are believed by the Company to have a reasonable
basis, including without limitation, management's examination of historical
operating trends, data contained in the Company's records and other data
available from third parties, but there can be no assurance that management's
expectations, beliefs or projections will result or be achieved or accomplished.
In addition to other factors and matters discussed elsewhere herein, the
following are important factors that, in the view of the Company, could cause
actual results to differ materially from those discussed in the forward-looking
statement:
1. Changes in economic conditions, demographic patterns and weather
conditionsconditions;
2. Changes in the availability and/or price of natural gas and oiloil;
3. Inability to obtain new customers or retain existing onesones;
4. Significant changes in competitive factors affecting the CompanyCompany;
5. Governmental/regulatory actions and initiatives, including those affecting
financings, allowed rates of return, industry and rate structure, franchise
renewal, and environmental/safety requirementsrequirements;
6. Unanticipated impacts of restructuring initiatives in the natural gas and
electric industriesindustries;
7. Significant changes from expectations in actual capital expenditures and
operating expenses and unanticipated project delaysdelays;
8. Occurrences affecting the Company's ability to obtain funds from
operations, debt or equity to finance needed capital expenditures and other
investmentsinvestments;
9. Ability to successfully identify and finance oil and gas property
acquisitions and ability to operate existing and any subsequently acquired
propertiesproperties;
10. Ability to successfully identify, drill for and produce economically viable
natural gas and oil reservesreserves;
11. Changes in the availability and/or price of derivative financial
instrumentsinstruments;
12. Inability of the various counterparties to meet their obligations with
respect to the Company's financial instrumentsinstruments;
13. Regarding foreign operations - changes in foreign trade and monetary
policies, laws and regulations related to foreign operations, political and
governmental changes, inflation and exchange rates, taxes and operating
conditionsconditions;
14. Significant changes in tax rates or policies or in rates of inflation or
interestinterest;
15. Significant changes in the Company's relationship with its employees and
the potential adverse effects if labor disputes or grievances were to
occuroccur;
16. Changes in accounting principles and/or the application of such principles
to the CompanyCompany; and/or
17. Unanticipated problems related to the Company's internal Year 2000
initiative as well as potential adverse consequences related to third party
Year 2000 compliance.
The Company disclaims any obligation to update any forward-looking
statements to reflect events or circumstances after the date hereof.
ITEM 7A Quantitative and Qualitative Disclosure About Market Risk
Not Applicable.
Refer to the "Market Rate Sensitive Instruments" section in Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
ITEM 8 Financial Statements and Supplementary Data
Index to Financial Statements
- -----------------------------
Page
----
Financial Statements:
Report of Independent Accountants 5056
Consolidated Statements of Income and Earnings Reinvested
in the Business, three years ended September 30, 1997 511998 57
Consolidated Balance Sheets at September 30, 1998 and 1997 and 1996 52-5358-59
Consolidated Statement of Cash Flows, three years ended
September 30, 1997 541998 60
Notes to Consolidated Financial Statements 55-5761
Financial Statement Schedules:
For the three years ended September 30, 19971998
II-Valuation and Qualifying Accounts 7786
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 JK - Quarterly Financial Data
(unaudited) and Note LM - Supplementary Information for Oil and Gas Producing
Activities, appears under this Item, and reference is made thereto.
Report of Management
- --------------------
Management is responsible for the preparation and integrity of the Company's
financial statements. The financial statements have been prepared in accordance
with generally accepted accounting principles consistently applied, and necessarily include some
amounts that are based on management's best estimates and judgment.
The Company maintains a system of internal accounting and
administrative controls and an ongoing program of internal audits that
management believes provide reasonable assurance that assets are safeguarded and
that transactions are properly recorded and executed in accordance with
management's authorization. The Company's financial statements have been
examined by our independent accountants, Price WaterhousePricewaterhouseCoopers LLP, which also
conducts a review of internal controls to the extent required by generally
accepted auditing standards.
The Audit Committee of the Board of Directors, composed solely of
outside directors, meets with management, internal auditors and
Price WaterhousePricewaterhouseCoopers LLP to review planned audit scope and results and to
discuss other matters affecting internal accounting controls and financial
reporting. The independent accountants have direct access to the Audit Committee
and periodically meet with it without management representatives present.
Report of Independent Accountants
---------------------------------
To the Board of Directors
and Shareholders of
National Fuel Gas Company
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of
National Fuel Gas Company and its subsidiaries at September 30, 19971998 and 1996,1997,
and the results of their operations and their cash flows for each of the three
years in the period ended September 30, 1997,1998, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSEAs discussed in Note A to the consolidated financial statements, the
Company changed its method of depletion for oil and gas properties in 1998.
PricewaterhouseCoopers LLP
Buffalo, New York
October 24, 199727, 1998
National Fuel Gas Company
-------------------------
Consolidated Statements of Income and Earnings
----------------------------------------------
Reinvested in the Business
--------------------------
Year Ended September 30 (Thousands of
Dollars, Except Per Common Share Amounts) 1998 1997 1996 1995
---- ---- ----
Income
Operating Revenues $1,248,000 $1,265,812 $1,208,017 $ 975,496
---------- ---------- ----------
Operating Expenses
Purchased Gas 441,746 528,610 477,357
351,094Fuel Used in Heat and Electric Generation 37,592 1,489 244
Operation 262,328 282,795 266,786294,221 260,839 282,551
Maintenance 25,793 25,698 26,411 25,719
Property, Franchise and Other Taxes 92,817 100,549 99,456 91,837
Depreciation, Depletion and Amortization 118,880 111,650 98,231
71,782Impairment of Oil and Gas Producing
Properties 128,996 - -
Income Taxes - Net24,024 68,674 66,321 43,879
---------- ---------- ----------
1,164,069 1,097,509 1,050,571 851,097
---------- ---------- ----------
Operating Income 83,931 168,303 157,446
124,399
Other Income 35,870 3,196 3,869 5,378
---------- ---------- ----------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 119,801 171,499 161,315 129,777
---------- ---------- ----------
Interest Charges
Interest on Long-Term Debt 53,154 42,131 40,872
40,896
Other Interest 32,130 14,680 15,772 12,987
---------- ---------- ----------
85,284 56,811 56,644
53,883---------- ---------- ----------
Minority Interest in Foreign Subsidiaries (2,213) - -
---------- ---------- ----------
Income Before Cumulative Effect 32,304 114,688 104,671
Cumulative Effect of Change in
Accounting for Depletion (9,116) - -
---------- ---------- ----------
Net Income Available for Common Stock 23,188 114,688 104,671 75,894
Earnings Reinvested in the Business
Balance at Beginning of Year 472,595 422,874 380,123 363,854
---------- ---------- ----------
495,783 537,562 484,794 439,748
Dividends on Common Stock 67,671 64,967 61,920 59,625
---------- ---------- ----------
Balance at End of Year $ 428,112 $ 472,595 $ 422,874
$ 380,123
========== ========== ==========
Basic Earnings Per Common ShareShare:
Income Before Cumulative Effect $0.85 $3.01 $2.78
$2.03
========== ========== ==========Cumulative Effect of Change in Accounting
For Depletion (0.24) - -
----- ----- -----
Net Income Available for Common Stock $0.61 $3.01 $2.78
===== ===== =====
Diluted Earnings Per Common Share:
Income Before Cumulative Effect $0.84 $2.98 $2.77
Cumulative Effect of Change in Accounting
For Depletion (0.24) - -
----- ----- -----
Net Income Available for Common Stock $0.60 $2.98 $2.77
===== ===== =====
Weighted Average Common Shares OutstandingOutstanding:
Used in Basic Calculation 38,316,397 38,083,514 37,613,305
37,396,875========== ========== ==========
Used in Diluted Calculation 38,703,526 38,440,018 37,825,453
========== ========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
At September 30 (Thousands of Dollars) 1998 1997 1996
---- ----
Assets
Property, Plant and Equipment $3,186,853 $2,668,478 $2,471,063
Less - Accumulated Depreciation,
Depletion and Amortization 938,716 849,112 761,457
---------- ----------
2,248,137 1,819,366 1,709,606
---------- ----------
Current Assets
Cash and Temporary Cash Investments 30,437 14,039 19,320
Receivables - Net 82,336 107,417 96,740
Unbilled Utility Revenue 15,403 20,433 20,778
Gas Stored Underground 31,661 29,856 34,727
Materials and Supplies - at average cost 24,609 19,115
21,544Unrecovered Purchased Gas Costs 6,316 -
Prepayments 19,755 17,807 27,872
---------- ----------
210,517 208,667 220,981
---------- ----------
Other Assets
Recoverable Future Taxes 88,303 91,011 88,832
Unamortized Debt Expense 22,295 23,394 25,193
Other Regulatory Assets 41,735 48,350 57,086
Investment in Unconsolidated Foreign Subsidiary - 18,887 -
Deferred Charges 8,619 12,025
7,377
Other 64,853 45,631 40,697
---------- ----------
225,805 239,298 219,185
---------- ----------
$2,684,459 $2,267,331 $2,149,772
========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
At September 30 (Thousands of Dollars) 1998 1997 1996
---- ----
Capitalization and Liabilities
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 100,000,000200,000,000 Shares; Issued and
Outstanding - 38,165,88838,468,795 Shares and 37,851,65538,165,888
Shares, Respectively $ 38,16638,469 $ 37,85238,166
Paid In Capital 416,239 405,028 395,272
Earnings Reinvested in the Business 428,112 472,595 422,874
Cumulative Translation Adjustment 7,265 (2,085) -
---------- ----------
Total Common Stock Equity 890,085 913,704 855,998
Long-Term Debt, Net of Current Portion 692,669 581,640 574,000
---------- ----------
Total Capitalization 1,582,754 1,495,344
1,429,998---------- ----------
Minority Interest in Foreign Subsidiaries 25,479 -
---------- ----------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 326,300 92,400 199,700
Current Portion of Long-Term Debt 216,929 103,359 -
Accounts Payable 59,933 74,105 64,610
Amounts Payable to Customers 5,781 10,516 4,618
Other Accruals and Current Liabilities 80,480 83,793 82,520
---------- ----------
689,423 364,173 351,448
---------- ----------
Deferred Credits
Accumulated Deferred Income Taxes 258,222 288,555 281,207
Taxes Refundable to Customers 18,404 19,427 21,005
Unamortized Investment Tax Credit 11,372 12,041 12,711
Other Deferred Credits 98,805 87,791 53,403
---------- ----------
386,803 407,814 368,326
---------- ----------
Commitments and Contingencies - -
---------- ----------
$2,684,459 $2,267,331 $2,149,772
========== ==========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
-------------------------
Consolidated Statement of Cash Flows
------------------------------------
Year Ended September 30 (Thousands of Dollars) 1998 1997 1996 1995
---- ---- ----
Operating Activities
Net Income Available for Common Stock $ 23,188 $114,688 $104,671 $ 75,894
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities
Cumulative Effect of a Change in Accounting
for Depletion 9,116 - -
Impairment of Oil and Gas Producing Properties 128,996 - -
Depreciation, Depletion and Amortization 118,880 111,650 98,231 71,782
Deferred Income Taxes (26,237) 3,800 3,907
8,452Minority Interest in Foreign Subsidiaries 2,213 - -
Other (6,378) 8,030 4,540 275
Change in:
Receivables and Unbilled Utility Revenue 45,200 (10,332) (20,747) 16,034
Gas Stored Underground and Materials and Supplies (1,271) 7,300 (6,308)
5,733Unrecovered Purchased Gas Costs (6,316) - -
Prepayments 829 10,065 1,881
(9,144)
Accounts Payable (24,975) 9,495 10,768 (14,451)
Amounts Payable to Customers (4,735) 5,898 (46,383) 12,287
Other Accruals and Current Liabilities (2,120)(15,481) 4,113 18,200 (1,305)
Other Assets and36 (2,856) (7,667)
Other Liabilities - Net 36,188 (291) 8,8049,913 32,811 7,376
-------- -------- --------
Net Cash Provided by Operating Activities 252,978 294,662 168,469 174,361
-------- -------- --------
Investing Activities
Capital Expenditures (393,233) (214,001) (171,567)
(182,826)
Investment in Unconsolidated Foreign SubsidiarySubsidiaries, Net of Cash Acquired (111,966) (21,075) -
-
Other 2,130 1,429 (1,366)
10,646-------- --------- -------- --------
Net Cash Used in Investing Activities (503,069) (233,647) (172,933)
(172,180)-------- --------- -------- --------
Financing Activities
Change in Notes Payable to Banks and Commercial
Paper 229,387 (107,300) 52,100 35,100
Net Proceeds from Issuance of Long-Term Debt 198,750 99,500 99,650 99,099
Reduction of Long-Term Debt (103,867) (1,310) (88,500) (96,000)
Proceeds from Issuance of Common Stock 7,853 7,074 8,956 2,555
Dividends Paid on Common Stock (66,959) (64,260) (61,179)
(59,194)Dividends Paid to Minority Interest (253) - -
-------- -------- --------
Net Cash Provided by (Used in) Financing Activities 264,911 (66,296) 11,027
(18,440)-------- -------- --------
Effect of Exchange Rates on Cash 1,578 - -
-------- -------- --------
Net Increase (Decrease) in Cash and
Temporary Cash Investments 16,398 (5,281) 6,563 (16,259)
Cash and Temporary Cash Investments at Beginning of Year 14,039 19,320 12,757 29,016
-------- -------- --------
Cash and Temporary Cash Investments at End of Year $ 30,437 $ 14,039 $ 19,320 $ 12,757
======== ======== ========
See Notes to Consolidated Financial Statements
National Fuel Gas Company
Notes to Consolidated Financial Statements
Note A - Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
its majority owned subsidiaries. The equity method is used to account for the
Company's investment in minority owned entities. All significant intercompany
balances and transactions have been eliminated where appropriate.
The Company currently uses the equity method of accounting for its
investment in Severoceske Teplarny, a.s. (SCT). In 1997, Horizon's wholly-owned
subsidiary, Beheer-En Beleggingsmaatschappij Bruwabel, B.V. (Bruwabel) acquired
a 36.8% equity interest in SCT.
The preparation of the consolidated financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current year
presentation.
Regulation
Two of the Company's principal subsidiaries, Distribution Corporation and Supply
Corporation, are subject to regulation by state and federal authorities having
jurisdiction. Distribution Corporation and Supply Corporation have accounting
policies which conform to generally accepted accounting principles, as applied
to regulated enterprises, and are in accordance with the accounting requirements
and ratemaking practices of the regulatory authorities. Reference is made to
Note B - Regulatory Matters for further discussion.
In the International segment, rates charged for the sale of thermal
energy and electric energy at the retail level are subject to regulation and
audit in the Czech Republic by the Czech Ministry of Finance. The regulation of
electric energy rates at the retail level indirectly impacts the rates charged
by the International segment for its electric energy sales at the wholesale
level.
Revenues
Revenues are recorded as bills are rendered, except that service supplied but
not billed is reported as "Unbilled Utility Revenue" and is included in
operating revenues for the year in which service is furnished.
Unrecovered Purchased Gas Costs and Refunds
Distribution Corporation's rate schedules contain clauses that permit adjustment
of revenues to reflect price changes from the cost of purchased gas included in
base rates. Differences between amounts currently recoverable and actual
adjustment clause revenues, as well as other price changes and pipeline and
storage company refunds not yet includable in adjustment clause rates, are
deferred and accounted for as either unrecovered purchased gas costs or amounts
payable to customers.
Distribution Corporation's rate settlements with the State of New York
Public Service Commission (PSC) include provisions for a sharing of earnings
over a specified rate of return on equity. Estimated refund liabilities are
recorded over the term of the settlements which reflect management's current
estimate of such refunds. Reference is made to Note B - Regulatory Matters for
further discussion.
Property, Plant and Equipment
The principal assets, consisting primarily of gas plant in service, are recorded
at the historical cost when originally devoted to service in the regulated
businesses, as required by regulatory authorities. Such cost includes an
Allowance for Funds Used During Construction (AFUDC), which is defined in
applicable regulatory systems of accounts as the net cost of borrowed funds used
for construction purposes and a reasonable rate on other funds when so used. The
rates used in the calculation of AFUDC are determined in accordance with
guidelines established by regulatory authorities.
Included in property, plant and equipment is the cost of gas stored
underground - noncurrent, representing the volume of gas required to maintain
pressure levels for normal operating purposes as well as gas volumes maintained
for system balancing and other purposes, including those needed for no-notice
transportation service.
Maintenance and repairs of property and replacements of minor items of
property are charged directly to maintenance expense. The original cost of the
regulated subsidiaries' property, plant and equipment retired, and the cost of
removal less salvage, are charged to accumulated depreciation.
Oil and gas property acquisition, 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 (discounted at 10%) from the
production of proved gas and oil reserves plus the lower of cost or market of
unevaluated properties, net of related income tax effect (the full-cost
ceiling). The present value of estimated futureFuture net revenues is computedare estimated based on end-of-yearend-of-period prices
adjusted for contracted price changes. At September 30, 1997,If capitalized costs exceed the full-cost
ceiling at the end of any quarter, a permanent impairment is required to be
charged to earnings in that quarter.
