UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSIONUnited States
                       Securities and Exchange Commission
                             Washington, D. C.D.C. 20549

                                   FORMForm 10-K
                (Mark One)
      [  X  ]   ANNUAL REPORT PURSUANT TO SECTIONAnnual Report Pursuant to Section 13 ORor 15(d) OF
                     THE SECURITIES EXCHANGE ACT OFof
                      The Securities Exchange Act of 1934

                  For the Fiscal Year Ended September 30, 1994
                                      OR
      [     ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                     THE SECURITIES EXCHANGE ACT OF 1934
             For the Transition Period From..........to..........1995

                         Commission File Number 1-3880

                           NATIONAL FUEL GAS COMPANYNational Fuel Gas Company
             (Exact name of registrant as specified in its charter)

           New Jersey                                          13-1086010
  (State or other jurisdiction of                           (I.R.S. Employer
  incorporation or organization)                           Identification No.)

       10 Lafayette Square                                       14203
        Buffalo, New York                                      (Zip Code)
(Address of principal executive offices)

                                  (716) 857-6980
               Registrant's telephone number, including area code
           -----------------------------------------------------------
          Securities  registered  pursuant to Section 12(b) of the Act:

                                                            Name of each
                                                              exchange
   Title of each class                                   on which registered
Common Stock, $1 Par Value                             New York Stock Exchange

          Securities  registered  pursuant to Section 12(g) of the Act:

                                      NONENone

     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during the  preceding  12 months (or for such shorter period that the 
registrant was required to file such reports), and (2) has been  subject to such  filing
requirements for the past 90 days. YES X   NO
                                      ---    ---
         Indicate by check mark if disclosure of delinquent  filers  pursuant to
Item 405 of Regulation S-K is not contained  herein,  and will not be contained,
to the best of the  registrant's  knowledge,  in definitive proxy or information
statements  incorporated  by  reference  in Part  III of this  Form  10-K or any
amendment to this Form 10-K. [ X ]

         The aggregate market value of the voting stock held by nonaffiliates of
the registrant amounted to $953,688,000$1,164,782,000 as of November 30, 1994.1995.

         Common stock, $1 par value, outstanding as of November 30, 1994: 
37,337,0561995:
37,437,663 shares.

                      DOCUMENTS INCORPORATED BY REFERENCE
         Portions of the registrant's Annual Report to Shareholders for 1995 are
incorporated  by  reference  into  Part  I  of  this  report.  Portions  of  the
registrant's  definitive  Proxy Statement for the Annual Meeting of Shareholders
to be held February 16, 1995,15, 1996 are incorporated by reference into Part III of this
report.






NATIONAL FUEL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Fiscal Year Ended September 30, 19941995

                               TABLE OF CONTENTS
                                                                         Page

  GLOSSARY OF TERMS                                                          3
PART I
ITEM  1.  BUSINESS                                                         
            THE COMPANY AND ITS SUBSIDIARIES                               61
            RATES AND REGULATION                                           72
            THE UTILITY OPERATION                                          83
            THE PIPELINE AND STORAGE 14
              SELECTED STATISTICS OFSEGMENT                               3
            THE SYSTEM'S REGULATED OPERATIONS      16 EXPLORATION AND PRODUCTION 17SEGMENT                         3
            OTHER NONREGULATED 19OPERATIONS                                  4
            SOURCES AND AVAILABILITY OF RAW MATERIALS                      4
            COMPETITION                                                    195
            SEASONALITY                                                    7
            CAPITAL EXPENDITURES                                           227
            ENVIRONMENTAL MATTERS                                          227
            MISCELLANEOUS                                                  228
            EXECUTIVE OFFICERS OF THE COMPANY                              238

ITEM  2.  PROPERTIES                                                       
            GENERAL INFORMATION ON FACILITIES                              249
            EXPLORATION AND PRODUCTION ACTIVITIES                          249

ITEM  3.  LEGAL PROCEEDINGS                                               
            PARAGON/TGX PROCEEDINGS                                       2710

ITEM  4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS             3012

PART II
ITEM  5.  MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
          SHAREHOLDER MATTERS                                             3112

ITEM  6.  SELECTED FINANCIAL DATA                                         3213

ITEM  7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
          CONDITION AND RESULTS OF OPERATIONS                             3314

ITEM  8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                     5228

ITEM  9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
          ACCOUNTING AND FINANCIAL DISCLOSURE                             9559

PART III
ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT              9559

ITEM 11.  EXECUTIVE COMPENSATION                                          9559

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
          MANAGEMENT                                                      9560

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                  9560

PART IV
ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
          FORM 8-K                                                        9660

SIGNATURES                                                                10165





                                     GLOSSARY OF TERMSPART I
ITEM 1  Business

The following termsCompany and abbreviations used in the text of this report 
are defined as indicated:

Bcf - Billion cubic feet.

Btu - British thermal unit.

Bypass - Obtaining service from a new supplier without utilizing the facility 
of the former supplier.

Cogeneration - The use of gas for on-site production of both electricity and  
heat for industrial and large commercial users.

Company or Registrant -its Subsidiaries

National  Fuel Gas Company.

Condensate - A liquid hydrocarbon recovered atCompany (the  Company or  Registrant),  a registered  holding
company under the surface as natural gas is 
produced.

Data-Track - Data-Track Account Services, Inc.

Degree Day - A measure of the coldness of weather experienced, based on the 
extent to which the daily mean temperature falls below a reference 
temperature, usually 65 degrees Fahrenheit (F).  For example, on a day when 
the mean temperature is 35 degrees F, there would be 30 degree days 
experienced.

Development Well - A well drilled to a known producing formation in a 
previously discovered field.

Distribution Corporation - National Fuel Gas Distribution Corporation.

Empire - Empire Exploration, Inc.

Exploratory Well - A well drilled to a previously untested geologic structure 
to determine the presence of oil or gas.

Farm Out - An arrangement whereby the owner of a lease assigns the lease, or 
some portion of it, to another party for drilling.

FERC - Federal Energy Regulatory Commission.

Firm Transportation - Pipeline transportation under contractual arrangements 
providing service not subject to interruption.

Highland - Highland Land & Minerals, Inc.

Holding Company Act - Public  Utility  Holding  Company Act of 1935, as amended.

Horizontal Drilling -A drilling technique in which the well bore runs 
horizontal or parallel to the earth's surface.  This exposes a greater portion 
of the underground producing rock formation to the well bore than conventional 
vertical drilling, improving overall productivity by permitting maximum 
recovery from a reservoir.


                        GLOSSARY OF TERMS (Continued)

Leidy Hub - Leidy Hub, Inc.

Mbbl - Thousand barrels.

Mcf - Thousand cubic feet.

MMcf - Million cubic feet.

MMcfe - Million cubic feet equivalent.

NFR - National Fuel Resources, Inc.

NGV - Natural gas vehicle.

Nonregulated Operations - Consist of the Company's Exploration and Production 
and Other Nonregulated business segments.

Note or Notes - Notes to Consolidated Financial Statements.

PaPUC - Pennsylvania Public Utility Commission.

Penn-York - Penn-York Energy Corporation.

PSC - State of New York Public Service Commission.

Regulated Operations - Consist of the Company's Utility and Pipeline and 
Storage business segments.

Reserves - Estimated volumes of oil, gas or other minerals that can be 
recovered from deposits in the earth with reasonable certainty.

Seneca - Seneca Resources Corporation.

SEC - Securities and Exchange Commission.

SFV - Straight fixed-variable.

Supply Corporation - National Fuel Gas Supply Corporation.

System - The Company and its subsidiaries.

Throughput - The sum  of volumes of gas sold and volumes of gas transported 
for customers.

Transportation Service - The movement of gas for third parties through 
pipeline facilities for a fee.

UCI - Utility Constructors, Inc.

Unbundled Service - The separation of pipeline company services, such as 
storage, gathering and transmission, with rates charged which reflect the cost 
of each service.



                        GLOSSARY OF TERMS (Continued)

Underground Storage -The injection of large quantities of natural gas into 
underground rock formations for storage during periods of low market demand 
and withdrawal during periods of peak market demand.

WNC - Weather normalization clause.

Working Gas - Gas in an underground storage field that is available for market 
which is in excess of the base gas.

                                    PART I


ITEM 1.  BUSINESS

COMPANY AND SUBSIDIARIES

      The Company, a registered holding company under theamended (the
Holding Company Act,Act), was organized under the laws of the State of New Jersey in
1902.  The Company is engaged in the  business of owning and holding  securities
issued by its subsidiary  companies.  Except as otherwise  indicated  below, the
Company owns all of the outstanding securities of the 
subsidiary companies identified below.  All referencesits subsidiaries. Reference to
years"the  Company" in this report are tomeans the  Company's fiscal year ended September 30 unless otherwise noted.Registrant  or the  Registrant  and its
subsidiaries collectively, as appropriate in the context of the disclosure.

        The System constitutesCompany is an integrated  natural gas  operation  and consistsconsisting of
operations which are regulated as to their rates and operations which are 
not so regulated.  The Regulated Operations fall within twothree major business segments:

Utility Operation and Pipeline and Storage.  The Nonregulated Operations 
consist principally of the Exploration and Production business segment.  Other 
Nonregulated operations include the System's natural gas marketing and 
brokerage operations, pipeline construction operations, sawmill and dry kiln 
operations, and natural gas market area hub operations.1. The  Utility  Operation  is carried  out by  Distribution Corporation.  
Pipeline and Storage operations are carried out by Supply Corporation. 
Effective July 1, 1994, all of the Company's natural gas storage services were 
consolidated into Supply Corporation through the merger of Penn-York into 
Supply Corporation.  Seneca is engaged in Exploration and Production 
operations.  Effective July 1, 1994, all of the Company's Exploration and 
Production operations were consolidated into Seneca through the merger of 
Empire into Seneca.  Supply Corporation's exploration and production 
activities were transferred to Empire, effective on January 1, 1994.  Other 
Nonregulated operations are carried out by NFR, UCI, Highland, Seneca, 
Data-Track and Leidy Hub.

      No single customer, or group of customers under common control, 
accounted for 10% or more of the System's consolidated revenues in 1994.

      Financial information about the Company's business segments can be found 
in Note H - "Business Segment Information," on pages 79 to 81 of this report.National  Fuel Gas  Distribution
Corporation  (Distribution  Corporation),  a New York corporation, is a public utility 
thatcorporation.  Distribution
Corporation sells natural gas and provides natural gas  transportation  serviceservices
through a local distribution system located in western New York and northwestern
Pennsylvania.  During 1994, Distribution Corporation 
served an average of 727,700 retail customers, compared with an average of 
724,400 retail customers served during 1993.  The principalPennsylvania   (principal   metropolitan  areas 
served areareas:  Buffalo,   Niagara  Falls  and
Jamestown, New York, andYork; Erie and Sharon, Pennsylvania.Pennsylvania).

2. The Pipeline and Storage  segment is carried out by National  Fuel Gas Supply
Corporation (Supply Corporation), a Pennsylvania corporation, is engaged in thecorporation. Supply Corporation
provides   interstate  natural  gas  transportation  and  storage  of natural gasservices  for
Systemaffiliated and  nonaffiliated  companies.  Supply Corporation owns and operatescompanies  through (i) an integrated gas pipeline
system extending from southwestern  Pennsylvania to the New York-Canadian border
at the Niagara River.River,  and (ii) 30 underground  natural gas storage fields owned
and  operated  by Supply  Corporation  owns and operates 30four other  underground  natural  gas
storage  fields in its operating area and four additional 
underground storage fields are  operated  jointly with certainvarious  major  interstate  gas pipeline
companies.


ITEM 1.  BUSINESS (Continued)3. The  Exploration  and Production  segment is carried out by Seneca  Resources
Corporation  (Seneca),  a  Pennsylvania  corporation,corporation.  Seneca is  engaged in the
exploration  for,  and the  development  and  purchase  of,  natural gas and oil
reserves  in the Gulf Coast of Texas and  Louisiana,  in  California  and in the
Appalachian region of the United States.

        Seneca's production is,Other  Nonregulated  operations  are carried  out by the  following
subsidiaries:

* National Fuel Resources,  Inc. (NFR), a New York  corporation  engaged in
the  marketing  and  brokerage  of  natural  gas and the  performance  of energy
management  services for  the most part, sold to 
purchasersutilities and  end-users  located in the  vicinitynortheastern
United States;

* Leidy Hub, Inc. (Leidy),  a New York corporation  engaged in providing various
natural gas hub services to customers in the northeastern, mid-Atlantic, Chicago
and Los Angeles  areas of its wells.  In addition,the United  States and  Ontario,  Canada,  through (i)
Leidy's 50% ownership of  Ellisburg-Leidy  Northeast Hub Company (a Pennsylvania
general  partnership) and (ii) Leidy's 14.5% ownership of Enerchange,  L.L.C. (a
Delaware limited liability company which in turn owns 50% of QuickTrade, L.L.C.,
another Delaware limited liability company);

* Horizon Energy Development,  Inc. (Horizon),  a New York corporation formed in
1995 to engage in foreign and domestic energy projects  through  investment as a
sole or partial  owner in various  business  entities  including  Sceptre  Power
Company,  a partnership  which includes a team with  considerable  experience in
developing such energy projects;

* Seneca is also engaged in the marketing of timber from its Pennsylvania land
holdings.

      NFR, a New York corporation, is engaged in the marketing and brokerage 
of natural gas and performs energy management services for utilities and 
end-users.

      UCI,holdings;





* Highland Land & Minerals,  Inc.  (Highland),  a Pennsylvania  corporation
is engaged in pipeline construction and 
other construction work for the System and nonaffiliated companies, and is 
headquartered in Linesville, Pennsylvania.

      Highland, a Pennsylvania corporation,which operates a sawmill and kiln in Kane,  Pennsylvania.Pennsylvania;

* Data-Track Account Services, Inc.(Data-Track), a New York corporation which
provides collection services (principally issuing collection notices) for the
Company's subsidiaries (principally Distribution Corporation); and

* Utility Constructors, Inc. (UCI), a Pennsylvania corporation which
discontinued its operations (primarily pipeline construction) in 1995 and whose
affairs are being wound down.

        Financial information about each of the Company, particularly Distribution Corporation, primarily 
throughCompany's industry segments
can be found in Item 8 at Note I -  "Business  Segment  Information."  No single
customer,  or group of customers under common  control,  accounted for more than
10% of the issuanceCompany's  consolidated  revenues in 1995. All references to years in
this report are to the Company's fiscal year ended September 30 unless otherwise
noted.

        The  discussion  of collection notices.

      Leidy Hub, a New York corporation, is a partnerthe  Company's  business  segments as contained
under  the  headings   "Exploration   and  Production  and  Other   Nonregulated
Activities," "Utility Operation," and "Pipeline and Storage," which are included
in the Ellisburg-Leidy 
Northeast Hub Company, which operates a natural gas market area hub in 
northeastern Pennsylvania serving the consuming regionspaper copy of the Northeast, 
Mid-AtlanticCompany's combined Annual Report to Shareholders/Form
10-K, are included in this electronic filing as Exhibit 13 and Canada.incorporated
herein by reference.

Rates and Regulation

The hub offers services designed to simplify the 
complexities and the volatility of the gas market for gas buyers and sellers.

RATES AND REGULATION

      All System companies areCompany is subject to regulation by the SECSecurities and Exchange Commission
(SEC) under the broad regulatory provisions of the Holding Company Act,
including provisions relating to issuance of securities, sales and acquisitions
of securities and utility assets, intra-Systemintra-Company transactions and limitations on
diversification.  Distribution Corporation is subjectThe SEC has recommended to regulation byCongress the PSC and the PaPUC 
concerning rates and other matters.  Supply Corporation is subject to 
regulation by the FERC, concerning rates and other matters.  In addition, 
System companies are subject to federal, state and local laws and regulations 
concerning numerous other matters.

      On November 2, 1994, the SEC issued a concept release soliciting comment 
on modernizationconditional  repeal of
the Holding Company Act.  The SEC has deemed thatAct, in conjunction with  legislation  which would allow the
various state regulatory commissions to have access to such books and records of
companies in a 
reexamination of the need for, and role of, a federal holding  company  statute 
issystem  as would be  necessary  in lightfor  effective
regulation,  and allow for federal  audit  authority  and oversight of affiliate
transactions.  The effect of these changes if  implemented,  combined with other
recent  utilitySEC rule  changes,  would  be to  significantly  reduce  the  number  of
applications  filed under the Holding Company Act, exempt routine financings and
expand diversification opportunities. However, the additional proposed access to
Company books and records by state regulatory  developments.commissions would correspondingly
increase  the amount of  regulatory  burden at the state  level.  The Company is
unable to  predict at this time what type of  modernizationregulatory  changes,  if any,  may
occur as a result offrom this  reexaminationproposal,  and therefore  what the impact will be 
on the Company.

ITEM 1.  BUSINESS (Continued)


UTILITY OPERATION

Gas SalesCompany might
be.

        The  Utility  Operation's  rates,  services  and Transportationother  matters are
regulated by the Public  Service  Commission of the State of New York (PSC) with
respect to services  provided  within New York, and by the  Pennsylvania  Public
Utility  Commission   (PaPUC)   with  respect  to  services   provided   within
Pennsylvania.  For additional  discussion of the Utility  Operation's  rates and
regulation,  see Item 7 under the  heading  "Rate  Matters,"  and Item 8 at Note
B-Regulatory Matters.

        The  System's Utility Operation is conducted solely through Distribution 
Corporation.  Substantially allPipeline  and  Storage  segment's  rates,  services  and other
matters are regulated by the Federal Energy Regulatory  Commission  (FERC).  For
additional   discussion  of  its sales are requirements sales (i.e., 
sales that varythe  Pipeline  and  are not subjectStorage   segment's  rates  and
regulation,  see Item 7 under the heading "Rate  Matters," and Item 8 at Note B-
Regulatory Matters.

        This  report   occasionally  refers  collectively  to significant minimum take obligations).  
In 1994, Distribution Corporation's sales and transportation volumes by 
customer class were 52% residential, 21% commercial and 27% industrial.  In 
1994,  the  Utility
Operation accountedand the Pipeline and Storage segment as the Regulated Operations.

        In addition,  the Company is subject to the same federal, state and
local  regulations on various  subjects as other companies doing business in the
same locations.





        The Company's operations other than Supply Corporation and Distribution
Corporation  are not regulated as to prices or rates for services.  Accordingly,
this report  occasionally  refers collectively to the Exploration and Production
segment and the Other Nonregulated operations as the Nonregulated Operations.

The Utility Operation

The Utility Operation  contributed  approximately 52%50% of Systemthe Company's operating
income before income taxes.  Information regarding the resultstaxes in 1995.

        Additional  discussion of 
operations for the Utility  Operation  can be foundindustry  segment
appears in the forepart of the paper copy of the Company's combined Annual
Report to Shareholders/Form 10-K under the heading "Utility Operation," which is
included in this electronic filing as Exhibit 13, below under the headings
"Sources and Availability of Raw Materials" and "Competition," in Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations,Operations" (MD&A), and in Item 8 at Notes B-Regulatory Matters, H-Commitments
and Contingencies and I-Business Segment Information.

The Pipeline and Storage Segment

The Pipeline and Storage segment contributed  approximately 40% of the Company's
operating income before income taxes in 1995.

        The Pipeline and Storage segment  currently has service  agreements
for  substantially  all  of  its  firm  transportation  capacity,  which  totals
approximately 1,860 million cubic feet (MMcf) per day. The Utility Operation has
contracted  for  approximately  1,120 MMcf per day or 60% of that capacity until
2003 and continuing year-to-year thereafter.

        The  Pipeline  and  Storage  segment  has  available  for  sale  to
customers  approximately 60.8 billion cubic feet (Bcf) of firm storage capacity.
The Utility  Operation has contracted  for 25.3 Bcf or 42% of that capacity,  in
service  agreements with initial terms of  approximately 10 years and continuing
year-to-year  thereafter,  effective  beginning in 1993 (23.3 Bcf) and 1996 (2.0
Bcf).  Nonaffiliated  customers were contracted for 35.5 Bcf of storage capacity
throughout 1995.

        The  primary   terms  of  current   storage   service   agreements,
representing   23.3  Bcf  of  the  firm  storage  capacity   contracted  for  by
nonaffiliated customers, expired in 1995. Service continues year-to-year and can
be  terminated by the customer on one year's  notice.  Six such  customers  have
given notice of termination or reduction  effective  March 31, 1996,  accounting
for a reduction of 4.2 Bcf of contracted firm storage capacity at that time. The
Pipeline and Storage segment is actively marketing this available capacity.

        Additional discussion of the Pipeline and Storage segment appears in the
forepart  of  the  paper  copy  of  the  Company's  combined  Annual  Report  to
Shareholders/Form  10-K  under the  heading  "Pipeline  and  Storage,"  which is
included  in this  electronic  filing as Exhibit 13,  below  under the  headings
"Sources and Availability of Raw Materials,"  "Competition"  and  "Environmental
Matters," Item 7 "MD&A," and Item 8 at Notes B-Regulatory Matters, H-Commitments
and Contingencies and I-Business Segment Information.

The Exploration and Production Segment

The  Exploration and Production  segment  contributed  approximately  10% of the
Company's operating income before income taxes in 1995.

        Additional discussion of the Exploration and Production segment appears
in the forepart of the paper copy of the Company's combined Annual Report to
Shareholders/Form  10-K under the heading  "Exploration and Production and Other
Nonregulated Activities," which is included in this electronic filing as Exhibit
13,  below under the heading  "Competition,"  Item 7 "MD&A," and Item 8 at Notes
F-Financial  Instruments,  I-Business  Segment  Information and  L-Supplementary
Information for Oil and Gas Producing Activities.





Other Nonregulated Operations

Other  Nonregulated  operations  contributed  approximately  2% of the Company's
operating income before income taxes in 1995.  Corporate  operations reduced the
Company's operating income before income taxes by approximately 2%.

        Horizon was formed in 1995 to engage in foreign and domestic energy
projects, including foreign utility companies and exempt wholesale generators of
electricity.  The  SEC in 1995  authorized  the  Company  (through  Horizon  and
intermediate  companies)  to (i)  invest up to an  aggregate  of $150.0  million
through  December  2001 in such  activities,  and (ii)  issue  debt and  equity,
provide  guarantees and assume liabilities up to that amount in order to finance
such activities.  The Company  contributed $1.0 million in capital to Horizon in
1995.  Horizon was at year-end  1995  considering  investment  opportunities  in
eastern  Europe,  South  America  and Asia,  and is the  controlling  partner in
Sceptre Power Company,  a partnership  which  includes a team with  considerable
experience in developing such energy projects.

        NFR is  seeking  to add the  brokering  of  electric  power  to its
existing gas marketing  business.  In 1995, NFR obtained  authorization from the
FERC to become an electric power broker in connection with the FERC's  announced
restructuring   of  the  electric  power   industry.   NFR's   application   for
authorization  from the SEC to engage in such activities was pending at year-end
1995.

        Leidy  recognized  a loss of less  than $1.0  million  in 1995 from
writing  off  Leidy's  equity  investment  in  Metscan,  Inc.,  a  developer  of
electronic gas meter reading  devices,  which ceased  operations and liquidated.
Leidy's business now consists  exclusively of activities  related to natural gas
hubs as described below.

        The SEC in 1995 authorized Leidy to enter into a transaction (which
was  consummated in October 1995) by which Leidy invested less than $1.0 million
to acquire a 14.5% ownership interest in Enerchange,  L.L.C. (Enerchange).  This
investment  effectively  gave Leidy (i) a somewhat larger portion of the profits
or  losses of  Ellisburg-Leidy  Northeast  Hub  Company,  (ii) a portion  of the
profits or losses of natural gas hubs in Chicago and Los Angeles, (iii) 14.5% of
Enerchange's  profits or losses in buying and  selling  gas at all three  market
hubs,  and (iv)  14.5% of  Enerchange's  profits  or  losses  as a 50%  owner of
QuickTrade,  L.L.C.,  which is developing an on-line  computer  service on pages 33which
subscribers will buy and sell gas at hubs and obtain related services.

        Additional discussion of the Other Nonregulated operations appears in
the forepart of the paper copy of the Company's combined Annual Report to
51Shareholders/Form  10-K under the heading  "Exploration and Production and Other
Nonregulated  Activities," subheading "Other Nonregulated  Activities," which is
included  in this  electronic  filing as Exhibit 13,  below  under the  headings
"Sources and  Availability of Raw Materials" and  "Competition,"  Item 7 "MD&A,"
and Item 8 at Note I-Business Segment Information.

Sources and Availability of Raw Materials

Natural gas is the principal raw material for the Utility  Operation and some of
the Other Nonregulated operations,  as discussed below. The Pipeline and Storage
segment  transports and stores gas owned by its customers,  whose gas originates
in the  southwestern  United States,  Canada and  Appalachia.  Some of the Other
Nonregulated  operations  rely upon timber  located on Seneca's  lands,  so that
source and availability are not issues.  The Exploration and Production  segment
seeks to discover and produce raw materials  (natural  gas, oil and  hydrocarbon
liquids) as described  in the  forepart of the paper copy of the  Company's
combined Annual Report to Shareholders/Form  10-K under the heading "Exploration
and Production  and Other  Nonregulated  Activities,"  which is included in this
report.

      On average, 97%electronic  filing as Exhibit 13, Item 7 "MD&A," and Item 8 at Notes  I-Business
Segment Information and L - Supplementary  Information for Oil and Gas Producing
Activities.




        In 1995,  the Utility  Operation  purchased  130.8 Bcf of Distribution Corporation'sgas.  Gas
purchases from various producers and marketers in the southwestern United States
under  long-term  (two years or  longer)  contracts  accounted  for 77% of these
purchases.  Purchases of gas in Canada under long-term  contracts,  purchases of
gas in Canada and the United States on the spot market (contracts of less than a
year) and purchases  from  Appalachian  producers  accounted for 3%, 15% and 5%,
respectively,  of the Utility Operation's 1995 gas purchases. Gas purchases from
Vastar  Resources,  Inc.  and Natural  Gas  Clearinghouse  (southwest  gas under
long-term  contract)  represented 13% and 12%,  respectively,  of total 1995 gas
purchases by the Utility  Operation.  No other producer or marketer provided the
Utility Operation with 10% or more of its gas requirements in 1995.

        To move its gas from the  point  of  purchase  to its  distribution
system  in New York and  Pennsylvania,  the  Utility  Operation  purchases  firm
transportation and storage services from various  interstate  pipeline companies
including Supply Corporation.  See Item 8, Note H-Commitments and Contingencies,
for a discussion of the Utility Operation's  obligations under its nonaffiliated
pipeline capacity, gas purchase and gas storage contracts.

        The  Utility   Operation  also   transports  gas  owned  by  others
(principally  industrial and commercial end-users).  Gas produced by Appalachian
producers, especially in Pennsylvania and New York, remained an important source
of  supply  for the  Utility  Operation's  transportation  customers,  who  also
purchased gas from the southwestern United States and Canadian suppliers.

        Other Nonregulated  operations need natural gas for NFR's marketing
and Leidy's hub services, but are relatively indifferent as to the source.

Competition

The natural gas industry was  competitive in 1995 and is expected to become more
competitive in the future.  Competition  existed among providers of natural gas,
as well as between natural gas and other sources of energy.

        Management  continues to believe that there will be increased usage
of natural gas nationwide over the longer term, so that opportunities  exist for
increased  sales.  This  increased use of natural gas  nationwide is expected to
result mainly from the  increased  use of natural gas as an electric  generation
and cogeneration fuel, conversion of home heating load from oil to gas, economic
and population growth,  competitive prices and technological  developments.  The
long-term  trend in  natural  gas will  depend  upon the  balance  of supply and
demand, as well as weather (colder weather  generally  increases demand and thus
price).  As noted,  demand is expected to increase over the longer term.  Supply
will be impacted by the  potential  increase  in domestic  supplies  due to more
efficient  exploration and production  technology and the amount of gas imported
into the United States from Canada and Mexico.

        The continuing deregulation of the natural gas industry should also
enhance the competitive position of natural gas relative to other energy sources
by  removing  some  of  the  regulatory  impediments  to  adding  customers  and
responding  to market  forces.  In addition,  the  environmental  advantages  of
natural gas compared with other fuels should increase the role of natural gas as
an energy source.  The potential  environmental role of natural gas was enhanced
by passage of the federal Clean Air Act Amendments of 1990,  which United States
industries have not completed implementing.  Moreover, natural gas is abundantly
available in North America,  which makes it a dependable alternative to imported
oil.

        The  electric   industry  is  moving  toward  a  more   competitive
environment as a result of the federal Energy Policy Act of 1992 and initiatives
undertaken by the FERC and others to restructure the electric  industry much the
same as the FERC restructured the gas industry. It is unclear at this point what
impact this restructuring will have on the natural gas industry.





        The Company  competes on the basis of price,  service,  quality and
reliability,  product  performance  and other factors.  Sources and providers of
energy,  other than those described  under this  "Competition"  heading,  do not
compete with the Company to any significant extent.

Competition:  the Utility Operation
The changes  precipitated  by the FERC's  restructuring  of the gas  industry in
Order No. 636 are redefining the roles of the gas utility industry and the state
regulatory commissions. Competition has arrived for utilities. The PSC issued an
order in 1995 providing for the Utility Operation to be the first gas utility in
New York to implement unbundling of its services pursuant to a 1994 PSC order on
restructuring.  The Utility Operation now offers unbundled  flexible services to
its large commercial and industrial  customers.  This unbundling is an important
step  toward  the  Utility  Operation's  goal  of  opening  its  market  area to
competition   for  all  customers,   including   residential.   Competition  for
large-volume   customers   continues,   with  pipeline  companies   increasingly
attempting  to sell or transport  gas directly to end-users  located  within the
Utility  Operation's  service  territories  (i.e.,  bypass).  The  FERC  remains
unwilling to shield local distribution  companies from such bypass. In addition,
competition  continues with fuel oil  suppliers,  and may increase with electric
utilities making retail energy sales.

        Responding  to those  developments,  the Utility  Operation  is now
better able to compete,  through its unbundled  flexible  services,  in its most
vulnerable  markets (the large commercial and industrial  markets).  The Utility
Operation  continues  to (i)  develop or promote new sources and uses of natural
gas and/or new services, rates and contracts and (ii) emphasize and provide high
quality service to its customers.