Due to significant declines in oil prices in 1998, Seneca's capitalized
costs under the full-cost method of accounting were well below the full-cost ceiling. There are
certain factors, including price declines, which could lowerexceeded the full-cost ceiling and causeat
March 31, 1998. Seneca was required to recognize an impairment of Seneca'sits oil and
gas assets.producing properties in the quarter ended March 31, 1998. This charge
amounted to $129.0 million (pretax) and reduced net income for 1998 by $79.1
million ($2.06 per common share, basic; $2.04 per common share, diluted).
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization are computed by application of either
the straight-line method or the gross revenueunits of production method, in amounts
sufficient to recover costs over the estimated service lives of property in
service, and for oil and gas properties, over the periodbased on quantities produced in
relation to proved reserves (see discussion of estimated gross revenues from proved
reserves.change in method of depletion for
oil and gas properties below). The costs of unevaluated oil and gas properties
are excluded from this computation. For timber properties, depletion, determined
on a property by property basis, is charged to operations based on the annual
amount of timber cut in relation to the total amount of recoverable timber. The
provisions for depreciation, depletion and amortization, as a percentage of
average depreciable property were 4.4% in 1998, 4.6% in 1997 and 4.4% in 1996.
Cumulative Effect of Change in Accounting
Effective October 1, 1997, Seneca changed its method of depletion for oil and
gas properties from the gross revenue method to the units of production method.
The new method was adopted because it provides a better matching of oil and gas
revenues and depletion expense and is the preferable method used by oil and gas
producing companies. Seneca's recent acquisition activities have increased its
scope of operations in relation to those of the Company. Consequently, the
change in method was warranted. The units of production method has been applied
retroactively to prior years to determine the cumulative effect through October
1, 1997. This cumulative effect reduced earnings for 1998 by $9.1 million, net
of income tax. Depletion of oil and gas properties for 1998 has been computed
under the units of production method. The effect of the change from the gross
revenue method to the units of production method increased net income for 1998
by $1.4 million ($0.04 per common share, basic and diluted).
Pro forma amounts for 1998, 1997 and 1996 and 3.5% in 1995.shown below, assume the
retroactive application of the new depletion method.
Year Ended
September 30
----------------------------------
1998 1997 1996
----- ---- ----
Net Income (Thousands):
As reported $ 23,188 $114,688 $104,671
Pro forma $ 32,304 $113,022 $102,655
Earnings Per Common Share:
Basic - As reported $0.61 $3.01 $2.78
Basic - Pro forma $0.85 $2.97 $2.73
Diluted - As reported $0.60 $2.98 $2.77
Diluted - Pro forma $0.84 $2.94 $2.71
Gas Stored Underground - Current
Gas stored underground - current is carried at lower of cost or market, on a
last-in, first-out (LIFO) method. Under present regulatory practice, the
liquidation of a LIFO layer is reflected in future gas cost adjustment clauses.
Based upon the average price of spot market gas purchased in September 1997,1998,
including transportation costs, the current cost of replacing the inventory of
gas stored underground-current exceeded the amount stated on a LIFO basis by
approximately $47.6$21.2 million at September 30, 1997.1998.
Unamortized Debt Expense
Costs associated with the issuance of debt by the Company are deferred and
amortized over the lives of the related issues. Costs associated with the
reacquisition of debt related to rate-regulated subsidiaries are deferred and
amortized over the remaining life of the issue or the life of the replacement
debt in order to match regulatory treatment.
Foreign Currency Translation
The functional currency for the Company's foreign operations is the Czech
Koruna.koruna. The translation from the Czech Korunakoruna to U. S. Dollarsdollars is performed for
balance sheet accounts by using current exchange ratios in effect at the balance
sheet date, and for revenue and expense accounts by using an average exchange
rate during the period. The resultant translation adjustment is reported as a
Cumulative Translation Adjustment, a separate component of Common Stock Equity.
Income Taxes
The Company and its domestic subsidiaries file a consolidated federal income tax
return. Investment Tax Credit, prior to its repeal in 1986, was deferred and is
being amortized over the estimated useful lives of the related property, as
required by regulatory authorities having jurisdiction.
Financial Instruments
The Company, in its ExplorationSeneca and Production segment and natural gas marketing
operations utilizesNFR utilize price swap agreements as well as exchange-traded futures
and natural gas futures,options, respectively, to manage a portion of the market risk associated
with fluctuations in the price of natural gas and crude oil. Gains or losses
from the price swap agreements are accrued in operating revenues on the
Consolidated Statement of Income at the contract settlement dates. Gains or
losses from natural gasexchange-traded futures and options are recorded in Other Deferred
Credits on the Consolidated Balance Sheet until the hedged commodity transaction
occurs, at which point they are reflected in operating revenues on the
Consolidated Statement of Income. Reference is made to Note F - Financial
Instruments for further discussion.
In the International segment, PSZT has purchased a forward contract to
hedge against the exchange rate risk associated with U.S. dollar denominated
debt. Exchange rate gains or losses related to the U.S. dollar denominated debt
are recorded in Other Income on the Consolidated Statement of Income on a
monthly basis. Gains or losses related to the forward contract are recorded in
Other Income on the Consolidated Statement of Income as an offset to the gains
or losses recognized on the U.S. dollar denominated debt. Reference is made to
Note F - Financial Instruments for further discussion.
Consolidated Statement of Cash Flows
For purposes of the Consolidated Statement of Cash Flows, the Company considers
all highly liquid debt instruments purchased with a maturity of generally three
months or less to be cash equivalents. Interest paid in 1998, 1997 and 1996 and 1995 was
$46.2 million, $52.4 million and $54.8 million, and $53.5 million, respectively. Net incomeIncome taxes paid
in 1998, 1997 and 1996 and 1995 were $64.5 million, $69.2 million and $60.8 million,
respectively. In 1998, the Company received a $22.4 million refund of taxes and
$34.6interest from the Internal Revenue Service stemming from the settlement of the
primary issues of audits of years 1977 - 1994. In addition, the Company received
$2.2 million respectively.in tax refunds issued to SCT and PSZT by the Czech Ministry of
Finance.
Details of the SCT, PSZT and HarCor stock acquisitions during 1998 are
as follows (dollars in millions):
SCT PSZT HarCor Total
--- ---- ------ -----
Assets acquired $66.1 $141.8 $105.6 $313.5
Liabilities assumed (22.3) (77.3) (73.0) (172.6)
Existing investment at acquisition (18.9) - - (18.9)
Cash acquired at acquisition (6.3) (0.9) (2.8) (10.0)
----- ----- ------ ------
Cash paid, net of cash acquired $18.6 $63.6 $ 29.8 $112.0
===== ===== ====== ======
Further discussion of these acquisitions can be found at Note J - Stock
Acquisitions.
In 1997, Seneca entered into non-cash investing activities whereby it
issued notes to third parties totaling $12.3 million in connection with the
acquisition of timber properties.
Earnings Per Common Share
EarningsBasic earnings per common share are calculated using the weighted average number of
shares outstanding during each fiscal year. Common stock equivalents in the form
of stock options do not have a material dilutive effect on earnings per common
share.
New Accounting Pronouncements
Earnings Per Share
In February 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 128, "Earnings per Share" (SFAS
128). SFAS 128 replaces the standards for computing earnings per share
previously found in Accounting Principles Board Opinion No. 15, "Earnings per
Share" (APB 15). SFAS 128 requires dual presentation of basic and diluted
earnings per share (EPS) on the face of the income statement for all entities
with complex capital structures. Basic EPS is computed by dividing income available tofor
common stockholdersstock by the weighted-averageweighted average number of common shares outstanding for the
period. Diluted EPSearnings per common share reflects the potential dilution that
could occur if securities or other contracts to issue common stock were
exercised or converted into common stock. Such additional shares are added to
the denominator of the basic EPSearnings per common share calculation in order to
calculate diluted EPS.earnings per common share. The only potentially dilutive
securities the Company has outstanding are stock options. The diluted weighted
average shares outstanding shown on the Consolidated Statement of Income
reflects the potential dilution as a result of these stock options. Such
dilution was determined using the Treasury Stock Method as required by Statement
of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share."
New Accounting Pronouncements
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS
133 establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. It requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The intended use of the derivative and its
designation as either (1) a hedge of the exposure to changes in the fair value
of a recognized asset or liability or a firm commitment (a fair value hedge),
(2) a hedge of the exposure to variable cash flows of a forecasted transaction
(a cash flow hedge), or (3) a hedge of the foreign currency exposure of a net
investment in a foreign operation (a foreign currency hedge), will determine
when the gains or losses on the derivatives are to be reported in earnings and
when they are to be reported as a component of other comprehensive income.
Management has determined that the price swap agreements utilized by
Seneca will qualify as cash flow hedges and that the exchange-traded futures and
options utilized by NFR will qualify as fair value hedges upon implementation of
SFAS 133. At adoption, these hedges will be recorded at fair value on the
Consolidated Balance Sheets as either an asset or liability. In the case of the
price swap agreements, the offset to the asset or liability will be other
comprehensive income, as discussed below. As for the exchange-traded futures and
options, the offset will be recorded as a cumulative effect of change in
accounting item on the Consolidated Statement of Income. Since the
exchange-traded futures and options will have been designated as hedges of firm
commitments, the firm commitments will also be recorded at fair value on the
Consolidated Balance Sheets as either an asset or liability. The offset to this
asset or liability will be the aforementioned cumulative effect of change in
accounting item on the Consolidated Statement of Income.
Management is continuing to evaluate other financial instruments and
contracts which may have embedded derivatives that could be impacted by the
adoption of SFAS 133. The Company is requiredplans to adopt SFAS 128133 in the first quarter
of 1998.
Earlier application is not permitted and restatement of all prior period EPS
data presented is required. The Company does not believe that common stock
equivalents in the form of stock options will have a material dilutive effect on
its EPS under SFAS 128. However, since SFAS 128 eliminated the 3% materiality
threshold of APB 15, diluted EPS will be disclosed as required by SFAS 128.fiscal 2000.
Comprehensive Income
In June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" (SFAS
130). SFAS 130 establishes standards for reporting and display of comprehensive
income in a full set of general-purpose financial statements. Comprehensive
income, as described in SFAS 130, includes Net Income Available for Common Stock
as well as items under existing accounting standards that are reported as
adjustments to stockholders' equity. Such adjustments to stockholders' equity
currently include foreign currency translation adjustments, minimum pension
liability adjustments and unrealized gains and losses on certain investments in
debt and equity securities. Upon adoption of SFAS 133, certain unrealized gains
or losses on derivative financial instruments will be included as a component of
other comprehensive income in accordance with SFAS 130. The Company is required towill adopt
SFAS 130 in the first quarter of 1999.
However, earlier application is permitted. The Company is currently in the
process of determining how it will present comprehensive income and its
components within the guidelines established by SFAS 130. SFAS 130 requires
restatement of prior period financial statements for comparability.
Business Segment Information
In June 1997, the FASB issued SFAS 131, "Disclosures about Segments of an
Enterprise and Related Informtion" (SFAS 131). SFAS 131 establishes standards
for the way that public business enterprises report information about operating
segments in annual financial statements and requires that those enterprises
report selected information about operating segments in interim financial
reports issued to shareholders. It also establishes standards for related
disclosures about products and services, geographic areas, and major customers.
Generally, SFAS 131 requires reporting segment information under a management
approach. The management approach is based on the way that management organizes
the segments within the enterprise for making operating decisions and assessing
performance. SFAS 131 supersedes SFAS 14, "Financial Reporting for Segments of a
Business Enterprise," but retains the requirement to report information about
major customers.
The Company is required to adopt SFAS 131 in its annual report for
1999. However, earlier application is permitted. In the second year of
application, SFAS 131 will be applied to interim periods. The Company is
currently in the process of determining how SFAS 131 will impact its segment
reporting. SFAS 131 would require restatement of prior period financial
statements for comparability.
Note B - Regulatory Matters
Regulatory Assets and Liabilities
Distribution Corporation and Supply Corporation have incurred various costs and
received various credits which have been reflected as regulatory assets and
liabilities on the Company's consolidated balance sheets.Consolidated Balance Sheets. Accounting for such
costs and credits as regulatory assets and liabilities is in accordance with
SFAS 71, "Accounting for the Effect of Certain Types of Regulation" (SFAS 71).
This statement sets forth the application of generally accepted accounting
principles for those companies whose rates are established by or are subject to
approval by an independent third-party regulator. Under SFAS 71, regulated
companies defer costs and credits on the balance sheet as regulatory assets and
liabilities when it is probable that those costs and credits will be allowed in
the ratesettingrate setting process in a period different from the period in which they
would have been reflected in income by an unregulated company. These deferred
regulatory assets and liabilities are then flowed through the income statement
in the period in which the same amounts are reflected in rates. Distribution
Corporation and Supply Corporation have recorded the following regulatory assets
and liabilities:
At September 30 (Thousands) 1998 1997 1996
---- ----
Regulatory Assets:
Recoverable Future Taxes (Note C) $ 91,01188,303 $ 88,83291,011
Unamortized Debt Expense (Note A) 16,886 18,603 20,319
Pension and Post-Retirement Benefit Costs (Note G) 22,483 24,200 22,259
Order 636 Transition Costs* 5,015 14,256
Gathering Plant 5,475 7,675 9,868
Environmental Clean-up (Note H) 12,394 8,697
8,144
Other 2,763 2,5591,383 7,778
-------- --------
Total Regulatory Assets 146,924 157,964 166,237
-------- --------
Regulatory Liabilities:
Amounts Payable to Customers (Note A) 5,781 10,516 4,618
New York Rate SettlementSettlement* 19,341 22,232 1,675
Taxes Refundable to Customers (Note C) 18,404 19,427 21,005
Pension and Post-Retirement
Benefit CostsCosts* (Note G) 20,222 10,446
4,665
OtherOther* 1,741 1,538 541
-------- --------
Total Regulatory Liabilities 65,489 64,159 32,504
-------- --------
Net Regulatory Position $ 81,435 $ 93,805 $133,733
======== ========
* Exclusive of amounts being collected through gas costs. Such amounts are
includedIncluded in unrecovered purchased gas costs or amounts payable to customers.Other Deferred Credits on the Consolidated Balance Sheets.
If for any reason, including deregulation, a change in the method of
regulation, or a change in competitive environment, Distribution Corporation
and/or Supply Corporation ceases to meet the criteria for application of SFAS 71
for all or part of their operations, the regulatory assets and liabilities
related to those portions ceasing to meet such criteria would be eliminated from
the balance sheet and included in income of the period in which the
discontinuance of SFAS 71 occurs. Such amounts would be classified as an
extraordinary item.
New York Rate Settlement
The New York jurisdictionAs of September 30, 1998, Distribution Corporation entered into aCorporation's 1996 rate settlement with
the Public Service CommissionPSC expired. As part of the State1996 rate settlement, earnings above a 12%
return on equity (determined on a cumulative basis over the three years ended
September 30, 1998) are to be shared equally between shareholders and customers.
As a result of New York (PSC)
during 1996. The settlement acknowledged thatthis sharing mechanism, Distribution Corporation may incur
expenses above thosehas determined
that the refund due customers as of September 30, 1998 is $10.7 million (of
which $3.0 million will be passed back to customers in 1999 and thus is included
as a current liability on the Consolidated Balance Sheet in Amounts Payable to
Customers). An additional $3.0 million will be passed back to customers in 2000
with the currentremaining amount, if any, to be passed back to customers as determined
by the PSC.
In addition, as part of the 1996 rate structure for certain specific
items. The settlement, allows Distribution
Corporation was allowed to utilizeaccumulate certain refunds from upstream pipeline
companies and certain credits (referred to as the "refund pool") to offset
such additional
expenses. Atcertain specific expense items. This refund pool had a balance at September 30,
19971998 of $6.0 million. Various other regulatory liabilities were also created
through the rate settlement process and 1996, such refunds and credits combined amounted to $19.2$5.6 million and $1.7 million, respectively. At the end of the
settlement period, if such refunds or credits exceed the specified additional
expenses, the excess amount would be passed back to the customers.
The settlement also provided that earnings above a 12% return on equity
(excluding certain items and determined on a cumulative basis over the three
years endingat September
30, 1998) will be shared equally between shareholders and
ratepayers. As a result of this sharing mechanism, Distribution Corporation
recorded an estimated cumulative refund provision to its customers of $3.0
million during the fourth quarter of 1997 related to the two years ended
September 30, 1997. The final amount owed to customers, if any, will not be
known until the conclusion of the settlement period.
1998.
Note C - Income Taxes
The components of federal and state income taxes included in the Consolidated
Statement of Income are as follows:
Year Ended September 30 (Thousands) 1998 1997 1996 1995
---- ---- ----
Operating Expenses:
Current Income Taxes -
Federal $57,807 $55,148 $30,522$ 40,740 $ 57,807 $ 55,148
State 6,635 7,067 7,266 4,905
Deferred Income Taxes 3,800 3,907 8,452
------- ------- --------
Federal (21,687) 2,895 2,160
State (5,997) 905 1,747
Foreign Income Taxes 4,333 - -
-------- -------- --------
24,024 68,674 66,321 43,879
Other Income:
Deferred Investment Tax Credit (665) (665) (672)
------- ------- -------(665)
Minority Interest in Foreign Subsidiaries (1,218) - -
Cumulative Effect of Change in Accounting
for Depletion (5,737) - -
-------- -------- --------
Total Income Taxes $68,009 $65,656 $43,207
======= ======= =======$ 16,404 $ 68,009 $ 65,656
======== ======== ========
The U.S. and foreign components of income (loss) before income taxes are as
follows:
Year Ended September 30 (Thousands) 1998 1997 1996
---- ---- ----
U.S. $ 31,127 $184,257 $170,424
Foreign 8,465 (1,560) (97)
-------- -------- --------
$ 39,592 $182,697 $170,327
======== ======== ========
Total income taxes as reported differ from the amounts that were
computed by applying the federal income tax rate to income before income taxes.
The following is a reconciliation of this difference:
Year Ended September 30 (Thousands) 1998 1997 1996 1995
---- ---- ----
Net Income Available for Common Stock $ 23,188 $114,688 $104,671
$ 75,894
Total Income TaxesTax Expense 16,404 68,009 65,656 43,207
-------- -------- --------
Income Before Income Taxes $182,697 $170,327 $119,101
======== ======== ========39,592 182,697 170,327
-------- -------- --------
Income Tax Expense, Computed at Federal
Statutory Rate of 35% $63,944 $59,614 $41,68513,857 63,944 59,614
Increase (Reduction) in Taxes Resulting from:
Current State Income Taxes Net of Federal Income Tax Benefit 4,594 4,723 3,188986 5,182 5,858
Depreciation 2,186 2,560 2,499
2,397Property Retirements (1,609) (1,320) (1,083)
Keyman Life Insurance (774) (695) (234)
Prior Years Tax Adjustment 2,846 - -
Miscellaneous (3,089) (1,180) (4,063)
------- ------- -------(1,088) (1,662) (998)
-------- -------- --------
Total Income Taxes $68,009 $65,656 $43,207
======= ======= =======$ 16,404 $ 68,009 $ 65,656
======== ======== ========
Significant components of the Company's deferred tax liabilities and
assets were as follows:
At September 30 (Thousands) 1998 1997 1996
---- ----
Deferred Tax Liabilities:
Excess ofAbandonments $ 15,545 $ 14,241
Accelerated Tax Over Book Depreciation $190,913 $182,271132,138 190,913
Exploration and Intangible Well
Drilling Costs 147,795 117,759
98,293
Other 62,189 67,03042,109 47,948
-------- --------
Total Deferred Tax Liabilities 337,587 370,861 347,594
-------- --------
Deferred Tax Assets:
Capitalized Overheads Capitalized for Tax Purposes(22,484) (19,406)
(16,289)
Other (56,881) (62,900) (50,098)
-------- --------
Total Deferred Tax Assets (79,365) (82,306) (66,387)
-------- --------
Total Net Deferred Income Taxes $258,222 $288,555 $281,207
======== ========
SFAS 109, "Accounting for Income Taxes" (SFAS 109), requires the
recognition of regulatoryRegulatory liabilities representing the reduction of previously
recorded deferred income taxes associated with rate-regulated activities that
are expected to be refundable to customers. Thesecustomers amounted to $19.4$18.4 million and $21.0$19.4
million at September 30, 19971998 and 1996,1997, respectively. Also, SFAS 109
requires the recognition ofregulatory assets,
representing future amounts collectible from customers, corresponding to
additional deferred income taxes not previously recorded because of prior
ratemaking practices. Substantially all of these
deferred taxes relate to property, plant and equipment and related investment
tax credits and will be amortized consistent with the depreciation and
amortization of these accounts. The additional deferred taxes and corresponding
regulatory assets, representing future amounts collectible from customers in the
ratemaking process,practices amounted to $91.0$88.3 million and $88.8$91.0 million at September
30, 1998 and 1997, respectively.
The primary issues related to Internal Revenue Service audits of the
Company for the years 1977-1994 were settled during the current year. Net income
for the year ended September 30, 1998 was increased approximately $5.0 million
as a result of interest, net of tax and 1996, respectively.other adjustments, related to this
settlement.
Note D - Capitalization
Summary of Changes in Common Stock Equity
Earnings
Paid Reinvested Cumulative
(Thousands, Except Common Stock In in the Translation
---------------
Per Share Amounts) Shares Amount Capital Business Adjustment
- ------------------ ------ ------ ------- ---------- -----------
Balance at
September 30, 1994 37,278 $37,278 $379,156 $363,854 $ -
Net Income Available
for Common Stock 75,894
Dividends Declared on
Common Stock
($1.60 Per Share) (59,625)
Common Stock Issued
Under Stock and
Benefit Plans 156 156 3,875
------ ------- -------- -------- -----------------
Balance at
September 30, 1995 37,434 37,434 383,031 380,123$37,434 $383,031 $380,123 $ -
Net Income Available
for Common Stock 104,671
Dividends Declared
on Common Stock
($1.65 Per Share) (61,920)
Common Stock Issued
Under Stock and
Benefit Plans 418 418 12,241
------ ------- -------- -------- -------
Balance at
September 30, 1996 37,852 37,852 395,272 422,874 -
Net Income Available
for Common Stock 114,688
Dividends Declared
on Common Stock
($1.71 Per Share) (64,967)
Cumulative Translation
Adjustment (2,085)
Common Stock Issued
Under Stock and
Benefit Plans 314 314 9,756
------ ------- -------- -------- -------
Balance at
September 30, 1997 38,166 $38,166 $405,028 $472,595* $(2,085)38,166 405,028 472,595 (2,085)
Net Income Available
for Common Stock 23,188
Dividends Declared on
Common Stock
($1.77 Per Share) (67,671)
Cumulative Translation
Adjustment 9,350
Common Stock Issued
Under Stock and
Benefit Plans 303 303 11,211
------ ------- -------- -------- -------
Balance at
September 30, 1998 38,469 $38,469 $416,239 $428,112* $ 7,265
====== ======= ======== ======== =======
* The availability of consolidated earnings reinvested in the business for
dividends payable in cash is limited under terms of the indentures covering
long-term debt. At September 30, 1997, $398.21998, $353.7 million of accumulated
earnings was free of such limitations.
Common Stock
The Company has various plans which allow shareholders, customers and employees
to purchase shares of Company common stock. The Dividend Reinvestment and Stock
Purchase Plan allows shareholders to reinvest cash dividends and/or make cash
investments in the Company's common stock. The Customer Stock Purchase Plan
provides residential customers the opportunity to acquire shares of Company
common stock without the payment of any brokerage commissioncommissions or service charges
in connection with such acquisitions. The 401(k) Plans allow employees the
opportunity to invest in Company common stock, in addition to a variety of other
investment alternatives. At the discretion of the Company, shares purchased
under these plans are either original issue shares purchased directly from the
Company or shares purchased on the open market by an agent.
The Company also has a Director Stock PlanProgram under which it issues
shares of Company common stock to its non-employee directors as partial
consideration for servicetheir services as directors.
Shareholder Rights Plan
In 1996, the Company's Board of Directors adopted a shareholder rights plan and
declared a dividend of one right (Right) for each share of common stock held by
the shareholders of record on July 31, 1996. The Rights become exercisable ten
days after actions that result or could result in the acquisition by a person or
entity of 10% or more of the Company's voting stock. If the Rights become
exercisable, each Company stockholder, except such an acquirer, will be able to
exercise a Right and receive common stock (or, in certain cases, cash, property
or other securities) of the Company, or common stock of the acquirer, having a
market value equal to twice the Right's then current purchase price. If a Right
were currently exercisable, it would entitle a Company stockholder, other than
an acquirer, to purchase $130 worth of Company common stock (or the common stock
of the acquirer) for $65.
The Company is able to exchange the Rights at an exchange ratio of one
share of common stock per Right. It is also is able to redeem, in whole but not in
part, the Rights at a price of $0.01 per Right anytime until ten days after an
acquirer announces that it has acquired or has the right to acquire 10% or more
of the Company's voting stock. AllIn September 1998, the Directors voted to amend
the shareholder rights plan to (i) remove provisions which would prevent newly
elected directors from voting on certain questions including the redemption of
Rights, expire on(ii) allow such questions to be decided by a vote of three quarters of
all the directors and (iii) extend the expiration date of the Rights by two
years to July 31, 2006.2008.
Stock Option and Stock Award Plans
The Company's 1997 AwardCompany has various stock option and Option Plan (1997 Plan) providesstock award plans which provide or
provided for the issuance of one or more of the following to key employees:
incentive stock options, nonqualified stock options, stock appreciation rights,
restricted stock, performance units andor performance shares to key
employees. The 1993 Award and Option Plan (1993 Plan) provided for the issuance
of the same type of awards and options as the 1997 Plan. The 1983 Incentive
Stock Option Plan (1983 Plan) provided for the issuance of incentive stock
options to key employees. The 1984 Stock Plan (1984 Plan) provided for awards of
restricted stock, nonqualified stock options and stock appreciation rights to
key employees.shares. Stock options under
all plans have exercise prices equal to the average market price of Company
common stock on the date of grant, and generally no option is exercisable less
than one year or more than ten years after the date of each grant.
In October 1995,The Company follows the FASB issueddisclosure provision of SFAS 123, "Accounting
for Stock-Based Compensation" (SFAS 123). In 1996, the Company adopted the disclosure provision
of SFAS 123, but opted to remainremains under the expense
recognition provisions of APBAccounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees," in accounting for its stock option
and stock award plans. For the years ended September 30, 1998, 1997 1996 and 1995,1996, no
compensation expense was recognized for options granted under these plans.
Compensation expense related to stock appreciation rights and restricted stock
under these stock plans was $4.1 million, $8.1 million $6.7 million and $1.4$6.7 million for the
years ended September 30, 1998, 1997 1996 and 1995,1996, respectively. Had compensation
expense for stock options granted under the Company's stock option and stock
award plans been determined based on fair value at the grant dates consistent
with the method of SFAS 123, the Company's net income and earnings per share
would have been reduced to the pro forma amounts below:
Year Ended September 30 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Income (Thousands):
As reported $23,188 $114,688 $104,671
Pro Formaforma $18,859 $110,506 $104,322
Earnings per Common Share:
Basic - As reported $0.61 $3.01 $2.78
Basic - Pro Formaforma $0.49 $2.90 $2.77
Diluted - As reported $0.60 $2.98 $2.77
Diluted - Pro forma $0.49 $2.87 $2.76
The above 1996 pro forma amount relates only to options granted since
the beginning of 1996. Had SFAS 123 been effective prior to 1996, the fair value
of options granted in 1995 but vesting in 1996 would have further reduced 1996
pro forma net income and earnings per share by $1.0 million and $0.03,
respectively.
Transactions involving option shares for all three plans are summarized as
follows:
Number of
Shares Subject Weighted Average
to Option Exercise Price
- ----------------------------------------------------------------------------
Outstanding at September 30, 1994 1,167,337 $26.80
Granted in 1995 362,100 $27.94
Exercised in 1995* (17,615) $19.46
Forfeited in 1995 (11,532) $31.00
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 1995 1,500,290 $27.13
Granted in 1996 487,750 $34.44
Exercised in 1996* (195,321) $22.72
Forfeited in 1996 (19,468) $27.90
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 1996 1,773,251 $29.62
Granted in 1997 678,750 $39.61
Exercised in 1997* (274,655) $25.80
Forfeited in 1997 (3,000) $36.81
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 1997 2,174,346 $33.21
Granted in 1998 770,000 $44.44
Exercised in 1998* (205,200) $27.41
Forfeited in 1998 (3,250) $41.63
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 1998 2,735,896 $36.80
- -------------------------------------------------------------------------------
Option shares exercisable
at September 30, 1997 1,495,596 $30.311998 1,965,896 $33.80
Option shares available for future
grant at September 30, 1997*1998** 1,401,270837,177
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
* In connection with exercising these options, 44,580; 117,326; 77,679; and 3,19277,679
shares were surrendered and canceled during 1998, 1997 1996 and 1995,1996,
respectively.
** Including shares available for restricted stock grants.
The weighted average fair value per share of options granted in 1998,
1997 and 1996 was $7.91, $7.66 and $5.58, respectively. These weighted average
fair values were estimated on the date of grant using a binomial option pricing
model which is a modification of the Black-Scholes option pricing model, with
the following weighted average assumptions forassumptions:
Year Ended September 30 1998 1997 and 1996
respectively: quarterly dividend
yield of---- ---- ----
Quarterly Dividend Yield 0.98% 1.06% and 1.22%, annual expected return of 16.25% and 12.83%, annual
standard deviation (volatility) of
Annual Standard Deviation (Volatility) 16.48% 16.76% and 15.62%, risk free rate of
Risk Free Rate 5.77% 6.58% and 6.28%, and expected term of 5.0 years and
Expected Term - in Years 5.5 years.5 5.5
The following table summarizes information about options outstanding at
September 30, 1997:1998:
Options Outstanding Options Exercisable
- -------------------------------------------------------------- -----------------------------
Number Weighted Average Weighted Number
Range of Outstanding Remaining Average Exercisable Weighted Average
Exercise Prices at 9/30/9798 Contractual Life Exercise Price at 9/30/9798 Exercise Price
- --------------- --------------------- ---------------- -------------- ----------- -------------------------- --------------
$18.00 - $25.19 307,941 3.90217,720 3.22 years $24.03 307,941 $24.03$24.47 217,720 $24.47
$27.94 - $36.75 1,353,776 6.98 years $33.03 1,353,776 $33.03
$41.63 1,866,405 8.25- $44.88 1,164,400 9.02 years $34.73 1,187,655 $31.94$43.49 394,400 $41.63
Restricted stock is subject to restrictions on vesting and
transferability. Restricted stock awards entitle the participants to full
dividend and voting rights. The market value of restricted stock on the date of
the award is being recorded as compensation expense over the periods during
which the vesting restrictions exist. Certificates for shares of restricted
stock awarded under the Company's 1984stock options and 1993 Plansstock award plans are held
by the Company during the periods in which the restrictions on vesting are
effective.
The following table summarizes the awards of restricted stock over the
past three years:
Year Ended September 30 1998 1997 1996
1995
- -----------------------------------------------------------------------------------------------------------------------------------------------------
Shares of Restricted Stock Awarded 7,609 6,300 8,000 8,000
Weighted Average Market Price of
Stock on Award Date $44.875 $40.875 $36.81
$26.00
- -----------------------------------------------------------------------
------------------------------------------------------------------------------
As of September 30, 1997, 121,9621998, 110,655 shares of non-vested restricted stock
were outstanding. Vesting restrictions will lapse on 107,662 of these shares on
January 2 of each year as follows: 1998 - 18,916 shares; 1999 - 20,916
shares; 2000 - 22,91628,216 shares; 2001 - 24,91430,523 shares; 2002 - 8,000 shares; 2003 -
6,0008,000 shares; 2004 - 4,0007,000 shares; 2005 - 6,000 shares; and 20052006 - 2,000 shares. For restricted stock
awarded before 1996, generally, the restrictions on transferability do not lapse
until the earliest of (a) six years from the date the vesting restrictions
lapse; (b) the recipient's attainment of age 65; or (c) the recipient's death.
For the 8,000 shares of restricted stock awarded in 1996, all restrictions will
lapse on one-fourth of such shares on each September 26, 2003 through 2006. For
the 6,300 shares of restricted stock awarded in 1997, all restrictions
respecting 5,300 shares will lapse on December 13, 1999 and all restrictions
respecting 1,000 shares will lapse on December 13, 2003.
Redeemable Preferred Stock
As of September 30, 1997,1998, there were 3,200,00010,000,000 shares of $25$1 par value
Cumulative Preferred Stock authorized but unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
At September 30 (Thousands) 1998 1997 1996
---- ----
National Fuel Gas Company:
Debentures:
7-3/4% due February 2004 $125,000 $125,000
Medium-Term Notes:
6.42% due November 1997 50,000- 50,000
6.08% due July 1998 50,000- 50,000
5.58% due March 1999 100,000 100,000
7.25% due July 1999 50,000 50,000
6.60% due February 2000 50,000 50,000
7.395% due March 2023 49,000 49,000
8.48% due July 2024*2024(1) 50,000 50,000
7.375% due June 2025 50,000 50,000
6.214% due August 2027**2027(2) 100,000 100,000
6.303% due May 2008 200,000 -
-------- --------
774,000 674,000
574,000
Other-------- --------
HarCor:
14.875% Senior Secured Notes 10,99962,571 -
-------- --------
PSZT:
8.04% U.S. Dollar Denominated
Debt due
March 2000 - December 2004(3) 50,596 -
13% Debentures due December 1999 9,908 -
-------- --------
60,504 -
-------- --------
SCT:
14.72% Term Loan payable quarterly
through June 2006(4) 4,524 -
-------- --------
Other Notes 7,999 10,999
-------- --------
Total Long-Term Debt 909,598 684,999 574,000
Less Current Portion 216,929 103,359 -
-------- --------
$692,669 $581,640 $574,000
======== ========
*(1) Callable by the Company beginning July 1999 at a redemption price of
106.36%. This price would be effective through July 2000 and would decline
in subsequent years.
(2) Putable by debt holders only on August 12, 2002, at par.