Competition:  the Pipeline and Storage Segment
The Pipeline and Storage  segment  competes for market growth in the natural gas
market with other pipeline companies transporting gas in the northeastern United
States and with other companies providing gas storage services. The Pipeline and
Storage  segment has some unique  characteristics  which enhance its competitive
position.  Its  facilities are located  adjacent to Canada and the  northeastern
United States, and provide part of the link between gas-consuming regions of the
northeastern  United  States  and  gas-producing   regions  of  Canada  and  the
southwestern,  southern  and  midwestern  regions  of the  United  States.  This
location  offers  the  opportunity  for  increased  transportation  and  storage
services in the  future.  The  Pipeline  and Storage  segment  will  continue to
evaluate  ways to take  advantage of its location to open new markets and expand
existing ones, especially in the gas storage business.

        There is, however, increased competition to provide services to the
northeastern  market  in the  form of other  proposed  pipeline  expansions  and
proposed storage  projects.  The northeastern  utilities which are currently the
largest  customers  of  transportation  and storage  services  are showing  some
hesitance to enter into new  long-term  transportation  or storage  arrangements
while their state commissions are considering significant restructuring of their
bundled sales services.





Competition:  the Exploration and Production Segment
The  Exploration  and  Production  segment  competes  with  other  gas  and  oil
producers,  and with fuel oil and electricity  wholesalers  and producers,  with
respect to its sales of oil and gas. The Exploration and Production segment also
competes with other oil and gas exploration and production  companies of various
sizes for leases and drilling rights for exploration and development prospects.

        To compete in this  environment,  the  Exploration  and  Production
segment  originates  and acts as operator on most  prospects,  minimizes risk of
exploratory efforts through  partnership-type  arrangements,  applies the latest
technology for both exploratory  studies and drilling  operations and focuses on
market niches that suit its size, operating expertise and financial criteria.

Competition:  Other Nonregulated Operations
In the Other Nonregulated operations,  NFR competes with other gas marketers and
energy management services providers.  Leidy competes with other natural gas hub
service  providers.  Highland  competes  with  other  sawmills  in  northwestern
Pennsylvania.  Horizon  competes with other entities  seeking to develop foreign
and domestic energy projects.

Seasonality

Variations  in  weather  conditions  can  materially  affect  the  volume of gas
delivered by the Utility  Operation,  as virtually  all of its  residential  and
commercial  customers  use gas for space  heating, which makes throughput, forheating.  The  effect  on the  most part, 
weather-sensitive.  In Distribution Corporation'sUtility
Operation in New York jurisdiction, it 
was 3.6% colder than the prior year and 3.9% colder than normal, based upon 
the number of Degree Days for the year.  In Distribution Corporation's 
Pennsylvania jurisdiction, it was 9.6% colder than the prior year and 8.4% 
colder than normal, based upon the number of Degree Days for the year.

      Weather that was colder than the prior year contributed to a 5 Bcf 
increase in retail sales in 1994.  Although industrial volumes sold remained 
level when compared with the prior year, they reflected a 2.5 Bcf switch from 
sales to transportation service, offset by increased gas sales to a new 
cogeneration customer.

      The impact that major weather variances have on revenues and margins is temperedmitigated  somewhat by a weather  normalization  clause
that the PSC has authorized in 
Distribution Corporation's New York retail jurisdiction.  This WNCwhich is designed to adjust the rates of retail  customers to reflect the impact
of deviations  from normal  weather.  Weather that is more than 2.2% warmer than
normal results in a surcharge  being added to customers'  current  bills,  while
weather  that is more than 2.2%  colder than  normal  results in a refund  being
credited to customers' current bills.

        In 1994, the WNC was in effect for the period 
from October 1993 through May 1994.  During this time, there were periods of 
both warmer than normal and colder than normal weather.  Overall, the WNC 
resulted in a net reduction to customer bills of approximately $5.8 million in 
1994.

      Distribution Corporation requested a WNC in the Pennsylvania rate 
jurisdiction in its March 8, 1994 rate case filing.  However, the PaPUC denied 
Distribution Corporation's request.  This decision continues to subject 
Distribution Corporation's operating results to the impact of major weather 
variances.

      Distribution Corporation offers large commercial and industrial 
customers transportation services and flexible rate designs.  Transportation 
service, which allows end-users to purchase gas directly from a producer or 
marketer and transport it through the System's pipeline network, provides the 

ITEM 1.  BUSINESS (Continued)


customer with various options in buying gas and transportation services, thus 
providing the opportunity for cost savings to the customer.  In 1994, 52.2 Bcf 
of gas were transported to such customers of Distribution Corporation, a 7% 
increase over the 48.9 Bcf transported in 1993.  Transportation volumes 
represented 30% of the Utility segment's total throughput  in 1994 and 29% in 
1993.

      The volume of gas transported by this segment increased 3.3 Bcf in 1994 
mainly because of industrial and commercial boiler fuel sales customers 
switching to transportation service, which amounted to approximately 2.9 Bcf.  
In addition, transportation volumes increased by approximately 2 Bcf for 
large- and small-volume industrial customers.  Partly offsetting these 
increases was a decline in transportation in the Pennsylvania jurisdiction of 
approximately 0.8 Bcf because of the shut down of three industrial customers 
and a decline of approximately 0.8 Bcf because of the bypass of the Company's 
pipeline system in favor of local producer gas service.  Rates that became 
effective in December 1994, in the Pennsylvania rate jurisdiction, compensate 
for the loss of throughput related to these customers.

      Distribution Corporation has a supplemental service rate in New York and 
a bypass rate in Pennsylvania which are intended to induce customers not to 
bypass the System.  These rates are designed to recover Distribution 
Corporation's cost of providing back-up service to customers utilizing an 
alternative gas supply.  In addition, Distribution Corporation has a flexible 
transportation tariff in Pennsylvania and New York, which allows it to 
negotiate a competitive rate to encourage customers to stay on the System.  

      The unbundling of services under the FERC's Order 636 has required 
transportation customers to incur storage service costs for use of storage 
facilities.  These costs were previously bundled and charged only to sales 
customers.  As a means of providing options to its customers, Distribution 
Corporation offers a Daily Metered Transportation rate in Pennsylvania.  
Customers using this rate would only incur storage charges for storage service 
utilized, as determined through a daily metering process, thus increasing the 
importance of each customer's management of its gas needs.  Distribution 
Corporation has proposed a similar rate in its New York jurisdiction rate case 
filed in October 1994.

      Through open dialogue with customers, utilization of the various rates 
discussed above and Distribution Corporation's in-house gas acquisition 
expertise which industrial customers and other end-users may not have, 
Distribution Corporation has been able to mitigate bypass of the System.

      Distribution Corporation also offers competitive boiler fuel rates to 
large commercial and industrial customers in its New York rate jurisdiction.  
These rates allow Distribution Corporation to adjust rates monthly to compete 
against suppliers of No. 6 oil and other boiler fuels.

ITEM 1.  BUSINESS (Continued)
 

      If boiler fuel and supplemental service rates in New York, the bypass 
rate in Pennsylvania and flexible transportation rates in both jurisdictions 
were not available, Distribution Corporation could become vulnerable to losses 
in throughput since natural gas is, in many cases, directly replaceable by    
No. 6 oil in industrial boilers, or can be obtained through bypass of the 
System.

      Distribution Corporation also offers rates in both its New York and 
Pennsylvania jurisdictions that provide competitive gas prices encouraging new 
technologies, such as the installation of small-packaged cogeneration and 
gas-fired cooling and dehumidification systems that utilize gas on an all-year 
or summerload basis.

      The System continues to encourage the development of the natural gas 
vehicle market.  The System operates over 400 NGVs along with four 
public-access refueling stations.  A fifth public-access station is scheduled 
to open in 1995.

      Distribution Corporation is not currently subject to any material 
restrictions upon the connection or service of new residential, commercial and 
industrial customers in its service territory.  However, because of the high 
natural gas saturation and the maturity of Distribution Corporation's service 
territory, its focus will be on retaining existing customers through rate 
design initiatives and, in the longer term, through the development and 
marketing of new natural gas utilization technologies.

Gas Supply 

      One of the major effects of restructuring of the natural gas industry 
under the FERC's Order 636 was the transfer of responsibility for acquiring 
gas supply from pipeline companies to natural gas utility companies.  This 
transfer of responsibility also carried with it the transfer to utility 
companies of the risks related to the purchasing of adequate and reliable gas 
supplies, transportation arrangements and storage arrangements.  In addition, 
the role of the state public utility commissions in monitoring the prudency of 
purchasing practices of the utility has become more significant.

      As a result of Supply Corporation's restructuring, which became 
effective August 1, 1993, gas supplies for the System are now obtained by 
Distribution Corporation in essentially the same manner operationally, as they 
were in recent years by Supply Corporation.

      Distribution Corporation's basic gas acquisition objective is to obtain 
reliable, diversified, long-term sources of gas supply at competitive prices 
and to maintain appropriate levels of pipeline and storage capacity to 
transport and store its gas supply.

      As a result of Order 636 restructuring, Distribution Corporation was 
provided a share of pipeline and storage capacity on Supply Corporation and on 
the upstream pipeline companies formerly serving Supply Corporation.  
Distribution Corporation has entered into contracts for the necessary capacity 
on Supply Corporation and on these upstream pipeline companies, to meet the 
requirements of its firm sales customers.

ITEM 1.  BUSINESS (Continued)


      Distribution Corporation has firm transportation capacity from Supply 
Corporation and the following pipeline companies:  Tennessee Gas Pipeline 
Company, Texas Eastern Transmission Corporation, Transcontinental Gas Pipe 
Line Corporation, CNG Transmission Corporation (CNG) and Columbia Gas 
Transmission Corporation (Columbia).  Total contracted capacity on these 
pipelines, in the aggregate, is approximately  155,916 MMcf annually.  

      Distribution Corporation has contracted storage capacity of 25.3 Bcf 
from Supply Corporation as well as contracted storage capacity, in the 
aggregate of 4.6 Bcf, from CNG and Columbia.  At September 30, 1994, 
Distribution Corporation had 28.0 Bcf of gas in storage.

      Pipeline companies' transportation and storage rates have been designed 
on a SFV basis, as mandated by Order 636.  This rate design allows pipeline 
companies to recover all of their fixed costs through a demand or reservation 
charge.  Thus, Distribution Corporation pays nearly all costs of its 
contracted pipeline transportation and storage through a demand charge.  
Distribution Corporation maintains its current level of firm capacity so it 
can continue to provide reliable service to its firm sales customers during 
peak winter months.  Distribution Corporation must pay to reserve capacity 
year round even though the demand of the firm customers significantly 
decreases during the summer months.  Distribution Corporation has reduced a 
small amount of its fixed costs by releasing unused capacity during off-peak 
periods and will continue to utilize capacity release programs.

      In order to provide gas service to its customers and fill the pipeline 
capacity obtained in the Order 636 unbundling process, Distribution 
Corporation was assigned Supply Corporation's pre-Order 636 gas purchase 
agreements and has since entered into its own gas purchase agreements.  
Currently, approximately 92% of Distribution Corporation's daily winter 
capacity on upstream pipelines is supported by long-term gas supply contracts, 
primarily with Southwest producers.  Distribution Corporation's firm gas 
supply portfolio is comprised of contracts, having an average six-year term, 
which supply gas from a variety of production areas and suppliers.  Many of 
Distribution Corporation's long-term supply contracts are adjusted to reflect 
the seasonal variations in customer demand, thereby decreasing costs.  Spot 
gas continues to be utilized when short-term gas supplies are plentiful and 
when it is economical to do so.  During off-peak periods, Distribution 
Corporation is able to make off-system sales when supplies are not needed to 
provide service to its firm sales customers.

      While Distribution Corporation's purchases of Appalachian produced gas 
has continued to decline, gas received from local producers and transported by 
Supply Corporation and Distribution Corporation for large industrial 
end-users, remains an important source of gas supply for these end-users.

      For additional details on sources of gas supply, see the "Sources of Gas 
Supply  - Regulated Operations" on page 13 of this report.


ITEM 1.  BUSINESS (Continued)


      Based on information currently available to the Company, Systemwide gas 
supply remains sufficient to meet anticipated demand.

      In 1994, Distribution Corporation's average cost of purchased gas, 
including the cost of transportation and storage, was $3.74 per Mcf, a 
decrease of 3% from Distribution Corporation's average cost of $3.84 per Mcf 
in 1993.  Regulation of gas prices at the wellhead is virtually nonexistent, 
and therefore, the market primarily dictates gas supply and gas prices.

      The total quantity of gas purchased by Distribution Corporation in 1994 
was 145.9 Bcf, compared with 131.5 Bcf purchased by Distribution Corporation 
and Supply Corporation (net of intersegment purchases) in 1993, an increase of 
14.4 Bcf or 11%.

      The 14.4 Bcf increase in purchases was the result of the following 
(refer to "Selected Statistics of the System's Regulated Operations" on page 
16 of this report):  (1) Net injections into storage in 1994 were 4.3 Bcf 
compared with net withdrawals from storage in 1993 of 3.0 Bcf.  This accounts 
for a 7.3 Bcf increase in the amount of gas required to be purchased in 1994.  
(2) Gas used in operations, shrinkage and other increased 8.5 Bcf in 1994.  
Shrinkage represents a percentage of gas retained by pipeline companies for 
purposes such as fueling their compressors.  Purchases reported by the System 
are gross amounts (i.e., prior to shrinkage).  The amount of shrinkage is 
dependent upon where title to such gas is taken.  The System has experienced a 
steady increase in the past several years in the amount of gas it has taken 
title to in the Southwest.  In 1994, Distribution Corporation took title to 
approximately 95% of its gas purchases in the Southwest.  Thus, amounts 
required to be purchased by Distribution Corporation were higher than amounts 
available for sale to Distribution Corporation's customers.  (3) A 5.1 Bcf 
increase in Distribution Corporation's retail sales required increased 
purchases in 1994.  (4) Elimination of Supply Corporation nonaffiliated 
wholesale sales under Order 636 restructuring, which amounted to 6.5 Bcf in 
1993, resulted in decreased purchases in 1994.

      Total System throughput increased 34.4 Bcf or 13% to 307.3 Bcf in 1994, 
from 272.9 Bcf in 1993.  This increase is mainly attributable to higher 
volumes of gas transported through Supply Corporation's Canadian gas 
transportation facilities and higher retail sales by Distribution Corporation 
which were up primarily because of colder weather and increased gas sales to a 
new cogeneration customer.

      The following table, "Sources of Gas Supply - Regulated Operations", 
sets forth the sources and quantities of gas purchases over the past three 
years.  (System throughput volumes are contained in the table on page 16.)


ITEM 1.  BUSINESS (Continued)


                              Sources of Gas Supply - Regulated Operations   

                                 Annual
                                Contract              Volumes Delivered-MMcf
                               Volumes in            Year Ended September 30,
                                  MMcf    (1)        1994       1993     1992

Producers and Marketers:

    Long-Term Contracts           124,471 (2)      107,487   60,664    28,819

    Appalachian                     4,595 (3)        4,595    7,366    11,883

    Affiliated Production           2,474 (4)        2,474    4,265     5,067

Spot Market                             - (5)       31,319   52,785    86,142

Interstate Pipelines                    - (6)            -    6,434     2,298


  Total Gas Supply - Regulated
   Operations                     131,540          145,875   131,514  134,209

(1)   This column reflects annual volumes under currently existing contracts.  
      Thermally-expressed annual contract quantities have been converted to 
      their volumetric equivalent on a nominal 1,000 Btu per cubic foot basis.

(2)   The producers and marketers from which Distribution Corporation 
      purchases gas pursuant to long-term supply contracts (contracts with a 
      term of two years or longer, the average length of Distribution 
      Corporation's contracts being six years) are:  Chevron U.S.A., Coastal 
      Gas Marketing, Enron Gas Marketing, Inc., Enron Excess Corporation, 
      Exxon Company U.S.A., Meridian Oil Trading, Inc., MidCon Gas Services, 
      Corp., Mobil Natural Gas, Inc., Natural Gas Clearinghouse, Shell Oil 
      Company, et al., Tejas Power Company, Texaco Gas Marketing, Transco 
      Energy Marketing Company and Vastar Gas Marketing, Inc. (formerly Arco 
      Natural Gas Marketing, Inc.).  In addition, the amounts include Canadian 
      gas under contract with Boundary Gas, Inc. and ANE Gas Marketing.

(3)   The annual contract volume represents 1994 purchases from independent 
      producers in the Appalachian region.  The independent producer contracts 
      generally continue until the reserves dedicated to them are economically 
      depleted.  The annual contract volumes applicable to these contracts 
      vary as a function of the deliverability of the wells committed to them.  
      The vast majority of this production is long-term dedicated supply.

(4)   The annual contract volume represents supply from the System's own 
      production in the Appalachian region.  Volumes decreased significantly 
      in 1994, as the System's own production is being sold to various 
      end-users. 

(5)   No annual contract volume is shown here as, generally, spot contracts 
      are very short-term.

ITEM 1.  BUSINESS (Continued)


(6)   No contract volumes are shown here as interstate pipeline companies have 
      terminated their merchant function under the FERC's Order 636.  
      Distribution Corporation has contracts with interstate pipeline 
      companies for pipeline capacity to transport gas purchased under direct 
      contracts.

      For a discussion of Distribution Corporation's obligations under its 
nonaffiliated pipeline capacity, gas purchase and gas storage contracts, see 
Note G - "Commitments and Contingencies," on pages 77 to 79 of this report.

PIPELINE AND STORAGE

      The System's Pipeline and Storage operations are conducted by Supply 
Corporation.  In 1994, these operations accounted for approximately 36% of 
System operating income before income taxes.  Information regarding the 
results of operations for the Pipeline and Storage operations can be found in 
"Management's Discussion and Analysis of Financial Condition and Results of 
Operations" on pages 33 to 51 of this report.

Pipeline Capacity and Transportation

      Supply Corporation currently has service agreements for substantially 
all of its pipeline capacity, which approximates 1,860 MMcf per day.  
Distribution Corporation has contracted for approximately  1,120 MMcf per day 
or 60% of this capacity.

      Effective with Supply Corporation's restructuring under Order 636, most 
of its upstream pipeline contracts have been assigned to its former sales 
customers.  Currently, there is a small amount of unallocated capacity on 
three upstream pipelines related to capacity which was not accepted by certain 
customers.  The reservation charges related to the unallocated capacity are 
considered stranded transportation costs, a category of Order 636 transition 
costs.  Supply Corporation is recovering these amounts from its customers 
pursuant to FERC authorization.

      Supply Corporation's transportation throughput in 1994 was 295.3 Bcf 
compared with 138.6 Bcf in 1993.  The increase in 1994 is primarily the result 
of unbundling of services under Order 636 under which Supply Corporation's 
former sales customers became transportation customers.  Also, throughput 
increased as a result of weather that was colder than the prior year, 
increased utilization of Supply Corporation's Canadian gas transportation 
facilities and the expanded capacity of these facilities.

      For a discussion of the impact of the Clean Air Act Amendments of 1990 
on Supply Corporation's compressor stations, see Note G - "Commitments and 
Contingencies," on pages 77 to 79 of this report.

Underground Storage

      To facilitate operational efficiencies, all of the System's natural gas 
storage services were consolidated into Supply Corporation through the July 1, 
1994 merger of Penn-York into Supply Corporation.  Supply Corporation owns and 

ITEM 1.  BUSINESS (Continued)


operates 30 underground storage fields in its operating area.  Four additional 
underground storage fields are operated jointly with certain major interstate 
pipeline companies.  All of these fields are former gas-producing reservoirs 
and are operated under FERC certification.

      Supply Corporation has available Working Gas capacity of approximately 
69.9 Bcf.  Of this amount, approximately 7 Bcf has been retained by Supply 
Corporation in order to render no notice transportation service and meet other 
delivery obligations.  Of the remaining available Working Gas capacity of 
approximately 62.9 Bcf, Distribution Corporation has contracted for 25.3 Bcf 
and nonaffiliated customers have contracted for 35.6 Bcf.

      The primary terms of current storage service agreements representing 
23.3 Bcf of the amount contracted for by nonaffiliated customers expire on 
March 31, 1995.  Service continues year-to-year and can be terminated upon one 
years notice.  None of these customers have elected to terminate service nor 
extend their term for ten years as provided under a settlement of a previous 
Penn-York rate case.

      Supply Corporation's proposed Laurel Fields Storage Project is a 19 Bcf 
underground natural gas storage development project.  Filings with the FERC 
were made in June 1994 to implement this project.  An "open season" was held 
in August 1994 to identify prospective customers for this project with whom 
agreements are currently being negotiated.  On November 4, 1994, a proposal 
was sent to the FERC to divide the project into two phases.  Phase I would 
encompass the expansion of the Limestone storage field to accommodate 
approximately 7 Bcf of storage and phase II would consist of the development 
of the Callen Run storage field, a depleted gas production field.  The 
estimated cost of both phases of this project, including related transmission 
facilities, is approximately $200 million.  Timing of the project has not been 
finalized.

      The Company believes that underground storage will have enhanced 
economic value in the post-Order 636 environment.  Furthermore, the growing 
demand for natural gas for home heating in the Northeast and on the East Coast 
creates a demand for peak period gas supplies, which may require additional 
storage service.  Supply Corporation's storage fields are strategically 
located between Southwest and Canadian gas supplies and the growing demand for 
natural gas in the Northeast and East Coast areas.

      The magnitude of future expansion in the System's Regulated Operations 
depends, to a large degree, upon market conditions coupled with adequate rate 
relief.


ITEM 1.  BUSINESS (Continued)
           SELECTED STATISTICS OF THE SYSTEM'S REGULATED OPERATIONS
              (Intra-System Sales Eliminated Where Appropriate)

                                         Year Ended September 30,               
                                 1994     1993      1992      1991      1990
GAS AVAILABLE FOR SALE (MMcf):
Natural Gas Purchased-
  Producers and Marketers      112,082    68,030    40,702   37,078    20,387
  Spot Market Purchases         31,319    52,785    86,142   90,822    93,961
  Interstate Pipelines               -     6,434     2,298    3,103    22,377
                               143,401   127,249   129,142  131,003   136,725

Natural Gas Produced             2,474     4,265     5,067    5,088     4,823

  Total Gas Supply             145,875   131,514   134,209  136,091   141,548
Gas Withdrawn from (delivered
 to) Storage - Net              (4,306)    2,992    (2,449)  (5,671)    2,320
Used in Operations, Shrinkage
 and Other                     (17,535)   (8,986)   (3,665)  (2,446)  (1,705)
  Total Gas Available for Sale 124,034   125,520   128,095  127,974   142,163

SYSTEM THROUGHPUT (MMcf):
Retail Sales -
    Residential                 90,565    86,854    84,762   79,299    85,761
    Commercial                  26,937    25,598    25,909   25,634    28,646
    Industrial                   6,532     6,528     9,131    9,893    10,872
Wholesale Sales                      -     6,540     8,293   13,148    16,884
  Total Gas Sales              124,034   125,520   128,095  127,974   142,163
Transportation                 183,255   147,357   172,505  128,731   101,512
  Total System Throughput      307,289   272,877   300,600  256,705   243,675

GAS OPERATING REVENUES INCLUDING TRANSPORTATION
 (Thousands of Dollars):
Retail -
    Residential               $677,068  $613,039  $533,908 $494,332  $517,026
    Commercial                 177,249   156,851   139,662  135,718   150,637
    Industrial                  31,096    31,609    35,985   38,395    45,707
Wholesale                        6,930*   27,451    30,150   43,917    47,773
  Total Gas Operating Revenues 892,343   828,950   739,705  712,362   761,143
Transportation                  68,695    64,641    61,204   42,308    35,192
  Total Gas Operating Revenues
    Including Transportation  $961,038  $893,591  $800,909 $754,670  $796,335

AVERAGE NUMBER OF UTILITY
 CUSTOMERS:
Retail -
    Residential                680,043   676,876   672,877  668,240   663,697
    Commercial                  46,518    46,344    46,051   45,292    44,859
    Industrial                   1,181     1,188     1,201    1,202     1,207
Transportation                   1,306     1,293     1,088      957       750
                               729,048   725,701   721,217  715,691   710,513

   *  1994 wholesale revenues represent revenues from Distribution 
      Corporation's off-system sales.

ITEM 1.  BUSINESS (Continued)


EXPLORATION AND PRODUCTION

      The System's Exploration and Production operations are carried out by 
Seneca.  Seneca is engaged in the exploration for, and the development of, 
natural gas and oil reserves in the Gulf Coast of Texas and Louisiana, in 
California, and in the Appalachian region of the United States.

      To facilitate operational efficiencies, all of the System's exploration 
and production operations were consolidated into Seneca through the July 1, 
1994 merger of Empire into Seneca.  Supply Corporation's exploration and 
production activities were transferred to Empire, effective January 1, 1994.

      Exploration and production activities in 1994 accounted for 
approximately 13% of System operating income before income taxes.  Information 
regarding the results of operations for the Exploration and Production 
operations can be found in "Management's Discussion and Analysis of Financial 
Condition and Results of Operations" on pages 33 to 51 of this report.

Gulf Coast/West Coast Exploration and Production

      Seneca's Gulf Coast activities in 1994 were directed toward continued 
offshore exploration for natural gas in the Gulf of Mexico and drilling of 
horizontal wells for gas production in the Austin Chalk formation in Seneca's 
Northeast Clay field in central Texas.

      The offshore exploration program uses advanced computer and seismic 
technology in an attempt to identify low risk gas prospects which can be 
drilled and placed in production in less than one year.  As of September 30, 
1994, Seneca had acquired and evaluated new offshore seismic data covering an 
area of over 45,000 square miles.  In 1994, Seneca drilled six gas wells in 
the Gulf of Mexico, five of which were successful.  The most significant 
discovery was in West Cameron Block 552 where one gas well was drilled in 1994.

      Seneca has continued to achieve its goal of placing new wells in 
production within one year.  Two of the five successful wells in the Gulf of 
Mexico were in production by September 30, 1994.  The other three wells are 
expected to be in production by March 31, 1995.  Future offshore activity 
should continue to be strong with Seneca's acquisition of three blocks in the 
Federal Lease Sale and acquisition of one block through a farm out.  These 
acquisitions have increased Seneca's inventory of offshore prospects to 
eleven, some of which will be evaluated in 1995.

      In addition, Seneca actively pursued identifying and drilling gas 
reserves in the tight Austin Chalk formation in its Northeast Clay Field in 
central Texas.  In 1994, Seneca drilled or participated in five horizontal 
wells, all of which were successful.  The scope of Seneca's horizontal 
drilling is expected to expand in 1995. Seneca has acquired nearly 4,000 acres 
and 6,000 acres to the west and east of the Northeast Clay Field, 
respectively.  Plans are to begin development of this acreage in 1995.

ITEM 1.  BUSINESS (Continued)


      As a result of this activity in the Gulf Coast Region, 93.4 Bcf of gas 
reserves and 1.1 million barrels of oil reserves were added in 1994.

      Reserves related to the Gulf Coast Region at September 30, 1994 amounted 
to 3.8 million barrels of oil and 153.2 Bcf of gas, or approximately 22% and 
62% of Seneca's total oil and gas reserves, respectively.  This represents a 
decrease of approximately 0.3 million barrels of oil and an increase of 73.7 
Bcf of gas compared with September 30, 1993.

      Seneca's California activities in 1994 were concentrated primarily on 
cost control and improving production in the Sespe and Silverthread Fields in 
Ventura, California while continuing development drilling in the new Temescal 
Field.  In 1994, Seneca drilled one additional successful well in the Temescal 
Field.

      Reserves related to Seneca's California operations at September 30, 
1994, amounted to 13.5 million barrels of oil and 32.0 Bcf of gas, or 
approximately  77% and 13% of Seneca's total oil and gas reserves, 
respectively.  This is a decrease of 0.7 million barrels in oil reserves and 
2.4 Bcf of gas compared with September 30, 1993.

      During 1994, Seneca's combined Gulf Coast and California operations 
produced 1.0 million barrels of oil and 17.0 Bcf of gas compared to 0.8 
million barrels of oil and 13.2 Bcf of gas produced in 1993.  This represents 
an increase of 25% in oil production and 29% in gas production.  In 1994, oil 
and gas sales were made to marketers and refiners under long-term agreements, 
which contain flexible pricing provisions.

Appalachian Exploration and Production

      Most of the gas production Seneca owns in the Appalachian region, is 
transported to end-users by the System.  A percentage of the production from 
these wells is dedicated to the System's Regulated Operations' gas supply.  
Seneca's drilling programs in this region depend, to a large degree, on gas 
prices.  In 1994, Seneca drilled or participated in drilling 8 net gas wells, 
of which 5 were completed as producers and 3 were plugged and abandoned as dry 
holes.  Approximately 0.7 Bcf of gas was discovered as a result of these 
efforts.  This is compared with 1993's drilling program of 18 net wells, of 
which 11 were completed as producers, and 1.1 Bcf of gas discovered.

      In 1994, Seneca's gas production from its Appalachian wells amounted to 
6.3  Bcf compared with 6.6 Bcf in 1993.  At September 30, 1994, Seneca had 
1,998 net productive wells in the Appalachian Region.  Seneca's gas reserves 
at September 30, 1994, located in this region amounted to 62.3 Bcf, or 
approximately 25% of Seneca's total gas reserves.  This represents an increase 
in gas reserves of 1.0 Bcf compared with 1993, as current year discoveries 
from drilling activities, revisions of previous estimates and acquisitions of 
reserves in place more than offset current year production.  Seneca's 
Appalachian oil production and oil reserves are not significant.

ITEM 1.  BUSINESS (Continued)


Oil and Gas Prices

      During 1994, the System's weighted average oil price at the wellhead was 
$14.86 per barrel, a decrease of $1.92 per barrel, or 11%, from 1993.  The 
System's weighted average gas price at the wellhead was $2.18 per Mcf, a 
decrease of $.02 per Mcf, or 1%, from 1993.  Nonetheless, efforts to stabilize 
prices through hedging activities contributed approximately $1.6 million of 
operating revenues for the year.  See further discussion of hedging activities 
in Note A - Summary of Significant Accounting Policies on pages 58 to 62 of 
this report.

      At September 30, 1994, Seneca did not experience an impairment of its 
oil and gas assets under the SEC full cost accounting rules.  Wellhead price 
declines in the future, if material, could have a negative impact on Seneca's 
oil and gas assets.

OTHER NONREGULATED

      The Systems's Other Nonregulated operations are carried out primarily by 
NFR, UCI, Highland and Leidy Hub, which are engaged in natural gas marketing 
and brokerage operations and energy management services; pipeline construction 
operations; sawmill and dry kiln operations; and natural gas market hub 
activities, respectively.  Other Nonregulated operations also include the 
marketing of timber.  In 1994, these operations accounted for 1% of System 
operating income before income taxes.  Corporate operations reduced System 
operating income before income taxes by 2%.  Information regarding the results 
of operations for the Other Nonregulated operations can be found in 
"Management's Discussion and Analysis of Financial Condition and Results of 
Operations" on pages 33 to 51 of this report.