(3) Interest rate is six month LIBOR (London Interbank Offered Rates) plus
2.2%.
(4) Interest rate is six month PRIBOR (Prague Interbank Offered Rate) plus 1%.
In May 1998, the Company issued $200.0 million of 6.303% medium-term
notes due to mature in May 2008. After deducting underwriting discounts and
commissions, the net proceeds to the Company amounted to $198.8 million.
The stock acquisitions of HarCor, PSZT and SCT and subsequent
consolidation of these companies into the Company's consolidated financial
statements accounts for the significant increase in long-term debt of Seneca and
Horizon. These stock acquisitions are discussed further at Note J - Stock
Acquisitions.
The senior secured notes recorded by Seneca as a result of the HarCor
acquisition have a book value of $53.6 million. In accordance with APB 16,
"Business Combinations" (APB 16), the senior secured notes were adjusted to fair
market value on the opening balance sheet to reflect an effective interest rate
of 5.875% and the projected redemption of this debt in 1999. ** Putable beginning August 2002.
Other Notes In January and April 1997, Seneca issued three notes to third
parties totaling $12.3 millionAs such, the entire
balance is included in connection with its acquisitionCurrent Portion of timber
properties. As shown inLong-Term Debt on the table above, the remaining principal amount on such
notes is approximately $11.0 millionConsolidated
Balance Sheets at September 30, 1997. All notes have an
interest rate of 6.75%. The principal amount will be paid in installments over
the term of the notes which mature in January 1999, October 1999 and June 2001.1998.
The aggregate principal amounts of long-term debt maturing for the next
five years are: $103.4 million in 1998, $153.7and thereafter are as follows: $216.9 million in 1999, $52.2$70.4 million
in 2000, $1.6$12.4 million in 2001, and none$10.7 million in 2002, (subject to$10.8 million in 2003 and
$588.4 million thereafter.
The Company's indenture contains covenants which limit, among other
things, the putincurrence of $100
million).
The amounts and timingfunded debt. Funded debt basically is indebtedness
maturing more than one year after the date of issuance. Because of the
impairment of oil and gas properties recorded by the Company in March 1998,
these covenants will restrict the Company's ability to issue additional funded
debt, with certain exceptions, until at least the third quarter of fiscal 1999.
This will not, however, limit the Company's issuance and sale of funded debt securities will
depend on market conditions, regulatory authorizations, and the requirements of
the Company.
to refund
existing funded debt.
Note E - Short-Term Borrowings
The Company has SEC authorization under the Public Utility Holding Company Act
of 1935, as amended, to borrow and have outstanding as much as $750.0 million of
short-term debt at any time.
The Company historically has borrowed short-term either through bank
loans or the issuance of commercial paper. As for the former, 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, acquisitions and capital expenditures of the Company, including
the Company's oil and gas exploration and development program and the purchase
and storage of gas. Borrowings under these lines of credit are made at
competitive money market rates, and the Company currently is authorized to borrow up to $600.0 million
thereunder.rates. These credit lines which are callablerevocable at the option of the
financial institutions and are reviewed on an annual basis.
The Company also has authorization tocould issue and have outstanding as much as $300.0$750.0 million
of commercial paper at any time (or a lesser amount so that short-term
borrowings from time to time,all sources do not exceed $750.0 million at any time), but is
not likely to exceed $130.0have more than $150.0 million in commercial paper outstanding
because of the terms of the revolving credit arrangement discussed below.
Unless theThe Company receives additional regulatory authority, its
borrowings under its discretionary lines of credit, or through the issuance of
commercial paper, may not exceed $600.0 million in the aggregate.
Additionally, the Company has entered into an agreement that
establishes a 364-day committed revolving credit arrangement with
five commercial banks, under which it may borrow as much as $130.0$150.0 million. This
arrangement may be utilized for general corporate purposes, primarily to support
the issuance of commercial paper. The Company pays a fee to maintain this
arrangement, and may borrow through this arrangement under four interest rate
options. If amounts are borrowed under this arrangement, the $600.0$750.0 million
available for short-term borrowing under the discretionary lines of creditby other means is correspondingly reduced. No
borrowings were made under this arrangement during the fiscal year ended
September 30, 1997.1998.
At September 30, 1998, the Company had outstanding notes payable to
banks and commercial paper of $196.3 million and $130.0 million, respectively.
At September 30, 1997, the Company had outstanding notes payable to banks and
commercial paper of $32.4 million and $60.0 million, respectively.
At
September 30, 1996, the Company had outstanding notes payable to banks and
commercial paper of $109.7 million and $90.0 million, respectively.
The weighted average interest rate on notes payable to banks was 6.12%5.67%
and 5.63%6.12% at September 30, 19971998 and 1996,1997, respectively. The weighted average
interest rate on commercial paper was 5.64%5.60% and 5.56%5.64% at September 30, 19971998 and
1996,1997, respectively.
Note F - Financial Instruments
Fair Values
The fair market value of the Company's long-term debt is estimated based on
quoted market prices of similar issues having the same remaining maturities,
redemption terms and credit ratings. Based on these criteria, the fair market
value of long-term debt, including current portion, was as follows:
At September 30 (Thousands)
1998 1998 1997 1996
------------------- -------------------1997
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
Long-Term Debt $909,598 $966,085 $684,999 $704,409 $574,000 $572,001
======== ======== ======== ========
The fair value amounts are not intended to reflect principal amounts
that the Company will ultimately be required to pay.
Temporary cash investments, notes payable to banks and commercial paper
are stated at amounts which approximate their fair value due to the short-term
maturities of those financial instruments. Investments in life insurance are
stated at their cash surrender values as discussed below.
Investments
Other assets consist principally ofinclude cash surrender values of insurance contracts. The cash
surrender values of these insurance contracts amounted to $35.7$40.1 million and
$31.6$35.7 million at September 30, 19971998 and 1996,1997, respectively. The insurance
contracts were established as aan informal funding mechanism for various benefit
obligations the Company has to certain employees.
Derivative Financial Instruments
The Company, in its Exploration and Production segment,Seneca has entered into certain price swap agreements to manage a portion of the
market risk associated with fluctuations in the price of natural gas and crude
oil, thereby providing more stability to theits operating results of that business segment.results. These agreements
are not held for trading purposes. The price swap agreements call for the
CompanySeneca to
receive monthly payments from (or make payment to) other parties based upon the
difference between a fixed and a variable price as specified by the agreement.
The variable price is either a crude oil price quoted on the New York Mercantile
Exchange or a quoted natural gas price in "Inside FERC." These variable prices
are highly correlated with the market prices received by the
CompanySeneca for its natural
gas and crude oil production.
The following summarizes the Company's settlements underAt September 30, 1998, Seneca had natural gas price swap agreements
during 1997, 1996 and 1995:
Year Ended September 30 1997 1996 1995
--------------- --------------- ---------------
Natural Gas Swap Agreements:
Notional Amount - Equivalent
Billion Cubic Feet (Bcf) 24.9 23.0 16.3
Range of Fixed Prices per
Thousand Cubic Feet (Mcf) $1.71 - $2.10 $1.71 - $3.05 $1.74 - $2.39
Weighted Average Fixed Price
per Mcf $1.92 $1.91 $2.03
Range of Variable Prices
per Mcf $1.77 - $4.11 $1.67 - $3.43 $1.36 - $1.77
Weighted Average Variable Price
per Mcf $2.57 $2.31 $1.59
Gain (Loss) $(16,387,000) $(9,231,000) $7,157,000
Crude Oil Swap Agreements:
Notional Amount - Equivalent
Barrels (bbl) 1,371,500 1,071,000 686,000
Range of Fixed Prices per bbl $17.40 - $18.71 $17.40 - $19.25 $16.68 - $19.60
Weighted Average Fixed Price
per bbl $18.00 $18.22 $18.01
Range of Variable Prices per
bbl $19.22 - $25.18 $17.40 - $23.93 $17.16 - $19.89
Weighted Average Variable Price
per bbl $21.69 $20.72 $18.35
Loss $(5,090,000) $(2,606,000) $(221,000)
The Companycovering a notional amount of 21.8 Bcf extending through 2000 at a weighted
average fixed rate of $2.34 per Mcf. Seneca also had the followingcrude oil price swap
agreements outstandingcovering a notional amount of 135,000 bbls extending through 1999 at
September
30, 1997:
Natural Gas Swap Agreements:
Notional Amount Rangea weighted average fixed rate of Fixed Weighted Average Fixed
Year (Equivalent Bcf) Prices$19.86 per Mcf Price per Mcf
---- ---------------- -------------- ----------------------
1998 24.5 $1.77 - $2.55 $2.11
1999 10.5 $2.00 - $2.35 $2.22
2000 1.3 $2.29 $2.29
----
36.3
====
Crude Oil Swap Agreements:
Notional Amount Range of Fixed Weighted Average Fixed
Year (Equivalent bbl) Prices per bbl Price per bbl
---- ---------------- --------------- ----------------------
1998 891,000 $17.50 - $20.56 $18.83
1999 135,000 $19.30 - $20.56 $19.86
---------
1,026,000
=========
At September 30, 1997, the Companybbl. Seneca had unrecognized losses
of approximately $16.3$1.0 million related to these price swap agreements which are
offset by corresponding unrecognized gains from the Company'sSeneca's anticipated natural gas
and crude oil production over the terms of the price swap agreements.
The Company, through its natural gas marketing operations, participates
in the natural gas futures market to manage a portionSeneca recognized net losses of the market risk
associated with fluctuations in the price of natural gas. Such futures are not
held for trading purposes. At September 30, 1997, the Company had the following
futures contracts outstanding:
Long "Buy" Positions:
Notional Amount Contract Price Weighted Average
Year (Equivalent Bcf) Range Per Mcf Contract Price Per Mcf
- ---- ---------------- -------------- ----------------------
1998 6.6 $2.04 - $3.49 $2.64
1999 0.8 $2.04 - $2.57 $2.37
---
7.4
===
Short "Sell" Positions:
Notional Amount Contract Price Weighted Average
Year (Equivalent Bcf) Range Per Mcf Contract Price Per Mcf
- ---- ---------------- -------------- ----------------------
1998 2.3 $2.06 - $3.61 $2.97
===
At September 30, 1997, the Company had unrealized gains of
approximately $2.9$4.1 million, $21.5 million and $11.8
million related to these futures contracts. The Company
recorded gains of approximately $1.4 million, $1.0 millionprice swap agreements during 1998, 1997 and $0.2 million
related to futures contracts during 1997, 1996,
and 1995, respectively. Since
these futures contracts qualify andAs the price swap agreements have been designated as hedges, any gains orthese
losses resulting from market price changes are substantiallywere offset by the
related commodity transaction.corresponding gains from Seneca's natural gas and crude
oil production.
The Company is exposed to credit risk on the price swap agreements that
Seneca has SEC authority to enter into interest rate and currency
exchange agreements associated with short-term borrowings covering a total
principal amount of $300.0 million. No such agreements were entered into during
the year ended September 30, 1997 and none are currently outstanding.
Credit Riskinto. Credit risk relates to the risk of loss that the
Company would incur as a result of nonperformance by counterparties pursuant to
the terms of their contractual obligations. The Company is at risk in the event of nonperformance by
counterparties on investments,To mitigate such as temporary cash investments and cash
surrender values of insurance contracts. The Company is exposed to credit risk, from its derivative financial instruments when fluctuations in natural gas and
crude oil market prices result in the Company realizing gains on thebefore
entering into a price swap agreementsagreement with a new counterparty, management
performs a credit check and futures contracts that it has entered into. When credit risk
arises, such risk toprepares a report indicating the Company is mitigated by the fact that the
counterparties, or the parent companies of such counterparties, are investment
grade financial institutions. As for the Company's derivative financial
instruments, in those instances where the Company is not dealing directly with
the parent company, the Company has obtained guarantees from the parent companyresults of the
credit investigation. This report must be approved by Seneca's board of
directors after which a Master Swap Agreement is executed between Seneca and the
counterparty. On an ongoing basis, periodic reports are prepared by management
to monitor counterparty that has issuedcredit exposure. Considering the price swap agreements. Accordingly,procedures in place,
the Company does not anticipate any material impact to its financial position,
results of operations, or cash flowflows as a result of nonperformance by
counterparties.
NFR utilizes exchange-traded futures and options to manage a portion of
the market risk associated with fluctuations in the price of natural gas. Such
futures and options are not held for trading purposes. At September 30, 1998,
NFR had natural gas futures contracts related to gas purchase and sale
commitments covering 14.3 Bcf of gas on a net basis extending through 2000 at a
weighted average contract price of $2.52 per Mcf. NFR also had sold natural gas
options related to gas purchase and sale commitments covering 2.3 Bcf of gas on
a net basis extending through 1999 at a weighted average strike price of $2.91
per Mcf. NFR had unrealized gains of approximately $0.5 million related to these
futures contracts and options. Since these futures contracts and options qualify
and have been designated as hedges, any gains or losses resulting from market
price changes would be substantially offset by the related commodity
transaction.
NFR recognized net gains of $1.3 million, $1.7 million and $1.0 million
related to futures contracts and options during 1998, 1997 and 1996,
respectively. Since these futures contracts and options qualify and have been
designated as hedges, these net gains were substantially offset by the related
commodity transaction.
PSZT purchased a $50.6 million U.S. dollar forward contract at an
exchange rate of 31.54 Czech koruna per U.S. dollar in September 1998. The
purpose of the forward contract is to hedge against the exchange rate risk
associated with PSZT's U.S. dollar denominated debt (reference is made to Note D
- - Capitalization). Since the functional currency of PSZT is the Czech koruna and
this debt must be repaid in U.S. dollars, a change in exchange rates between the
Czech koruna and the U.S. dollar may increase or decrease the amount of Czech
koruna required to repay the debt, resulting in a corresponding gain or loss to
be recognized in the Consolidated Statement of Income. At September 30, 1998,
PSZT had a loss of $2.1 million related to this forward contract. This loss
offset the gain on the U.S. dollar denominated debt from the date of purchase of
the forward contract.
The Company has SEC authority to enter into hedging transactions
related to all or a portion of its existing or anticipated debt. The notional
amounts of the hedging instruments may not exceed the amount of the Company's
outstanding debt. No such hedging transactions were entered into during the year
ended September 30, 1998 and none are currently outstanding.
Note G - Retirement Plan and Other Post-Retirement Benefits
Retirement Plan
The Company has a tax-qualified, noncontributory, defined-benefit retirement
plan (Plan) that covers substantially all domestic employees of the Company. The
Plan uses years of service, age at retirement and earnings of employees to
determine benefits.
The Company's policy is to fund at least an amount necessary to satisfy
the minimum funding requirements of applicable laws and regulations and not more
than the maximum amount deductible for federal income tax purposes. Plan funding
is subject to annual review by management and its consulting actuary. Plan
assets primarily consist of equity and fixed income investments and units in
commingled funds.
For financial reporting purposes, the regulated subsidiaries record the
difference between the amounts of pension cost recoverable in rates and the
amounts of pension cost determined by the actuary under SFAS 87, "Employers'
Accounting for Pensions," as deferred pension assets. The amounts deferred are
expected to be recovered in rates as contributions are made to the Plan. Pension
cost in 1997 and 1996 reflects the amount recovered from customers in rates during the year.
Under the PSC's policies, Distribution Corporation segregates the amount of
pension cost collected in rates, but not yet contributed to the pension plan,
into a regulatory liability account. This liability accrues interest at the PSC
mandated interest rate and this interest cost is included in pension cost. For
purposes of disclosure, the liability also remains in the disclosed pension
liability amount because it has not yet been contributed.
Reconciliations of the Benefit Obligation, Plan Assets and Funded
Status, as well as the components of Net Periodic Benefit Cost and the Weighted
Average Assumptions are as follows:
Year Ended September 30 (Thousands) 1998 1997
---- ----
Change in Benefit Obligation
Benefit Obligation at Beginning of Period $462,377 $432,753
Service Cost 10,655 9,988
Interest Cost 35,485 33,532
Amendments - 1,479
Actuarial Loss 52,446 10,336
Benefits Paid (28,713) (25,711)
-------- --------
Benefit Obligation at End of Period $532,250 $462,377
-------- --------
Change in Plan Assets
Fair Value of Assets at Beginning of Period $473,205 $431,828
Actual Return on Plan Assets 59,415 65,790
Employer Contribution 5,486 1,298
Benefits Paid (28,713) (25,711)
-------- --------
Fair Value of Assets at End of Period $509,393 $473,205
-------- --------
Reconciliation of Funded Status
Funded Status $(22,857) $ 10,828
Unrecognized Net Actuarial Gain (12,659) (38,687)
Unrecognized Transition Asset (18,580) (22,296)
Unrecognized Prior Service Cost 11,369 12,435
-------- --------
Accrued Benefit Cost $(42,727) $(37,720)
-------- --------
Weighted Average Assumptions
as of September 30 1998 1997 1996
---- ---- ----
Discount Rate 7.00% 7.75% 8.00%
Expected Return on Plan Assets 8.50% 8.50% 8.50%
Rate of Compensation Increase 5.00% 5.00% 5.00%
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost 1998 1997 1996
---- ---- ----
Service Cost $ 10,655 $ 9,988 $ 11,049
Interest Cost 35,485 33,532 31,422
Expected Return on Plan Assets (35,724) (34,011) (32,122)
Amortization of Prior Service Cost 1,065 991 1,001
Amortization of Transition Asset (3,716) (3,754) (4,167)
Amortization of Loss 981 - -
Early Retirement Window - 1,904 6,986
Net Amortization and Deferral for
Regulatory Purposes 4,829 (374) (2,320)
-------- -------- --------
Net Periodic Benefit Cost $ 13,575 $ 8,276 $ 11,849
======== ======== ========
The Benefit Obligation was determined using an assumed discount rate as
noted in the data above. The effect of the discount rate change in 1998 was to
increase the Benefit Obligation by $45.0 million as of the end of the period.
The effect of the discount rate change in 1997 was to increase the Benefit
Obligation as of the beginning of the period by $12.8 million.
The mortality assumption for healthy lives was changed from the 1983
Group Annuity Mortality Tables to the 1994 Group Annuity Mortality Tables. This
change had the effect of increasing the Benefit Obligation as of the beginning
of the period by $9.8 million.
As described in Note B - Regulatory Matters, subheading "New York Rate
Settlement," Distribution Corporation was allowed a refund pool to offset
certain specific expense items. Of the amount utilized in 1998, $6.6 million was
recorded as pension cost and is included in Net Amortization and Deferral for
Regulatory Purposes in the table above.
In June 1997, the Company completed an early retirement offer for the
Pennsylvania operating union employees of Distribution Corporation and Supply
Corporation. As a result, the Company recorded expense of $1.9 million ($1.2
million after tax) related to special termination benefits, which is included in
1997 pension cost.
In 1996, the Company had an early retirement offer for certain
salaried, non-union hourly and New York union employees of Distribution
Corporation and Supply Corporation. The Company recorded related expense in 1996
of $8.2 million ($5.2 million after-tax)after tax), comprised of special termination
benefits and severance pay. The special termination benefits portion of the
expense of $7.0 million is included in 1996 pension cost.
On October 26, 1998, the Company announced an early retirement offer to
certain salaried, non-union hourly and union employees of Distribution
Corporation and Supply Corporation who have completed at least five years of
service and have attained at least 55 years of age on or before December 1,
1998. Approximately 280 employees are eligible for the early retirement offer.
The componentsoffer must be accepted by an eligible employee by November 30, 1998 and will
become effective December 1, 1998. The Company anticipates that approximately
40% of pension cost were as follows:
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Service Cost $ 9,988 $11,049 $ 9,680
Interest Cost 33,532 31,422 28,338
Actual Return on Plan Assets (65,791) (48,022) (47,591)
Net Amortization and Deferral 28,643 10,414 9,722
Special Termination Benefits 1,904 6,986 -
------- ------- -------
Pension Cost $ 8,276 $11,849 $ 149
======= ======= =======
The projected benefit obligation was determined using an assumed
discount rate of 7.75% for 1997, and 8% for 1996 and 1995. The effectthose eligible will accept the offer. Management's estimate of the discount rate changepretax
expense associated with this early retirement offer related to special
termination benefits is approximately $5.0 million to $5.7 million. A charge to
earnings will be reflected in 1997 was to increase the projected benefit obligation by
$12.8 million. The assumed rate of compensation increase was 5% for all three
years. The expected long-term rate of return on Plan assets was 8.5% for all
three years.
A reconciliation of the Plan's funded status as determined by the Company's consulting actuaryfirst quarter of 1999 financial
results after the number of employees accepting the offer is presented in the following table:
At September 30 (Thousands) 1997 1996
---- ----
Actuarial Present Value of:
Vested Benefit Obligation $341,859 $317,049
======== ========
Accumulated Benefit Obligation $394,605 $367,612
======== ========
Projected Benefit Obligation $462,377 $432,753
Plan Assets at Fair Value 473,205 431,828
-------- --------
Funded Status 10,828 (925)
Unrecognized Net Asset (22,296) (26,278)
Unrecognized Prior Service Cost 12,435 11,947
Unrecognized Net Gain (38,687) (15,111)
-------- --------
Pension Liability $(37,720) $(30,367)
========= ========known.
Other Post-Retirement Benefits
In addition to providing retirement plan benefits, the Company provides health
care and life insurance benefits for substantially all domestic retired
employees under a post-retirement benefit plan (Post-Retirement Plan).
The Company has established Voluntary Employees' Beneficiary
Association (VEBA) trusts for collectively bargained employees and
non-bargaining employees. The VEBA trusts are similar to the Company's
Retirement Plan trust. Contributions to the VEBA trusts are tax deductible,
subject to limitations contained in the Internal Revenue Code and regulations.
Contributions to the VEBA trusts are made to fund employees' post-retirement
health care and life insurance benefits, as well as benefits as they are paid to
current retirees. Post-Retirement Plan assets primarily consist of equity and
fixed income investments and money market funds.
Distribution Corporation and Supply Corporation represent virtually all
of the Company's total post-retirement benefit costs. Distribution Corporation
and Supply Corporation are fully recovering their net periodic post-retirement
benefit costs in accordance with the PSC and the Pennsylvania Public Utility
Commission (PaPUC) and Federal Energy Regulatory Commission (FERC)
authorization, respectively. In accordance with regulatory guidelines, the
difference between the amounts of post-retirement benefit costs recoverable in
rates and the amounts of post-retirement benefit costs determined by the actuary
under SFAS 106, "Employers' Accounting for Post-retirementPost-Retirement Benefits Other Than
Pensions," are deferred in each jurisdiction as either a regulatory asset or
liability, as appropriate. The PSC policy regarding amounts collected in rates,
but not contributed, described under the Retirement Plan section in this note,
also applies to other post-retirement benefits.
The Company has elected to amortizeReconciliations of the initial accumulated liability
at October 1, 1993 to post-retirement benefit cost on a straight-line basis over
a 20-year period.
TheBenefit Obligation, Plan Assets and Funded
Status, as well as the components of post-retirement benefit cost wereNet Periodic Benefit Cost and the Weighted
Average Assumptions are as follows:
Year Ended September 30 (Thousands) 1998 1997
---- ----
Change in Benefit Obligation
Benefit Obligation at Beginning of Period $ 218,370 $ 212,047
Service Cost 4,022 4,056
Interest Cost 17,122 16,594
Plan Participants' Contributions 867 417
Actuarial (Gain) Loss 27,014 (6,653)
Benefits Paid (10,412) (8,091)
--------- ---------
Benefit Obligation at End of Period $ 256,983 $ 218,370
--------- ---------
Change in Plan Assets
Fair Value of Assets at Beginning of Period $ 98,639 $ 73,059
Actual Return on Plan Assets 14,602 13,618
Employer Contribution 19,174 19,636
Plan Participants' Contributions 867 417
Benefits Paid (10,412) (8,091)
--------- ---------
Fair Value of Assets at End of Period $ 122,870 $ 98,639
--------- ---------
Reconciliation of Funded Status
Funded Status $(134,113) $(119,731)
Unrecognized Net Actuarial Loss 19,660 505
Unrecognized Transition Obligation 106,907 114,034
--------- ---------
Accrued Benefit Cost $ (7,546) $ (5,192)
--------- ---------
Weighted Average Assumptions
as of September 30 1998 1997 1996
1995---- ---- ----
Discount Rate 7.00% 7.75% 8.00%
Expected Return on Plan Assets 8.50% 8.50% 8.50%
Rate of Compensation Increase 5.00% 5.00% 5.00%
Year Ended September 30 (Thousands)
Components of Net Periodic Benefit Cost 1998 1997 1996
---- ---- ----
Service Cost $ 4,022 $ 4,056 $ 3,926
$ 3,394
Interest Cost 17,122 16,594 14,391
13,027
ActualExpected Return on Post-Retirement Plan Assets (13,618) (9,072) (4,613)(8,099) (6,014) (4,306)
Amortization of Transition Obligation 7,127 7,768 7,862
Amortization of Loss 683 - -
Net Amortization and Deferral 14,115 11,830 12,592
------- ------- -------
Post-Retirementfor
Regulatory Purposes 915 (1,257) (798)
-------- -------- --------
Net Periodic Benefit Cost $21,147 $21,075 $24,400
======= ======= =======$ 21,770 $ 21,147 $ 21,075
======== ======== ========
The weighted averageBenefit Obligation was determined using an assumed discount rate usedas
noted in determining the accumulated post-retirement benefit obligation (APBO)data above. The effect of the discount rate change in 1998 was 7.75% for 1997, and 8%
for 1996 and 1995.to
increase the Benefit Obligation by $25.3 million. The effect of the discount
rate change in 1997 was to increase the APBOBenefit Obligation as of the beginning
of the period by $7.0 million.
The average assumed annual ratemortality assumption for healthy lives was changed from the 1983
Group Annuity Mortality Tables to the 1994 Group Annuity Mortality Tables. This
change had the effect of salary
increase forincreasing the applicable life insurance plans was 5% for all three years. The
expected long-term rateBenefit Obligation as of return on Post-Retirement Plan assets was 8.5% for
all three years.the beginning
of the period by $7.4 million.
The annual rate of increase in the per capita cost of covered medical
care benefits was assumed to be 12% for 1995, 11% for 1996, and 10% for 1997;1997 and 9% for 1998; this
rate was assumed to decrease gradually to 5.5% by the year 2003 and remain at
that level thereafter. The annual rate of increase for medical care benefits
provided by Healthcare Maintenance Organizations (HMO) was assumed to be 7.5% in 1998
and gradually decline to 5.5% by the year 20032002 and remain level thereafter. The
annual rate of increase in the per capita cost of covered prescription drug
benefits was assumed to be 10% for 1995 and 1996, and 8.5% for 1997.1997 and 9% for 1998. This
rate was assumed to decrease gradually to 5.5% by the year 2003 and remain level
thereafter. The annual rate increase in the per capita Medicare Part B
Reimbursement was assumed to be 12.2% for 1995, 12% for 1996, and 3.1% for 1997.1997 and 9% for 1998.
This rate was assumed to be 9% for 1998 and decrease gradually to 5.5% by the year 2003 and remain
level thereafter. These trend assumptions reflect various
changes made for fiscal 1998, the impact of the changes was to increase the APBO
by $6.9 million. Medicare Risk HMO's for retirees over age 65 were introduced by
the HMO providers serving the Company. The effect of this plan amendment was to
reduce the APBO by $10.3 million. Since no unrecognized prior service cost
exists, this plan amendment was used to reduce the unrecognized transition
obligation as of September 30, 1997.
A reconciliation of the Post-Retirement Plan's funded status as
determined by the Company's consulting actuary is in the following table:
At September 30 (Thousands) 1997 1996
---- ----
Accumulated Post-Retirement Benefit Obligation:
Inactives $118,465 $111,970
Actives Fully Eligible 26,528 25,363
Actives Not Yet Fully Eligible 73,377 74,715
-------- --------
218,370 212,048
Fair Value of Post-Retirement Plan Assets 98,639 73,059
-------- --------
Funded Status (119,731) (138,989)
Unrecognized Transition Obligation 114,034 132,055
Unrecognized Net Loss 505 4,510
-------- --------
Post-Retirement Liability $ (5,192) $ (2,424)
========= ========
The health care cost trend rate assumptions used to calculate the per
capita cost of covered medical care benefits have a significant effect on the
amounts reported. If the health care cost trend rates were increased by 1% in
each year, the APBOBenefit Obligation as of October 1, 1996,1998, would be increased by
$31.0$39.9 million. This 1% change would also have increased the aggregate of the
service and interest cost components of net periodic post-retirement benefit
cost for 19971998 by $3.5$2.8 million. If the health care cost trend rates were
decreased by 1% in each year, the Benefit Obligation as of October 1, 1998,
would be decreased by $34.7 million. This 1% change would also have decreased
the aggregate of the service and interest cost components of net periodic
post-retirement benefit cost for 1998 by $3.1 million.
Note H - Commitments and Contingencies
Leases
System companies have entered into lease agreements, principally for the use of
office space, business machines, transportation equipment and meters. The
Company's policy is to treat all leases as operating leases for both accounting
and ratemaking purposes. While certain of these leases are capital leases, had
they been capitalized, the effect on results of operations and financial
position would not be material. Total lease expense approximated $14.0 million
in 1998, $16.0 million in 1997 and $16.9 million in 1996 and $16.3 million in 1995.1996. At September 30, 1997,1998,
the future minimum payments under the Company's lease agreements for the next
five years are: $11.7 million in 1998, $8.4$11.3 million in 1999, $6.6$9.3 million in 2000, $5.2$7.6 million in
2001, and $4.1$5.7 million in 2002.2002 and $4.5 million in 2003. The aggregate future
minimum lease payments attributable to later years is $12.4$15.7 million.
Environmental Matters
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for the on-going evaluation of its operations to identify potential
environmental exposures and assure compliance with regulatory policies and
procedures.
Distribution Corporation has incurred and is incurring clean-up costs
at several former manufactured gas plant sites in New York and Pennsylvania.
Distribution Corporation has been designated by the New York Department of
Environmental Conservation (DEC) as a potentially responsible party (PRP) with
respect to one of these sites in New York, and is also engaged in litigation
with the DEC and the party who bought the site from Distribution Corporation's
predecessor.
Distribution Corporation recently received an informal inquiry from a
DEC staff member as to whether Distribution Corporation or a predecessor had
used a former manufactured gas plant site in New York in a way that could
account for a complaint the DEC received from a neighboring landowner.
Distribution Corporation has begun an investigation at that site but has not
incurred any clean-up costs nor has it been able to reasonably estimate the
probability or extent of potential liability.
Distribution Corporation is also currently identified by the DEC or the
federal Environmental Protection Agency as one of a number of companies
considered to be PRPs with respect to several waste disposal sites in New York
which were operated by unrelated third parties. The PRPs are alleged to have
contributed to the materials that may have been collected at such waste disposal
sites by the site operators. The ultimate cost to Distribution Corporation with
respect to the remediation of these sites will depend on such factors as the
remediation plan selected, the extent of the site contamination, the number of
additional PRPs at each site and the portion, if any, attributed to Distribution
Corporation.
It is the Company's policy to accrue estimated environmental clean-up costs
(investigation and remediation) when such amounts can reasonably be estimated
and it is probable that the Company will be required to incur such costs.
Distribution Corporation has estimated thatits clean-up costs related to the above noted sites
aredescribed below in (i) and (ii) will be in the range of $9.3$12.4 million to $9.9$13.4
million. At September 30, 1997,1998, Distribution Corporation has recorded the
minimum liability of $9.3$12.4 million. The Company is currently not aware of any
material additional exposure to environmental liabilities. However, adverse
changes in environmental regulations or other factors could impact the Company.
In New York and Pennsylvania, Distribution Corporation is recovering
site investigation and remediation costs in rates. Accordingly, the Consolidated
Balance Sheet at September 30, 1997,1998 includes related regulatory assets in the
amount of approximately $8.7$12.4 million.
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 ongoing evaluation of its operations to identify
potential environmental exposures and assure compliance with regulatory policies
and procedures.
(i) Former Manufactured Gas Plant Sites
Distribution Corporation has incurred and is incurring clean-up costs
at five former manufactured gas plant sites in New York and Pennsylvania. Two of
these sites are at the remediation stage, two at the investigation stage, and
one has completed the investigation stage with remediation being designed.
Distribution Corporation has been designated by the New York Department of
Environmental Conservation (DEC) as a potentially responsible party (PRP) with
respect to one of these sites in New York, and is also engaged in litigation
with the DEC and the party who bought that site from Distribution Corporation's
predecessor.
Distribution Corporation also received in 1998 a notice that the DEC
believes Distribution Corporation is responsible for contamination discovered at
an additional former manufactured gas plant site in New York (without naming
Distribution Corporation as a PRP). Distribution Corporation responded that
other companies operated that site before Distribution Corporation's predecessor
did, that liability could be imposed upon Distribution Corporation only if
hazardous substances were disposed of at the site during a period when the site
was operated by Distribution Corporation's predecessor, and that Distribution
Corporation was unaware of any such disposal. Distribution Corporation has not
incurred any clean-up costs at this site nor has it been able to reasonably
estimate the probability or extent of potential liability.
(ii) Third Party Waste Disposal Sites
Distribution Corporation and Supply Corporation are each currently
identified by the DEC or the federal Environmental Protection Agency as one of a
number of companies considered to be PRPs with respect to certain waste disposal
sites in New York which were operated by unrelated third parties. The PRPs are
alleged to have contributed to the materials that may have been collected at
such waste disposal sites by the site operators. The ultimate cost to
Distribution Corporation or Supply Corporation with respect to the remediation
of these sites will depend on such factors as the remediation plan selected, the
extent of site contamination, the number of additional PRPs at each site and the
portion, if any, attributed to Distribution Corporation or Supply Corporation.
Distribution Corporation is a PRP at two waste disposal sites, one of which is
in remediation and the other has completed the investigation stage with
remediation being designed to begin in fiscal 1999. Supply Corporation is a PRP
at one waste disposal site, which is at the investigation stage, and has
estimated its exposure at less than $0.1 million for that site.