      In 1994, Leidy Hub received SEC approval to enter into a partnership 
with a subsidiary of Natural Gas Clearinghouse (Clearinghouse) to develop a 
market area hub in north central Pennsylvania, where, in order to manage their 
gas supply, customers such as pipelines, marketers and utilities can store or 
borrow gas short-term, move gas from one pipeline to another, and buy or sell 
gas.  The partnership became effective September 1, 1994. Leidy Hub has a 50% 
interest in this partnership.

COMPETITION

      The natural gas industry was a competitive one in 1994 and is expected 
to become more competitive in the future.  Competition existed among providers 
of natural gas, as well as between natural gas and other sources of energy.

      Management continues to believe that there will be increased usage of 
natural gas nationwide over the longer-term and, therefore, opportunities 
exist for increased sales, transportation and storage of natural gas, 
primarily on behalf of off-system end-users.  This increased use of natural 
gas nationwide is expected to result mainly from the increased use of natural 
gas as an electric generation and cogeneration fuel, conversion of home 
heating load from oil to gas, economic and population growth and competitive 

ITEM 1.  BUSINESS (Continued)


prices.  Nonetheless, there is currently downward pressure on gas prices due 
to milder than normal weather and increased supply because of the continued 
growth of Canadian imports and increasing domestic supplies attributable to 
more efficient exploration and production technology.  While seasonal swings 
in gas prices between the heating and nonheating season are expected to 
continue, the longer term trend in natural gas prices is dependent upon the 
balance of demand and supply.  Current estimates of the United States demand 
growth rate range from 1 - 4%, while estimates for increases in available 
supply range from 2 - 5%.

      The continuing deregulation of the gas industry should also enhance the 
competitive position of gas relative to other energy sources by removing some 
of the regulatory impediments to adding customers and responding to market 
forces.  In addition, the environmental advantages of natural gas compared 
with other fuels should increase the role of natural gas as an energy source.  
The potential environmental role of natural gas was enhanced by the passage of 
the Clean Air Act in 1990.  Moreover, natural gas, which is abundantly 
available in North America, is a dependable domestic alternative to foreign 
oil.

      The electric utility industry is moving toward a more competitive 
environment as a result of the Energy Policy Act of 1992 and actions of 
various regulatory commissions.  It is unclear at this point what impact this 
restructuring will have on the natural gas industry.

      System companies compete on the basis of price, service, quality and 
reliability, product performance and other factors.

Utility Operations

      The changes precipitated by the FERC's Order 636 are redefining the 
roles of the utility industry and the state regulatory commissions.  
Competition has arrived for utilities, and it is anticipated that, similar to 
what was done in the pipeline sector of the natural gas industry, regulators 
will require utilities to unbundle their services.  The anticipated result is 
that utility service will divide into "core" markets consisting of the 
traditional residential and commercial customers, as well as customers taking 
firm transportation service and "non-core" markets consisting of competitive 
commercial and industrial markets.  It is anticipated that competition for the 
"non-core" market will continue from parties desiring to bypass the System by 
selling and/or transporting gas directly to Distribution Corporation's 
industrial and commercial customers.  Furthermore, the FERC, in its recent 
Bypass Policy, appears to be unwilling to shield local distribution companies 
from bypass.  In addition, competition will exist with fuel oil suppliers and 
electric utilities in making retail energy sales.  Distribution will attempt 
to retain, and if possible expand, its most vulnerable markets, such as the 
large industrial market, through favorable rate design, business development 
and related efforts.  Distribution Corporation continues to (a) develop or

ITEM 1.  BUSINESS (Continued)


promote new sources and uses of natural gas and/or new services, rates and 
contracts; (b) purchase gas from lowest cost suppliers consistent with 
operating and long-term gas supply needs; and (c) emphasize and provide high 
quality service to its customers.

Pipeline and Storage Operations

      The Pipeline and Storage segment competes for market growth in the 
natural gas market with other pipeline companies transporting gas in the 
Northeastsegment's  volumes  transported and with other companies providing gas storage service.stored
may vary  materially  depending on weather,  without  materially  affecting  its
earnings.  The  System 
has some unique characteristics which enhance its competitive position.  Its 
service area, which is located adjacent to CanadaPipeline  and  the Northeast United 
States, and partially connects the Northeast with the South, Southwest and 
Midwest, is advantageous for the provision of increased transportation and 
storage service in the future.  The Company will continue to evaluate ways to 
take advantage of its location to open up new markets and expand existing 
ones, especially in the gas storage business.  There will, however, be 
increased competition to provide services due to a number of recent large 
pipeline expansions in the Northeast.  Likewise, new storage projects face 
competition from existing storage facilities and a number of planned storage 
projects which have been announced as a result of Order 636.

Exploration and Production

      The Exploration and Production segment competes with other gas and oil 
producers and with fuel oil and electricity wholesalers and producers.  Seneca 
competes with other oil and gas exploration and production companies of 
various sizes for leases and drilling rights for exploration and development 
prospects, and competes with other producers for markets to sell its 
productionStorage  segment's  rates are based on price and deliverability.

      To competea straight
fixed-variable  rate design  which  allows  recovery of all fixed costs in this environment, Seneca acts as operatorfixed
monthly reservation charges. Variable charges based on most 
prospects, sheds riskvolumes are designed only
to reimburse the variable  costs caused by actual  transportation  or storage of
exploratory efforts through partnerships, applies the 
latest technology for both exploratory studies and drilling operations and 
focuses on market niches that suit its size, operating expertise and financial 
criteria.

Other Nonregulated

      In the Other Nonregulated segment, NFR competes with other gas marketers 
and energy management services providers.  Leidy Hub competes with other gas 
market service providers.  Highland competes with other sawmills in 
northwestern Pennsylvania, and UCI competes with other pipeline construction 
companies in its area of operation.  Sources and providers of energy, other 
than those described above, do not compete with System companies to any 
significant extent.

ITEM 1.  BUSINESS (Continued)


CAPITAL EXPENDITURESgas.

Capital Expenditures

A discussion of capital  expenditures by business  segment is included in "Management's Discussion and Analysis of Financial Condition and Results of 
Operations,Item 7
under the heading "Investing Cash Flow," on pages 33 to 51 of this report.

ENVIRONMENTAL MATTERSsubheading "Capital Expenditures."

Environmental Matters

Supply Corporation iswas engaged in discussions, but not formal proceedings,  with
the New York Department of Environmental  Conservation (NYDEC) concerning the 71
plugged and abandoned gas wells located  within the boundaries of the Bennington
and  Holland,  New York  underground  natural gas storage  fields.  Before 1995,
Supply  Corporation  voluntarily  agreed to re-plug 30replugged  27 wells which were  believed to be
venting small amounts of natural gas to the  atmosphere.  Twenty-sevenIn November  1995, the
NYDEC informed  Supply  Corporation  that it had accepted  Supply  Corporation's
proposed  monitoring  program and would not require the previously  contemplated
replugging of wells unless those wells have been plugged, at a cost of 
approximately $3.1 million, and the other 3 have been found notstarted to be venting 
gas anymore.  There are on-going discussions regarding the NYDEC's 
determination that Supply Corporation should also re-plug 37 plugged and 
abandoned wells which are not venting any naturalvent gas to the atmosphere.

        Re-plugging those additional 37 wells, plus the 3 wells which were formerly 
venting small amounts of gas to the atmosphere, would cost an additional 
amount of approximately $5.1 million.

      For additionalA discussion  of  environmental  matters  involving  the Company seeis
included in Item 8, Note G - "CommitmentH-Commitments and Contingencies" on pages 77 to 79 of this 
report.

MISCELLANEOUSContingencies.





Miscellaneous

The SystemCompany had 3,148 regular2,925  full-time  employees at September 30, 1994,1995, a decrease of
5.4%7% from the 3,3293,148 employed at September 30, 1993.1994.

        Agreements covering employees in collective bargaining units in the 
State of New
York were last  renegotiated  in  calendarOctober  1994 and are  scheduled  to expire in
calendarFebruary 1998. Agreements covering most employees in collective bargaining units
in the Commonwealth of Pennsylvania  were  renegotiated in calendar 1993 and are scheduled to expire
in April  and May 1996.  The  Company  expects  to begin  negotiations  with the
Pennsylvania unions early in calendar 1996.

        System companies haveThe Company has  numerous  county and  municipal  franchises  under
which they useit uses public roads and certain other  rights-of-way  and public property
for  the  location  of  facilities.  System companies haveThe  Company  has  regularly  renewed  such
franchises at expiration and expectexpects no difficulty in continuing to renew them.


ITEM 1.  BUSINESS (Concluded)


EXECUTIVE OFFICERS OF THE COMPANY (1)

                     Age as of                                    Date Elected
      Name            9/30/94           Position                  To Position 

Bernard J. Kennedy      63       Chairman of the Board of
                                 Directors.                     March 21, 1989
                                 Chief Executive Officer.       August 1, 1988
                                 President.                    January 1, 1987
                                 Director.                      March 29, 1978
                                 Executive Vice President
                                 and General Counsel from
                                 1976 to 1986.
                                 Chairman of the Board of
                                 certain subsidiariesOfficers of the Company since August 1988.
                                 President and Chief Executive
                                 Officer of Supply Corporation
                                 and an officer of certain
                                 other subsidiaries of the
                                 Company from prior to 1989
                                 until June 1, 1989.

Philip C. Ackerman      50       Director(1)
Age as of Company Position Date Elected Name 9/30/95 Since 1990 To Position ---- -------- ---------- ----------- Bernard J. Kennedy 64 Chairman of the Board of Directors. March 21, 1989 Chief Executive Officer. August 1, 1988 President. January 1, 1987 Director. March 29, 1978 Chairman of the Board of certain subsidiaries of the Company. August 1, 1988 Philip C. Ackerman 51 Director. March 16, 1994 Senior Vice President. June 1, 1989 President of Distribution Corporation. October 1, 1995 President of Seneca. June 1, 1989 Executive Vice President of Supply Corporation. October 1, 1994 President of Horizon. September 13, 1995 President of certain other of the Company's subsidiaries from prior to 1990. Richard Hare 57 President of Supply Corporation. June 1, 1989 Senior Vice President of Penn-York Energy Corpor- ation until its merger into Supply Corporation on July 1, 1994. June 1, 1989 William J. Hill 65 Director. September 20, 1995 President of Distribution Corporation until October 1, 1995. June 1, 1989 Vice President from July 1, 1980 until June 1, 1989. President of certain of the Company's subsidiaries from prior to 1989. Richard Hare 56 President of Supply Corporation. June 1, 1989 An executive officer of certain of the Company's subsidiaries from prior to 1989. William J. Hill 64 President of Distribution June 1, 1989 Corporation. An executive officer of Distribution Corporation from prior to 1989. (1) The Company has been advised that there are no family relationships among any of the officers listed, and that there is no arrangement or understanding among any one of them and any other persons pursuant to which he was elected as an officer.
ITEM 2.2 PROPERTIES GENERAL INFORMATION ON FACILITIESGeneral Information on Facilities The investment of the SystemCompany in net property, plant and equipment was $1,542,739,000$1,649.2 million at September 30, 1994.1995. Approximately 80%78% of this investment is in the System's Utility Operation and Pipeline and Storage segments, which are primarily located in western New York and western Pennsylvania. The remaining investment in property, plant and equipment is mainly in the Exploration and Production Segment,segment, which is primarily located in the Gulf Coast, southwestern, western and Appalachian regions of the United States. The Utility Operation has the largest net investment in property, plant and equipment, compared with the System'sCompany's other business segments. Most of thisIts net investment representsin its gas distribution network. These properties include 14,592network (including 14,666 miles of pipeline (exclusive of service pipe), whichdistribution pipeline) and its services represent approximately 55%58% and 27%, respectively, of the Utility Operation's net investment of $787,794,000.$822.8 million. The Pipeline and Storage segment represents a net investment of $440,810,000$463.6 million in transmission and storage facilities at September 30, 1994.1995. Transmission pipeline, with a net cost of $132,591,000,$145.1 million, represents 30%31% of this segment's total net investment and includes 2,7862,778 miles of pipeline required to move large volumes of gas throughout the System'sits service area. Storage facilities consist of 34 storage fields, four4 of which are jointly operated with certain pipeline suppliers, and 512511 miles of pipeline. Included in the storage facilities net investment is $80,942,000$85.6 million of base gas. The Pipeline and Storage segment has 31 compressor stations with 72,10073,450 installed compressor horsepower. The Exploration and Production segment had a net investment in properties amounting to $295,419,000$340.0 million at September 30, 1994.1995. Of this amount, Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast regions was $238,175,000,$285.2 million, and Seneca's net investment in oil and gas properties in the Appalachian region aggregated $57,244,000.$54.8 million. During the past five years, the SystemCompany has made significant additions to plant in order to expand and improve transmission and distribution facilities for both retail and wholesaletransportation customers and to augment the reserve base of oil and gas. Net plant has increased $455,276,000,$442.8 million, or 42%37%, since 1989.1990. The System'sRegulated Operation's facilities provided the capacity to meet the System's 1994its 1995 peak day sendout, including transportation service, of 1,9881,847 MMcf, which occurred on January 19, 1994.February 5, 1995. Withdrawals from storage provided approximately 47%45% of the requirements on that day. SystemCompany maps, which are included as Exhibit 99.2in the paper copy of the Company's combined Annual Report to Shareholders/Form 10-K, are narratively described in the Appendix to this report. EXPLORATION AND PRODUCTION ACTIVITIESelectronic filing and are incorporated herein by reference. Exploration and Production Activities The information that follows is disclosed in accordance with SEC regulations, and relates to the System'sCompany's oil and gas producing activities. For a further discussion of oil and gas producing activities, refer to Note K - - "SupplementaryL-Supplementary Information for Oil and Gas Producing Activities," on pages 84 to 88 under Item 8 of this report, and to Exploration and Production on pages 17 to 19 of this report. ITEM 2. PROPERTIES (Continued)Form 10-K. Supply Corporation files Form 2 "Annual Report of Natural Gas Companies" and Form 15 "Annual Report of Gas Supply" with the FERC. The reserve disclosures in these reports were filed as of December 31, 1993, whereas the reserve disclosures1994, and represent reserves related to Supply Corporation's held for future use storage wells. These reserves are appropriately not included in reserves reported in Note K are reported as of September 30, 1994. The gas reserves of Supply Corporation reported as of December 31, 1993, in Forms 2 and 15, were in-house estimates arrived at by qualified Supply Corporation geologists and engineers.L. Seneca is not regulated by the FERC, and thus is not required to file Forms 2 and 15. As discussed in Item 1, Supply Corporation's exploration and production activities were transferred to Empire effective January 1, 1994. Subsequently, on July 1, 1994, Empire was merged into Seneca. Seneca's oil and gas reserves reported in Note KL as of September 30, 1994,1995, were estimated for Senecaby Seneca's qualified geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis, Inc. The following is a summary of certain oil and gas information taken from SystemSeneca's records: Production For the Year Ended September 30 1994 1993 1992 Average sales price per Mcf of gas $ 2.18 $ 2.20 $ 1.97 Average sales price per barrel of oil $14.86 $16.78 $17.11 Average production (lifting) cost per Mcf equivalent of gas and oil produced
For the Year Ended September 30 1995 1994 1993 - ------------------------------- ---- ---- ---- Average Sales Price per Mcf of Gas $ 1.67 $ 2.18 $ 2.20 Average Sales Price per Barrel of Oil $16.16 $14.86 $16.78 Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ .44 $ .45 $ .54 $ .62
Productive Wells At September 30, 1994 Gas Oil Productive Wells - gross 2,153 201 - net 2,013 172
At September 30, 1995 Gas Oil - --------------------- --- --- Productive Wells - gross 2,115 257 - net 1,941 202
Developed Andand Undeveloped Acreage At September 30, 1994 Developed Acreage - gross 568,736 - net 508,753 Undeveloped Acreage - gross 516,743 - net 476,482 ITEM 2. PROPERTIES (Concluded)
At September 30, 1995 - --------------------- Developed Acreage - gross 595,787 - net 520,849 Undeveloped Acreage - gross 624,085 - net 588,431
Drilling Activity Productive Dry For the Year Ended September 30 1994 1993 1992 1994 1993 1992 Net Wells Completed - Exploratory 5 9 5 5 6 5 - Development 7 16 11 1
Productive Dry ------------------ ------------------ For the Year Ended September 30 1995 1994 1993 1995 1994 1993 ---- ---- ---- ---- ---- ---- Net Wells Completed - Exploratory 5 5 9 0 4 6 - Development 6 8 16 0 0 3 3
Present Activities At September 30, 1994 Wells in Process of Drilling - gross 1 - net 1
At September 30, 1995 - --------------------- Wells in Process of Drilling - gross 7 - net 6
There are currently no waterflood projects or pressure maintenance operations of material importance. ITEM 3. LEGAL PROCEEDINGS PARAGON/3 Legal Proceedings Paragon/TGX PROCEEDINGSProceedings A. New York Litigation OnSince November 30, 1984, Distribution Corporation commenced an actionhas been involved in litigation against Paragon Resources, Inc. (Paragon) and TGX Corp. (collectively Paragon/TGX), in the United States District Court for the Western District of New York (the District Court) seeking. Distribution Corporation sought a declaratory judgment concerning the contract effect of a December 20, 1983 PSC order (the Disapproval Order) which, among other things, disapproved a 1974 gas purchase agreement between Distribution Corporation's predecessor in interest, Iroquois Gas Corporation, and Paragon (the Paragon Contract). Paragon/TGX counterclaimed for (i) a declaration that the Disapproval Order did not affect the Paragon Contract in any way, whatsoever, (ii) approximately $4,400,000$4.4 million in respect of take-or-pay claims, and (iii) unquantified amounts in respect of other alleged breaches of the Paragon Contract. Commencing with its payment for production received in September 1984, and continuing through December 1993, when Paragon/TGX purported to assign the Paragon Contract, Distribution Corporation has paid Paragon/TGX for Paragon Contract gas at prices below those developed by the Paragon Contract's price formula, as the same have been impacted, from time to time, by the Natural Gas Policy Act of 1978 (NGPA). On the basis of a Memorandum and Order dated December 10, 1988, the District Court in January 1991 issued a partial summary judgment which declared that, whereas the Disapproval Order abrogated only the Paragon Contract's price term, the legal consequence of such abrogation was to render the Paragon Contract "void and no longer of any force or effect" as of December 20, 1983.1978. On December 3, 1991, the U. S.United States Court of Appeals for the Second Circuit (the Second Circuit) reversed the District Court'sissued an opinion regarding a partial summary judgment and remanded the case togranted by the District Court for further proceedings.Court. The Second Circuit agreed with the District Courtessentially held that the Disapproval Order had "voided the Contract's price term," but did not agree that the Paragon Contract as a whole was "voided by the cancellation of the price term." Rather, the Second Circuit found that Paragon/TGX had elected an option available to it under the Paragon Contract to continue that contract, in the aftermath of the Disapproval Order, at "a price consistent with" that order. The Second Circuit also remanded the case to the District Court for further proceedings. In a letter dated December 13, 1991, TGX demanded that Distribution Corporation pay it $21,874,042$21.9 million (including interest), alleged to represent the difference between the amount received by Paragon/TGX in respect of Paragon Contract gas delivered during the period September 1984 through October 1991, and the amount allegedly due TGX in respect of such gas during such period. Distribution Corporation rejected TGX's demand. By Order entered March 23, 1992, the District Court granted Distribution Corporation permission to amend its reply to Paragon/TGX's counterclaims to allege, among other things, (i) Distribution Corporation's "termination" of the Paragon Contract by letter effective February 1, 1988; (ii) Paragon's pre- September 1984 repudiation of the Paragon Contract; and (iii) the PSC's "primary jurisdiction" to interpret the Disapproval Order as respects "a price consistent" therewith. With respect to (iii) above, Distribution Corporation ITEM 3. LEGAL PROCEEDINGS - (Continued) notes that the New York State Public Service Law provides that no charge for gas made pursuant to a contract with a New York gas utility shall exceed the "just and reasonable charge" for such gas. In response to Distribution Corporation's motion for partial summary judgment in respect of the defense denominated (ii) above, the District Court, in a Memorandum and Order entered July 10, 1992, as revised by a Memorandum and Order entered March 1, 1993, denied Distribution Corporation's summary judgment motion (due to a perceived question of fact as to the occurrence of a condition precedent to Paragon's pre-September 1984 contract repudiation), but confirmed Distribution Corporation's right to assert the repudiation defense upon the trial of the action. On January 4, 1993, the District Court entered a non-final order purportedly responsive to a February 13, 1992 Paragon/TGX motion. The order purports to declare that, by voiding the Paragon Contract price escalation mechanism effective December 31, 1983, the PSC's 1983 Disapproval Order effectively capped the Paragon Contract price, at the lesser, from time to time, of (i) the 1983 Paragon Contract summer/winter "base prices," or (ii) the applicable "Natural Gas Ceiling Prices" set forth in 18 CFR paragraph 271.101 Table I. Under date of January 19, 1993 Distribution Corporation sought rehearing, reargument, reconsideration and clarification of the January 4, 1993 order. On July 12, 1993, the District Court filed a Memorandum and Order granting in part the January 19, 1993 motion. The July 12, 1993 Order stated that, while the January 4, 1993 Memorandum and Order did determine that an obligation on Distribution Corporation's part to pay for gas purchased pursuant to the gas purchase agreement at the applicable NGPA ceiling price arose out of the conduct of the parties after the NGPA became effective and that the Disapproval Order did not relieve Distribution Corporation of such obligation, it did not determine the just and reasonable price for the gas pursuant to Public Service Law section 110(4), set a contract price for the duration of the contract, resolve any defenses presented by Distribution Corporation, determine whether such obligation continues until the present time, or rule on any deregulation issues. Effective January 14, 1994, TGX purportedly effected a partial assignment of its interest under the Paragon Contract to an unaffiliated third-party, with whom Distribution Corporation subsequently negotiated agreements to supersede the terms of the Paragon Contract, prospectively. These transactions did not materially increase (and potentially may have decreased) Distribution Corporation's exposure in the New York Litigation. On September 29, 1994, Paragon/TGX served an amended answer and counterclaim. That pleading restates Paragon/TGX's claims for unquantified money damages respecting Distribution Corporation's alleged (i) breach of contract price and "take-or-pay" provisions, (ii) "lack of good faith...materialfaith . . . material breach" of the contract, and (iii) repudiation of the contract. The pleading also adds two new, but unquantified claims - (i) consequential damages suffered upon the sale of properties and assignment of the Paragon Contract at less than full value, and (ii) damages related to the allegation that Distribution Corporation "tortiously and with intent injured ITEM 3. LEGAL PROCEEDINGS - (Continued) TGX in the conduct of its business." Distribution Corporation filed a timely reply to Paragon/TGX's claims. The parties are awaiting a scheduling orderVarious motions have been heard before the District Court. A United States Magistrate Judge is now handling other preliminary matters and discovery issues before the case is ultimately set for trial. B. State Commission Proceedings In 1992, Distribution Corporation filed two petitions with the PSC that involved the Paragon Contract. Distribution Corporation sought authority from the magistrate regarding discoveryPSC to defer, and the trial of this proceeding. B. Louisiana Litigation On February 22, 1990, TGX, the purported assignee of the Paragon Contract, filed a voluntary petition pursuant to Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Western District of Louisiana (the Bankruptcy Court). Thereafter TGX commenced a "turnover" proceeding against Distribution Corporation, premised upon TGX's December 13, 1991 payment demand described above under "New York Litigation." Pursuant toultimately recover through rates, a partial settlement agreement between TGX andpayment made to TGX. Distribution Corporation approvedalso requested the PSC to review the prices charged by the Bankruptcy Court in August 1992, TGX has withdrawn the "turnover" proceeding and Distribution Corporation has paid to TGX $2,940,000 in consideration of, among other things, TGX's release of Distribution Corporation from the cause of action asserted in the "turnover" proceeding. TGX is still free to pursue its breach of contract counterclaims in the New York Litigation. However, the $2,940,000 paid by Distribution Corporation to TGX will be credited against the amount, if any, which is ultimately adjudged due TGX and/or Paragon in the New York Litigation. C. State Commission Proceedings By its "Order Instituting Proceeding," issued in Case 93-G-0352, et al., and effective April 28, 1993, the PSC granted Distribution Corporation deferral authority in respect of the New York allocable share ($2,006,000) of the partial settlement payment described above under "Louisiana Litigation" and instituted a proceeding designed to address Distribution Corporation's request for recovery authority in respect of that amount. Distribution Corporation received authority to treat the Pennsylvania allocable share ($934,000) of the partial settlement payment as a gas cost experienced during the twelve (12) month period ending November 30, 1992. The PSC proceeding is also expected to address Distribution Corporation's recovery in New York of gas costs incurred in respect of the Paragon Contract during the reconciliation period September 1, 1991 through August 30, 1992. Finally, the PSC proceeding is expected to include the review of the Paragon Contract in lightcontext of the "just and reasonable" standard of Section 110(4) of the New York Public Service Law. Under date of October 25, 1994,Law and issue a declaratory order regarding its findings. The PSC consolidated the Administrativeproceedings, and, in an order issued on May 5, 1995, (i) authorized Distribution Corporation to recover through rates the amounts previously paid to TGX, and (ii) dismissed Distribution Corporation's petition regarding the New York Public Service Law Judge (ALJ) in this proceeding issuedSection 110(4) issues because the PSC determined there was no "properly reviewable contract" that had been filed with it. In September 1995, Distribution Corporation filed a recommended decision (RD). The RD seemingly recommends thatpetition with the maximum price Paragon/TGX should be authorized to receive for gas delivered in respectNew York Supreme Court (Albany County, Special Term) seeking judicial review of the contract should be $3.714 per Mcf. The ALJ noted thatPSC's May 1995 order regarding the dismissal of Distribution Corporation might owe approximately $9.6 million moreCorporation's petition for a declaratory order. ITEM 4 Submission of Matters to Paragon/TGX under this scenario. The ALJ also found that payments previously made by Distribution Corporation were prudent and reasonable. Nonetheless, he recommended that Distribution Corporation be allowed to recover from ratepayers only one-halfa Vote of the $2,006,000 payment referred to ITEM 3 LEGAL PROCEEDINGS - (Concluded) above and one-half of future amounts that might be paid to Paragon/TGX. The ALJ's recommendations are not binding on the PSC or the courts. All parties to the proceedings have taken exception to various portions of the RD. The PSC is expected to issue its decision in this proceeding during 1995. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSSecurity Holders No matter was submitted to a vote of security holders during the fourth quarter of 1994. 1995. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS5 Market for the Registrant's Common Stock and Related Shareholder Matters Information regarding the market for the Registrant's common stock and related shareholder matters appears in Note D - "Capitalization"Capitalization and Note J - "MarketK- Market for Common Stock and Related Shareholder Matters (unaudited)," on pages 67 to 71 and 83, respectively, under Item 8 of this report,Form 10-K, and reference is made thereto. ITEM 6 Selected Financial Data
ITEM 6. SELECTED FINANCIAL DATA Year Ended September 30 1995 1994 1993 1992 1991 1990- ----------------------- ---- ---- ---- ---- ---- SUMMARY OF OPERATIONSSummary of Operations (Thousands) Operating Revenues $975,496 $1,141,324 $1,020,382 $920,450 $865,131 $892,009-------- ---------- ---------- -------- -------- Operating Expenses: Purchased Gas 351,094 497,687 409,005 363,690 364,246 415,052 Operation Expense and Maintenance 292,505 291,390 283,230 263,084 245,253 227,593 Property, Franchise and Other Taxes 91,837 103,788 95,393 89,158 83,095 75,846 Depreciation, Depletion and Amortization 71,782 74,764 69,425 55,726 50,805 43,740 Income Taxes - Net 43,879 47,792 41,046 35,231 23,285 27,480-------- ---------- ---------- -------- -------- 851,097 1,015,421 898,099 806,889 766,684 789,711-------- ---------- ---------- -------- -------- Operating Income 124,399 125,903 122,283 113,561 98,447 102,298 Other Income 5,378 3,656 4,833 5,790 11,793 7,483-------- ---------- ---------- -------- -------- Income Before Interest Charges 129,777 129,559 127,116 119,351 110,240 109,781 Interest Charges 53,883 47,124 51,899 59,041 61,250 57,783-------- ---------- ---------- -------- -------- Income Before Cumulative Effect 75,894 82,435 75,217 60,310 48,990 51,998 Cumulative Effect of Changes in Accounting - 3,237 - - - --------- ---------- ---------- -------- -------- Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217 $ 60,310 $ 48,990 $ 51,998 PER COMMON SHARE DATA======== ========== ========== ======== ======== Per Common Share Data Earnings $2.03 $2.32* $2.15 $1.94 $1.63 $1.83 Dividends Declared $1.60 $1.56 $1.52 $1.48 $1.44 $1.38 Dividends Paid $1.59 $1.55 $1.51 $1.47 $1.43 $1.36 Dividend Rate at Year-End $1.62 $1.58 $1.54 $1.50 $1.46 $1.42 NUMBER OF COMMON SHAREHOLDERS AT YEAR-ENDNumber of Common Shareholders at Year-End 21,429 22,465 22,893 23,218 22,662 22,203 PROPERTY, PLANT AND EQUIPMENT======== ========== ========== ======== ======== Net Property, Plant and Equipment (Thousands) Regulated: Utility Operation $1,036,225 $ 983,417822,764 $ 929,601787,794 $ 871,102754,466 $ 813,736719,755 $ 678,933 Pipeline and Storage 640,124 618,917 594,580 539,904 481,003 1,676,349 1,602,334 1,524,181 1,411,006 1,294,739463,647 443,622 436,547 423,383 380,008 ---------- ---------- ---------- ---------- ---------- 1,286,411 1,231,416 1,191,013 1,143,138 1,058,941 ---------- ---------- ---------- ---------- ---------- Nonregulated: Exploration and Production 464,725 415,642 378,815 353,090 323,132339,950 295,418 273,470 261,446 248,787 Other 24,938 21,237 15,170 8,202 7,196 489,663 436,879 393,985 361,292 330,32822,690 18,579 16,209 11,670 5,896 ---------- ---------- ---------- ---------- ---------- 362,640 313,997 289,679 273,116 254,683 ---------- ---------- ---------- ---------- ---------- Corporate 244 223 223 216 216 Gross Plant 2,166,256 2,039,436 1,918,389 1,772,514 1,625,283 Accumulated Depreciation, Depletion and Amortization 623,517 561,433 502,007 458,763 418,893131 137 122 128 127 ---------- ---------- ---------- ---------- ---------- Total Net Plant $1,542,739 $1,478,003$1,649,182 $1,545,550 $1,480,814 $1,416,382 $1,313,751 $1,206,390 TOTAL ASSETS========== ========== ========== ========== ========== Total Assets (Thousands) $2,038,302 $1,981,657 $1,801,540 $1,760,830 $1,560,834 $1,436,687 CAPITALIZATION========== ========== ========== ========== ========== Capitalization (Thousands) Common Stock Equity $ 800,588 $ 780,288 $ 736,245 $ 632,333 $ 542,109 $ 484,044 Long-Term Debt, Net of Current Portion 474,000 462,500 478,417 479,500 442,071 397,350---------- ---------- ---------- ---------- ---------- Total Capitalization $1,274,588 $1,242,788 $1,214,662 $1,111,833 $ 984,180 $ 881,394 ========== ========== ========== ========== ========== * Includes1994 includes Cumulative Effect of Changes in Accounting of $.09. See Notes A and FG to Consolidated Financial Statements.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For a graph7 Management's Discussion and Analysis of "The Revenue Dollar - 1994" see graph A. in the Appendix to this report.Financial Condition and Results of Operations 1994Results of Operations 1995 Compared with 1993.1994 National Fuel's consolidated earnings were $85.7$75.9 million, or $2.32$2.03 per common share, in 1994.1995. This included $3.2compares with earnings of $82.4 million, or $.09$2.23 per common share related toin 1994 (before the cumulative effect of the mandated changes in accounting for income taxes and post-employment benefits, (as adoptedwhich added a net $3.2 million, or $0.09 per common share of earnings in accordance1994). The earnings decrease in 1995 was attributable to lower earnings of the Company's Exploration and Production segment and Utility Operation, partly offset by higher earnings of the Pipeline and Storage segment, Other Nonregulated, and Corporate operations. Exploration and Production earnings declined because of low gas prices coupled with management's decision, based on those low gas prices, to delay Gulf Coast activity causing reduced levels of gas and oil production. The Utility Operation's earnings suffered from the warm weather and the impact of lower normalized usage per residential and commercial account. Additionally, the Utility Operation's New York jurisdiction annual reconciliation of gas costs, performed in August of each year, determined an amount of lost and unaccounted-for gas in excess of that allowed to be recovered by the Public Service Commission of the State of New York (PSC). The Pipeline and Storage segment earnings reflect the application of a final rule issued by the Federal Energy Regulatory Commission (FERC) in September 1995, which addresses and clarifies financial reporting aspects of the current practices for unbundled pipeline sales and open access transportation. The increase in earnings from the application of this rule was partly offset by higher operating and interest expense as well as the recording of a reserve for previously deferred preliminary survey and investigation charges for the Laurel Fields Storage Project. An open season held during August and September 1995 for nominations for firm storage capacity for this proposed underground natural gas storage development project failed to produce sufficient interest to proceed with the Financial Accounting Standards Board's (FASB) Statementsproject at this time. Accordingly, this project has been delayed until at least 1997. Increased earnings in the Company's Other Nonregulated operations resulted mainly from a gain on the sale of Financial Accounting Standards (SFAS) No. 109equipment, net of accrued expenses, by the Company's pipeline construction subsidiary. This sale pertained to a strategic decision to discontinue the operations of this subsidiary. The Company's gas marketing subsidiary also increased earnings on a year-to-year basis as a result of increased margins and No. 112, respectively). Earnings before thesean increase in customers. In addition, Corporate operations benefited from cost saving measures, including the relocation of corporate headquarters. 1994 Compared with 1993 National Fuel's earnings (before the cumulative effect of the changes in accounting changes amounted tofor income taxes and post-employment benefits, discussed above) were $82.4 million, or $2.23 per common share, in 1994. This represents an approximate 10% increase of approximately 10% over 1993 earnings of $75.2 million. Onmillion and a per-common-share basis, earnings before the accounting changes were $2.23 for 1994, up 4% increase from 1993 earnings per common share of $2.15. Share amounts reflect a greater number of weighted average shares outstanding in the current year,1994, principally because of the sale of 2.5 million shares of common stock in May 1993. Earnings growthThe earnings increase in 1994 was primarily dueattributable to higher earnings in the Company's nonregulated operations.Nonregulated and Utility operations, offset in part by lower earnings in the Pipeline and Storage segment. The increase in the Nonregulated operations consisted of higher earnings in the Exploration and Production segment's successes have continued in 1994, withsegment as a result of record oil and gas production, more than compensating for a decline in oil and gas prices. Earnings from Other Nonregulated operations increased because of the improved performance ofFurthermore, the Company's natural gas marketing, pipeline construction and timber operations. Earnings from the Company's regulated operations in total, increased in 1994.had improved earnings. The Utility Operation's earnings were upincreased slightly over last year because of higher throughput due to colder weather as well as Stateand the impact of rate increases in New York Public Service Commission (PSC) and Pennsylvania Public Utility Commission (PaPUC) authorization to earn a return on increased capital investment. ThePennsylvania. These increases were partly offset by an earnings decrease in the Pipeline and Storage segment's earnings decreased in 1994 compared with 1993,segment, which resulted mainly because of two nonrecurring items in 1993: the settlement of a Supply Corporation rate case which resulted in a partial reduction of a provision for refund due customers; and a change in rate design, effective August 1, 1993, which boostedincreased 1993 earnings.
Operating Revenues Year Ended September 30 (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Utility Operation Retail Revenues: Residential $ 569,603 $ 677,068 $ 613,039 Commercial 137,869 177,249 156,851 Industrial 18,269 31,096 31,609 - ----------------------------------------------------------------------------- 725,741 885,413 801,499 Off-System Sales 18,255 6,930 945 Transportation 37,183 34,419 30,213 Other 4,885 4,911 3,961 - ----------------------------------------------------------------------------- 786,064 931,673 836,618 - ----------------------------------------------------------------------------- Pipeline and Storage Wholesale Revenues - - 444,142 Storage Service 59,826 58,971 41,041 Transportation 88,766 90,416 45,313 Other 15,995 3,734 4,072 - ----------------------------------------------------------------------------- 164,587 153,121 534,568 - ----------------------------------------------------------------------------- Exploration and Production 56,232 70,261 58,636 Other Nonregulated 57,075 72,036 42,099 - ----------------------------------------------------------------------------- 113,307 142,297 100,735 - ----------------------------------------------------------------------------- Less: Intersegment Revenues 88,462 85,767 451,539 - ----------------------------------------------------------------------------- Total Operating Revenues $ 975,496 $1,141,324 $1,020,382 ============================================================================= Operating Income (Loss) Before Income Taxes Year Ended September 30 (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Utility Operation $ 83,774 $ 90,584 $ 86,690 Pipeline and Storage 67,884 62,302 67,375 Exploration and Production 16,404 21,767 12,980 Other Nonregulated 3,021 2,505 (986) Corporate (2,805) (3,463) (2,730) - ----------------------------------------------------------------------------- Total Operating Income Before Income Taxes $168,278 $173,695 $163,329 =============================================================================
System Natural Gas Volumes Year Ended September 30 (in billion cubic feet) 1995 1994 1993 - ------------------------------------------------------------------------- Regulated Gas Sales Residential 79.9 90.6 86.9 Commercial 22.2 26.9 25.6 Industrial 4.8 6.5 6.5 Wholesale * - - 118.7 Off-System 9.4 3.3 0.3 - ------------------------------------------------------------------------- 116.3 127.3 238.0 - ------------------------------------------------------------------------- Nonregulated Gas Sales Gas Sales for Resale 0.4 0.3 - Production (in equivalent billion cubic feet) 25.4 29.5 24.9 - ------------------------------------------------------------------------- 25.8 29.8 24.9 - ------------------------------------------------------------------------- Total Gas Sales 142.1 157.1 262.9 - ------------------------------------------------------------------------- Transportation Utility Operation 52.8 52.2 48.9 Pipeline and Storage * 290.8 296.6 138.6 Nonregulated 2.5 1.4 - - ------------------------------------------------------------------------- 346.1 350.2 187.5 - ------------------------------------------------------------------------- Marketing Volumes 18.8 18.2 7.3 - ------------------------------------------------------------------------- Less Intersegment Volumes: Transportation 154.2 164.8 40.1 Production 5.0 2.5 4.3 Gas Sales - 0.1 112.2 - ------------------------------------------------------------------------- 159.2 167.4 156.6 - ------------------------------------------------------------------------- Total System Natural Gas Volumes 347.8 358.1 301.1 ========================================================================= * The elimination of wholesale volumes, as well as the increase in transportation volumes from 1993 to 1994 reflects Supply Corporation's adoption of FERC Order 636, effective on August 1, 1993.
Utility Operation Operating Revenues 1995 Compared with 1992. Earnings were $75.21994 Operating revenues decreased $145.6 million in 1993, up $14.9 million, or 25%, over 1992 earnings1995 compared with 1994. This decrease reflects the recovery of $60.3 million. Earnings per common share in 1993 were $2.15, an 11% increase from the $1.94 earned in 1992. Share amounts reflect a greater number of weighted average shares outstanding in 1993, principallydecreased gas costs mainly because of lower gas sales of 11.0 billion cubic feet (Bcf) as well as a 15% decline in the saleaverage cost of 2.5 million sharespurchased gas. The decline in residential and commercial gas sales of common stock15.4 Bcf can be attributed mainly to weather in Distribution Corporation's service territory that was, on average, 12.3% warmer than last year. The decline in industrial volumes of 1.7 Bcf reflects lower sales to a cogeneration customer. These declines were partly offset by an increase in off-system gas sales of 6.1 Bcf. Distribution Corporation, in each of May 1993its jurisdictions, has a mechanism whereby it has the opportunity to recover certain costs and September 1992. The earnings increase in 1993 resulted from improvements in both the Pipeline and Storage and Exploration and Production segments' earnings which, in the aggregate, more than offsetretain a decline in the earningsportion of the Utility Operation and the Company's Other Nonregulated operations. New rates, coupled with a change in rate design, were the major reasons for the Pipeline and Storage segment's improved results, while increased natural gas production and higher prices improved the Exploration and Production segment's performance. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Operating Income (Loss) Before Income Taxes Year Ended September 30 (in thousands) 1994 1993 1992 Utility Operation $ 90,584 $ 86,690 $ 90,025 Pipeline and Storage 62,302 67,375 49,796 Exploration and Production 21,767 12,980 7,021 Other Nonregulated 2,505 (986) 4,229 24,272 11,994 11,250 Corporate (3,463) (2,730) (2,279) Total Operating Income Before Income Taxes $173,695 $163,329 $148,792 Operating Revenues Year Ended September 30 (in thousands) 1994 1993 1992 Utility Operation Retail Revenues: Residential $ 677,068 $ 613,039 $533,908 Commercial 177,249 156,851 139,662 Industrial 31,096 31,609 35,985 885,413 801,499 709,555 Off-System Sales 6,930 945 - Transportation 34,419 30,213 27,424 Other 4,911 3,961 3,685 931,673 836,618 740,664 Pipeline and Storage Wholesale Revenues - 444,142 425,931 Storage Service 58,971 41,041 36,064 Transportation 90,416 45,313 33,821 Other 3,734 4,072 3,054 153,121 534,568 498,870 Exploration and Production 70,261 58,636 36,303 Other Nonregulated 72,036 42,099 47,479 142,297 100,735 83,782 Less: Intersegment Revenues 85,767 451,539 402,866 Total Operating Revenues $1,141,324 $1,020,382 $920,450 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) UTILITY OPERATION Operating Revenuesmargin on these off-system sales. 1994 Compared with 1993.1993 Operating revenues increased $95.1 million in 1994 compared with 1993. This increase reflects recovery of increased gas costs mainly due to higher throughput,gas sales, as well as general rate increases in the New York rate jurisdiction effective in both July 1993 and 1994 and in the Pennsylvania rate jurisdiction in December 1993 and higher revenues from off-system sales. Distribution Corporation, in each of its jurisdictions, has a mechanism whereby it has the opportunity to recover certain costsHigher residential and retain a portion of the margin on these off-system sales. Higher retailcommercial sales of 5 billion cubic feet (Bcf)5.0 Bcf resulted primarily from weather in Distribution Corporation's service territory that was, on average, 6.5% colder than lastthe prior year. Operating Income 1995 Compared with 1994 Operating income before income taxes decreased $6.8 million in 1995 compared with 1994. This decrease reflects the lower gas sales, discussed above, coupled with higher operating expenses. Although industrialDistribution Corporation received general rate increases in New York and Pennsylvania in July 1994 and December 1994, respectively, the weather related reduction in volumes sold, remained level when compared with last year, they reflected a 2.5 Bcf switch from sales to transportation service, offset by increased gas sales to a new cogeneration customer. Transportation throughput was up 3.3 Bcf mainly because of the above noted 2.5 Bcf switch, as well as a similar switch from sales to transportation service by commercial customers of .4 Bcf. In addition, there was increased transportation of 2 Bcf to large- and small-volume industrial customers. The shut-down of three industrial customers and the bypass of National Fuel's pipeline system by three customersespecially in the Pennsylvania jurisdiction, partially offsetnegatively impacted margins. In both jurisdictions, lower normalized usage per residential and commercial account than was established in the total increaseratemaking process also contributed to lower pretax operating income. In addition, Distribution Corporation's annual reconciliation of gas costs in its New York jurisdiction, performed in August each year, determined an amount of lost and unaccounted-for gas in excess of that allowed to be recovered by approximately 1.6 Bcf. Rates that go intothe PSC. The Utility Operation recognized an additional $4.3 million of gas cost expense as a result of this reconciliation. The impact of weather on Distribution Corporation's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on pretax operating income and earnings for the New York rate jurisdiction. In 1995, the WNC in DecemberNew York preserved pretax operating income of $8.2 million as weather, overall, was warmer than normal for the period of October 1994 inthrough May 1995. Since the Pennsylvania rate jurisdiction compensate fordoes not have a WNC, uncontrollable weather variations directly impact pretax operating income and earnings. In the loss of throughput related to these customers. 1993 Compared with 1992. Operating revenue increased $96 millionPennsylvania service territory, weather was 14.2% warmer than last year and 5.8% warmer than normal. The warmer weather in 19931995 compared with 1992, although throughput remained relatively unchanged. The flow-through of higher gas costs, as well as rate increases in the New York rate jurisdiction in both July 19921994 had a negative impact on pretax operating income and 1993, and a rate increase inearnings for the Pennsylvania rate jurisdiction effective in December 1991, resulted in increased revenues. Weather-sensitive residential throughput increased 2.1 Bcf as a result of weather that was, on average, 1.9% colder than last year in Distribution Corporation's service territory. Combined industrial and end-user transportation throughput decreased 2.4 Bcf as a result of the bankruptcy of a major customer in Pennsylvania and a decrease in boiler fuel sales. These declines were partially mitigated by a significant increase attributable to a full year's throughput for a cogeneration project that came on line in May 1992. Operating Incomejurisdiction. 1994 Compared with 1993.1993 Operating income before income taxes increased $3.9 million in 1994 compared with 1993. This increase reflects higher revenues, discussed above, partly offset by increased operating expenses. The severe cold weather during January and February 1994 necessitated an unusually high number of system repairs and related site restoration work, which increased maintenance expense. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) The impact of weather on Distribution Corporation's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on pretax operating income and earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits Distribution Corporation's New York customers. In 1994, the WNC in New York resulted in a benefit to customers of $5.8 million. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact pretax operating income and earnings. In the Pennsylvania service territory, weather was 9.6% colder than lastthe prior year and 8.4% colder than normal. The colder weather in 1994 compared with 1993 had a positive impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction. 1993 Compared with 1992. Operating income before income taxes decreased $3.3 million in 1993 compared with 1992. This decline reflects the impact of lower average gas use per residential account in the New York rate jurisdiction compared with that imputed in rates resulting in a lower margin on gas sales which was not adequate to cover the increase in operating expenses. This problem was remedied by reflecting a lower usage per account in Distribution Corporation's rates that went into effect on July 23, 1993, in New York. In 1993, the WNC in New York preserved pretax operating income of $1.2 million and earnings per share of $.02. In the Pennsylvania service territory, weather was 2.5% colder in 1993 than 1992, although it was 5.4% warmer than normal. This colder weather had a positive impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction. Degree Days Percent Colder (Warmer) Than Year Ended September 30 Normal Actual Normal Last Year 1994: Buffalo 6,710 6,975 3.9% 3.6% Erie 6,202 6,726 8.4% 9.6% 1993: Buffalo 6,723 6,730 0.1% 1.3% Erie 6,484 6,135 (5.4%) 2.5% 1992: Buffalo 6,778 6,644 (2.0%) 15.9% Erie 6,556 5,983 (8.7%) 13.1%