Without being named a PRP, Distribution Corporation has also signed a
consent decree (court approval pending) by which it would share the costs of
remediating another waste disposal site in New York.
Distribution Corporation also understands that PRPs at another site
have obtained records from the operator (a waste oil collector) indicating that
the site received used oil from Distribution Corporation (among others). A
contribution claim will likely be asserted against Distribution Corporation,
which has not incurred any clean-up costs at this site nor been able to
reasonably estimate the probability or extent of potential liability.
(iii) Clean Air Standards
The Company, in its international operations in the Czech Republic, is
in the process of reconstructing boilers at the heating plant of PSZT to comply
with certain clean air standards mandated by the Czech Republic government.
Capital expenditures related to this reconstruction incurred by PSZT in 1998
(since its acquisition by Horizon through September 30, 1998) were approximately
$12 million. Approximately $33 million is budgeted for this reconstruction work
in 1999.
Other
The Company has entered into contractual commitments in the ordinary course of
business including commitments by Distribution Corporation to purchase capacity
on nonaffiliated pipelines to meet customer gas supply needs. The majority of
these contracts (representing 80% of current contracted demand capacity) expire
within the next five years. Costs incurred under these contracts are purchased
gas costs, subject to state commission review, and are being recovered in
customer rates through inclusion in Distribution Corporation's rate schedules.
The Company is involved in litigation arising in the normal course of
its business. In addition to the regulatory matters discussed in Note B -
Regulatory Matters, the Company is involved in other regulatory matters arising
in the normal course of business that involve rate base, cost of service and
purchased gas cost issues. While the resolution of such litigation or other
regulatory matters could have a material effect on earnings and cash flows in
the year of resolution, none of this litigation, and none of these other
regulatory matters, are expected to have a material adverse effect on the
financial condition of the Company at this time.
Note I - Business Segment Information
The Company includesCompany's operations which are rate-regulated (regulated) and
operations which are not regulated as to their rates (nonregulated). The
regulated operations fall primarily within twocomprised of five business segments: Utility,
and
Pipeline and Storage. The nonregulated operations consist principally of theStorage, Exploration and Production, business segment. TheInternational and Other
Nonregulated segment
consists primarily of the Company's sawmill and dry kiln operations, natural gas
marketing operations, natural gas hub operations, investment in foreign energy
projects and pipeline construction operations (which were discontinued during
1995, the effect of which was immaterial to the Company).Nonregulated.
The Utility segment is regulated by the PSC and the PaPUC and isits
operations are carried out by Distribution Corporation. Distribution Corporation
sells and transports gas to retail customers located in western New York and
northwestern Pennsylvania. It also provides off-system sales to customers
located in regions through which the upstream pipelines serving Distribution
Corporation pass (i.e., from the southwestern to northeastern regions of the
United States).
The Pipeline and Storage segment is regulated by the FERC and isits
operations are carried out by Supply Corporation and SIP. Supply Corporation
transports and stores natural gas for utilities and pipeline companies in the
northeastern United States markets. In 1998, 1997 and 1996, 51%, 52% and 1995, 52%51%, 51% and 48%,
respectively, of Supply Corporation's revenue was from affiliated companies,
mainly Distribution Corporation. SIP has agreed to purchase, upon receipt of
regulatory approval, a one-third general partnership
interest in Independence Pipeline Company.
The Exploration and Production segment's operations are carried out by
Seneca. Seneca is engaged in exploration for, and development and purchase of,
oil and natural gas reserves in the Gulf Coast areas of Texas, Louisiana, and
Alabama, and in California, Wyoming, and the Appalachian region of the United
States. Seneca's production is, for the most part, sold to purchasers located in
the vicinity of its wells.
Highland operates two sawmills and one dry kiln
operation in Pennsylvania. NFR is engaged in the marketing and brokerage of
natural gas and electricity and performs energy management services for
utilities and end-users in the northeastern United States markets. Leidy's
activities center around its investment in natural gas hubThe International segment's operations providing
services to customers in the northeastern, mid-Atlantic, Chicago and Los Angeles
areas of the United States and Ontario, Canada.are carried out by Horizon.
Horizon is engaged in the investigation and development of foreign and domesticinternational energy
projects. Horizon
has an equityHorizon's primary focus currently is in the Czech Republic where it
owns a majority interest in SCT a company withand PSZT, which have district heating and power
generation operations located in the northern partoperations.
The Other Nonregulated segment consists primarily of the Czech Republic. It
also ownsCompany's
timber, sawmill and operates an additional district heating plantdry kiln operations (carried out by the northeast division
of Seneca and a power
development group in the Czech Republic. NET was formed in July 1997 to engage
in wholesale natural gas tradingby Highland) and other energy-related activities. NIM was
formed in September 1997 to own a one-third general partnership interest in
DirectLink Gas Marketing Company, which will engage in natural gasenergy marketing operations (carried out by NFR
and related business. UCI was engaged in the Company's pipeline construction
operations prior to the discontinuance of its business in the third quarter of
fiscal 1995.Upstate).
The data presented in the tables below reflect the Company's regulated
and nonregulated business
segments for the three years ended September 30, 1997.1998. Total operating revenues
by segment include both revenues from nonaffiliated customers and intersegment
revenues. Operating income is total operating revenues less operating expenses,
not including income taxes. The elimination of significant intercompany balances
and transactions, if appropriate, is made in order to reconcile segment
information with consolidated amounts. Identifiable assets of a segment are
those assets that are used in the operations of that segment. Corporate assets
are principally cash and temporary cash investments, receivables, deferred
charges and cash surrender values of insurance contracts.
Year Ended September 30 (Thousands) 1998 1997 1996 1995
---- ---- ----
Operating Revenues
Regulated:
Utility $ 871,180 $ 991,366 $ 954,326
$786,064
Pipeline and Storage 170,983 172,694 176,553 164,587
---------- ---------- --------
1,164,060 1,130,879 950,651
---------- ---------- --------
Nonregulated:
Exploration and Production 124,272 119,260 114,462
56,232International 76,259 1,910 286
Other 83,915 68,930 57,075Nonregulated 106,527 82,005 68,644
Intersegment Revenues(1) (101,221) (101,423) (106,254)
---------- ---------- ----------
$1,248,000 $1,265,812 $1,208,017
========== ========== ==========
Operating Income (Loss) Before
Income Taxes
Utility $124,482 $123,856 $115,257
Pipeline and Storage 71,510 73,523 72,914
Exploration and Production(2)(3) (93,266) 42,694 46,408
International 2,136 (2,987) (14,281)
Other Nonregulated 5,347 2,244 5,700
Corporate (2,254) (2,353) (2,231)
-------- 203,175 183,392 113,307-------- --------
$107,955 $236,977 $223,767
======== ======== ========
Depreciation, Depletion and Amortization
Utility $ 33,459 $ 32,972 $ 31,491
Pipeline and Storage 21,816 21,459 19,942
Exploration and Production(3) 50,937 51,117 46,042
International 7,309 107 -
Other Nonregulated 5,357 5,992 752
Corporate 2 3 4
-------- ------- --------
$118,880 $111,650 $ 98,231
======== ======== ========
Capital Expenditures
Utility $ 50,680 $ 66,908 $ 63,730
Pipeline and Storage 23,692 22,562 22,260
Exploration and Production(4) 293,870 120,282 83,554
International(4) 14,778 292 133
Other Nonregulated(5) 10,213 16,266 3,056
Intersegment Elimination - - (1,166)
-------- -------- --------
$393,233 $226,310 $171,567
======== ======== ========
Identifiable Assets
At September 30 (Thousands)
Utility $1,161,046 $1,163,702 $1,154,364
Pipeline and Storage 513,346 510,109 515,569
Exploration and Production 661,742 466,208 396,077
International 239,763 23,987 3,370
Other Nonregulated 62,228 51,200 35,585
Corporate 46,334 52,125 44,807
---------- ---------- --------
Intersegment Revenues* (101,423) (106,254) (88,462)
----------
---------- --------
$1,265,812 $1,208,017 $975,496$2,684,459 $2,267,331 $2,149,772
========== ========== ========
*==========
(1) Represents primarily Pipeline and Storage revenue from the Utility
segment.
Year Ended September 30 (Thousands) 1997 1996 1995
---- ---- ----
Operating Income (Loss) Before
Income Taxes
Regulated:
Utility $123,856 $115,257 $ 83,774
Pipeline(2) 1998 includes impairment of oil and Storage 73,523 72,914 67,884
-------- -------- --------
197,379 188,171 151,658
-------- -------- --------
Nonregulated:gas producing properties of $129.0
million. Refer to Note A - Summary of Significant Accounting Policies for
further discussion.
(3) In 1998, Seneca changed its method of depletion for oil and gas producing
properties from the gross revenue method to the units of production
method. The effect of this change was to reduce 1998 depletion expense and
to reduce the operating loss before income taxes of the Exploration and
Production 42,694 46,408 16,404
Other (743) (8,581) 3,021
-------- -------- --------
41,951 37,827 19,425
-------- -------- --------
Corporate (2,353) (2,231) (2,805)
-------- -------- --------
$236,977 $223,767 $168,278
======== ======== ========
Identifiable Assets
At September 30 (Thousands)
Regulated:
Utility $1,163,702 $1,154,364 $1,098,757
Pipeline and Storage 510,109 515,569 512,546
---------- ---------- ----------
1,673,811 1,669,933 1,611,303
---------- ---------- ----------
Nonregulated:segment by $2.3 million. See further discussion in Note A -
Summary of Significant Accounting Policies.
(4) 1998 amounts exclude stock acquisitions. Refer to Note J - Stock
Acquisitions for further discussion.
(5) 1997 amount includes noncash acquisition of $12.3 million in exchange for
long-term debt obligations.
Note J - Stock Acquisitions
Exploration and Production
466,208 396,077 351,262
Other 75,187 38,955 33,734
---------- ---------- ----------
541,395 435,032 384,996
---------- ---------- ----------
Corporate 52,125 44,807 40,524
---------- ---------- ----------
$2,267,331 $2,149,772 $2,036,823
========== ========== ==========
Year EndedIn May 1998, Seneca West Corporation (Seneca West), a wholly-owned subsidiary of
Seneca, completed a tender offer (an offer of $2.00 per share) for the
outstanding shares of HarCor. The tender offer was commenced pursuant to the
terms of an Agreement and Plan of Merger among HarCor, Seneca and Seneca West
which provided for the merger of Seneca West with and into HarCor following the
successful consummation of the tender offer. Approximately 95% of the
outstanding shares of HarCor common stock were tendered in accordance with the
tender offer. Accordingly, Seneca West was merged with and into HarCor and the
common stock that was not purchased pursuant to the tender offer was converted
in the merger into the right to receive $2.00 per share. The cost of the tender
offer and subsequent conversion of the remaining shares of HarCor was
approximately $32.6 million.
The acquisition of HarCor was accounted for in accordance with the
purchase method as specified by APB 16. HarCor's results of operations were
incorporated into the Company's consolidated financial statements for the period
subsequent to the completion of the tender offer in May 1998. See Note D -
Capitalization for discussion of HarCor's senior secured debt.
International
During the year, Horizon, through a wholly-owned subsidiary, increased its
ownership interest in SCT from 36.8% at September 30, (Thousands)
Depreciation, Depletion1997 to 82.7% at September
30, 1998. The cost of acquiring these additional shares was approximately $24.9
million. Also in 1998, Horizon invested in PSZT, and Amortization
Regulated:
Utility $32,972 $31,491 $30,052
Pipelineowned an 86.2% interest at
September 30, 1998. The cost of acquiring the shares of PSZT was approximately
$64.5 million. PSZT is a wholesale power and Storage 21,459 19,942 19,320
------- ------ -------
54,431 51,433 49,372
------- ------- -------
Nonregulated:
Explorationdistrict heating company that
adjoins the service territory of SCT in the northern Bohemia region of the Czech
Republic.
The acquisitions of SCT and Production 51,117 46,042 21,201PSZT have been accounted for in accordance
with the purchase method as specified by APB 16. The acquisitions resulted in
approximately $10.6 million of goodwill, which is being amortized over a
twenty-year period. This goodwill ($10.1 million at September 30, 1998) is
recorded in Other 6,099 752 1,203
------- ------- -------
57,216 46,794 22,404
------- ------- -------
Corporate 3 4 6
------- ------- -------
$111,650 $98,231 $71,782
======== ======= =======
Capital Expenditures
Regulated:
Utility $ 66,908 $ 63,730 $ 64,844
PipelineAssets in the Company's Consolidated Balance Sheet. See Note D
Capitalization for discussion of the debt of SCT and Storage 22,562 22,260 38,678
-------- -------- --------
89,470 85,990 103,522
-------- -------- --------
Nonregulated:
Exploration and Production 120,282 83,554 69,741
Other 16,558 3,189 9,563
-------- -------- --------
136,840 86,743 79,304
-------- -------- --------
Intersegment Elimination - (1,166) -
-------- -------- --------
$226,310 $171,567 $182,826
======== ======== ========PSZT.
Note JK - 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 perPer common share amounts 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 amounts shown on the Consolidated Statement of
Income, which is based on the weighted average number of shares outstanding for
the entire fiscal year. Because of the seasonal nature of the Company's heating
business, there are substantial variations in operations reported on a quarterly
basis.
Financial data for the quarter ended September 30,December 31, 1997 reflects anthe
accounting change in depletion methods for Seneca's oil and gas assets, which
had a negative after tax charge of $2.0$9.1 million, or $0.05$0.24 per share related to an estimated(basic and diluted)
non-cash cumulative refund provision to Distribution Corporation's customers, for a 50%
sharingeffect through October 1, 1997. See further discussion of
earnings over a predetermined amountthis accounting change in accordance with Distribution
Corporation's New York rate settlementNote A - Summary of July 1996.Significant Accounting Policies.
Financial data for the quarter ended September 30, 1996March 31, 1998 reflects the
after-tax net benefitan
impairment of Seneca's oil and gas cost reconciliation adjustmentsproducing properties. The after tax amount of
$2.7this impairment charge was $79.1 million, or $0.07$2.07 per shareand (basic). See
further discussion of this impairment in Note A - Summary of Significant
Accounting Policies.
Financial data for the reversalquarter ended March 31, 1998 also reflects an
after tax income amount of estimated lost and unaccounted-for gas
accrued in prior quarters of 1996 of $4.6 million, after-tax, or $0.12 per
share. These items were offset by an after-tax charge to earnings of $5.2$5.0 million, or $0.14$0.13 per share related(basic) from the
settlement of the primary issues relating to an early retirement offer to certain
salaried, non-union hourly and union employeesIRS audits of Distribution Corporation and
Supply Corporation. In addition, Horizon recognized a fourth quarter after-tax
charge to earnings of $3.8 million, or $0.10years 1977 - 1994.
Diluted per share relatedamounts for the quarter ended March 31, 1998 are not
applicable due to its decision
to withdraw from participation in the development of a 151 megawatt power plant
near Kabirwala, Punjab Province, in east-central Pakistan.
Net Income Earnings
(Loss) (Loss)
Availableantidilution effect on the loss for Per
Quarter Operating Operating Common Common
Ended Revenues Income Stock Share
- ------- --------- --------- ------------- --------
1997 (Thousands, except earnings per common share)
- ------------------------------------------------------------------------
12/31/96 $363,492 $52,153 $38,590 $1.02
3/31/97 $498,704 $70,812 $57,109 $1.50
6/30/97 $246,051 $31,283 $18,905 $ .50
9/30/97 $157,565 $14,055the quarter.
Net
Income (Loss) Income
Income Per Common (Loss)
(Loss) Share Before Available Earnings
Operating Before Cumulative for (Loss) Per
Quarter Operating Income Cumulative Effect Common Common Share
-------------- --------------
Ended Revenues (Loss) Effect Basic Diluted Stock Basic Diluted
----- -------- ------ ------ ----- ------- ----- ----- -------
1998 (Thousands, except per common share amounts)
- ------------------------------------------------------------------------------------
12/31/97 $371,021 $ 52,280 $ 37,534 $ 0.98 $0.97 $ 28,418 $ 0.74 $0.73
3/31/98 $462,648 $(16,228) $(21,262) $(0.56) N/A $(21,262) $(0.56) N/A
6/30/98 $242,447 $ 33,726 $ 19,107 $ 0.50 $0.49 $ 19,107 $ 0.50 $0.49
9/30/98 $171,884 $ 14,153 $ (3,075) $(0.08) N/A $ (3,075) $(0.08) N/A
1997 (Thousands, except per common share amounts)
- ------------------------------------------------------------------------------------
12/31/96 $363,492 $ 52,153 $ 38,590 $ 1.02 $1.01 $ 38,590 $ 1.02 $1.01
3/31/97 $498,704 $ 70,812 $ 57,109 $ 1.50 $1.48 $ 57,109 $ 1.50 $1.48
6/30/97 $246,051 $ 31,283 $ 18,905 $ 0.50 $0.49 $ 18,905 $ 0.50 $0.49
9/30/97 $157,565 $ 14,055 $ 84 $ - $ - $ 84 $ - $ -
1996 (Thousands, except earnings per common share)
N/A - ------------------------------------------------------------------------
12/31/95 $316,328 $46,344 $32,392 $ .87
3/31/96 $492,376 $69,631 $55,692 $1.48
6/30/96 $239,330 $29,687 $17,310 $ .46
9/30/96 $159,983 $11,784 $ (723) $(.02)
Not applicable due to antidilution.