Degree Days Percent Colder (Warmer) Than Year Ended September 30 Normal Actual Normal Last Year - ------------------------------------------------------------------------------ 1995: Buffalo 6,693 6,181 (7.6%) (11.4%) Erie 6,128 5,773 (5.8%) (14.2%) - ---------------------------------------------------------------------------- 1994: Buffalo 6,710 6,975 3.9% 3.6% Erie 6,202 6,726 8.4% 9.6% - --------------------------------------------------------------------------- 1993: Buffalo 6,723 6,730 0.1% 1.3% Erie 6,484 6,135 (5.4%) 2.5% - ---------------------------------------------------------------------------
Purchased Gas.Gas The cost of purchased gas is by far the Company's single largest operating expense. Annual variations in purchased gas costs can be attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and five upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers and for storage service with Supply Corporation and two nonaffiliated companies. In addition, Distribution Corporation can satisfy a portion of its gas requirements through spot market purchases. Distribution Corporation's average cost of purchased gas, including the cost of transportation and storage, was $3.74$3.19 per thousand cubic feet (Mcf) in 1994,1995, a decrease of 3%15% from the average cost of $3.84$3.74 per Mcf in 1993.1994. The average cost of purchased gas in 19931994 was 22% higher3% lower than the $3.15$3.84 per Mcf in 1992. System Throughput (billion cubic feet) Year Ended September 30 1994 1993 1992 Utility Operation Retail Sales: Residential 90.6 86.9 84.8 Commercial 26.9 25.6 25.9 Industrial 6.5 6.5 9.1 124.0 119.0 119.8 Transportation- End-Users 52.2 48.9 48.7 176.2 167.9 168.51993. Pipeline and Storage Wholesale SalesOperating Revenues 1995 Compared with 1994 Operating revenues increased $11.5 million in 1995 compared with 1994. The increase reflects the application of a final rule issued by the FERC in September 1995, which addresses and clarifies financial reporting aspects of the current practices for unbundled pipeline sales and open access transportation. The Company restated interim operating revenues, operating income, net income and earnings per share in the first three quarters of fiscal 1995 to conform with the new requirements. For further details, refer to Note J - 118.7 130.3 Transportation 295.3 138.6 157.0 295.3 257.3 287.3 Less Intersegment Throughput: Sales - 112.2 122.0 Transportation 164.2 40.1 33.2 164.2 152.3 155.2 Total System Throughput 307.3 272.9 300.6 PIPELINE AND STORAGE Operating RevenuesQuarterly Financial Data (unaudited), in Item 8 of this report. Management cannot predict as to whether or not comparable revenue relating to unbundled pipeline sales and open access transportation would be generated in the future, since much depends on the efficiency of transporting gas through Supply Corporation's system. 1994 Compared with 1993.1993 Operating revenues decreased $381.4 million in 1994 compared with 1993. This decline reflects Supply Corporation's restructured operations under the Federal Energy Regulatory Commission's (FERC)FERC Order 636, which became effective August 1, 1993. Under Order 636, Supply Corporation's gas purchasing and sales functions were discontinued and replaced with new transportation and storage services, thusservices. Thus the recovery of purchased gas costs has been eliminated from Supply Corporation's revenues. 1993Operating Income 1995 Compared with 1992.1994 Operating revenuesincome before income taxes increased $35.7$5.6 million in 19931995 compared with 1992, despite a 30 Bcf decline1994. This increase reflects the increase in throughput. New rates that became effectiveoperating revenues discussed above, offset in July 1992, subject to refund, significantly increased ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) revenues in 1993. Supply Corporation filed a Stipulationpart by higher operating expense and Agreement (the Settlement) with the FERC on October 15, 1993, respecting these new rates. As a result of the Settlement, Supply Corporation reversed approximately $15 million of its previously accrued refund provision. Approximately $2.8 million of the amount reversed related to 1992. Additionally, as the Settlement included full recovery of Supply Corporation's portion of the net periodic post-retirement benefit costs under SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Supply Corporation recorded $3.6 million of related post-retirement benefit expense. These adjustments relate to rates that were in effect since July 1, 1992, subject to refund. The change to the straight fixed-variable (SFV) rate design mandated by Order 636, which provides for recovery of Supply Corporation's fixed costs in the demand, or reservation charge, contributed additional revenues of approximately $2.7 million for August and September 1993 when compared to Supply Corporation's former rate design. All of these items were reflected in earningsrecording, in the fourth quarter of 1993. Operating Income1995, of a reserve in the amount of $3.7 million for previously deferred preliminary survey and investigation charges for the Laurel Fields Storage Project, as discussed above. 1994 Compared with 1993.1993 Operating income before income taxes decreased $5.1 million in 1994 compared with 1993. This decrease was principally because of two nonrecurring items reflected in 1993. The favorable SettlementA rate case settlement in 1993, discussed above, resulted in Supply Corporation recording approximately $2.8 million of revenues in 1993 that related to 1992. In addition, the change to the SFVstraight fixed-variable (SFV) rate design contributed additional revenues of approximately $2.7 million for August and September 1993, when compared to Supply Corporation's former rate design. Throughput increased 38 Bcf in 1994 Exploration and can be attributed to increased utilization of Supply Corporation's Canadian gas transportation facilities, the expanded capacity of these facilities and weather that was colder than last year. However, because of the SFV rate design, the increase in throughput did not have a significant impact on pretax operating income. 1993Production Operating Revenues 1995 Compared with 1992.1994 Operating income before income taxes increased $17.6revenues decreased $14.0 million in 19931995 compared with 1992.1994. This increasedecrease reflects lower natural gas prices and management's decision to delay production activity in its Gulf Coast operations based on the decrease in prices. Natural gas production decreased 2.3 Bcf, or 10%, 2.0 Bcf of which occurred in the Gulf Coast operations. In addition, the weighted average price received for natural gas in fiscal 1995 decreased $0.51 per Mcf, or 23%. Oil production was mainlydown 291,000 barrels, or 28%. This drop reflects natural depletion and lower condensate production related to decreased gas production. Although the result of higherweighted average price received for oil in fiscal 1995 increased 9%, this was not enough to offset the lower production level. The fluctuations in prices denoted above do not reflect revenue from hedging activities, which contributed approximately $7.0 million in revenues discussed above, which were partly offset by higher gas costs and operation and maintenance (O & M) expenses, primarily for labor and employee benefits. EXPLORATION AND PRODUCTION Operating Revenuesduring 1995. 1994 Compared with 1993.1993 Operating revenues increased $11.6 million in 1994 compared with 1993. This increase was primarily attributable to Seneca's Gulf Coast operations and reflects the continued success of both its offshore drilling program in the Gulf of Mexico and its horizontal drilling program in central Texas. Gas production and oil production (mainly condensate from gas wells) hit record levels in 1994 and were up 34% and 59%, respectively, in the ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Gulf Coast Region and 17% and 24%, respectively, for all geographic regions combined. Systemwide, theThe weighted average price received for gas and oil production in 1994 was $2.18as compared to 1993 decreased $0.02 per Mcf and $14.86$1.92 per barrel (bbl), respectively. This is a decline of $.02 per Mcf in gas prices and $1.92 per bbl in oil prices compared with 1993. Nonetheless, efforts to stabilize prices through hedging activities contributed approximately $1.6 million of operating revenues for the year. At present, Seneca's goal is to hedge approximately 60% of its Gulf Coast gas and oil production.
Production Volumes Year Ended September 30 1995 1994 1993 - ---------------------------------------------------------- Gas Production (million cubic feet) Gulf Coast 14,294 16,296 12,134 West Coast 840 706 1,059 Appalachia 5,808 6,271 6,681 - ----------------------------------------------------------- 20,942 23,273 19,874 =========================================================== Oil Production (thousands of barrels) Gulf Coast 287 615 387 West Coast 433 404 431 Appalachia 19 11 13 - ----------------------------------------------------------- 739 1,030 831 ===========================================================
Weighted Average Prices Year Ended September 30 1995 1994 1993 - ---------------------------------------------------------- Weighted Average Gas Price/Mcf Gulf Coast $1.56 $2.03 $1.99 West Coast $1.33 $1.58 $1.62 Appalachia $2.01 $2.65 $2.67 Weighted Average Price $1.67 $2.18 $2.20 - ------------------------------------------------------------ Weighted Average Oil Price/bbl Gulf Coast $16.94 $15.54 $17.84 West Coast $15.66 $13.79 $15.76 Appalachia $15.72 $15.92 $18.81 Weighted Average Price $16.16 $14.86 $16.78
Operating Income 1995 Compared with 1992.1994 Operating revenues increased $22.3income before income taxes decreased $5.4 million in 19931995 compared with 1992.1994. This increasedecrease reflects the lower revenues discussed above, partly offset by lower depletion expense, which is directly related to lower revenues. Lower operation and maintenance (O & M) expense also partly offset the decrease in revenues. The decrease in O & M was also primarily attributable to Seneca's Gulf Coast operations. Natural gas production from the Gulf Coast operations increased 217% to 12.1 Bcf from 3.8 Bcf in 1992. In total, from all geographic areas, production rose by 7.8 Bcf to 19.9 Bcf. Lower natural gas production was realized from Appalachian and West Coast properties. Systemwide, the average price received for gas production in 1993 was $2.20 per Mcf, an increasea result of $.23 per Mcf from $1.97 per Mcf in 1992. Oil production (mainly condensate from gas wells) also increased in 1993 by 188,000 bbls compared with 1992. Systemwide, the average price received for oil production in 1993 was $16.78 per bbl, a decrease of $.33 per bbl from $17.11 per bbl in 1992. Production Volumes Year Ended September 30 1994 1993 1992 Gas Production (million cubic feet) Gulf Coast 16,296 12,134 3,828 West Coast 706 1,059 1,234 Appalachia 6,271 6,681 7,008 23,273 19,874 12,070 Oil Production (thousands of barrels) Gulf Coast 615 387 172 West Coast 404 431 454 Appalachia 11 13 17 1,030 831 643 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Operating Incomedecreased production. 1994 Compared with 1993.1993 Operating income before income taxes increased $8.8 million in 1994 compared with 1993. This increase reflects the higher revenues discussed above, partly offset by higher depletion expense which is directly related to higher revenues. O & M expense remained basicallysubstantially level in 1994 compared with 1993. Although O & M expense related to increased production activity in the Gulf Coast operations was higher in 1994 than 1993, it was offset by a charge to O & M in 1993 for work performed on Appalachian wells that did not recur in 1994. 1993Other Nonregulated Operating Revenues 1995 Compared with 1992.1994 Operating income before income taxes increased $6revenues decreased $15.0 million in 19931995 compared with 1992.1994. This increase was alsodecrease reflects lower operating revenues from UCI, the Company's pipeline construction subsidiary, as a result of management's decision to discontinue its pipeline construction operations. The decrease also reflects lower revenues from NFR, the increaseCompany's gas marketing subsidiary, largely because of lower natural gas prices in operating revenues, discussed above, partly offset by increases in depletion and O & M expenses. The increase in O & M expenses is related to the increased production activity in the Gulf Coast operations. Additionally, a charge to O & M expense of $2.3 million was recorded in the fourth quarter of 1993 for work performed on Appalachian wells. OTHER NONREGULATED Operating Revenues1995 compared with 1994. 1994 Compared with 1993.1993 Operating revenues increased $29.9 million in 1994 compared with 1993. This increase is almost entirely due to higher revenues from NFR the Company's gas marketing subsidiary, as its gas marketing volumes more than doubled to 18.2 Bcf in 1994 from 7.3 Bcf in 1993. 1993Operating Income 1995 Compared with 1992.1994 Operating revenues decreased $5.4income before income taxes increased $0.5 million in 19931995 compared with 1992.1994. This decline reflected lower revenues fromincrease can be attributed to improved performance by NFR as a result of improved margins and an increase in customers combined with better performance by UCI prior to the Company'sdiscontinuance of its pipeline construction subsidiary, partly offset by higher revenues from NFR. UCI had an exceptionally productive year in 1992, completing several projects in Virginia and New York for nonaffiliated pipeline companies that were expanding their systems. The lack of large projects in 1993 negatively impacted UCI's revenues. NFR's revenues increased in 1993, as gas marketing volumes increased to 7.3 Bcf from 5.4 Bcf in 1992. Operating Incomeoperations. 1994 Compared with 1993.1993 Operating income before income taxes increased $3.5 million in 1994 compared with 1993. This increase is due to the improved performance of UCI, which, although still operating at a loss, had higher margins than in 1993. In addition, the improved performance of NFR and the Company's timber operations enhanced operating income before income taxes of this segment. 1993 Compared with 1992. Operating income before incomeIncome Taxes, Other Income and Interest Charges Income Taxes Income taxes decreased $5.2 million in 1993 compared with 1992. This decline was mainly the result of the lack of a contribution by UCI to operating income before income taxes. The lack of large projects, coupled with tight margins contributed to poor performance in 1993. This more than offset the increase in NFR's operating income before income taxes resulting from increased marketing activities. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) INCOME TAXES, OTHER INCOME AND INTEREST CHARGES Income Taxes. Income taxes increased in 1994 and 1993,1995, mainly because of increasesa decrease in pretax income. The opposite was true in 1994 as income as well as higher income tax rates. In addition, thetaxes increased because of an increase in incomepretax income. Income taxes in 1994 reflects1995 reflect lower Section 29 nonconventional fuel tax credits. These credits, which relate to production from qualified gas wells, decreased to $0.9 million in 1995 from $1.7 million in 1994 down fromand $2.6 million in 1993. These credits are a direct reduction of income tax expense. Other Income.Income Other income increased $1.7 million in 1995, primarily because of a gain of $2.5 million recorded by UCI on the sale of its pipeline construction equipment. The sale of the equipment resulted from management's decision to discontinue its pipeline construction operations. Other income decreased $1.2 million and $1 million in 1994 and 1993, respectively.1994. A portion of the decrease in 1994 and 1993 was because Distribution Corporation discontinued the accrual of interest income on deferred contract reformation costs (CRC) in April 1993, in accordance with a settlement with the PSC for full recovery of CRC. In addition, the decrease in 1994 reflects lower interest income on temporary cash investments. Other income also decreased in 1993 because of lower income associated with funds used during construction by the Pipeline and Storage segment resulting from lower construction balances. The decreases in 1993 were partly offset by higher interest income on temporary cash investments related to the proceeds from the September 1992 issuance of 2.5 million shares of common stock. Interest Charges.Charges Interest on long-term debt increased $4.2 million in 1995 and decreased $1.8 million and $1.4 millionin 1994. The increase in 1995 can be attributed to a higher average amount of long-term debt balance in 1995 compared to 1994. The decrease in 1994 and 1993, respectively. This was mainly due to refinancing activities, whereby higher-interest long-term debt was replaced with lower-interest long-term debt and with equity.debt. Other interest charges decreased $3 million and $5.7increased $2.6 million in 1995 and decreased $3.0 million in 1994. The increase in 1995 resulted primarily from an increase in the weighted average interest rate on short-term borrowings, partly offset by lower average outstanding balances. In addition, interest in 1995 includes increased interest expense on Amounts Payable to Customers. The decline in 1994 and 1993, respectively. The declines in both 1994 and 1993 reflectreflects lower interest on short-term borrowings because of lower average amounts outstanding. A lower weighted average interest rateoutstanding, offset in 1993 also contributed to the decline in short-term interest. However, 1994 reflectspart by an increase in the weighted average interest rate. 1995 OUTLOOK The coming year will be one of transition for the Company as it works through the impact of the FERC's Order 636 on the state level. As a result, 1995 earnings are expected to be lower than the record earnings of 1994. However, management continues to believe that the integrated strength of the Company places it on a course for growth in 1996Capital Resources and beyond. When reviewing 1994 earnings it is important to note that $.09 per share was due to the cumulative effect of mandated accounting changes which will not recur in 1995. In addition, allowed returns on pipeline equity are expected to decrease as a result of allegedly lower risks associated with that business. Supply Corporation, therefore, anticipates a lower return on equity for rates to become effective in 1995. Further, in the Utility Operation, Distribution Corporation saw its allowed return on equity in its New York rate jurisdiction fall from 12.0% to 10.7% in July. The Company expects allowed returns on equity at the state level to increase in future years as a result of the state ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) commission recognition of increased risks under the FERC's Order 636, as well as the rise in interest rates. Nevertheless, such a rise will not significantly benefit 1995 earnings. Our Exploration and Production segment, and our Other Nonregulated operations should increase their earnings contribution in 1995. However, the current low prices received for natural gas production will temper the increase and, therefore, it is unlikely that increased contributions for our nonregulated operations will cause consolidated earnings to increase in 1995. CAPITAL RESOURCES AND LIQUIDITYLiquidity The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
Sources and (Uses) of Cash Year Ended September 30 (in millions) 1995 1994 1993 - ----------------------------------------------------------------- Provided by Operating Activities $173.5 $199.2 $123.7 Capital Expenditures (182.8) (135.1) (131.9) Short-Term Debt, Net Change 35.1 (84.3) (30.2) Long-Term Debt, Net Change 4.0 80.1 (51.1) Issuance of Common Stock 2.5 9.1 78.8 Common Dividends (59.2) (57.2) (52.2) All Other-Net 10.6 3.6 0.2 - ------------------------------------------------------------------ Net Increase (Decrease) in Cash and Temporary Cash Investments $(16.3) $ 15.4 $(62.7) ==================================================================
Operating Cash Year Ended September 30 (in millions) 1994 1993 1992 Provided by Operating Activities $199.2 $123.7 $ 93.0 Capital Expenditures (135.1) (131.9) (157.9) Short-Term Debt (84.3) (30.2) 20.5 Long-Term Debt, Net Change 80.1 (51.1) 74.3 Issuance of Common Stock 9.1 78.8 73.7 Common Dividends (57.2) (52.2) (45.6) All Other-Net 3.6 .2 (2.1) Net Increase (Decrease) in Cash and Temporary Cash Investments $ 15.4 $(62.7) $ 55.9 OPERATING CASH FLOWFlow Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, deferred income taxes and allowance for funds used during construction. In 1994, noncash items also included the cumulative effect of required changes in accounting for income taxes and post-employment benefits in accordance with SFAS 109 and SFAS 112, respectively.benefits. Cash provided by operating activities in the Utility Operation and Pipeline and Storage segment may vary substantially from year to year because of fluctuations in weather, supplier refunds, the impact of rate cases, and for the Utility Operation, fluctuations in weather and over- or under-recovered purchased gas costs. The impact of weather on cash flow is tempered in the Utility Operation's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's SFV rate design. For a graph of "Book Value Per Common Share" see graph B. in the Appendix of this report. Net cash provided by operating activities totalled $199.2$173.5 million in 1994, an increase1995, a decrease of $75.5$25.7 million compared with the $123.7$199.2 million provided by ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) operating activities in 1993.1994. This increase reflected higherdecrease reflects lower revenues and earnings in the Exploration and Production segment, mainly from its Gulf Coast operations. Theoperations, coupled with lower payable balances. This was partly offset by higher cash flow from the Utility Operation hadbecause of an over-recovery of gas costs, an increase in cash flow from operations mainly because Distribution Corporation had over-recovered purchased gas costs at September 30, 1994, while it was in an under-recovery position at September 30, 1993. In addition, the Pipeline and Storage segment had an increase in upstream pipeline companysupplier refunds received during the year, a reduction in 1994, thus increasing its cash flow from operations. INVESTING CASH FLOWstored gas inventory, and a decrease in receivable balances. Investing Cash Flow Capital Expenditures.Expenditures Capital expenditures totalled $138.3$182.8 million in 1994.1995. The table below presents these expenditures by business segment: Year Ended September 30 (in millions) 1994 Percentage Utility Operation $ 61.7 44.6% Pipeline and Storage 20.5 14.8 Exploration and Production 52.5* 38.0 Other Nonregulated 3.6 2.6 $138.3* 100% * Includes noncash acquisition of $3.2 million in a stock-for-asset swap.
1995 Year Ended September 30 (in millions) Amount Percentage - ----------------------------------------------------------------------- Utility Operation $ 64.8 35.4% Pipeline and Storage 38.7 21.2 Exploration and Production 69.7 38.1 Other Nonregulated 9.6 5.3 - -------------------------------------------------------------------- $182.8 100.0% ==================================================================== Most of the Utility Operation's capital expenditures were for the replacement of mains and main extensions, as well as for the replacement of service lines and, to a minor extent, the installation of new services. Pipeline and Storage capital expenditures included an increase in compression at two locations, other additions, improvements and replacements to the Company's transmission and storage systems. The majority of the Exploration and Production segment's capital expenditures were made for the exploration for and development of oil and gas properties located offshore in the Gulf of Mexico, and in Seneca's Northeast Clay Field in central Texas. As a result of activity in the Gulf Coast Region, reserves included 93.4 Bcf of new gas reserves and 1.1 million barrels of new oil reserves at September 30, 1994. In addition, capital expenditures in the Appalachian Region included $3.2 million for the acquisition of natural gas production assets in exchange for Company common stock. This acquisition added approximately 3 Bcf of gas reserves. Other Nonregulated capital expenditures included approximately $5.0 million in connection with its link with the Empire State Pipeline at Grand Island, New York and approximately $5.1 million related to compressor engine emission controls necessary to comply with the Clean Air Amendments of 1990. In addition, capital expenditures were made for additions, improvements and replacements to this segment's transmission and storage systems. The Exploration and Production segment spent approximately $49.0 million on its offshore program in the Gulf of Mexico, including offshore lease acquisitions and drilling expenditures. Lease acquisitions included a 30% working interest in an oil and gas field in West Delta Blocks 31 and 32. The majority of offshore drilling expenditures were spent on West Cameron 552, West Cameron 522, West Delta 17 and Vermillion 252. Approximately $21.0 million was spent on the Exploration and Production segment's onshore program, including horizontal onshore drilling in central Texas and the acquisition of a 240-acre oil field located in the Silverthread Field in California. Other Nonregulated capital expenditures consisted primarily of timberland and equipment purchases. The Company's estimated capital expenditures for the next three years are: Year Ended September 30 (in millions) 1995 1996 1997 Utility Operation $ 63.6 $ 59.1 $ 58.1 Pipeline and Storage 38.0 17.6 18.3 Exploration and Production 74.3 78.2 80.8 Other Nonregulated 7.1 1.2 1.3 $183.0 $156.1 $158.5 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Year Ended September 30 (in millions) 1996 1997 1998 - -------------------------------------------------------------------- Utility Operation $ 60.7 $ 58.9 $ 57.9 Pipeline and Storage 21.5 20.5 20.5 Exploration and Production 90.4 91.3 95.0 Other Nonregulated 0.3 0.3 0.3 - -------------------------------------------------------------------- $172.9 $171.0 $173.7 ====================================================================
Estimated expenditures for the Utility Operation during the next three years will be concentrated in the areas of main replacements and extensions, service line replacements and, to a minor extent, the installation of new services. Included inEstimated expenditures for the Pipeline and Storage segment's capital expenditures for 1995 is approximately $5.6 million tosegment in 1996 will be spent in connection with several expansion projects, the most significant of which is a link with the Empire State Pipeline at Grand Island, New York. This will greatly increase the reliability, flexibility and efficiency of service to the Company's service territoryconcentrated in the areas northreconditioning of Buffalostorage wells and to Grand Island, New York. Also included in the 1995 capital expenditures is approximately $4.3 million for compressor engine emission controls necessary to comply with the standards of the Clean Air Act Amendments of 1990 (the Act). Approximately $.6 million of capital expenditures were incurred in 1994 to comply with the Act. The Company does not anticipate incurring significant additional capital expenditures to comply with the current standards of the Act. However, changes in standards may require additional expenditures in the future. Management expects that all related capital expenditures will be recoverable through rates. Significant capital expenditures related to Supply Corporation's Laurel Fields Storage Project (which is pending the FERC's approval) are not expected to be incurred until 1996. Since the timing of expenditures related to this project are not finalized, the preceding table does not include significant amounts for this project. Laurel Fields is a 19 Bcf underground natural gas storage development project, which entails the development of Supply Corporation's Callen Run (a depleted gas field) and expansion of its Limestone Storage Field. Filings with the FERC were made in June 1994 to implement this project. An "open season" was held in August 1994 to identify prospective customers for this project. Precedent agreements are currently being negotiated with interested customers. On November 4, 1994, a proposal was sent to the FERC to divide the project into two phases. Phase I would encompass the expansion of the Limestone Storage Field to accommodate approximately 7 Bcfreplacement of storage and phase II would consist of the development of the Callen Run Storage Field. The potential cost of the project is approximately $200 million. For a graph of "Capital Expenditures" see graph C. in the Appendix to this report.transmission lines. Estimated capital expenditures in 19951996 for the Exploration and Production segment are approximately 40%30% higher than capital spending in 19941995 as the Company sees significant opportunities for growth in this segment. These expenditures will be directed mainly toward developing Seneca's Gulf Coast offshore prospects, evaluating reserve acquisitions and significantly expanding exploration activities. Capital expenditures for Other Nonregulated operations will primarily be used for timberland. The Company's capital expenditure program is under continuous review. The amounts are subject to modification for opportunities in the natural gas industry such as the acquisition of attractive oil and gas properties or storage ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) facilities and the expansion of transmission line capacities. TheWhile the majority of capital expenditures in the Utility Operation are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures in the regulatedCompany's other business segments depends, to a large degree, upon market conditions coupled withconditions. Expenditures in the Regulated Operations are also dependent on adequate rate relief. Other.Other Cash received on the sale of the Company's investment in property, plant and equipment is reflected as a cash flow from investing activities. Approximately $2.3$4.0 million of cash was received during fiscal 1995 related to the sale of certain gas reserves in the firstGulf of Mexico. Proceeds of this sale were credited to property, plant and equipment in accordance with the full cost method of accounting. During the third quarter of fiscal 1994,1995, approximately $6.2 million of cash was received related to the fiscal 1993 sale of Seneca's interestUCI's pipeline construction equipment. On August 29, 1995, the Company received SEC approval to acquire all of the issued and outstanding common stock of Horizon Energy Development, Inc. (Horizon), a New York corporation formed to engage in its Alberta, Canada, gas reserves. FINANCING CASH FLOWforeign and domestic energy projects, including foreign utility companies and exempt wholesale generators of electricity. The SEC authorized the Company (through Horizon and intermediate companies) to invest up to an aggregate of $150.0 million through December 2001 in such activities. On September 15, 1995, the Company acquired 500 shares of Horizon $1 par common stock for $1.0 million. Currently, Horizon is considering investment opportunities in eastern Europe, South America and Asia, and is the controlling partner in Sceptre Power Company, a partnership which includes a team with considerable experience in developing such energy projects. Financing Cash Flow In order to meet the Company's capital requirements, cash from external sources must periodically be obtained through short-term bank loans and commercial paper, as well as through issuances of long-term debt and equity securities. The Company expects these traditional sources of cash to continue to supplement its internally generated cash during the next several years. On JulyMay 1, 1994,1995, the Company redeemed $19.9retired $55.0 million remaining outstanding principal amount of 9-1/2% debentures due July 1, 2019, for $21.36.07% medium-term notes and $20.0 million including redemption premium.of 6.10% medium-term notes, both of which matured on that date. On July 14, 1994,June 8, 1995 and June 23, 1995, the Company retired $20.0 million of 9.32% medium-term notes and $1.0 million of 6.10% medium-term notes, respectively, which matured on those dates. On June 12, 1995, the Company issued $50$50.0 million of 7.375% medium-term notes due July 1999, at an interest rate of 7.25%. Also on July 14, 1994, the Company issued $50 million of medium-term notes due July 2024, at an interest rate of 8.48%. These latter notes are callable beginning July 1999.in June 2025. After reflecting underwriting discounts and commissions, the combined proceeds to the Company of these two issuances amounted to $99.4$49.3 million. TheOn July 3, 1995, the Company issued $50.0 million of 6.08% medium-term notes due in July 1998. After reflecting underwriting discounts and commissions, the proceeds were used to reduce outstanding short-term borrowings.the Company amounted to $49.8 million. The Company's embedded cost of long-term debt was 7.3% at both September 30, 19941995 and 1993.1994. At September 30, 1994,1995, the Company has registered under the Securities Act of 1933, as amended, and Exchange Commission (SEC)has authority remaining under a shelf registration filed in March 1993the Public Utility Holding Company Act of 1935, as amended, to issue and sell up to $220$120.0 million of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company. For a graph of "Embedded Cost of Long-Term Debt" see graph D. in the Appendix to this report. Consolidated short-term debt decreased $84.3increased $35.1 million during 1994.1995. The Company continues to consider short-term bank loans and commercial paper important sources of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, exploration and development expenditures and other working capital needs. The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company's covenants contained in its indenture covering its long-term debt, as amended, the Company would have been permitted to issue up to a maximum of approximately $483.0 million in additional long-term unsecured indebtedness at September 30, 1995, in light of then current long-term interest rates. In addition, at September 30, 1995, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $252.4 million of short-term debt. The Company has recently filed with the SEC for authorization to borrow on a short-term basis for a five-year period. With this request, the Company is seeking to increase its short-term borrowing limits. The filing, if approved, would increase the Company's limit on commercial paper from $105.0 million to $300.0 million and would increase the aggregate maximum short-term borrowing level from $400.0 million to $600.0 million. The Company, through Seneca, and NFR, is engaged in certain natural gas and crude oil price swap agreements and in the gas futures market as a means of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) hedging a portion of the market risk associated with fluctuations in the market price of natural gas and crude oil. These price swap agreements are not held for trading purposes. During 1995, Seneca utilized natural gas and crude oil swap agreements with notional amounts of 16.3 equivalent Bcf and 711,000 equivalent bbl, respectively. This activity resulted in net revenues of approximately $7.0 million. At September 30, 1995, Seneca had natural gas swap agreements outstanding with a notional amount of approximately 23.8 equivalent Bcf at prices ranging from $1.70 per Mcf to $2.16 per Mcf. Seneca also had crude oil swap agreements outstanding at September 30, 1995 with a notional amount of 1,780,000 equivalent bbl at prices ranging from $17.40 per bbl to $19.00 per bbl. In addition, the Company has SEC authority to enter into certain interest rate swap agreements. For further discussion, see disclosure in Note F - Financial Instruments under "Financialthe heading "Derivative Financial Instruments" in Note A - SummaryItem 8 of Significant Accounting Policies.this report. The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, in Item 8 of this report, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none ofneither this litigation nor these other regulatory matters are expected to materially change the Company's present liquidity position. The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company's covenants contained in its indenture covering long-term debt, at September 30, 1994, the Company would have been permitted to issue up to a maximum of $434.5 million in additional long-term unsecured indebtedness, subject to maturity and long-term interest rates. In addition, at September 30, 1994, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $287.5 million of short-term debt. For a graph of "Capitalization Ratios" see graph E. in the Appendix to this report. RATE MATTERSRate Matters Utility Operation New York Jurisdiction In November 1995, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $28.9 million with a requested return on equity of 11.5%. Proceedings in this rate case are ongoing and management cannot predict their outcome. New rates are expected to become effective in October 1996. Prior to this filing, Distribution Corporation entered into proceedings concerning a multi-year settlement, the outcome of which is uncertain at this time. In October 1994, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $56.5 million or 8.9%, with a requested return on equity of 12.85%. New rates are expected to become effective in August orIn September 1995. On November 17, 1994, Distribution Corporation presented the PSC staff with a preliminary proposal for a multi-year settlement. In August 1993, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $55.4 million, or 8.5%, with a return on equity of 12.16%. Included in the requested rate increase was an initial amount of $24.9 million for the recovery of transition costs arising from the FERC's Order 636, which represented 3.8% of the total 8.5% requested increase. On July 19, 1994,1995, the PSC issued an order authorizing a base rate increase of $11.1$14.2 million or 1.7%, with a return on equity of 10.7%10.4%. In addition, the PSC authorized recovery of transition costs arising from the FERC's Order 636 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) of up to $11 million annually from sales customers through the monthly Gas Adjustment Clause (GAC). Distribution Corporation will defer, for recovery in future periods, any amounts that may exceed the $11 million annual amount. NewThe new rates became effective July 24, 1994. The recoveryas of transition costs from transportation customers in New York remains unresolved. The PSC has postponed its decision on transportation customers' allocable share of transition costs pending further consideration of the issue in a generic restructuring case (the Generic Case) which began in October 1993. The PSC staff's position in the Generic Case is that transportation customers should be assigned a per-unit charge that is equal to 50% of the per-unit charge being collected from sales customers for gas supply realignment (GSR) costs and stranded costs. The PSC has authorized Distribution Corporation's continued deferral of transition costs relating to transportation customers until resolution in the Generic Case. At September 30, 1994, deferred transition costs related to transportation customers amounted to approximately $2 million. In July 1993, in connection with a previously approved two-year settlement,20, 1995. Pennsylvania Jurisdiction On March 15, 1995, Distribution Corporation received PSC approvalfiled in its Pennsylvania jurisdiction a request for the second year of the settlement. The approval was for aan annual rate increase of $13.3$22.0 million or 2.1%, forwith a return on equity of 13.25%. In September 1995, the 12-month period ended July 31, 1994. ThisPennsylvania Public Utility Commission (PaPUC) approved a settlement authorizing a base rate increase went into effectof $6.0 million with no specified rate of return on July 23, 1993. Pennsylvania Jurisdictionequity. The new rates became effective as of September 27, 1995. On March 8, 1994, Distribution Corporation filed in its Pennsylvania jurisdiction a request for an annual rate increase of $16$16.0 million or 6.8%, with a return on equity of 12.25%. A proposal for a WNC was included in this filing. On December 6, 1994, an order was issued by the PaPUC authorizing an annual rate increase of $4.8 million or 2.0 %, with a return on equity of 11.0% and without a WNC. New rates are scheduled to become effective as of December 7, 1994. In March 1993, Distribution Corporation filed with the PaPUC for an annual rate increase in its Pennsylvania jurisdiction of $33.4 million, or 16.2%, with a return on equity of 12.4%. Included in the requested rate increase was an initial amount of $8.2 million for the recovery of transition costs arising from the FERC's Order 636. On December 1, 1993, an order was issued by the PaPUC authorizing an annual rate increase of $11.4 million, or 4.9%, exclusive of transition costs. The new rates became effective as of December 1, 1993. The PaPUC's December 1, 1993 order also addressed certain issues concerning recovery of GSR costs and stranded costs resulting from the implementation of the FERC's Order 636. Under this order, Distribution Corporation began collecting, effective December 1, 1993, GSR and stranded costs from its customers through a separate surcharge. Distribution Corporation is allowed to update this surcharge on a quarterly basis. Distribution Corporation is recovering under-recovered purchased gas transition costs from its Pennsylvania sales customers through its gas cost recovery rates. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)7, 1994. General rate increases in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses. State Regulatory Environment The seeds of changeChanges precipitated by the FERC's Order 636 are redefining the roles of the utility industry and the state regulatory commissions. Competition has arrived for utilities, and it is anticipated that, similar to what was done in the pipeline sector of the natural gas industry, regulators will requireare requiring utilities to unbundle their services. The anticipated result is that utility service will divide into "core" markets consistingDetails of the typical residential and commercial customers, as well as customers taking firm transportation service and the "non-core" markets consisting of competitive commercial and industrial markets. It is anticipated that non-core services will be lightly regulated and, with respect to core customers, regulatorsthese recent developments are expected to focus on increased utility efficiency.described below. Many state regulators believe that utilities can gain efficiency through performance-based incentive ratemaking. Such ratemaking is intended to enhance the traditional cost-of-service ratemaking formula, which many believe does not provide incentives to operate efficiently. Distribution Corporation has proposed several customer service performance incentives in its New York rate case filed in October 1994. If these incentives are accepted,In its September 1995 order concerning the mechanisms would allowOctober 1994 rate filing, the PSC adopted incentive mechanisms that will allow it to administer financial penalties or rewards determined by the utility'sDistribution Corporation's ability to meet or exceedmaintain required performance levels. The proposed incentives relate to: response time to customer inquiries and complaints; billing accuracy; keeping appointments for service; and efficiency in the installation of new service lines. The New York and Pennsylvania regulatory commissions have instituted several generic proceedings related, among other things, to restructuring in response to the FERC's Order 636. Distribution Corporation is working closely with the state regulatory commissions to resolve the complexities of industry restructuring. The more significant ones,proceedings, all of which are still pending, are discussed below: New York Finance Proceeding. The purpose of this proceeding is to develop a uniform method for calculating a utility's rate of return on equity. Ratesetting Proceeding. This proceeding is intended to develop guidelines for settlements, incentive ratemaking and multi-year rate filings, in addition to the traditional single-year procedure. Thus, a menu of options would be available for each utility to select the appropriate ratemaking proposal. Generic Restructuring Proceeding. This proceeding is examining the appropriate retail or end-use impacts resulting from the FERC's Order 636 pipeline restructuring. ItIn December 1994, the PSC issued an Opinion and Order in this docket instructing the state's local distribution companies (LDC) to file tariffs that would, among other things, unbundle retail services, provide for small-customer aggregation, adopt flexible, market-based rates and divide the LDC's market into core and non-core segments. In connection with its 1994 rate case, Distribution Corporation implemented many of the policies and guidelines contained in the December 1994 Order, and now offers unbundled, flexible services to its commercial and industrial customers. In November 1995, Distribution Corporation submitted a filing designed to further comply with the December 1994 Order by (i) offering transportation service to all customers, including residential; and (ii) surcharging transportation customers for Order 636 transition costs. These latter changes are subject to approval by the PSC. Generic Affordability/Gas Cost Incentive Proceeding. This proceeding is investigating the development of guidelines for "affordable" natural gas utility service and, on a separate track, an appropriate gas cost incentive mechanism. For the Affordability track, it is expected that the PSC will issue an order addressing key issuesadopting guidelines for, among other things, rates for low-income or payment-troubled customers. The Gas Cost Incentive track is expected to result in guidelines for designing and applying performance-based incentives for the LDC's gas purchasing function. Among the various incentives being studied are so-called "hard" price caps and mechanisms that would allow the PSC to administer rewards or penalties based on the LDC's gas purchasing practices as measured against benchmarks such as unbundling, rate design and the extent of state regulation. Implementation will likely be achieved by each utility on a case-by-case basis.published gas cost index. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) Pennsylvania Settlement Guidelines. This proceeding is intended to develop orders addressing specific rules of procedure to accomplish settlement of complex proceedings, including rate cases. FERC Order 636 Proceedings. The PaPUC has thus far responded to the FERC's Order 636 with three generic proceedings addressing different operational areas. They are proceedings on transportation services, gas procurement practices (including a gas purchase incentive mechanism) and capacity release. Distribution Corporation has already implemented many of the proposed changes in previous rate cases and expects that additional changes will not significantly alter current operations. Chairman Quain's Legislative Collaborative. In the latter part of fiscal 1995, the Chairman of the PaPUC convened a collaborative among the Commonwealth's LDCs, Staff for the PaPUC, intervenors and marketers/producers to examine existing public utility laws to determine whether they should be amended to meet the requirements of the post-Order 636 environment. Under consideration by the parties are changes to existing laws governing utility practices and development of new legislation that would allow utilities to seek deregulation of traditional services. Distribution Corporation is working closely withhas expressed its support for, and participated in, the state regulatory commissions to resolvedrafting of many of the complexitiesproposals. However, Distribution Corporation cannot determine the outcome of industry restructuring.these proceedings at this time. Pipeline and Storage For a discussion of Supply Corporation's gathering rates, refer to Note B - Regulatory Matters.Matters in Item 8 of this report. On October 31, 1994, Supply Corporation filed for an annual rate increase of $21$21.0 million, with a requested return on equity of 12.6%. Settlement discussions to resolve the various issues have achieved a settlement in principle. This rate case was filed as a result of the FERC's order issued on October 28, 1994, rejectingsettlement in principle will increase Supply Corporation's rate case filedrevenues by approximately $6.4 million annually from current levels, with a return on September 30, 1994.equity of 11.3%. The FERC rejected the September 30, 1994 filing because it disagreed with the proposed method of rolling-in rates for the storage service previously offered byformer Penn-York (Penn-York wasEnergy Corporation (Penn-York) services, which were merged into Supply Corporation effective July 1, 1994). On December 30, 1993,1994, will be rolled-in for ratemaking purposes. Approximately two-thirds of the FERC issued an order approving, with slight modificationformer Penn-York service is now on year-to-year contracts and Supply Corporation has agreed not to seek recovery of revenues related to terminated Penn-York service from other storage customers for five years, as long as the Settlement, whichterminations are not greater than approximately 30% of the terminable service. Supply Corporation is marketing and will actively market available storage capacity. Supply Corporation also agreed not to seek recovery for increased cost of service for three years. A Stipulation and Agreement incorporating the settlement in principle was filed with the FERC in September 1995 and the Administrative Law Judge certified the settlement as uncontested to the FERC on October 15, 1993, respecting two Supply Corporation rate proceedings. As modified, the Settlement provided forNovember 6, 1995. Approval is expected in early calendar year 1996 and rates that produced annual revenues of approximately $125 million between Julyare expected to become effective retroactive to June 1, 1992, and July 31, 1993. Rates for the period beginning August 1, 1993, reflect reduced costs after restructuring plus certain settlement concessions, and will produce revenues of approximately $121 million annually. As a result of the Settlement, Supply Corporation refunded to its customers $13.6 million, including interest, during the second quarter of 1994. OTHER MATTERS1995. Other Matters Environmental Matters.Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Distribution Corporation has been identified by the Environmental Protection Agency or the New York State Department of Environmental Conservation (DEC) as one of a number of companies that are considered to be potentially ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued) responsible parties (PRPs) with respect to several waste disposal sites in New York that were operated by unrelated third parties. These PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to Distribution Corporation with respect to the remediation of these sites will be dependent on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion attributed, if any, to Distribution Corporation. Distribution Corporation's estimated share of the clean-up costs has been accrued for four of these sites. One of these four sites was formerly used for a manufactured gas plant. Distribution Corporation is currently involved in litigation regarding this site. The current owner of the site has submitted a claim against Distribution Corporation for contribution of a share of approximately $1.6 million of removal/remediation costs that have been incurred. It is anticipated that future remedial costs will be incurred and on the basis of a Record of Decision issued by the DEC, as amended on September 19, 1994, the estimated future remedial costs for the site are approximately $5.7 million. Management believes that the ultimate outcome of these matters will not have a material impact on the financial condition, results of operations or cash flows of the Company. Distribution Corporation has incurred clean-up costs at two additional sites in New York and one site in Pennsylvania related to former manufactured gas plant sites. Supply Corporation is involved in a remediation program of certain of its measuring and regulating stations in Pennsylvania. Estimated clean-up costs have been accrued for these sites. It is the Company's policy to accrue estimated environmental clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The CompanyDistribution Corporation has estimated that clean-up costs related to the above notedseveral former manufactured gas plant sites and several other waste disposal sites are in the range of $6.7$8.1 million to $10.1$9.5 million. At September 30, 1994, the Company1995, Distribution Corporation has recorded the minimum liability of $6.7$8.1 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company. In New York, Distribution Corporation has received approval from the PSC to defer and amortize both former manufactured gas and non-manufactured gasis recovering site investigation and remediation costs over a three-year period for each site. These costs are then included in rate cases for recovery through base rates. Distribution Corporation is currently recovering such costs in this manner. In Pennsylvania, Distribution Corporation and Supply Corporation expectexpects to recover such costs in rates, as the PaPUC and the FERC, respectively, havehas allowed recovery of other environmental clean-up costs in rate cases. Accordingly,For further discussion, see disclosure in Note H - Commitments and Contingencies under the Consolidated Balance Sheets at September 30, 1994, include related regulatory assetsheading "Environmental Matters" in Item 8 of this report. Accounting for Stock Based Compensation In October 1995, the amountFinancial Accounting Standards Board issued SFAS 123, "Accounting for Stock Based Compensation," which establishes a fair value based method of approximately $7.3 million, $.6 millionaccounting for employee stock options or similar equity instruments and encourages all companies to adopt that method of which relates to costs that have already been incurred.accounting for all of their employee stock compensation plans. For a further discussion of what this new accounting standard entails, see Note D - Capitalization in Item 8 of this report. Effects of Inflation.Inflation Although the rate of inflation has been relatively low over the past few years, and thus has benefited both the Company and its ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Concluded) customers, the Company's operations remain sensitive to increases in the rate of inflation because of the capital-intensive and regulated nature of its major operating segments. Delays inherent in the ratemaking process prevent the Company from obtaining immediate recovery of increased operating costs. Also, while the ratemaking process gives no recognition to the current cost of replacing property, plant and equipment, based on past practices the Company believes that it will be allowed to earn on the increased cost of its net investment when replacement of facilities occurs. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAFinancial Statements and Supplementary Data Index to Financial Statements - ----------------------------- Page ---- Financial Statements: Report of Independent Accountants 5330 Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 1994 541995 31 Consolidated Balance Sheets at September 30, 1995 and 1994 and 1993 55 - 5632-33 Consolidated Statement of Cash Flows, three years ended September 30, 1994 571995 34 Notes to Consolidated Financial Statements 58 - 8835-58 Financial Statement Schedules: For the three years ended September 30, 1994 V -Property, Plant and Equipment 89 and 91 VI -Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 90 - 91 VIII-Valuation1995 II-Valuation and Qualifying Accounts and Reserves 92 IX -Short-Term Borrowings 93 X -Supplementary Income Statement Information 9459 All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto. Supplementary Data - ------------------ Supplementary data that is included in Note IJ - "QuarterlyQuarterly Financial Data (unaudited)" and Note KL - "SupplementarySupplementary Information Forfor Oil and Gas Producing Activities," appears on page 82 and pages 84 to 88, respectively, ofunder this report,Item, and reference is made thereto. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)Report of Management - -------------------- Management is responsible for the preparation and integrity of the Company's financial statements. The financial statements have been prepared in accordance with generally accepted accounting principles consistently applied, and necessarily include some amounts that are based on management's best estimates and judgment. The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management's authorization. The Company's financial statements have been examined by our independent accountants, Price Waterhouse LLP, which also conducts a review of internal controls to the extent required by generally accepted auditing standards. The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors and Price Waterhouse LLP to review planned audit scope and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent accountants have direct access to the Audit Committee and periodically meet with it without management representatives present. Report of Independent Accountants To the Board of Directors and Shareholders of National Fuel Gas Company In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 19941995 and 1993,1994, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1994,1995, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Notes A and FG to the consolidated financial statements, the Company adopted the new accounting standards for postretirement benefits other than pensions, income taxes and other postemployment benefits in fiscal 1994. PRICE WATERHOUSE LLP Buffalo, New York October 28, 199427, 1995 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) National Fuel Gas Company Consolidated Statements of Income and Earnings Reinvested in the Business Year Ended September 30 1994 1993 1992 (Thousands of Dollars) INCOME Operating Revenues $1,141,324 $1,020,382 $920,450 Operating Expenses Purchased Gas 497,687 409,005 363,690 Operation Expense 260,411 258,918 240,645 Maintenance 30,979 24,312 22,439 Property, Franchise and Other Taxes 103,788 95,393 89,158 Depreciation, Depletion and Amortization 74,764 69,425 55,726 Income Taxes - Net 47,792 41,046 35,231 1,015,421 898,099 806,889 Operating Income 125,903 122,283 113,561 Other Income 3,656 4,833 5,790 Income Before Interest Charges 129,559 127,116 119,351 Interest Charges Interest on Long-Term Debt 36,699 38,507 39,949 Other Interest 10,425 13,392 19,092 47,124 51,899 59,041 Income Before Cumulative Effect 82,435 75,217 60,310 Cumulative Effect of Changes in Accounting 3,237 - - Net Income Available for Common Stock 85,672 75,217 60,310 EARNINGS REINVESTED IN THE BUSINESS Balance at Beginning of Year 335,907 314,334 301,066 421,579 389,551 361,376 Dividends on Common Stock 57,725 53,644 47,042 Balance at End of Year $ 363,854 $ 335,907 $314,334 Earnings Per Common Share Income Before Cumulative Effect $2.23 $2.15 $1.94 Cumulative Effect of Changes in Accounting .09 - - Net Income Available for Common Stock $2.32 $2.15 $1.94 Weighted Average Common Shares Outstanding 37,046,249 34,938,722 31,152,635
National Fuel Gas Company Consolidated Statements of Income and Earnings Reinvested in the Business Year Ended September 30 (Thousands of Dollars) 1995 1994 1993 ---- ---- ---- Income Operating Revenues $ 975,496 $1,141,324 $1,020,382 ---------- ---------- ---------- Operating Expenses Purchased Gas 351,094 497,687 409,005 Operation Expense 266,786 260,411 258,918 Maintenance 25,719 30,979 24,312 Property, Franchise and Other Taxes 91,837 103,788 95,393 Depreciation, Depletion and Amortization 71,782 74,764 69,425 Income Taxes - Net 43,879 47,792 41,046 ---------- ---------- ---------- 851,097 1,015,421 898,099 ---------- ---------- ---------- Operating Income 124,399 125,903 122,283 Other Income 5,378 3,656 4,833 ---------- ---------- ---------- Income Before Interest Charges 129,777 129,559 127,116 ---------- ---------- ---------- Interest Charges Interest on Long-Term Debt 40,896 36,699 38,507 Other Interest 12,987 10,425 13,392 ---------- ---------- ---------- 53,883 47,124 51,899 ---------- ---------- ---------- Income Before Cumulative Effect 75,894 82,435 75,217 Cumulative Effect of Changes in Accounting - 3,237 - ---------- ---------- ---------- Net Income Available for Common Stock 75,894 85,672 75,217 Earnings Reinvested in the Business Balance at Beginning of Year 363,854 335,907 314,334 ---------- ---------- ---------- 439,748 421,579 389,551 Dividends on Common Stock 59,625 57,725 53,644 ---------- ---------- ---------- Balance at End of Year $ 380,123 $ 363,854 $ 335,907 ========== ========== ========== Earnings Per Common Share Income Before Cumulative Effect $2.03 $2.23 $2.15 Cumulative Effect of Changes in Accounting - .09 - ---------- ---------- ---------- Net Income Available for Common Stock $2.03 $2.32 $2.15 ========== ========== ========== Weighted Average Common Shares Outstanding 37,396,875 37,046,249 34,938,722 ========== ========== ========== See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) National Fuel Gas Company Consolidated Balance Sheets At September 30 1994 1993 (Thousands of Dollars) ASSETS Property, Plant and Equipment $2,166,256 $2,039,436 Less - Accumulated Depreciation, Depletion and Amortization 623,517 561,433 1,542,739 1,478,003 Current Assets Cash and Temporary Cash Investments 29,016 13,595 Receivables - Net 95,993 86,957 Unbilled Utility Revenue 17,311 27,210 Gas Stored Underground 34,711 22,120 Materials and Supplies - at average cost 23,796 20,848 Unrecovered Purchased Gas Costs - 20,772 Prepayments 20,111 17,094 220,938 208,596 Other Assets Recoverable Future Taxes 99,742 - Unamortized Debt Expense 28,396 28,735 Other Regulatory Assets 47,737 43,644 Deferred Charges 15,796 21,255 Other 26,309 21,307 217,980 114,941 $1,981,657 $1,801,540
National Fuel Gas Company Consolidated Balance Sheets At September 30 (Thousands of Dollars) 1995 1994 ---- ---- Assets Property, Plant and Equipment $2,322,335 $2,169,067 Less - Accumulated Depreciation, Depletion and Amortization 673,153 623,517 ---------- ---------- 1,649,182 1,545,550 ---------- ---------- Current Assets Cash and Temporary Cash Investments 12,757 29,016 Receivables - Net 75,933 95,494 Unbilled Utility Revenue 20,838 17,311 Gas Stored Underground 25,589 31,900 Materials and Supplies - at average cost 24,374 23,796 Prepayments 29,753 20,609 ---------- ---------- 189,244 218,126 ---------- ---------- Other Assets Recoverable Future Taxes 94,053 99,742 Unamortized Debt Expense 26,976 28,396 Other Regulatory Assets 37,040 47,737 Deferred Charges 8,653 15,797 Other 33,154 26,309 ---------- ---------- 199,876 217,981 ---------- ---------- $2,038,302 $1,981,657 ========== ========== See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) National Fuel Gas Company Consolidated Balance Sheets At September 30 1994 1993 (Thousands of Dollars) CAPITALIZATION AND LIABILITIES Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 100,000,000 Shares; Issued and Outstanding - 37,278,409 Shares and 36,661,008 Shares, Respectively $ 37,278 $ 36,661 Paid In Capital 379,156 363,677 Earnings Reinvested in the Business 363,854 335,907 Total Common Stock Equity 780,288 736,245 Long-Term Debt, Net of Current Portion 462,500 478,417 Total Capitalization 1,242,788 1,214,662 Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 112,500 196,800 Current Portion of Long-Term Debt 96,000 - Accounts Payable 66,667 42,893 Amounts Payable to Customers 38,714 40,776 Other Accruals and Current Liabilities 61,368 69,523 375,249 349,992 Deferred Credits Accumulated Deferred Income Taxes 273,560 188,793 Taxes Refundable to Customers 31,688 - Unamortized Investment Tax Credit 14,057 14,743 Other Deferred Credits 44,315 33,350 363,620 236,886 Commitments and Contingencies - - $1,981,657 $1,801,540
National Fuel Gas Company Consolidated Balance Sheets At September 30 (Thousands of Dollars) 1995 1994 ---- ---- Capitalization and Liabilities Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 100,000,000 Shares; Issued and Outstanding - 37,434,363 Shares and 37,278,409 Shares, Respectively $ 37,434 $ 37,278 Paid In Capital 383,031 379,156 Earnings Reinvested in the Business 380,123 363,854 ---------- ---------- Total Common Stock Equity 800,588 780,288 Long-Term Debt, Net of Current Portion 474,000 462,500 ---------- ---------- Total Capitalization 1,274,588 1,242,788 ---------- ---------- Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 147,600 112,500 Current Portion of Long-Term Debt 88,500 96,000 Accounts Payable 53,842 68,293 Amounts Payable to Customers 51,001 38,714 Other Accruals and Current Liabilities 52,118 59,742 ---------- ---------- 393,061 375,249 ---------- ---------- Deferred Credits Accumulated Deferred Income Taxes 288,763 273,560 Taxes Refundable to Customers 23,080 31,688 Unamortized Investment Tax Credit 13,380 14,057 Other Deferred Credits 45,430 44,315 ---------- ---------- 370,653 363,620 ---------- ---------- Commitments and Contingencies - - ---------- ---------- $2,038,302 $1,981,657 ========== ========== See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) National Fuel Gas Company Consolidated Statement of Cash Flows Year Ended September 30 1994 1993 1992 (Thousands of Dollars) 1995 1994 1993 ---- ---- ---- OPERATING ACTIVITIESOperating Activities Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217 $ 60,310 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities Effect of Noncash Adjustments: Cumulative Effect of Changes in Accounting - (3,237) - - Depreciation, Depletion and Amortization 71,782 74,764 69,425 55,726 Deferred Income Taxes 8,452 4,853 16,919 14,125 Other 275 5,780 5,574 2,997 167,832 167,135 133,158 Change in: Receivables and Unbilled Utility Revenue 16,034 863 (21,531) (12,074) Gas Stored Underground and Materials and Supplies 5,733 (15,539) 7,156 (5,221) Unrecovered Purchased Gas Costs - 20,772 (7,739) (7,703) Prepayments (9,144) (3,017) (1,489) 2,862 Accounts Payable (14,451) 23,774 (2,579) 4,349 Amounts Payable to Customers 12,287 (2,062) (18,808) (6,728) Other Accruals and Current Liabilities (1,305) 3,072 15,249 15,704 Other Assets and Liabilities - Net 7,903 3,534 (13,691) (31,359)-------- -------- -------- Net Cash Provided by Operating Activities 173,460 199,229 123,703 92,988 INVESTING ACTIVITIES-------- -------- -------- Investing Activities Capital Expenditures (182,826) (135,084) (131,926) (157,856) Other 10,646 3,586 225 (2,052)-------- -------- -------- Net Cash Used in Investing Activities (172,180) (131,498) (131,701) (159,908) FINANCING ACTIVITIES-------- -------- -------- Financing Activities Change in Notes Payable to Banks and Commercial Paper 35,100 (84,300) (30,200) 20,500 Proceeds from Issuance of Long-Term Debt 100,000 100,000 129,000 251,000 Reduction of Long-Term Debt (96,000) (19,917) (180,083) (176,729) Proceeds from Issuance of Common Stock 2,555 9,064 78,822 73,728 Dividends Paid on Common Stock (59,194) (57,157) (52,224) (45,634)-------- -------- -------- Net Cash Provided by (Used In)Used in Financing Activities (17,539) (52,310) (54,685) 122,865-------- -------- -------- Net Increase (Decrease) in Cash and Temporary Cash Investments (16,259) 15,421 (62,683) 55,945 Cash and Temporary Cash Investments at Beginning of Year 29,016 13,595 76,278 20,333-------- -------- -------- Cash and Temporary Cash Investments at End of Year $ 12,757 $ 29,016 $ 13,595 $ 76,278======== ======== ======== See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)National Fuel Gas Company Notes to Consolidated Financial Statements Note A - Summary of Significant Accounting Policies Principles of Consolidation.Consolidation The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated where appropriate. Reclassification.The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Reclassification Certain prior year amounts have been reclassified to conform with current year presentation. Regulation.Regulation Two of the Company's principal subsidiaries, National Fuel Gas Distribution Corporation (Distribution Corporation) and National Fuel Gas Supply Corporation, (Supply Corporation) are subject to regulation by state and federal authorities having jurisdiction. The Company accounts for these regulated operations in accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation." This statement sets forth the application ofDistribution Corporation and Supply Corporation have accounting policies which conform to generally accepted accounting principles, for those companies whose ratesas applied to regulated enterprises, and are established by or are subject to approval by an independent third-party regulator. Under SFAS 71, regulated companies defer costs as assets on the balance sheet (regulatory assets) when these costs have been or are expected to be allowed in the ratesetting process in a period different from the period in which the costs would be charged to expense by an unregulated company. These deferred regulatory assets are then flowed through the income statement in the period in which the same amounts are recovered in revenues through rates. Costs deferred in accordance with SFAS 71 include "Recoverable Future Taxes," "Unamortized Debt Expense"the accounting requirements and "Other Regulatory Assets." Referratemaking practices of the regulatory authorities. Reference is made to the separate Income Taxes and Unamortized Debt Expense sections of this Note B for further discussion. Otherdiscussion of regulatory assets are shown below: At September 30 (in thousands) 1994 1993 Pension and Post-Retirement Benefit Costs (Note F) $17,199 $ 8,125 Order 636 Transition Costs* (Note B) 8,417 200 Deferred Contract Reformation Costs (Note B) 7,736 24,862 Environmental Clean-up (Note G) 7,310 4,873 All Other 7,075 5,584 $47,737 $43,644 * Exclusive of amounts being collected through gas costs. Such amounts are included in unrecovered purchased gas costs. Revenues.matters. Revenues Revenues are recorded as bills are rendered, except that service supplied but not billed is reported as "Unbilled Utility Revenue" and is included in operating revenues for the year in which service is furnished. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Unrecovered Purchased Gas Costs and Refunds.Refunds Distribution Corporation's rate schedules contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Supply Corporation collects revenues subject to refund if rates in effect are pending a final rate case determination by the Federal Energy Regulatory Commission (FERC). Estimated rate refund liabilities are recorded which reflect management's current estimate as to the ultimate outcome of each rate case. Property, Plant and Equipment.Equipment The principal assets, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities. Such cost includes an Allowance for Funds Used During Construction (AFUDC), which is defined in applicable regulatory systems of accounts as the net cost of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. The rates used in the calculation of AFUDC are determined in accordance with guidelines established by regulatory authorities. Included in property, plant and equipment is the cost of gas stored underground - noncurrent, representing the volume of gas required to maintain pressure levels for normal operating purposes.purposes as well as gas volumes maintained for system balancing purposes, including those needed for no-notice transportation service. Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries' property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation. Oil and gas exploration and development costs are capitalized under the full-cost method of accounting as prescribed by the Securities and Exchange Commission (SEC). All costs directly associated with property acquisition, exploration and development activities are capitalized, with the principal limitation that such capitalized amounts not exceed the present value of estimated future net revenues from the production of proved gas and oil reserves plus the lower of cost or market of unevaluated properties, net of related income tax effect. The present value of estimated future net revenues was computed based on end-of-year prices adjusted for contracted price changes. At September 30, 1995, Seneca did not experience an impairment of its oil and gas assets under the SEC full cost accounting rules. There are certain factors, including price declines, which could cause an impairment of Seneca's oil and gas assets. Depreciation, Depletion and Amortization.Amortization Depreciation, depletion and amortization are computed by application of either the straight-line method or the gross revenue method, in amounts sufficient to recover costs over the estimated service lives of property in service, and for oil and gas properties, over the period of estimated gross revenues from proved reserves. The costs of unevaluated oil and gas properties are excluded from this calculation. For timber properties, depletion, determined on a property by property basis, is charged to operations based on the annual amount of timber cut in relation to the total amount of recoverable timber. The provisions for depreciation, depletion and amortization, including amounts capitalized or charged to other operating accounts, were $75,686,000$73.1 million in 1995, $75.7 million in 1994 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) $70,629,000and $70.6 million in 1993, and $56,506,000 in 1992, and were equivalent to 3.5% in 1995, 3.9% in 1994 and 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and equipment for those years. Gas Stored Underground - Current.Current Gas stored is carried at cost, on a last-in, first-out (LIFO) basis. Under present regulatory practice, the liquidation of a LIFO layer is reflected in future gas cost adjustment clauses. Based upon the average price of spot market gas purchased in September 1994,1995, including transportation costs, the current cost of replacing the inventory of gas stored underground-current exceeded the amount stated on a LIFO basis by approximately $19,300,000$19.2 million at September 30, 1994.1995. Unamortized Debt Expense.Expense Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related issues. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. Income Taxes.Taxes The Company and its wholly-owned subsidiaries file a consolidated federal income tax return. Prior to its repeal in 1986, Investment Tax Credit was either reflected currently in income or deferred and amortized to income over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction. On October 1, 1993, the Company adopted SFASStatement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109). The adoption of SFAS 109, which changed the Company's method of accounting for income taxes from the deferred method to an asset and liability approach. Previously, deferred taxes were provided for the tax effects of timing differences between financial reporting purposes and tax reporting purposes except where not permitted by regulatory authorities. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences attributable to temporary differences between the carrying amounts of assets and liabilities and their tax bases. In addition, such deferred tax assets and liabilities will be adjusted for the effects of enacted changes in tax laws and rates.taxes. The cumulative effect of this change increased net income for the fiscal year ended September 30, 1994 by $3,826,000$3.8 million as a result of the reduction in deferred income taxes associated with the Company's nonregulated operations. The effect on the recorded deferred income taxes associated with rate-regulated activities was to reclassify a portion to a regulatory liability since such amounts are expected to be refundable to customers under regulatory procedures. This liability amounted to $31,688,000 at September 30, 1994. In addition, under SFAS 109, the Company is required to recognize additional deferred taxes for timing differences on which deferred tax treatment was not permitted by regulatory authorities. The recognition of these deferred tax balances had no effect on earnings due to the recording of corresponding regulatory assets representing future amounts collectible from customers in the ratemaking process. Substantially all of these deferred taxes relate to property, plant and equipment and related investment tax credits and will be amortized consistent with the depreciation and amortization of these accounts. The additional deferred taxes amounted to $99,742,000 at September 30, 1994. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Financial Instruments. In October 1994, the Financial Accounting Standards Board (FASB) issued SFAS 119, "Disclosure about Derivative Financial Instruments The Company, in its Exploration and Fair Value of Financial Instruments" (SFAS 119). This statement requires disclosures about amounts, nature, and terms of derivative financial instruments. It also requires that a distinction be made between financial instruments held or issued for trading purposes and those held or issued for purposes other than trading. The Company's disclosure is in accordance with the provisions of SFAS 119. Seneca Resources Corporation (Seneca) has entered into certainProduction segment, utilizes price swap agreements that effectively hedge a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These agreements are not held for trading purposes. The price swap agreements call for Seneca to receive monthly payments from (or make payments to) other parties based upon the differential between a fixed and a variable price as specified by the agreement. At September 30, 1994, Seneca had natural gas price swap agreements which run through December 1996 and have an aggregate notional amount of approximately 16.2 billion cubic feet (Bcf) of natural gas equivalent. In October 1994, Seneca entered into natural gas price swap agreements for an additional aggregate notional amount of approximately 3.6 Bcf of natural gas equivalent. These agreements cover the period from March 1995 through February 1996. Seneca also had crude oil price swap agreements at September 30, 1994, which run through September 1997 and have an aggregate notional amount of 773,000 barrels of crude oil equivalent. Gains or losses from these price swap agreements are reflected in operating revenues on the Consolidated Statement of Income at the time of settlement with the other parties, whichparties. Reference is when the underlying hedged commodity transaction occurs. National Fuel Resources, Inc. (NFR) participates in the natural gas futures marketmade to lock in natural gas prices to decrease volatility related to fluctuations in market prices. Futures are not heldNote F - Financial Instruments, for trading purposes. At September 30, 1994, NFR had short positions on futures amounting to approximately 1.1 Bcffurther discussion of natural gas. It also had long positions on futures amounting to approximately .1 Bcf of natural gas. Gains or losses resulting from changes in the market value of these transactions are deferred until the hedged commodity transaction occurs, at which point they are reflected in operating revenues on the Consolidated Statement of Income. Seneca and NFR are at risk in the event of nonperformance by counterparties on natural gas and crude oil price swap agreements and natural gas futures, respectively, but Seneca and NFR do not anticipate nonperformance by any of these counterparties. The Company currently has authorization from the SEC to enter into interest rate swap agreements and certain other derivative instruments up to a notional amount of $350,000,000. Currently, no such agreements are outstanding.financial instruments. Consolidated Statement of Cash Flows.Flows For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. Interest paid in 1995, 1994 and 1993 was $53.5 million, $46.2 million and 1992 was $46,183,000, ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) $48,282,000 and $58,530,000,$48.3 million, respectively. Net income taxes paid in 1995, 1994 and 1993 were $34.6 million, $37.6 million and 1992 were $37,573,000, $19,872,000 and $15,282,000,$19.9 million, respectively. In December 1993, the Company entered into a non-cash investing activity whereby it issued 108,396 shares of Company common stock to Empire Exploration, Inc. (Empire), which in turn exchanged those shares for $3,184,000$3.2 million of natural gas production assets, $167,000 of other current assets and $280,000 of cash. On July 1, 1994, Empire was merged into Seneca.assets. Earnings Per Common Share.Share Earnings per common share are calculated using the weighted average number of shares outstanding during each fiscal year. Common stock equivalents in the form of stock options do not have a material dilutive effect on earnings per common share. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)New Accounting Pronouncement In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS 121). This statement establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles and goodwill related to those assets to be held and used and for long-lived assets and certain identifiable intangibles to be disposed of. Essentially, SFAS 121 requires review of these assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. SFAS 121 also requires that a rate-regulated enterprise recognize an impairment for the amount of costs excluded when a regulator excludes all or part of a cost from an enterprise's rate base or when regulatory assets are no longer probable of recovery. The Company has adopted SFAS 121 with no impact on its results of operations for 1995. Note B - Regulatory Matters Regulatory Assets and Liabilities Distribution Corporation and Supply Corporation have incurred various costs and received various credits which have been reflected as regulatory assets and liabilities on the Company's consolidated balance sheets. Accounting for such costs and credits as regulatory assets and liabilities is in accordance with SFAS 71, "Accounting for the Effect of Certain Types of Regulation" (SFAS 71). This statement sets forth the application of generally accepted accounting principles for those companies whose rates are established by or are subject to approval by an independent third-party regulator. Under SFAS 71, regulated companies defer costs and credits on the balance sheet as regulatory assets and liabilities when it is probable that those costs and credits will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in income by an unregulated company. These deferred regulatory assets and liabilities are then flowed through the income statement in the period in which the same amounts are reflected in rates. Distribution Corporation and Supply Corporation have recorded the following regulatory assets and liabilities:
At September 30 (in thousands) 1995 1994 ---- ---- Regulatory Assets: Recoverable Future Taxes (Note C) $ 94,053 $ 99,742 Unamortized Debt Expense (Note A) 22,035 23,751 Pension and Post-Retirement Benefit Costs (Note G) 18,412 17,199 Order 636 Transition Costs* 12,358 8,417 Environmental Clean-up (Note H) 7,475 7,310 Other (1,205) 14,811 -------- -------- Total Regulatory Assets 153,128 171,230 -------- -------- Regulatory Liabilities: Amounts Payable to Customers (Note A) 51,001 38,714 Taxes Refundable to Customers (Note C) 23,080 31,688 Other 8,628 9,513 -------- -------- Total Regulatory Liabilities 82,709 79,915 -------- -------- Net Regulatory Position $ 70,419 $ 91,315 ======== ======== * Exclusive of amounts being collected through gas costs. Such amounts are included in unrecovered purchased gas costs or amounts payable to customers.
If for any reason, including deregulation, a change in the method of regulation, or a change in competitive environment, Distribution Corporation and/or Supply Corporation ceases to meet the criteria for application of SFAS 71 for all or part of their operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in income of the period in which the discontinuance of SFAS 71 occurs. Such amounts would be classified as an extraordinary item. Distribution Corporation and Supply Corporation are not currently facing a requirement to discontinue SFAS 71. Order 636 Transition Costs.Costs As a result of the industrywide restructuring under the FERC's Order 636, Distribution Corporation is incurring transition costs billed by Supply Corporation and other upstream pipeline companies. AtAs of September 30, 1994,1995, Distribution Corporation's estimate of its exposure to outstanding transition cost claims is in the range of $4,600,000$7.1 million to $80,700,000.$71.0 million. The majority of theseestimated maximum exposure is declining as transition costs relate to gas supply realignment (GSR) costsare incurred and stranded costs and is exclusive of any potential stranded costs related to production plant or gathering facilities which pipeline companies, including Supply Corporation, may file for at a future date, and any potential GSR costs claimed by an upstream supplier, which are subject to the outcome of its bankruptcy and FERC proceedings.paid. At September 30, 1994, the Company1995, Distribution Corporation has recorded the minimum liability and corresponding regulatory asset of $4,600,000.$7.1 million. Distribution Corporation has authorization from the State of New York Public Service Commission (PSC) to recover up to $11,000,000 annually ofis currently recovering transition costs from its sales customers in New York throughand its sales and transportation customers in Pennsylvania. Recovery of the monthly Gas Adjustment Clause (GAC). Distribution Corporation will defer, for recovery in future periods, any amounts that may exceed the $11,000,000 annual amount. The recoveryallocable portion of transition costs fromrelated to Distribution Corporation's transportation customers in New York remains unresolved. The PSC has postponed its decision on transportation customers' allocable share of transition costs pending further considerationis expected to begin upon the Public Service Commission of the issueState of New York's (PSC) acceptance of a compliance filing made in a generic restructuring case (the Generic Case) which began in October 1993. The PSC staff's position inNovember 1995. It is expected that the Generic Case is that transportation customers shouldcompliance filing will be assigned a per-unit charge that is equal to 50%accepted by the Spring of the per-unit charge being collected from sales customers for GSR and stranded costs. The PSC has authorized Distribution Corporation's continued deferral of transition costs relating to transportation customers until resolution in the Generic Case. At September 30, 1994, deferred transition costs related to transportation customers amounted to $2,031,000. In its Pennsylvania jurisdiction, Distribution Corporation is recovering GSR and stranded costs from its customers through a separate surcharge. At September 30, 1994, Distribution Corporation had deferred GSR and stranded costs of $900,000. Distribution Corporation will recover these costs through a true-up mechanism whereby it is allowed to update its surcharge on a quarterly basis. Distribution Corporation is recovering under-recovered purchased gas transition costs from its Pennsylvania sales customers through its gas cost recovery rates.1996. Distribution Corporation will continue to actively challenge relevant FERC filings made by the upstream pipeline companies to ensure the eligibility and prudency of all transition cost claims. This industrywide issue will potentially involve years of rate proceedings before the FERC, state commissions and the courts. Management believes that any transition costs resulting from the implementation of Order 636 which have been determined to ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) be both eligible and prudently incurred should be fully recoverable from the respective customers of Supply Corporation and Distribution Corporation.customers. Gathering Rates.Rates Supply Corporation has approximately $19,000,000$20.0 million of net production and gathering facilities used, in part, to gather natural gas of local producers, including the Company's production in the Appalachian Region. Currently, Supply Corporation has a gathering rate in place under an interim settlement with customers and local producers. In its restructuring orders, the FERC has directed Supply Corporation to fully unbundle its gathering rate effective July 1, 1995. Supply Corporation submitted an offer of settlement (the Settlement) which if approved would provide for a ten-year transition to fully unbundle rates beginning July 1, 1995. Comments on the Settlement have been filed by the parties. Such comments were generally favorable. However, opposition came largely from offsystem customers claiming that they should not have any cost responsibility for the production and gathering plant becausecost of service from the transmission cost of service, and to establish a separate gathering rate. A Stipulation and Agreement complying with the FERC's directives was filed with the FERC in September 1995 and the Administrative Law Judge certified it as uncontested to the FERC. Approval is not necessary to provide service to them. The Settlement currently awaits a FERC decision. The FERC has, however, also directedexpected early in calendar 1996. If approved, it will permit Supply Corporation to file a fully unbundled rate by December 31, 1994, that would become immediately effective on July 1, 1995. Supply Corporation has requested an extensionrecover its investment in production and gathering plant, as well as its gathering cost of the December deadline to April 28, 1995, since approval of the Settlement in the meantime would make further filings unnecessary. Contract Reformation Issues. As a result of the FERC's Orders 436 and 528 issued in October 1985 and November 1990, respectively, pipeline companies have made, and have agreed to make, payments to producers in exchange for reformation of the price and/or take-or-pay provisions of their long-term wellhead gas supply arrangements, also referred to as contract reformation costs (CRC). The Company is currently recovering from its customers substantially all CRC billed to it. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)service. Note C - Income Taxes Deferred tax liabilities (assets) were comprised of the following: At September 30, 1994 (in thousands) Accumulated Deferred Deferred Income Taxes Income Taxes Current* Deferred Tax Liabilities: Excess of Tax Over Book Depreciation $174,006 $ - Exploration and Intangible Well Drilling Costs 78,224 - Other 64,181 - Total Deferred Tax Liabilities 316,411 - Deferred Tax Assets: Deferred Investment Tax Credits (8,388) - Overheads Capitalized for Tax Purposes (9,238) - Provisions for Rate Contingencies and Refunds - (686) Unrecovered Purchased Gas Costs - (3,762) Other (25,225) - Total Deferred Tax Assets (42,851) (4,448) Total Net Deferred Income Taxes $273,560 $( 4,448) * Included on the Consolidated Balance Sheets in "Other Accruals and Current Liabilities." The components of federal and state income taxes included in the Consolidated Statement of Income are as follows: Year Ended September 30 (in thousands) 1994 1993 1992 Operating Expenses: Current Income Taxes - Federal $36,630 $21,148 $17,680 State 6,309 2,979 3,426 Deferred Income Taxes 4,853 16,919 14,125
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Operating Expenses: Current Income Taxes - Federal $30,522 $36,630 $21,148 State 4,905 6,309 2,979 Deferred Income Taxes 8,452 4,853 16,919 ------- ------ ------ 43,879 47,792 41,046 35,231 Other Income: Deferred Investment Tax Credit (672) (682) (693) (706) Cumulative Effect of Changes in Accounting: Adoption of SFAS 109 - (3,826) - Tax Effect of Adoption of SFAS 112 - (425) - ------- ------ ------ Total Income Taxes $43,207 $42,859 $40,353 ======= ======= =======
Prior to the adoption of SFAS 109 (3,826) - - Tax Effectin 1994, deferred income tax expense resulted from timing differences between the recognition of Adoptionrevenues and expenses for income tax and financial reporting purposes except where not permitted by regulatory authorities. The sources of SFAS 112 (425) - - Total Income Taxes $42,859 $40,353 $34,525these timing differences and the related income tax effect of each are as follows:
Year Ended September 30 (in thousands) 1993 ---- Unrecovered Purchased Gas Costs $11,641 Excess of Tax Over Book Depreciation 6,717 Exploration and Intangible Well Drilling Costs 7,377 Revenue Refunds Payable to Customers (2,994) Debt Retirement Costs 3,780 Tax Credit Carryforward (2,608) Miscellaneous (6,994) ------- Total Deferred Income Taxes $16,919 =======
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Net Income Available for Common Stock $ 75,894 $ 85,672 $ 75,217 Total Income Taxes 43,207 42,859 40,353 -------- -------- -------- Income Before Income Taxes $119,101 $128,531 $115,570 ======== ======== ======== Income Tax Expense, Computed at Statutory Rate of 35% in 1995 and 1994 and 34.75% in 1993 $41,685 $ 44,986 $40,161 Increase (Reduction) in Taxes Resulting from: Current State Income Taxes 3,188 4,101 1,944 Depreciation 2,397 2,174 2,221 Production Tax Credits (899) (1,658) (2,608) Adoption of SFAS 109 - (3,826) - Miscellaneous (3,164) (2,918) (1,365) ------- ------- ------ Total Income Taxes $43,207 $42,859 $40,353 ======= ======= =======
Significant components of the Company's deferred tax liabilities and assets were as follows:
At September 30 (in thousands) 1995 1994 ------------------------- ------------------------- Accumulated Deferred Accumulated Deferred Deferred Income Taxes Deferred Income Taxes Income Taxes Current* Income Taxes Current* ------------ ------------ ------------ ------------ Deferred Tax Liabilities: Excess of Tax Over Book Depreciation $185,595 $ - $ 174,006 $ - Exploration and Intangible Well Drilling Costs 84,380 - 78,224 - Other 67,831 - 64,181 - -------- ------- --------- ------- Total Deferred Tax Liabilities 337,806 - 316,411 - ======== ======= ========= ======= Deferred Tax Assets: Deferred Investment Tax Credits (7,860) - (8,388) - Overheads Capitalized for Tax Purposes (11,766) - (9,238) - Unrecovered Purchased Gas Costs - (8,322) - (4,448) Other (29,417) - (25,225) - -------- ------- --------- ------- Total Deferred Tax Assets (49,043) (8,322) (42,851) (4,448) ======== ======= ========= ======= Total Net Deferred Income Taxes $288,763 $(8,322) $ 273,560 $(4,448) ======== ======= ========= ======= * Included on the Consolidated Balance Sheets in "Other Accruals and Current Liabilities."
SFAS 109 requires the recognition of regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers. These amounted to $23.1 million and $31.7 million at September 30, (in thousands)1995 and 1994, 1993 1992 Net Income Available for Common Stock $ 85,672 $ 75,217 $60,310 Total Income Taxes 42,859 40,353 34,525 Income Before Income Taxes $128,531 $115,570 $94,835 Income Tax Expense, Computed at Statutory Rate of 35% in 1994 and 34.75% in 1993 and 34% in 1992 $ 44,986 $40,161 $32,244 Increase (Reduction) in Taxes Resulting from: Current State Income Taxes 4,101 1,944 2,261 Depreciation 2,174 2,221 1,893 Production Tax Credits (1,658) (2,608) (520) Adoption ofrespectively. Also, SFAS 109 (3,826) - - Miscellaneous (2,918) (1,365) (1,353) Total Income Taxes $42,859 $40,353 $34,525requires the recognition of additional deferred income taxes not previously recorded because of prior ratemaking practices. Substantially all of these deferred taxes relate to property, plant and equipment and related investment tax credits and will be amortized consistent with the depreciation and amortization of these accounts. The additional deferred taxes and corresponding regulatory assets, representing future amounts collectible from customers in the ratemaking process, amounted to $94.1 million and $99.7 million at September 30, 1995 and 1994, respectively. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Note D - Capitalization
Summary of Changes in Common Stock Equity Earnings Paid Reinvested Common Stock In in the (in thousands) Shares Amount Capital Business ------ ------ ------- ---------- Balance at September 30, 1992 33,856 $33,856 $284,143 $314,334 Net Income Available for Common Stock 75,217 Dividends Declared on Common Stock ($1.52 Per Share) (53,644) Common Stock Issued: Sale of Common Stock 2,500 2,500 71,425 Stock Options and Stock Award Plans 50 50 832 401(k) Plans 115 115 3,423 Customer Stock Purchase Plan 140 140 4,101 Common Stock Issuance Costs (247) ------ ------- -------- -------- Balance at September 30, 1993 36,661 36,661 363,677 335,907 Net Income Available for Common Stock 85,672 Dividends Declared on Common Stock ($1.56 Per Share) (57,725) Common Stock Issued: Acquisition of Natural Gas Production Assets 108 108 3,523 Stock Options and Stock Award Plans 164 164 1,163 401(k) Plans 136 136 4,234 Customer Stock Purchase Plan 209 209 6,559 ------ ------- -------- -------- Balance at September 30, 1994 37,278 37,278 379,156 363,854 Net Income Available for Common Stock 75,894 Dividends Declared on Common Stock ($1.60 Per Share) (59,625) Common Stock Issued: Stock Options and Stock Award Plans 22 22 377 401(k) Plans 88 88 2,310 Customer Stock Purchase Plan 46 46 1,188 ------ ------- -------- Balance at September 30, 1995 37,434 $37,434 $383,031 $380,123* ====== ======= ======== ========= * The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 1995, $305.7 million of accumulated earnings was free of such limitations.
Common Stock.Stock The Company issued 2,500,000has various plans which allow shareholders, customers and employees to purchase shares of Company common stock in each of May 1993 and September 1992.stock. The shares issued in May 1993 were sold to the public at a price of $30.50 per share, and the net proceeds to the Company after underwriting discounts and commissions were $29.57 per share, or $73,925,000. The shares issued in September 1992 were sold to the public at a price of $27.625 per share, and the net proceeds to the Company after underwriting discounts and commissions were $26.715 per share, or $66,787,500. Through the Company's Dividend Reinvestment and Stock Purchase Plan (DRP), holders of shares of the Company's common stock mayallows shareholders to reinvest cash dividends and/or make cash investments in the Company's common stock of the Company. In 1994 and 1993, open market shares were utilized for issuance under the DRP. In 1992, 65,015 new shares as well as open market shares were issued under the DRP. Under the Company's section 401(k) plans, the Company issued 136,100 shares, 115,300 shares and 108,700 shares of common stock during 1994, 1993 and 1992, respectively.stock. The Company's Customer Stock Purchase Plan (CSPP) provides residential customers the opportunity to acquire shares of Company common stock without the payment of any brokerage commission or service charges in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in Company common stock, in addition to a variety of other investment alternatives. At the discretion of the Company, the shares purchased under the CSPPthese plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an agent. The Company issued 208,990 shares, 139,986 shares and 156,607 shares of common stock under the CSPP during 1994, 1993 and 1992, respectively. Effective March 17, 1992, after having received shareholder approval, the Company amended its Restated Certificate of Incorporation, as amended, to change the designation of its authorized and issued common stock from shares having no par value to shares having a par value of $1 per share. Accordingly, $214,461,000 was transferred from Common Stock to Paid In Capital. This change eliminated unnecessary additional qualification and licensing fees incurred by the Company in certain states as a result of having no par value common stock. This change has no effect on the rights and privileges of Company stockholders. Stock Options and Stock Award Plans.Plans The Company's 1993 Award and Option Plan (1993 Plan) provides for the issuance of incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, performance units and performance shares to key employees. The 1983 Incentive Stock Option Plan (1983 Plan) provided for the issuance of incentive stock options to key employees, and the 1984 Stock Plan (1984 Plan) provided for awards of restricted stock, nonqualified stock options and stock appreciation rights to key employees. Stock options under all three plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) In 1993, the authorized maximum number of shares of common stock under the 1983 Plan and 1984 Plan was reached, and therefore no further options or restricted stock have been awarded under these plans. Under the 1993 Plan, the maximum number of shares of common stock available for option grants and stock awards is 1,600,000 shares. Stock options outstanding do not have a materially dilutive effect on earnings per common share. Transactions involving option shares for all three plans are summarized as follows: Number of Shares Subject Option Price to Option Per Share Outstanding at September 30, 1991 516,260 $13.19 to $23.81 Granted in 1992 206,500 $23.88 Exercised in 1992* (100,664) $13.19 to $23.81 Forfeited in 1992 (4,000) $23.81 Outstanding at September 30, 1992 618,096 $15.59 to $23.88 Granted in 1993 416,500 $25.19 and $31.50 Exercised in 1993* (78,750) $15.59 to $23.88 Outstanding at September 30, 1993 955,846 $15.59 to $31.50 Granted in 1994 272,000 $31.63 Exercised in 1994* (60,509) $18.00 to $25.19 Outstanding at September 30, 1994 1,167,337 $15.59 to $31.63 Shares Exercisable at September 30, 1994 895,337 Shares Reserved for Future Grant at September 30, 1994 1,159,072 *In connection with exercising these options, 18,088, 36,797 and 35,532
Number of Shares Subject Option Price to Option Per Share - ---------------------------------------------------------------------- Outstanding at September 30, 1992 618,096 $15.59 to $23.88 Granted in 1993 416,500 $25.19 and $31.50 Exercised in 1993* (78,750) $15.59 to $23.88 - ---------------------------------------------------------------------- Outstanding at September 30, 1993 955,846 $15.59 to $31.50 Granted in 1994 272,000 $31.63 Exercised in 1994* (60,509) $18.00 to $25.19 - ---------------------------------------------------------------------- Outstanding at September 30, 1994 1,167,337 $15.59 to $31.63 Granted in 1995 362,100 $27.94 Forfeited in 1995 (11,532) $25.19 to $31.63 Exercised in 1995* (17,615) $15.59 to $23.88 - ---------------------------------------------------------------------- Outstanding at September 30, 1995 1,500,290 $18.00 to $31.63 ====================================================================== Shares Exercisable at September 30, 1995 1,138,190 Shares Reserved for Future Grant at September 30, 1995 795,148 - ------------------------------------------------------------------------- * In connection with exercising these options, 3,192, 18,088 and 36,797 shares were surrendered and/or canceled during 1995, 1994 and 1993, respectively.
On October 4, 1995, an additional 140,000 stock option shares were surrendered and/or cancelled during 1994, 1993 and 1992, respectively. Asgranted at an option price per share of September 30, 1994, a total of 286,308$28.56. During 1995, 8,000 shares of restricted stock had beenwere awarded under the 1993 Plan, bringing the total, as of September 30, 1995, to 294,308 shares of restricted stock awarded under the 1984 Plan and 1993 Plan, since inception. Restrictions have lapsed respecting 148,814 of these shares. Of the remaining 137,494145,494 shares of restricted stock, restrictions on 113,494 shares will lapse respecting one-sixth of such shares on each January 2, 1996 through 2001. Restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 1999 through 2002. Restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 2000 through 2003. Restrictions on 113,494 shares will lapse respecting approximately one-sixth of such shares on each January 2, 1996 through 2001. Restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 2001 through 2004. Restrictions on 8,000 shares will lapse respecting one-fourth of such shares on each January 2, 2002 through 2005. The market value of the restricted stock on the date the award was made is being recorded as compensation expense over the periods over which the restrictions lapse. During the restriction period, share certificates are held by the Company. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)In October 1995, the FASB issued SFAS 123, "Accounting for Stock Based Compensation" (SFAS 123). This statement establishes a fair value based method of accounting for employee stock options or similar equity instruments and encourages all companies to adopt that method of accounting for all of their employee stock compensation plans. SFAS 123 allows companies to continue to measure compensation cost for employee stock options or similar equity instruments using the method of accounting prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Companies electing to remain with this method are required to make pro forma disclosures of net income and earnings per share as if SFAS 123 accounting had been applied. The Company is required to adopt the disclosure requirements of SFAS 123 for its fiscal year ending September 30, 1997. Measurement of compensation cost under SFAS 123, if adopted, is effective for all awards granted after the beginning of the fiscal year in which that method is first applied. Management is currently reviewing the provisions of SFAS 123. If the fair value base measurement provisions are adopted, they are not expected to have a material impact on the results of operations or financial condition of the Company. Redeemable Preferred Stock.Stock As of September 30, 1994,1995, there were 3,200,000 shares of $25 par value Cumulative Preferred Stock authorized but unissued. Summary of Changes in Common Stock Equity Earnings Paid Reinvested Common Stock In in the (in thousands) Shares Amount Capital Business Balance at September 30, 1991 30,926 $241,043 $301,066 Net Income Available for Common Stock 60,310 Dividends Declared on Common Stock ($1.48 Per Share) (47,042) Transfer from Common Stock to Paid In Capital (214,461) $214,461 Common Stock Issued: Sale of Common Stock 2,500 2,500 64,288 DRP, Incentive Compensation Plans and 401(k) Plans 273 3,314 3,065 CSPP 157 1,460 2,614 Common Stock Issuance Costs (285) Balance at September 30, 1992 33,856 33,856 284,143 314,334 Net Income Available for Common Stock 75,217 Dividends Declared on Common Stock ($1.52 Per Share) (53,644) Common Stock Issued: Sale of Common Stock 2,500 2,500 71,425 Incentive Compensation Plans and 401(k) Plans 165 165 4,255 CSPP 140 140 4,101 Common Stock Issuance Costs (247) Balance at September 30, 1993 36,661 36,661 363,677 335,907 Net Income Available for Common Stock 85,672 Dividends Declared on Common Stock ($1.56 Per Share) (57,725) Common Stock Issued: Acquisition of Natural Gas Production Assets 108 108 3,523 Incentive Compensation Plans and 401(k) Plans 300 300 5,397 CSPP 209 209 6,559 Balance at September 30, 1994 37,278 $ 37,278 $379,156 $363,854* * The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 1994, $289,470,000 of accumulated earnings was free of such limitations. However, substantially all of this amount has been reinvested in the business. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Long-Term Debt.Debt The outstanding long-term debt is as follows: At September 30 (in thousands) 1994 1993 Debentures: 7-3/4% due February 2004 $125,000 $125,000 9-1/2% due July 2019 - 19,917 Medium-Term Notes: 6.07% due May 1995 55,000 55,000 6.10% due May 1995 20,000 20,000 6.10% due June 1995 1,000 1,000 9.32% due June 1995 20,000 20,000 8.875% due December 1995 20,000 20,000 8.90% due December 1995 38,500 38,500 4.53% due September 1996 30,000 30,000 6.42% due November 1997 50,000 50,000 7.25% due July 1999 50,000 - 6.60% due February 2000 50,000 50,000 7.395% due March 2023 49,000 49,000 8.48% due July 2024* 50,000 - 558,500 478,417 Less Current Portion 96,000 - $462,500 $478,417
At September 30 (in thousands) 1995 1994 ---- ---- Debentures: 7-3/4% due February 2004 $125,000 $125,000 Medium-Term Notes: 6.07% due May 1995 - 55,000 6.10% due May 1995 - 20,000 6.10% due June 1995 - 1,000 9.32% due June 1995 - 20,000 8.875% due December 1995 20,000 20,000 8.90% due December 1995 38,500 38,500 4.53% due September 1996 30,000 30,000 6.42% due November 1997 50,000 50,000 6.08% due July 1998 50,000 - 7.25% due July 1999 50,000 50,000 6.60% due February 2000 50,000 50,000 7.395% due March 2023 49,000 49,000 8.48% due July 2024* 50,000 50,000 7.375% due June 2025 50,000 - -------- -------- 562,500 558,500 Less Current Portion 88,500 96,000 -------- -------- $474,000 $462,500 ======== ======== * Callable beginning July 1999.
The aggregate principal amounts of long-term debt maturing for the next five years, including amounts classified as Current Portion of Long-Term Debt, are: $96,000,000 in 1995, $88,500,000$88.5 million in 1996, none in 1997, $50,000,000$100.0 million in 1998, $50.0 million in 1999 and $50,000,000$50.0 million in 1999. The fair market value of the Company's long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, is $541,327,000 and $513,107,000 at September 30, 1994 and 1993, respectively. Such value is not intended to reflect principal amounts that the Company will ultimately be required to repay.2000. During 1994, the Company redeemed $19,917,000 remaining outstanding principal amount of 9-1/2% debentures due July 1, 2019, for $21,337,000, including redemption premium. Also during 1994,1995, the Company issued $50,000,000an aggregate $100.0 million of medium-term notes. In June 1995, $50.0 million of 7.375% medium-term notes due July 1999, at an interest rate of 7.25% and $50,000,000 of medium-term notes due July 2024, at an interest rate of 8.48%. The 8.48% notes are callable beginning July 1999.in June 2025 were issued. After reflecting underwriting discounts and commissions, the combined proceeds to the Company of these issuancesfrom this issuance amounted to $99,415,500. The$49.3 million. In July 1995, $50.0 million of 6.08% medium-term notes due in July 1998 were issued. After reflecting underwriting discounts and commissions, the proceeds were used to reduce outstanding short-term borrowings. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) In March 1993, the Company filed a shelf registration with the SEC for $350,000,000 of debentures and/or medium-term notes that became effective on March 30, 1993.from this issuance amounted to $49.8 million. The Company has authority remaining under thisa shelf registration and has authority under the Public Utility Holding Company Act of 1935, as amended, to issue and sell up to $220,000,000$120.0 million of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Note E - Short-Term Borrowings The Company maintains uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. These lines are utilized primarily as a means of financing, on an interim basis, various working capital requirements and capital expenditures of the Company, including the Company's oil and gas exploration and development program pipeline construction and the purchase and storage of gas. Borrowings under these lines of credit are made at competitive money market rates, and the Company currently is authorized to borrow up to $400,000,000$400.0 million thereunder. These credit lines, which are callable at the option of the financial institutions, are reviewed on an annual basis and are expected to remain in place through 1995.throughout 1996. The Company may also issue as much as $150,000,000$105.0 million of commercial paper from time to time, but in no event may its borrowings under its discretionary lines of credit, or through the issuance of commercial paper, exceed $400,000,000$400.0 million in the aggregate. Additionally, the Company has entered into an agreement that establishes a 364-day committed revolving credit arrangement with seven commercial banks, under which it may borrow as much as $105,000,000.$105.0 million. This arrangement may be utilized for general corporate purposes, including to support the issuance of commercial paper. The Company pays a fee to maintain this arrangement, and may borrow through this arrangement under four interest rate options. If amounts are borrowed under this arrangement, the $400,000,000$400.0 million available for borrowing under the discretionary lines of credit is correspondingly reduced. No borrowings under this arrangement were outstanding at September 30, 1994.1995. The arrangement expires on September 20, 1995,19, 1996, and the Company expects to renew or replace all or most of this arrangement before then. The Company has recently filed with the SEC to borrow on a short-term basis for a five year period. With this request the Company is seeking to increase its short-term borrowing limits. The filing, if approved, would increase the Company's limit on commercial paper from $105.0 million to $300.0 million and would increase the aggregate maximum short-term borrowing level from $400.0 million to $600.0 million. At September 30, 1995, the Company had outstanding notes payable to banks and commercial paper of $52.6 million and $95.0 million, respectively. At September 30, 1994, the Company had outstanding notes payable to banks and commercial paper of $102,500,000$102.5 million and $10,000,000, respectively. At September 30, 1993, the Company had outstanding notes payable to banks and commercial paper of $125,800,000 and $71,000,000,$10.0 million, respectively. The weighted average interest rate on notes payable to banks was 5.13%6.15% and 3.29%5.13% at September 30, 19941995 and 1993,1994, respectively. The weighted average interest rate on commercial paper was 5.09%5.85% and 3.32%5.09% at September 30, 19941995 and 1993,1994, respectively. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Note F - Financial Instruments Fair Values The fair market value of the Company's long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
At September 30 (in thousands) 1995 1994 ---------------------- ------------------ Carrying Fair Carrying Fair Amount Value Amount Value -------- ----- -------- ----- Long-Term Debt $562,500 $570,236 $558,500 $541,327 ======== ======== ======== ========
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Temporary cash investments, notes payable to banks and commercial paper are stated at amounts which approximate their fair value due to the short-term maturities of those financial instruments. Investments in life insurance are stated at their cash surrender values as discussed below. Investments Other assets consist principally of cash surrender values of insurance contracts. The cash surrender values of these insurance contracts amounted to $28.2 million and $21.3 million at September 30, 1995 and 1994, respectively. The insurance contracts were established as a funding mechanism for various benefit obligations the Company has to certain employees. Derivative Financial Instruments The Company, in its Exploration and Production operations, has entered into certain price swap agreements that effectively hedge a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These agreements are not held for trading purposes. The price swap agreements call for the Company to receive monthly payments from (or make payment to) other parties based upon the difference between a fixed and a variable price as specified by the agreement. The variable price is either a crude oil price quoted on the New York Mercantile Exchange or a quoted natural gas price in "Inside FERC." The following summarizes the Company's activity under swap agreements during 1995 and 1994:
Year Ended September 30 1995 1994 --------------- ------------- Natural Gas Swap Agreements: Notional Amount - Equivalent Billion Cubic Feet (Bcf) 16.3 8.0 Fixed Prices per Thousand Cubic Feet (Mcf) $1.73 - $2.38 $2.16 - $2.38 Variable Prices per Mcf $1.35 - $1.76 $1.44 - $2.44 Gain $7,157,000 $1,986,000 Crude Oil Swap Agreements: Notional Amount - Equivalent Barrels (bbl) 711,000 - Fixed Prices per bbl $16.68 - $19.60 - Variable Prices per bbl $17.16 - $19.89 - Loss $(221,000) -
The Company had the following swap agreements outstanding at September 30, 1995:
Natural Gas Swap Agreements: Notional Amount Fiscal Year (Equivalent Bcf) Fixed Price per Mcf ----------- ---------------- ------------------- 1996 17.6 $1.70 - $2.16 1997 3.9 $1.70 - $1.98 1997 1.7 (1) 1998 0.6 (1) ---- 23.8 ====
Crude Oil Swap Agreements: Notional Amount Fiscal Year (Equivalent bbl) Fixed Price per bbl ----------- ---------------- ------------------- 1996 946,000 $17.40 - $19.00 1997 738,000 $17.40 - $18.33 1998 96,000 $18.31 --------- 1,780,000 ========= (1) Price to be set according to market prices at a future date.