Note KL - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 1997,1998, there were 20,26723,743 holders of National Fuel Gas Company
common stock. The common stock is listed and traded on the New York Stock
Exchange. Information related to restrictions on the payment of dividends can be
found in Note D - Capitalization. The quarterly price ranges and quarterly
dividends declared for the fiscal years ended September 30, 19971998 and 1996,1997, are
shown below:
Price Range Dividends
Quarter Ended High Low Declared
- ------------- ---- --- -----------------
1998
12/31/97 $48-15/16 $42-11/16 $.435
3/31/98 $48-13/16 $45-3/8 $.435
6/30/98 $49-1/8 $39-5/8 $.450
9/30/98 $47 $39-13/16 $.450
1997
----
12/31/96 $44-1/8 $36-5/8 $.42$.420
3/31/97 $44-7/8 $39-3/8 $.42$.420
6/30/97 $44-1/8 $40-5/8 $.435
9/30/97 $45-7/16 $40-1/8 $.435
1996
----
12/31/95 $33-7/8 $28-1/2 $.405
3/31/96 $34-7/8 $31-3/8 $.405
6/30/96 $36-3/8 $33-3/4 $.42
9/30/96 $38 $33-3/8 $.42
Note LM - Supplementary Information for Oil and Gas Producing Activities
The following supplementary information is presented in accordance with SFAS 69,
"Disclosures about Oil and Gas Producing Activities," and related SEC accounting
rules.
Capitalized Costs Relating to Oil and Gas Producing Activities
At September 30 (Thousands) 1998 1997 1996
---- ----
Capitalized Costs Subject to AmortizationProved Properties $739,684 $658,327
$570,815
Capitalized Acquisition Costs Excluded
from AmortizationUnproved Properties 141,873 64,597 35,627
-------- --------
881,557 722,924 606,442
Less - Accumulated Depreciation, Depletion
and Amortization 261,236 284,429 233,743
-------- --------
$620,321 $438,495 $372,699
======== ========
Certain costsCosts related to unproved properties are excluded from amortization as
they represent unevaluated properties that require additional drilling to
determine the existence of oil and gas reserves. The remainingFollowing is a summary of such
costs incurred during and prior toexcluded from amortization at September 30, 1998:
Total Year Costs Incurred
--------------------------------
(Thousands) at September 30, 1998 1998 1997 consist of individually insignificant oil and gas leases still early in their
primary terms and individually insignificant unproved perpetual oil and gas
rights.1996 Prior
--------------------- ---- ---- ---- -----
Acquisition Costs $123,632 $ 92,864 $7,114 $12,930 $10,724
Exploration Costs 18,241 18,241 - - -
-------- -------- ------ ------- -------
$141,873 $111,105 $7,114 $12,930 $10,724
======== ======== ====== ======= =======
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
Year Ended September 30 (Thousands) 1998 1997 1996 1995
---- ---- ----
Property Acquisition Costs:*
Proved $189,201 $ 4,154 $ 4,632
$13,186
Unproved 88,369 23,120 12,879
12,119
Exploration Costs 74,421 76,703 33,191
18,588
Development Costs 23,887 15,583 32,747
25,161
Other - - 230
559-------- -------- -------
-------$375,878 $119,560 $83,679
$69,613======== ======== =======
=======
* Total proved and unproved property acquisition costs of $277.6 million
include amounts related to the HarCor, Bakersfield Energy and Whittier Trust
properties acquired in 1998 of $87.0 million, $25.3 million and $141.1
million, respectively.
Results of Operations for Producing Activities
Year Ended September 30 (Thousands) 1998 1997 1996 1995
---- ---- ----
Operating Revenues:
Natural Gas (includes revenues from sales
to affiliates of $11,065, $10,682 and
$11,872, and
$8,650, respectively) $ 89,284 $100,411 $ 91,018 $ 34,849
Oil, Condensate and Other Liquids 31,770 39,237 33,978
11,948
-------- -------- ---------------
Total Operating Revenues* 121,054 139,648 124,996 46,797
Production/Lifting Costs 23,622 17,335 15,196 11,215
Depreciation, Depletion and Amortization
($0.36,0.96 per Mcfe of production,
$0.36 and $0.44, respectively,$0.36 per dollar of
operating revenues)revenues, respectively)** 50,221 50,687 45,502
20,528Impairment of Oil and Gas Producing
Properties*** 128,996 - -
Income Tax (Benefit) Expense (28,949) 24,699 22,069 4,301
-------- -------- --------
Results of Operations for Producing
Activities (excluding corporate overheads
and interest charges) $(52,836) $ 46,927 $ 42,229
$ 10,753
======== ======== ========
*Exclusive* Exclusive of hedging gains and losses. See further discussion in Note F -
Financial Instruments.
** In 1998, Seneca changed its method of depletion for oil and gas producing
properties from the gross revenue method to the units of production method.
See further discussion in Note A - Summary of Significant Accounting
Policies.
*** See discussion of impairment in Note A - Summary of Significant Accounting
Policies.
Reserve Quantity Information (unaudited)
The Company's proved oil and gas reserves are located in the United States. The
estimated quantities of proved reserves disclosed in the table below are based
upon estimates by qualified Company geologists and engineers and are audited by
independent petroleum engineers. Such estimates are inherently imprecise and may
be subject to substantial revisions as a result of numerous factors including,
but not limited to, additional development activity, evolving production
history, and continual reassessment of the viability of production under varying
economic conditions.
Gas Oil
Year Ended MMcf Mbbl
---------------------- ---------------------
September 30 1998 1997 1996 19951998 1997 1996 1995
---- ---- ---- ---- ---- ----
Proved Developed and
Undeveloped Reserves:
Beginning of Year 232,449 207,082 221,459 247,44717,981 25,749 22,865 17,495
Extensions and
Discoveries 40,293 47,951 29,161 9,912640 359 5,701 3,863
Revisions of
Previous Estimates (18,623) 20,820 (3,442) (21,046)(4,191) (6,224) (1,173)
(60)
Production (36,474) (38,586) (38,767) (20,942)(2,614) (1,902) (1,742) (739)
Sales of Minerals in
Place - (5,464) (1,532) (4,685)- (1) (27) (474)
Purchases of Minerals
in Place and Other 107,420 646 203 10,77354,775 - 125 2,780
------- ------- ------- ------ ------ ------
End of Year 325,065 232,449 207,082 221,45966,591 17,981 25,749 22,865
======= ======= ======= ====== ====== ======
Proved Developed Reserves:
Beginning of Year 163,537 162,504 179,291 14,043 14,937 10,110
======= ======= ======= ====== ====== ======
End of Year 194,454 163,537 162,504 11,354 14,043 14,937
======= ======= ======= ====== ====== ======
End of Year 230,508 194,454 163,537 48,081 11,354 14,043
======= ======= ======= ====== ====== ======
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (unaudited)
The Company cautions that the following presentation of the standardized measure
of discounted future net cash flows is intended to be neither a measure of the
fair market value of the Company's oil and gas properties, nor an estimate of
the present value of actual future cash flows to be obtained as a result of
their development and production. It is based upon subjective estimates of
proved reserves only and attributes no value to categories of reserves other
than proved reserves, such as probable or possible reserves, or to unproved
acreage. Furthermore, it is based on year-end prices and costs adjusted only for
existing contractual changes, and it assumes an arbitrary discount rate of 10%.
Thus, it gives no effect to future price and cost changes certain to occur under
the widely fluctuating political and economic conditions of today's world.
The standardized measure is intended instead to provide a somewhat
better means for comparing the value of the Company's proved reserves at a given
time with those of other oil- and gas-producing companies than is provided by a
simple comparison of raw proved reserve quantities.
Year Ended September 30 (Thousands) 1998 1997 1996 1995
---- ---- ----
Future Cash Inflows $1,547,216 $1,072,375 $1,003,280 $738,711
Less:
Future Production and Development Costs 574,637 252,205 294,778 272,268
Future Income Tax Expense at
Applicable Statutory Rate 245,120 257,172 221,956
129,055
---------- ---------- -----------------
Future Net Cash Flows 727,459 562,998 486,546 337,388
Less:
10% Annual Discount for Estimated
Timing of Cash Flows 260,688 179,798 157,302
92,120
---------- ---------- ------------------
Standardized Measure of Discounted Future
Net Cash Flows $ 466,771 $ 383,200 $ 329,244
$245,268
========== ========== ==================
The principal sources of change in the standardized measure of
discounted future net cash flows were as follows:
Year Ended September 30 (Thousands) 1998 1997 1996 1995
---- ---- ----
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year $383,200 $329,244 $245,268 $215,266
Sales, Net of Production Costs (97,432) (122,313) (109,801) (35,582)
Net Changes in Prices, Net of
Production Costs (180,853) 78,499 147,330 10,757
Purchases of Minerals in Place 364,102 1,138 770 18,602
Sales of Minerals in Place - (9,632) (1,141) (5,688)
Extensions and Discoveries 36,844 88,228 93,864 47,236
Changes in Estimated Future
Development Costs (104,181) (20,785) (53,630) (50,366)
Previously Estimated Development
Costs Incurred 28,514 43,731 42,780 39,833
Net Change in Income Taxes at
Applicable Statutory Rate 57,190 (24,797) (52,613) (6,838)
Revisions of Previous Quantity
Estimates (75,136) (27,317) (15,491) (20,934)
Accretion of Discount and Other 54,523 47,204 31,908 32,982
-------- -------- --------
Standardized Measure of Discounted
Future Net Cash Flows at End of Year $466,771 $383,200 $329,244 $245,268
======== ======== ========
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
Schedule II - Valuation and Qualifying Accounts
(Thousands)
--------------------
Additions
----------------------
Charged to
Balance at Charged to Charged toOther Balance at
Beginning Costs and OtherAccounts Deductions End of
Description of Period Expenses Accounts (Note)(Note 1) (Note 2) Period
- ----------- ---------- ---------- ----------- ---------- ---------- -------------------
Year Ended September 30, 1998
- -----------------------------
Reserve for Doubtful
Accounts $8,291 $15,861 $ 746 $18,666 $6,232
====== ======= ====== ======= ======
Year Ended September 30, 1997
- -----------------------------
Reserve for Doubtful
Accounts $7,672 $16,586 $ - $15,967 $8,291
====== ======= ====== ======= ======
Year Ended September 30, 1996
- -----------------------------
Reserve for Doubtful
Accounts $5,924 $15,191 $ - $13,443 $7,672
====== ======= ====== ======= ======
Year Ended September 30, 1995Note 1 - -----------------------------
ReserveRepresents opening balance sheet reserve plus exchange rate impact of
translating the Czech koruna to the U.S. dollar for Doubtful
Accounts $5,055 $15,187 $ - $14,318 $5,924
====== ======= ====== ======= ======Horizon.
Note 2 - Amounts represent net accounts receivable written-off.
ITEM 9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
PART III
--------
ITEM 10 Directors and Executive Officers of the Registrant
The information required by this item concerning the directors of the Company is
omitted pursuant to Instruction G of Form 10-K since the Company's definitive
Proxy Statement for its February 26, 199818, 1999 Annual Meeting of Shareholders will be
filed with the SEC not later than 120 days after September 30, 1997.1998. The
information provided in such definitive Proxy Statement is incorporated herein
by reference. Information concerning the Company's executive officers can be
found in Part I, Item 1, of this report.
ITEM 11 Executive Compensation
The information required by this item is omitted pursuant to Instruction G of
Form 10-K since the Company's definitive Proxy Statement for its February 26,
199818,
1999 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1997.1998. The information provided in such definitive
Proxy Statement is incorporated herein by reference.
ITEM 12 Security Ownership of Certain Beneficial Owners and Management
The information required by this item is omitted pursuant to Instruction G of
Form 10-K since the Company's definitive Proxy Statement for its February 26,
199818,
1999 Annual Meeting of Shareholders will be filed with the SEC not later than
120 days after September 30, 1997.1998. The information provided in such definitive
Proxy Statement is incorporated herein by reference.
ITEM 13 Certain Relationships and Related Transactions
At September 30, 1997,1998, the Company knows of no relationships or transactions
required to be disclosed pursuant to Item 404 of Regulation S-K.
PART IV
-------
ITEM 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) Financial Statement Schedules
All financial statement schedules filed as part of this report
are included in Item 8 of this Form 10-K and reference is made
thereto.
(b) Reports on Form 8-K
None
(c) Exhibits
Exhibit
Number Description of Exhibits
------------- -----------------------
3(i) Articles of Incorporation:
*3.1 Restated Certificate of Incorporation of National Fuel Gas
Company dated March 15, 1985 (Exhibit 10-OO, Form
10-K for fiscal year ended September 30, 1991 in File
No. 1-3880)
* Certificate of Amendment of Restated Certificate of
Incorporation of National Fuel Gas Company, dated March
9, 1987 (Exhibit 3.1, Form 10-K for fiscal year ended
September 30, 1995 in File No. 1-3880)
* Certificate of Amendment of Restated Certificate of
Incorporation of National Fuel Gas Company, dated
February 22, 1988 (Exhibit 3.2, Form 10-K for fiscal
year ended September 30, 1995 in File No. 1-3880)
* Certificate of Amendment of Restated Certificate of
Incorporation, dated March 17, 1992 (Exhibit EX-3(a),
Form 10-K for fiscal year ended September 30, 1992 in
File No. 1-3880)21, 1998
3(ii) By-Laws:
3.13.2 National Fuel Gas Company By-Laws as amended through
September 18, 199717, 1998
(4) Instruments Defining the Rights of Security Holders,
Including Indentures:
* Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company)
(Exhibit 2(b) in File No. 2-51796)
* Third Supplemental Indenture dated as of December 1, 1982,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(a)(4) in File No. 33-49401)
* Tenth Supplemental Indenture dated as of February 1, 1992,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(a), Form 8-K dated February 14, 1992 in
File No. 1-3880)
* Eleventh Supplemental Indenture dated as of May 1, 1992, to
Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company)
(Exhibit 4(b), Form 8-K dated February 14, 1992 in File No.
1-3880)
* Twelfth Supplemental Indenture dated as of June 1, 1992, to
Indenture dated as of October 15, 1974, between the Company
and The Bank of New York (formerly Irving Trust Company)
(Exhibit 4(c), Form 8-K dated June 18, 1992 in File No.
1-3880)
* Thirteenth Supplemental Indenture dated as of March 1, 1993,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4(a)(14) in File No. 33-49401)
* Fourteenth Supplemental Indenture dated as of July 1, 1993,
to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4.1, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
* Fifteenth Supplemental Indenture dated as of September 1,
1996 to Indenture dated as of October 15, 1974, between the
Company and The Bank of New York (formerly Irving Trust
Company) (Exhibit 4.1, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
* Rights Agreement between National Fuel Gas Company and
Marine Midland Bank dated June 12, 1996 (Exhibit 99.1, Form
8-K dated June 13, 1996 in File No. 1-3880)
(10) Material Contracts:
(ii) (B) Contracts upon which Registrant's business is substantially
dependent:
* Service Agreement No. 830016 with Texas Eastern Transmission
Corporation, under Rate Schedule FT-1, dated November 2,
1995 (Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
* Service Agreement No. 830017 with Texas Eastern Transmission
Corporation, under Rate Schedule FT-1, dated November 2,
1995 (Exhibit 10.2, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
* Service Agreement with Texas Eastern Transmission
Corporation, under Rate Schedule CDS, dated November 2, 1995
(Exhibit 10.3, Form 10-K for fiscal year ended September 30,
1996 in File No. 1-3880)
* Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation, under
Rate Schedule FSS, dated April 3, 1996 [Portions of this
agreement are subject to confidential treatment under Rule
24b-2] (Exhibit 10.4, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
* Service Agreement with St. Clair Pipelines Ltd., dated
January 29, 1996 [Portions of this agreement are subject to
confidential treatment under Rule 24b-2] (Exhibit 10.5, Form
10-K for fiscal year ended September 30, 1996 in File No.
1-3880)
* Service Agreement with Empire State Pipeline under Rate
Schedule FT, dated December 15, 1994 [Portions of this
agreement are subject to confidential treatment under Rule
24b-2] (Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1995, in File No. 1-3880)
* Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation under
Rate Schedule ESS dated August 1, 1993 (Exhibit 10.2, Form
10-K for fiscal year ended September 30, 1995, in File No.
1-3880)
* Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation under
Rate Schedule ESS dated September 19, 1995 (Exhibit 10.3,
Form 10-K for fiscal year ended September 30, 1995, in File
No. 1-3880)
* Service Agreement between National Fuel Gas Distribution
Corporation and National Fuel Gas Supply Corporation under
Rate Schedule EFT dated August 1, 1993 (Exhibit 10.4, Form
10-K for fiscal year ended September 30, 1995, in File No.
1-3880)
* Amendment dated as of May 1, 1995 to Service Agreement
between National Fuel Gas Distribution Corporation and
National Fuel Gas Supply Corporation under Rate Schedule EFT
dated August 1, 1993 (Exhibit 10.5, Form 10-K for fiscal
year ended September 30, 1995, in File No. 1-3880)
* Service Agreement with Transcontinental Gas Pipe Line
Corporation under Rate Schedule FT dated August 1, 1993
(Exhibit 10.6, Form 10-K for fiscal year ended September 30,
1995, in File No. 1-3880)
* Service Agreement with Transcontinental Gas Pipe Line
Corporation under Rate Schedule FT dated October 1, 1993
(Exhibit 10.7, Form 10-K for fiscal year ended September 30,
1995, in File No. 1-3880)
* Service Agreement with Columbia Gas Transmission Corporation
under Rate Schedule FTS, dated November 1, 1993 and executed
February 13, 1994 (Exhibit 10.1, Form 10-K for fiscal year
ended September 30, 1994 in File No. 1-3880)
* Service Agreement with Columbia Gas Transmission Corporation
under Rate Schedule FSS, dated November 1, 1993 and executed
February 13, 1994 (Exhibit 10.2, Form 10-K for fiscal year
ended September 30, 1994 in File No. 1-3880)
* Service Agreement with Columbia Gas Transmission Corporation
under Rate Schedule SST, dated November 1, 1993 and executed
February 13, 1994 (Exhibit 10.3, Form 10-K for fiscal year
ended September 30, 1994 in File No. 1-3880)
* Gas Transportation Agreement with Tennessee Gas Pipeline
Company under Rate Schedule FT-A (Zone 4), dated September
1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
* Gas Transportation Agreement with Tennessee Gas Pipeline
Company under Rate Schedule FT-A (Zone 5), dated September
1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended
September 30, 1993 in File No. 1-3880)
* Service Agreement with CNG Transmission Corporation under
Rate Schedule FT, dated October 1, 1993 (Exhibit 10.5, Form
10-K for fiscal year ended September 30, 1993 in File No.
1-3880)
* Service Agreement with CNG Transmission Corporation under
Rate Schedule GSS, dated October 1, 1993 (Exhibit 10.6, Form
10-K for fiscal year ended September 30, 1993 in File No.
1-3880)
(iii) Compensatory plans for officers:
* Employment Agreement, dated September 17, 1981, with Bernard
J. Kennedy (Exhibit 10.4, Form 10-K for fiscal year ended
September 30, 1994 in File No. 1-3880)
* Ninth Extension to Employment Agreement with Bernard J.
Kennedy, dated September 19, 1996 (Exhibit 10.6, Form 10-K
for fiscal year ended September 30, 1996 in File No. 1-3880)
* National Fuel Gas Company 1983 Incentive Stock Option Plan,
as amended and restated through February 18, 1993 (Exhibit
10.2, Form 10-Q for the quarterly period ended March 31,
1993 in File No. 1-3880)
* National Fuel Gas Company 1984 Stock Plan, as amended and
restated through February 18, 1993 (Exhibit 10.3, Form 10-Q
for the quarterly period ended March 31, 1993 in File No.
1-3880)
* Amendment to the National Fuel Gas Company 1984 Stock Plan,
dated December 11, 1996 (Exhibit 10.7, Form 10-K for fiscal
year ended September 30, 1996 in File No. 1-3880)
* National Fuel Gas Company 1993 Award and Option Plan, dated
February 18, 1993 (Exhibit 10.1, Form 10-Q for the quarterly
period ended March 31, 1993 in File No. 1-3880)
* Amendment to National Fuel Gas Company 1993 Award and Option
Plan, dated December 18, 1996 (Exhibit 10, Form 10-Q for the
quarterly period ended December 31, 1996 in File No. 1-3880)
* Amendment to National Fuel Gas Company 1993 Award and Option
Plan, dated December 11, 1996 (Exhibit 10.8, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
* Amendment to National Fuel Gas Company 1993 Award and Option
Plan, dated October 27, 1995 (Exhibit 10.8, Form 10-K for
fiscal year ended September 30, 1995 in File No. 1-3880)
* National Fuel Gas Company 1997 Award and Option Plan
(Exhibit 10.9, Form 10-K for fiscal year ended September 30,
1996 in File No. 1-3880)
* Change in Control Agreement, dated May 1, 1992, with Philip
C. Ackerman (Exhibit EX-10.4, Form 10-K for fiscal year
ended September 30, 1992 in File No. 1-3880)
* Change in Control Agreement, dated May 1, 1992, with Richard
Hare (Exhibit EX-10.5, Form 10-K for fiscal year ended
September 30, 1992 in File No. 1-3880)
* Agreement, dated August 1, 1989, with Richard Hare (Exhibit
10-Q, Form 10-K for fiscal year ended September 30, 1989 in
File No. 1-3880)
10.1* Agreement dated August 1, 1986, with Joseph P. Pawlowski
10.2(Exhibit 10.1, Form 10-K for fiscal year ended September
30,1997 in File No. 1-3880)
* Agreement dated August 1, 1986, with Gerald T. Wehrlin
(Exhibit 10.2, Form 10-K for fiscal year ended September 30,
1997, in File No. 1-3880)
* National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through May 1, 1994 (Exhibit 10.7, Form
10-K for fiscal year ended September 30, 1994 in File No.
1-3880)
* Amendment to the National Fuel Gas Company Deferred
Compensation Plan, dated September 19, 1996 (Exhibit 10.10,
Form 10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
* Amendment to National Fuel Gas Company Deferred Compensation
Plan, dated September 27, 1995 (Exhibit 10.9, Form 10-K for
fiscal year ended September 30, 1995 in File No. 1-3880)
10.3* National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through March 20, 1997 10.4(Exhibit 10.3,
Form 10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
* Amendment to National Fuel Gas Company Deferred Compensation
Plan dated June 16, 1997 (Exhibit 10.4, Form 10-K for fiscal
year ended September 30, 1997 in File No. 1-3880)
10.1 Amendment No. 2 to the National Fuel Gas Company Deferred
Compensation Plan, dated March 13, 1998
* National Fuel Gas Company Tophat Plan, effective March 20,
1997 (Exhibit 10, Form 10-Q for the quarterly period ended
June 30, 1997 in File No. 1-3880)
10.2 Amendment No. 1 to the National Fuel Gas Company Tophat
Plan, dated April 6, 1998
* Death Benefits Agreement, dated August 28, 1991, with
Bernard J. Kennedy (Exhibit 10-TT, Form 10-K for fiscal year
ended September 30, 1991 in File No. 1-3880)
* Amendment to Death Benefit Agreement of August 28, 1991,
with Bernard J. Kennedy, dated March 15, 1994 (Exhibit
10.11, Form 10-K for fiscal year ended September 30, 1995 in
File No. 1-3880)
10.5* Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 17, 1997 with Philip C.
Ackerman 10.6(Exhibit 10.5, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
* Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Richard Hare
10.7(Exhibit 10.6, Form 10-K for fiscal year ended September 30,
1997 in File No. 1-3880)
* Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Joseph P.
Pawlowski 10.8(Exhibit 10.7, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
* Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Gerald T.
Wehrlin (Exhibit 10.8, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
* National Fuel Gas Company and Participating Subsidiaries
Executive Retirement Plan as amended and restated through
November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year
ended September 30, 1995 in File No. 1-3880)
* National Fuel Gas Company and Participating Subsidiaries
1996 Executive Retirement Plan Trust Agreement (II) dated
May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal year ended
September 30, 1996 in File No. 1-3880)
10.9* Amendments to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan dated September 18,
1997 (Exhibit 10.9, Form 10-K for fiscal year ended
September 30, 1997 in File No. 1-3880)
* Summary of Annual at Risk Compensation Incentive Program
(Exhibit 10.10, Form 10-K for fiscal year ended September
30, 1993 in File No. 1-3880)
* Administrative Rules with Respect to at Risk Awards under
the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
* Administrative Rules of the Compensation Committee of the
Board of Directors of National Fuel Gas Company as amended
through December 11, 1996 (Exhibit 10.15, Form 10-K for
fiscal year ended September 30, 1996 in File No. 1-3880)
* Excerpts of Minutes from the National Fuel Gas Company Board
of Directors Meeting of December 5, 1991 regarding change in
control agreements, non-employee director retirement plan,
and restrictions on restricted stock (Exhibit 10-UU, Form
10-K for fiscal year ended September 30, 1991 in File No.
1-3880)
* Excerpts from Minutes from the National Fuel Gas Company
Board of Directors Meeting of September 19, 1996 regarding
compensation of non-employee directors and related
amendments of By-Laws (Exhibit 3.1, Form 10-K for fiscal
year ended September 30, 1996 in File No. 1-3880)
10.10* Excerpts of Minutes from the National Fuel Gas Company Board
of Directors Meeting of February 20, 1997 regarding the
Retirement Benefits for Bernard J. Kennedy 10.11(Exhibit 10.10,
Form 10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
* Excerpts of Minutes from the National Fuel Gas Company Board
of Directors Meeting of March 20, 1997 regarding the
Retainer Policy for Non-Employee Directors (Exhibit 10.11,
Form 10-K for fiscal year ended September 30, 1997 in File
No. 1-3880)
* Form of Change in Control Agreement, dated May 1, 1992, with
Walter E. DeForest, Bruce H. Hale, Joseph P. Pawlowski,
Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin, and
dated March 16, 1995, with James A. Beck (Exhibit 10.16,
Form 10-K for fiscal year ended September 30, 1996 in File
No. 1-3880)
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Letter to Shareholders as contained in the 19971998 Annual
Report and incorporated by reference into this Form 10-K
(21) Subsidiaries of the Registrant:
See Item 1 of Part I of this Annual Report on
Form 10-K
(23) Consents of Experts and Counsel:
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
(27) Financial Data Schedules
(99) Additional Exhibits:
99.1 Report of Ralph E. Davis Associates, Inc.
All other exhibits are omitted because they are not applicable or the
required information is shown elsewhere in this Annual Report on Form 10-K.
* Incorporated herein by reference as indicated.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
National Fuel Gas Company
(Registrant)
-----------------------------------------------------
By /s/ B. J. Kennedy
---------------------------------------------------------
B. J. Kennedy
Chairman of the Board, President
Date: December 11, 199710, 1998 and Chief Executive Officer
-------------------
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title
--------- -----
/s/ B. J. Kennedy
------------------------------------------------- Chairman of the Board,
B. J. Kennedy President, Chief Executive
Officer and Director
Date: December 11, 199710, 1998
-----------------
/s/ P. C. Ackerman
------------------------------------------------- Senior Vice President, Principal
P. C. Ackerman Financial Officer and Director
Date: December 11, 199710, 1998
-----------------
/s/ R. T. Brady
------------------------------------------------- Director
R. T. Brady
Date: December 11, 199710, 1998
-----------------
/s/ J. V. Glynn
------------------------ Director
J. V. Glynn
Date: December 10, 1998
-----------------
/s/ W. J. Hill
------------------------------------------------- Director
W. J. Hill
Date: December 11, 199710, 1998
-----------------
/s/ B. S. Lee
------------------------------------------------- Director
B. S. Lee
Date: December 11, 199710, 1998
-----------------
/s/ E. T. Mann
------------------------------------------------- Director
E. T. Mann
Date: December 11, 199710, 1998
-----------------
/s/ G. L. Mazanec
------------------------------------------------- Director
G. L. Mazanec
Date: December 11, 199710, 1998
-----------------
/s/ G. H. Schofield
------------------------------------------------- Director
G. H. Schofield
Date: December 11, 199710, 1998
-----------------
/s/ J. P. Pawlowski
------------------------------------------------- Treasurer and Principal
J. P. Pawlowski Accounting Officer
Date: December 11, 199710, 1998
-----------------
/s/ A. M. Cellino
------------------------------------------------- Secretary
A. M. Cellino
Date: December 11, 199710, 1998
-----------------
/s/ G. T. Wehrlin
------------------------------------------------- Controller
G. T. Wehrlin
Date: December 11, 199710, 1998
-----------------
APPENDIX TO ITEM 2 - PROPERTIES
FourFive maps outlining the Company's operating areas at September 30, 19971998
are included on pagesthe inside front cover and on page 1 and 2 of the paper format
version of the Company's combined Annual Report to Shareholders/Form 10-K.
The first map identifies the Company's Pipeline and Storage operating area
(i.e., Supply Corporation's storage areas and pipelines). The second map
identifies the Company's Utility OperatingExploration and Production operating area (i.e.,
Distribution Corporation's serviceSeneca's operating area). The third map identifies the Company's
Exploration and ProductionInternational operating area (i.e., Seneca Resources' operating area)Horizon's Czech Republic operations).
The fourth map identifies the geographic location of the Company's Other
Nonregulated operating areas (i.e., NFR's marketing offices Horizon's Czech Republic
operations and Highland's
sawmill operations). The fifth map identifies the Company's Utility
Operating area (i.e., Distribution Corporation's service area).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 19971998
Two pie graphs detailing the revenue dollar in 1997:1998: where it came from
and where it went to, broken down as follows:
Where it came from:
$ .560.483 Residential Gas Sales
.184.147 Commercial, Industrial and Off-System Gas Sales
.101.083 Oil and Gas Production Revenues
.065.077 Gas Transportation Revenues
.055.070 Energy Marketing Revenues
.029.039 District Heating Revenues
.028 Gas Storage Service Revenues
.006.018 Electric Generation Revenues
.014 Timber and Sawmill Revenues
.041 Other Revenues
$1.000 Total
Where it went to:
$ .417.348 Gas Purchased
.141.150 Wages, Including Benefits
.133 Taxes
.088.105 Depreciation
.086.102 Impairment of Oil and Gas Producing Properties
.096 Other Materials and Services
.051 Dividends - Common Stock
.045.087 Taxes
.062 Interest
.039 Reinvested.030 Fuel Used in the BusinessHeat and Electric Generation
.018 Earnings
.002 Minority Interest in Foreign Subsidiaries
$1.000 Total
B. Capital Expenditures
A bar graph detailing capital expenditures (millions of dollars) for the
years 1993 through 1997, broken down as follows:
1993 1994 1995 1996 1997
---- ---- ---- ---- ----
Other Nonregulated $ 6.2 $ 3.6 $ 9.6 $ 3.2 $ 16.5
Pipeline and Storage 27.4 20.5 38.7 22.2 22.6
Utility 61.8 61.7 64.8 62.6 66.9
Exploration and Production 36.5 52.5 69.7 83.6 120.3
------ ------ ------ ------ ------
$131.9 $138.3 $182.8 $171.6 $226.3
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION - GRAPHS (Concluded)
C. Capitalization Ratios
A bar graph detailing capitalization (percentage) for the years 1993
through 1997, broken down as follows:
Debt (%) Equity (%)
1993 47.8 52.2
1994 46.2 53.8
1995 47.0 53.0
1996 47.5 52.5
1997 46.0 54.0
D. Book Value Per Common Share
A bar graph detailing book value per common share (dollars) for the years
1993 through 1997, as follows:
1993 - 20.08
1994 - 20.93
1995 - 21.39
1996 - 22.61
1997 - 23.94
Exhibit Index
-------------
3.1 Restated Certificate of Incorporation of National Fuel Gas
Company dated September 21, 1998
3.2 National Fuel Gas Company By-Laws as amended through
September 18, 199717, 1998
10.1 Agreement dated August 1, 1986, with Joseph P. Pawlowski
10.2 Agreement dated August 1, 1986, with Gerald T. Wehrlin
10.3 National Fuel Gas Company Deferred Compensation Plan, as
amended and restated through March 20, 1997
10.4 Amendment No. 2 to the National Fuel Gas Company Deferred
Compensation Plan, dated June 16, 1997
10.5 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 17, 1997 with Philip C.
Ackerman
10.6 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Richard Hare
10.7 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Joseph P.
Pawlowski
10.8 Amended and Restated Split Dollar Insurance and Death
Benefit Agreement dated September 15, 1997 with Gerald T.
Wehrlin
10.9 AmendmentsMarch 13, 1998
10.2 Amendment No. 1 to National Fuel Gas Company and Participating
Subsidiaries Executive Retirement Plan dated September 18,
1997
10.10 Excerpts of Minutes from the National Fuel Gas Company Board
of Directors Meeting of February 20, 1997 regarding the
Retirement Benefits for Bernard J. Kennedy
10.11 Excerpts of Minutes from the National Fuel Gas Company Board
of Directors Meeting of March 20, 1997 regarding the
Retainer Policy for Non-Employee DirectorsTophat
Plan, dated April 6, 1998
(12) Computation of Ratio of Earnings to Fixed Charges
(13) Letter to Shareholders as contained in the 19971998 Annual
Report and incorporated by reference into this Form 10-K
23.1 Consent of Ralph E. Davis Associates, Inc.
23.2 Consent of Independent Accountants
(27)27.1 Financial Data Schedule for 12 months endingended September 30,
1998
27.2 Financial Data Schedule Restated for 12 months ended
September 30, 1997
27.3 Financial Data Schedule Restated for 12 months ended
September 30, 1996
27.4 Financial Data Schedule Restated for 3 months ended December
31, 1996
27.5 Financial Data Schedule Restated for 3 months ended March
31, 1997
27.6 Financial Data Schedule Restated for 3 months ended June 30,
1997
99.1 Report of Ralph E. Davis Associates, Inc.