Gains or losses from these price swap agreements are reflected in operating revenues on the Consolidated Statement of Income at the time of settlement with the other parties. Based upon the September 30, 1995 variable prices of these price swap agreements, there is an unrecognized gain of approximately $6.7 million. The actual gain or loss realized upon settlement of these price swap agreements will depend upon the variable price at the time of settlement. The Company has SEC authority to enter into interest rate swaps associated with short-term and long-term borrowings up to a notional amount of $350.0 million. However, within this combined limitation, the Company may only enter into interest rate swaps associated with short-term borrowings up to a notional amount of $200.0 million. No such agreements were entered into in 1995 and none are currently outstanding. Credit Risk Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company is at risk in the event of nonperformance by counterparties on investments, such as temporary cash investments and cash surrender values of insurance contracts, and on its derivative financial instruments. The counterparties to the Company's investments and derivative financial instruments are investment grade financial institutions. Furthermore, the Company has guarantees from counterparty affiliates on a large portion of its derivative financial instruments. Accordingly, the Company does not anticipate any material impact to its financial position, results of operations or cash flow as a result of nonperformance by counterparties. Note G - Retirement Plan and Other Post-Employment Benefits Retirement Plan.Plan The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Plan) that covers substantially all employees of the Company. The Plan uses years of service, age at retirement and earnings of employees to determine benefits. The Company's policy is to fund at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. Plan funding is subject to annual review by management and its consulting actuary. Plan assets primarily consist of equity and fixed income investments and units in commingled funds. AIn 1994, a plan amendment was adopted which provided for an early retirement window program which iswas accounted for under the rules prescribed by SFAS 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Plans and for Termination Benefits." For ratemaking purposes, pension expense equals the amount funded less amounts capitalized. Since Plan funding has not been required in recent years, the Company deferred the pension expense associated with its regulated subsidiaries. The amounts deferred are expected to be recovered in rates as contributions are made to the Plan. The actuarial valuation funding report for the 1996 Plan year indicates that a contribution to the Plan is required. Rate recovery for the Distribution Corporation portion of pension costs began with rates that went into effect on September 20, 1995 and September 27, 1995 in New York and Pennsylvania, respectively. The components of net periodic pension expense were as follows: Year Ended September 30 (in thousands) 1994 1993 1992 Service Cost for Benefits Earned During the Period $10,441 $ 9,181 $ 8,816 Interest Cost on Projected Benefit Obligation 26,532 24,258 22,446 Actual Return on Plan Assets (16,212) (35,657) (37,107) Net Amortization and Deferral (16,603) 4,287 7,077 Early Retirement Window 2,855 - - Net Periodic Pension Cost 7,013 2,069 1,232 Deferred for Regulatory Purposes (6,875) (2,012) (1,192) Pension Cost Recognized in Consolidated Statement of Income $ 138 $ 57 $ 40
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Service Cost $ 9,680 $10,441 $ 9,181 Interest Cost 28,338 26,532 24,258 Actual Return on Plan Assets (47,591) (16,212) (35,657) Net Amortization and Deferral 13,570 (16,603) 4,287 Early Retirement Window - 2,855 - ------- ------- ------- Net Periodic Pension Cost 3,997 7,013 2,069 Deferred for Regulatory Purposes (3,848) (6,875) (2,012) ------- ------- ------- Pension Cost Recognized in Consolidated Statement of Income $ 149 $ 138 $ 57 ======= ======= =======
The projected benefit obligation was determined using an assumed discount rate of 8% in 1995, 8.5% in 1994 and 7.75% in 1993 and 8.5% in 1992.1993. The assumed rate of compensation increase was 5% for all three years. The expected long-term rate of return on Plan assets was 8.5% for all three years. The unrecognized net asset that arose from the initial application of SFAS 87, "Employers' Accounting for Pensions," is being amortized on a straight-line basis over the future working lifetime of those expected to receive benefits under the Plan. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)In 1995, in addition to the decrease in the discount rate from 8.5% to 8%, the mortality assumption was changed by using a more current mortality table and rates of assumed retirement were revised to more accurately reflect actual retirement experience. The effect of the discount rate change was to increase the projected benefit obligation (PBO) by $22.8 million. The effect of the mortality and retirement rate changes was to increase the PBO by $15.4 million. A reconciliation of the Plan's funded status as determined by the Company's consulting actuary is presented in the following table: At September 30 (in thousands) 1994 1993 Actuarial Present Value of: Vested Benefit Obligation $245,095 $241,676 Accumulated Benefit Obligation $282,340 $278,843 Projected Benefit Obligation $342,050 $346,634 Plan Assets at Fair Value 370,150 369,920 Plan Assets in Excess of Projected Benefit Obligation 28,100 23,286 Unrecognized Net Asset (37,502) (42,688) Unrecognized Prior Service Cost 13,339 14,418 Unrecognized Net Gain (19,959) (4,025) Pension Liability (16,022) (9,009) Deferred for Regulatory Purposes 15,001 8,126 Pension Liability Recognized on Consolidated Balance Sheets $ (1,021) $ (883)
At September 30 (in thousands) 1995 1994 ---- ---- Actuarial Present Value of: Vested Benefit Obligation $287,470 $245,095 ======== ======== Accumulated Benefit Obligation $333,597 $282,340 ======== ======== Projected Benefit Obligation $404,157 $342,050 Plan Assets at Fair Value 399,608 370,150 -------- -------- Funded Status (4,549) 28,100 Unrecognized Net Asset (33,335) (37,502) Unrecognized Prior Service Cost 12,446 13,339 Unrecognized Net Loss (Gain) 5,419 (19,959) -------- -------- Pension Liability (20,019) (16,022) Deferred for Regulatory Purposes 18,849 15,001 -------- -------- Pension Liability Recognized on Consolidated Balance Sheets $ (1,170) $ (1,021) ======== ========
Other Post-Retirement Benefits.Benefits In addition to providing retirement plan benefits, the Company currently provides health care and life insurance benefits for substantially all retired employees under a post-retirement benefit plan (Post-Retirement Plan). The Company has adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), effective October 1, 1993. This statement required the Company to change its accounting for these post-retirement benefits from the "pay-as-you-go" (cash) basis to the accrual basis. The Company has established Voluntary Employees' Beneficiary Association (VEBA) trusts for collectively bargained employees and non-bargaining employees. The VEBA trusts are similar to the Company's Retirement Plan trust. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations. Contributions to the VEBA trusts are made to fund employees' post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. The Company's current policy is to invest Post-Retirement Plan assets primarily inconsist of equity securities and municipal bonds.fixed income investments and money market funds. The Company has elected to amortize the initial accumulated liability (transition obligation) to net periodic post-retirement benefit cost on a straight-line basis over a 20-year period. Total post-retirement benefit cost under SFAS 106 was $23,530,000$24.4 million and $23.5 million in 1995 and 1994, respectively, compared with the costs based on cash payments for retiree health care and life insurance benefits of $5,974,000 and $4,945,000$6.0 million in 1993 and 1992, respectively. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)1993. The components of net periodic post-retirement benefit cost were as follows: Year Ended September 30 (in thousands) 1994 Service Cost $ 3,974 Interest Cost 13,714 Expected Return on Post-Retirement Plan Assets (1,035) Amortization of Transition Obligation 8,628 Net Periodic Post-Retirement Benefit Cost 25,281 Deferred for Regulatory Purposes, Net (1,751) Post-Retirement Benefit Cost Recognized in Consolidated Statement of Income $ 23,530
Year Ended September 30 (in thousands) 1995 1994 ---- ---- Service Cost $ 3,394 $ 3,974 Interest Cost 13,027 13,714 Actual Return on Post-Retirement Plan Assets (4,613) (1,035) Net Amortization and Deferral 8,739 8,628 ------- ------- Net Periodic Post-Retirement Benefit Cost 20,547 25,281 Deferred for Regulatory Purposes, Net 3,853 (1,751) ------- ------- Post-Retirement Benefit Cost Recognized in Consolidated Statement of Income $24,400 $23,530 ======= =======
The weighted-average assumed discount rate used in determining the accumulated post-retirement benefit obligation was 8% in 1995 and 8.5% in 1994. The average assumed annual rate of salary increase for the applicable life insurance plans was 5%. for both years. The expected long-term rate of return on Post-Retirement Plan assets was 8.5% for both years. The annual rate of increase in the per capita cost of covered medical care benefits for the active participants and medical plans available to new retirees was assumed to be 13% for 1994;1994 and 12% for 1995; this rate was assumed to decrease gradually to 5.5% by the year 2002 and remain at that level thereafter. The annual rate of increase in the per capita cost of covered medical care benefits for the medical plans not available to new retirees was assumed to be 8% for 1994, 7% for 1995, 6% for 1996 and 5.5% for each year after 1996. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed t oto be 14% for 1994.1994 and 10% for 1995. This rate was assumed to decrease gradually to 5.5% by the year 20032005 and remain level thereafter. The annual rate increase in the per capita Medicare Part B Reimbursement was assumed to be 12.3% in 1994, 12.2% in 1995, 12% for 1996 and 5.5% for each year after 1996. In 1995, in addition to the decrease in the discount rate from 8.5% to 8%, there were plan changes to the prescription drug and life insurance post-retirement benefits. The effect of the discount rate change was to increase the accumulated post-retirement benefit obligation (APBO) by $25.8 million. The net effect of the plan changes was to reduce the APBO by $6.4 million. A reconciliation of the Post-Retirement Plan's funded status as determined by the Company's consulting actuary is in the following table: At September 30 (in thousands) 1994 Accumulated Post-Retirement Benefit Obligation $ 155,976 Fair Value of Post-Retirement Plan Assets 29,035 Accumulated Benefit Obligation in excess of Plan Assets (126,941) Unrecognized Transition Obligation 156,210 Unrecognized Net (Gain)/Loss (31,776) Post-Retirement Liability (2,507) Deferred for Regulatory Purposes, Net 1,751 Post-Retirement Benefit Liability Recognized on Consolidated Balance Sheets $ (756) ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
At September 30 (in thousands) 1995 1994 ---- ---- Accumulated Post-Retirement Benefit Obligation: Inactives $ 76,272 $ 63,934 Actives Fully Eligible 36,223 31,983 Actives Not Yet Fully Eligible 70,620 60,059 -------- -------- 183,115 155,976 Fair Value of Post-Retirement Plan Assets 48,678 29,035 -------- -------- Funded Status (134,437) (126,941) Unrecognized Transition Obligation 141,561 156,210 Unrecognized Net Gain (8,930) (31,776) -------- -------- Post-Retirement Liability (1,806) (2,507) Deferred for Regulatory Purposes, Net (2,102) 1,751 --------- -------- Post-Retirement Benefit Liability Recognized on Consolidated Balance Sheets $ (3,908) $ (756) ======== ========
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the accumulated post-retirement benefit obligationAPBO as of October 1, 1993,1994, would be increased by $26,600,000.$23.3 million. This 1% change would also increase the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 19941995 by $3,100,000.$2.8 million. Distribution Corporation and Supply Corporation represent virtually all of the Company's total post-retirement benefit costs. Distribution Corporation and Supply Corporation are fully recovering their net periodic post-retirement benefit costs in accordance with the PSC and the Pennsylvania Public Utility Commission (PaPUC) and FERC authorization, respectively. In accordance with regulatory guidelines, the difference between the amounts of post-retirement benefit costs recoverable in rates and the amounts of post-retirement benefit costs determined by the actuary are deferred in each jurisdiction as either a regulatory asset or liability, as appropriate. Post-Employment Benefits.Benefits In November 1992, the FASB issued SFAS 112, "Employers' Accounting for Postemployment Benefits" (SFAS 112), which establishes standards of financial accounting and reporting for benefits, such as salary continuation, severance pay, workers' compensation and other disability-related benefits, provided to former or inactive employees subsequent to employment but prior to retirement. The Company adopted SFAS 112 in the fourth quarter of 1994. Essentially, the new standard required the Company to change its accountingThe Consolidated Statement of Income for significant post-employment benefits from the "pay-as-you-go" (cash) to the accrual basis. The only significant post-employment benefit that the Company has relates to workers' compensation. In the Company's regulated operations, workers' compensation is recovered in rates on1994 includes a cash basis and is not material. Workers' compensation claims related to the Company's nonregulated operations at September 30, 1994, is approximately $1,014,000 ($589,000charge of $0.6 million, net of income taxes) using a discount rate of 8.5%. As required by SFAS 112, the adoption of the standard is reflected on the Consolidated Statement of Incometaxes, as a cumulative effect of a change in accounting principle. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Note GH - Commitments and Contingencies Leases. System companies haveLeases The Company has entered into lease agreements, principally for the use of office space, business machines, transportation and construction equipment and meters. The Company's policy is to treat all leases as operating leases for both accounting and ratemaking purposes. Total lease expense approximated $17,190,000$16.3 million in 1995, $17.2 million in 1994 $16,864,000and $16.9 million in 1993 and $17,570,000 in 1992.1993. At September 30, 1994,1995, the future minimum payments under the Company's lease agreements for the next five years are: $13,075,000 in 1995, $9,779,000$13.9 million in 1996, $6,959,000$10.9 million in 1997, $5,021,000$7.6 million in 1998, $5.1 million in 1999 and $3,650,000$3.6 million in 1999.2000. The future minimum lease payments attributable to later years is $6,059,000.$9.7 million. Obligations Under Firm Contracts.Contracts Distribution Corporation has agreements with five nonaffiliated upstream pipeline companies that provide for the availability of needed pipeline transportation capacity for periods that extend through 2004. These agreements provide for payment of a demand or reservation charge, at FERC-approved rates, for contracted capacity. Distribution Corporation has various gas purchase agreements with nonaffiliated gas producers that require payment of fixed monthly charges. These charges are tied to various indices. These agreements have an average term of six years. Additionally, Distribution Corporation has agreements with two nonaffiliated companies for gas storage services through 2004 that require payment of a demand charge, at FERC-approved rates, for contracted storage. At September 30, 1994,1995, the projected aggregate amounts of such required future payments, based on current FERC-approved rates and current indices, where applicable, are approximately $88,600,000, $12,500,000$97.7 million, $12.7 million and $6,900,000$2.0 million annually for the next five years, for pipeline capacity, gas purchases and storage service, respectively. Additionally, these agreements call for the payment of commodity charges based upon actual quantities shipped, purchased and stored. These obligations under firm contracts are considered purchased gas costs, subject to state commission review, and are being recovered in customer rates through the inclusion in Distribution Corporation's rate schedules. For the fiscal year ended September 30, 1994,1995, total gross costs incurred under these contracts, including commodity charges on actual quantities shipped, purchased and stored, amounted to $347,100,000.$270.7 million. Environmental Matters.Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Distribution Corporation has incurred and is incurring clean-up costs at four former manufactured gas plant sites. Distribution Corporation owns two of those sites in New York and one in Pennsylvania. Distribution Corporation has been identifieddesignated by the Environmental Protection Agency or the New York State Department of Environmental Conservation (DEC) as a potentially responsible party (PRP) with respect to a third New York site, and is also engaged in litigation with the DEC and the party who bought the site from Distribution Corporation's predecessor. Distribution Corporation's estimated clean-up costs for all four sites have been accrued. Distribution Corporation is also currently identified by the DEC or the federal Environmental Protection Agency as one of a number of companies that are considered to be potentially responsible parties (PRPs)PRPs with respect to several waste disposal sites in New York thatwhich were operated by unrelated third parties. TheseThe PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to Distribution ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Corporation with respect to the remediation of these sites will be dependentdepend on such factors as the remediation plan selected, the extent of the site contamination, the number of additional PRPs at each site and the portion, attributed, if any, attributed to Distribution Corporation. Distribution Corporation's estimated share of the clean-up costs has been accrued for fourtwo of these sites. One of these four sites was formerly used for a manufactured gas plant. Distribution Corporation is currently involved in litigation regarding this site. The current owner of the site has submitted a claim against Distribution Corporation for contribution of a share of approximately $1,600,000 of removal/remediation costs that have been incurred. It is anticipated that future remedial costs will be incurred and on the basis of a Record of Decision issued by the DEC, as amended on September 19, 1994, the estimated future remedial costs for the site are approximately $5,700,000. Management believes that the ultimate outcome of these matters will not have a material impact on the financial condition, results of operations or cash flows of the Company. Distribution Corporation has incurred clean-up costs at two additional sites in New York and one site in Pennsylvania related to former manufactured gas plant sites. Supply Corporation is involved in a remediation program of certain of its measuring and regulating stations in Pennsylvania. Estimated clean-up costs have been accrued for these sites. It is the Company's policy to accrue estimated environmental clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The CompanyDistribution Corporation has estimated that clean-up costs related to all of the above noted sites are in the range of $6,700,000$8.1 million to $10,100,000.$9.5 million. At September 30, 1994, the Company1995, Distribution Corporation has recorded the minimum liability of $6,700,000.$8.1 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company. In New York, Distribution Corporation has received approval from the PSC to defer and amortize both former manufactured gas and non-manufactured gas plant site investigation and remediation costs over a three-year period for each site. These costs are then included in rate cases for recovery through base rates. Distribution Corporation is currently recovering such costs in this manner. In Pennsylvania, Distribution Corporation and Supply Corporation expectexpects to recover such costs in rates as the PaPUC and the FERC, respectively, havehas allowed recovery of other environmental clean-up costs in rate cases. Accordingly, the Consolidated Balance Sheets at September 30, 1994,1995, include related regulatory assets in the amount of approximately $7,300,000, $600,000 of which relates to costs that have already been incurred.$7.5 million. The Company has begun a program to complyis in compliance with the current standards of the Clean Air Act Amendments of 1990 (the Act). This program focuses on emission controls for Supply Corporation's compressor stations in New York and Pennsylvania. These facilities arePennsylvania were affected by the nitrogen oxide emission standards of the Act. Supply Corporation incurred capital expenditures for emission controls of approximately $623,000$0.6 million in 1994 and expects$5.1 million in 1995 to incur approximately $4,300,000 in 1995.bring its emission controls into compliance with the Act. The Company does not anticipate incurring significant additional capital ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) expenditures to comply with the current standards of the Act, however, changes in the standards may require additional expenditures in the future. Management expects that all related capital expenditures will be recoverable through rates. Other.Act. Other The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are expected to have a material adverse effect on the financial condition of the Company at this time. Note HI - Business Segment Information The SystemCompany includes operations which are rate-regulated (regulated) and operations which are not regulated as to their rates (nonregulated). The regulated operations fall primarily within two business segments: Utility Operation and Pipeline and Storage. The nonregulated operations consist principally of the Exploration and Production business segment. Other Nonregulated operations consist primarily of the Company's pipeline construction operations, sawmill and dry kiln operations, natural gas marketing operations, and natural gas market area hub operations.operations and pipeline construction operations (which were discontinued during 1995, the effect of which was immaterial to the Company). Late in 1995, the Company formed a subsidiary for the purpose of investing in foreign and domestic energy projects. The Utility Operation is regulated by the PSC and the PaPUC and is carried out by Distribution Corporation. Distribution Corporation sells and transports gas to retail customers located in western New York and northwestern Pennsylvania. It also provides off-system sales to customers located in regions through which the upstream pipelines serving Distribution Corporation pass (i.e., from the southwestern to northeastern regions of the United States). Pipeline and Storage operations are regulated by the FERC and are carried out by Supply Corporation. Supply Corporation transports and stores natural gas for utilities and pipeline companies in the northeastern United States markets. In 1994, 52%1995, 48% of Supply Corporation's revenue was from affiliated companies, mainly Distribution Corporation. Seneca is engaged in exploration for, and development and purchase of, oil and natural gas reserves in the Gulf Coast, and the southwestern, western and Appalachian regions of the United States. Seneca's production is, for the most part, sold to purchasers located in the vicinity of its wells. Highland Land & Minerals, Inc. operates a sawmill and dry kiln operation in Pennsylvania. NFR is engaged in the marketing and brokerage of natural gas and performs energy management services for utilities and end-users in the northeastern United States markets. Leidy Hub, Inc. is engaged in the Company's natural gas hub operations, providing services to customers in the northeastern, mid-Atlantic, Chicago and Los Angeles areas of the United States and Ontario, Canada. Horizon Energy Development, Inc. was formed in 1995 to engage in foreign and domestic energy projects. Utility Constructors, Inc. iswas engaged in the Company's pipeline construction operations Highland Land & Minerals, Inc. is engagedprior to the discontinuance of its operations in the Company's sawmill and dry kiln operations, NFR is engaged in the Company's natural gas marketing operations and Leidy Hub, Inc. is engaged in the Company's natural gas market area hub opreations.third quarter of fiscal 1995. The data presented in the tables below reflect the Company's regulated and nonregulated business segments for the years ended September 30, 1995, 1994 1993 and 1992.1993. Total operating revenues by segment include both revenues from nonaffiliated customers and intersegment revenues. Operating income is total operating revenues less operating expenses, not including income taxes. The elimination of significant intercompany balances and transactions, if appropriate, is made in order to reconcile segment information with consolidated amounts. Identifiable assets of a segment are those assets that are used in the operations of that segment. Corporate assets are principally cash and temporary cash investments, receivables, deferred charges and deferred charges.cash surrender values of insurance contracts.
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Operating Revenues Regulated: Utility Operation $ 786,064 $ 931,673 $ 836,618 Pipeline and Storage 164,587 153,121 534,568 ---------- ---------- ---------- 950,651 1,084,794 1,371,186 ---------- ---------- ---------- Nonregulated: Exploration and Production 56,232 70,261 58,636 Other 57,075 72,036 42,099 ---------- ---------- ---------- 113,307 142,297 100,735 ---------- ---------- ---------- Intersegment Revenues* (88,462) (85,767) (451,539) ---------- ---------- ---------- $ 975,496 $1,141,324 $1,020,382 ========== ========== ========== Operating Income (Loss) Before Income Taxes Regulated: Utility Operation $ 83,774 $ 90,584 $ 86,690 Pipeline and Storage 67,884 62,302 67,375 ---------- -------- -------- 151,658 152,886 154,065 ---------- -------- -------- Nonregulated: Exploration and Production 16,404 21,767 12,980 Other 3,021 2,505 (986) ---------- -------- -------- 19,425 24,272 11,994 ---------- -------- -------- Corporate (2,805) (3,463) (2,730) ---------- -------- -------- $ 168,278 $173,695 $163,329 ========== ======== ========
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Year Ended September 30 (in thousands) 1994 1993 1992 Operating Revenues Regulated: Utility Operation $ 931,673 $ 836,618 $ 740,664 Pipeline and Storage 153,121 534,568 498,870 1,084,794 1,371,186 1,239,534 Nonregulated: Exploration and Production 70,261 58,636 36,303 Other 72,036 42,099 47,479 142,297 100,735 83,782 Intersegment Revenues* (85,767) (451,539) (402,866) $1,141,324 $1,020,382 $ 920,450 Operating Income (Loss) Before Income Taxes Regulated: Utility Operation $ 90,584 $ 86,690 $ 90,025 Pipeline and Storage 62,302 67,375 49,796 152,886 154,065 139,821 Nonregulated: Exploration and Production 21,767 12,980 7,021 Other 2,505 (986) 4,229 24,272 11,994 11,250 Corporate (3,463) (2,730) (2,279) $ 173,695 $ 163,329 $ 148,792 Identifiable Assets At September 30 Regulated: Utility Operation $1,106,053 $ 961,990 $ 874,101 Pipeline and Storage** 498,798 491,291 495,626 1,604,851 1,453,281 1,369,727 Nonregulated: Exploration and Production** 311,037 290,346 271,444 Other 33,357 27,867 27,808 344,394 318,213 299,252 Corporate 32,412 30,046 91,851 $1,981,657 $1,801,540 $1,760,830
Identifiable Assets At September 30 (in thousands) Regulated: Utility Operation $1,100,236 $1,106,053 $ 961,990 Pipeline and Storage 512,546 498,798 491,291 ---------- ---------- ---------- 1,612,782 1,604,851 1,453,281 ---------- ---------- ---------- Nonregulated: Exploration and Production 351,262 311,037 290,346 Other 33,734 33,357 27,867 ---------- ---------- ---------- 384,996 344,394 318,213 ---------- ---------- ---------- Corporate 40,524 32,412 30,046 ---------- ---------- ---------- $2,038,302 $1,981,657 $1,801,540 ========== ========== ========== * Represents revenue primarily from Pipeline and Storage to Utility Operation. ** Prior year amounts have been reclassified to eliminate an intersegment receivable and to conform with current year presentation. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Year Ended September 30 (in thousands) 1994 1993 1992 Depreciation, Depletion and Amortization Regulated: Utility Operation $ 28,216 $ 27,137 $ 25,001 Pipeline and Storage 17,516 16,347 16,202 45,732 43,484 41,203 Nonregulated: Exploration and Production 27,496 24,249 13,257 Other 1,530 1,686 1,260 29,026 25,935 14,517 Corporate 6 6 6 $ 74,764 $ 69,425 $ 55,726 Capital Expenditures Regulated: Utility Operation $ 61,715 $ 61,803 $ 65,650 Pipeline and Storage 20,472 27,420 58,646 82,187 89,223 124,296 Nonregulated: Exploration and Production 52,458 36,473 26,328 Other 3,603 6,229 7,225 56,061 42,702 33,553 Corporate 20 1 7 $138,268 $131,926 $ 157,856 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Depreciation, Depletion and Amortization Regulated: Utility Operation $ 30,052 $ 28,216 $27,137 Pipeline and Storage 19,320 17,516 16,347 -------- -------- ------- 49,372 45,732 43,484 -------- -------- ------- Nonregulated: Exploration and Production 21,201 27,496 24,249 Other 1,203 1,530 1,686 -------- -------- ------- 22,404 29,026 25,935 -------- -------- ------- Corporate 6 6 6 -------- -------- ------- $ 71,782 $ 74,764 $69,425 ======== ======== ======= Capital Expenditures Regulated: Utility Operation $ 64,844 $ 61,715 $ 61,803 Pipeline and Storage 38,678 20,472 27,420 -------- -------- -------- 103,522 82,187 89,223 -------- -------- -------- Nonregulated: Exploration and Production 69,741 52,458 36,473 Other 9,563 3,603 6,229 -------- -------- -------- 79,304 56,061 42,702 -------- -------- -------- Corporate - 20 1 -------- -------- -------- $182,826 $138,268 $131,926 ======== ======== ========
Note IJ - Quarterly Financial Data (unaudited) In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Earnings per common share are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the earnings per common share shown on the Consolidated Statement of Income, which is based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company's heating business, there are substantial variations in operations reported on a quarterly basis. Financial data for the quarters ended December 31, 1994, March 31, 1995, and June 30, 1995 have been restated to reflect the application of a final rule issued by the FERC in September 1995, which addresses and clarifies financial reporting aspects of the current practices for unbundled pipeline sales and open access transportation. Financial data for the quarter ended September 30, 1995 reflects the recording of $4.3 million and $3.7 million of operating expenses by Distribution Corporation and Supply Corporation, respectively. Distribution Corporation recognized an additional $4.3 million of gas cost expense as a result of the annual reconciliation of gas costs in its New York jurisdiction, which is performed in August of each year. This reconciliation determined an amount of lost and unaccounted-for gas in excess of that allowed to be recovered by the PSC. Supply Corporation recorded a reserve in the amount of $3.7 million for previously deferred preliminary survey and investigation charges related to a storage project. Financial data for the quarters ended December 31, 1993 and September 30, 1994, reflect the Company's adoption of SFAS 109 and SFAS 112, respectively. As discussed in Note A - Summary of Significant Accounting Policies, the Company adopted SFAS 109 during the quarter ended December 31, 1993. The cumulative effect of this change increased net income by $3,826,000.$3.8 million. As discussed in Note FG - Retirement Plan and Other Post-Employment Benefits, the Company adopted SFAS 112 during the quarter ended September 30, 1994. The cumulative effect of this change decreased net income by $589,000. Income Net Income Earnings Before Available for Per Quarter Operating Operating Cumulative Common Common Ended Revenues Income Effect Stock Share 1994 (in thousands, except earnings per common share) 12/31/93 $310,131 $38,745 $27,800 $31,626* $ .86* 3/31/94 $473,722 $54,686 $43,839 $43,839 $1.18 6/30/94 $216,281 $19,782 $ 9,833 $ 9,833 $ .26 9/30/94 $141,190 $12,690 $ 963 $ 374* $ .01* 1993 (in thousands, except earnings per common share) 12/31/92 $294,220 $38,452 $25,941 $25,941 $ .77 3/31/93 $391,790 $57,195 $45,160 $45,160 $1.33 6/30/93 $185,525 $14,993 $ 3,228 $ 3,228 $ .09 9/30/93 $148,847 $11,643 $ 888 $ 888 $ .02$0.6 million.
Income Net Income Earnings Before Available for Per Quarter Operating Operating Cumulative Common Common Ended Revenues Income Effect Stock Share ------- --------- --------- ---------- ------------- -------- 1995 (in thousands, except earnings per common share) - ------------------------------------------------------------------------------------- 12/31/94 - As Previously Reported $271,548 $38,578 $25,861 $25,861 $ .69 - As Restated $279,332 $43,288 $30,571 $30,571 $ .82 3/31/95 - As Previously Reported $376,680 $55,197 $42,047 $42,047 $1.12 - As Restated $378,762 $56,457 $43,307 $43,307 $1.16 6/30/95 - As Previously Reported $191,480 $17,789 $ 7,783 $ 7,783 $ .21 - As Restated $193,461 $18,987 $ 8,981 $ 8,981 $ .24 9/30/95 $123,941 $ 5,667 $(6,965) $(6,965) $(.19) 1994 (in thousands, except earnings per common share) - ------------------------------------------------------------------------------------- 12/31/93 $310,131 $38,745 $27,800 $31,626* $ .86 * 3/31/94 $473,722 $54,686 $43,839 $43,839 $1.18 6/30/94 $216,281 $19,782 $ 9,833 $ 9,833 $ .26 9/30/94 $141,190 $12,690 $ 963 $ 374* $ .01 * * Includes Cumulative Effect of Changes in Accounting as discussed above. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note JK - Market for Common Stock and Related Shareholder Matters (unaudited) At September 30, 1994,1995, there were 22,46521,429 holders of National Fuel Gas Company common stock. The market for the common stock is the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note D - Capitalization. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 19931994 and 1994,1995, are shown below: Price Range Dividends Quarter Ended High Low Declared 1993 12/31/92 $30-1/2 $24-5/8 $.375 3/31/93 $33-1/2 $29-1/4 $.375 6/30/93 $33-1/2 $28-3/4 $.385 9/30/93 $36-7/8 $32-1/4 $.385 1994 12/31/93 $36-5/8 $32-1/2 $.385 3/31/94 $36-1/4 $29-7/8 $.385 6/30/94 $32-7/8 $28-3/8 $.395 9/30/94 $31-7/8 $28-7/8 $.395 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Price Range Dividends Quarter Ended High Low Declared - ------------- ---- --- --------- 1994 ---- 12/31/93 $36-5/8 $32-1/2 $.385 3/31/94 $36-1/4 $29-7/8 $.385 6/30/94 $32-7/8 $28-3/8 $.395 9/30/94 $31-7/8 $28-7/8 $.395 1995 ---- 12/31/94 $30 $25-1/4 $.395 3/31/95 $28-1/2 $25 $.395 6/30/95 $30-3/4 $27-1/2 $.405 9/30/95 $29-5/8 $26-1/2 $.405
Note KL - Supplementary Information for Oil and Gas Producing Activities The following supplementary information is presented in accordance with SFAS 69, "Disclosures about Oil and Gas Producing Activities," and related SEC accounting rules. Capitalized Costs Relating to Oil and Gas Producing Activities At September 30 (in thousands) 1994 1993 Capitalized Costs Subject to Amortization $442,224 $399,781 Capitalized Acquisition Costs Excluded from Amortization 16,636 15,849 458,860 415,630 Less - Accumulated Depreciation, Depletion and Amortization 167,592 145,553 $291,268 $270,077
Capitalized Costs Relating to Oil and Gas Producing Activities At September 30 (in thousands) 1995 1994 ---- ---- Capitalized Costs Subject to Amortization $495,802 $442,224 Capitalized Acquisition Costs Excluded from Amortization 28,565 16,636 -------- -------- 524,367 458,860 Less - Accumulated Depreciation, Depletion and Amortization 188,241 167,592 -------- -------- $336,126 $291,268 ======== ========
Certain costs excluded from amortization represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. The remaining costs, incurred during and prior to 1994,1995, consist of individually insignificant oil and gas leases still early in their primary terms and individually insignificant unproved perpetual oil and gas rights.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Property Acquisition Costs $25,305 $ 8,215 $ 9,027 Exploration Costs 18,588 17,855 10,140 Development Costs 25,161 25,102 16,258 Other 559 259 25 ------- ------- ------- $69,613 $51,431 $35,450 ======= ======= =======
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued) Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 (in thousands) 1994 1993 1992 Property Acquisition Costs $ 8,215 $ 9,027 $ 5,260 Exploration Costs 17,855 10,140 4,552 Development Costs 25,102 16,258 11,172 Other 259 25 3,284 $51,431 $35,450 $24,268 Results of Operations for Producing Activities Year Ended September 30 (in thousands) 1994 1993 1992 Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $5,456, $11,474 and $10,945, respectively) $50,803 $43,679 $24,022 Oil, Condensate and Other Liquids 15,307 13,943 10,974 Total Operating Revenues 66,110 57,622 34,996 Production/Lifting Costs 13,177 13,452 9,828 Depreciation, Depletion and Amortization ($.41, $.42 and $.37, respectively, per dollar of operating revenues) 26,992 23,995 13,049 Income Tax Expense 7,907 4,311 3,874 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $18,034 $15,864 $ 8,245 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Results of Operations for Producing Activities Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $8,650, $5,456 and $11,474, respectively) $34,849 $50,803 $43,679 Oil, Condensate and Other Liquids 11,948 15,307 13,943 ------- ------- ------- Total Operating Revenues 46,797 66,110 57,622 Production/Lifting Costs 11,215 13,177 13,452 Depreciation, Depletion and Amortization ($0.44, $0.41 and $0.42, respectively, per dollar of operating revenues) 20,528 26,992 23,995 Income Tax Expense 4,301 7,907 4,311 ------- ------- ------- Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $10,753 $18,034 $15,864 ======= ======= =======
Reserve Quantity Information (unaudited) The Company's proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by the Company'squalified Company geologists and engineers and are audited by independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions. Gas Oil Year Ended MMcf Mbbl September 30 1994 1993 1992 1994 1993 1992 Proved Developedrevisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and Undeveloped Reserves: Beginningcontinual reassessment of Year 175,051 179,811 176,772 18,519 19,805 20,316 Extensions and Discoveries 94,733 26,416 21,645 1,666 1,713 270 Revisionsthe viability of Previous Estimates (2,075) (3,962) (3,391) (1,660) (1,995) (85) Production (23,273) (19,874)(12,070) (1,030) (831) (643) Sales of Minerals in Place (32) (7,401) (3,377) - (173) (53) Purchases of Minerals in Place and Other 3,043 61 232 - - - End of Year 247,447 175,051 179,811 17,495 18,519 19,805 Proved Developed Reserves: Beginning of Year 134,712 126,176 131,035 10,801 11,437 12,210 End of Year 179,291 134,712 126,176 10,110 10,801 11,437production under varying economic conditions. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Gas Oil Year Ended MMcf Mbbl -------------------------- ---------------------- September 30 1995 1994 1993 1995 1994 1993 ---- ---- ---- ---- ---- ---- Proved Developed and Undeveloped Reserves: Beginning of Year 247,447 175,051 179,811 17,495 18,519 19,805 Extensions and Discoveries 9,912 94,733 26,416 3,863 1,666 1,713 Revisions of Previous Estimates (21,046) (2,075) (3,962) (60) (1,660) (1,995) Production (20,942) (23,273) (19,874) (739) (1,030) (831) Sales of Minerals in Place (4,685) (32) (7,401) (474) - (173) Purchases of Minerals in Place and Other 10,773 3,043 61 2,780 - - ------- ------- ------- ------ ------ ------ End of Year 221,459 247,447 175,051 22,865 17,495 18,519 ======= ======= ======= ====== ====== ====== Proved Developed Reserves: Beginning of Year 179,291 134,712 126,176 10,110 10,801 11,437 ======= ======= ======= ====== ====== ====== End of Year 162,504 179,291 134,712 14,937 10,110 10,801 ======= ======= ======= ====== ====== ======
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited) The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company's oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under the widely fluctuating political and economic conditions of today's world. The standardized measure is intended instead to provide a somewhat better means for comparing the value of the Company's proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities. Year Ended September 30 (in thousands) 1994 1993 1992 Future Cash Inflows $705,874 $689,198 $772,017 Less: Future Production and Development Costs 252,901 240,417 217,654 Future Income Tax Expense at Applicable Statutory Rate 131,060 132,528 159,888 Future Net Cash Flows 321,913 316,253 394,475 Less: 10% Annual Discount for Estimated Timing of Cash Flows 106,647 106,598 154,184 Standardized Measure of Discounted Future Net Cash Flows $215,266 $209,655 $240,291 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Future Cash Inflows $738,711 $705,874 $689,198 Less: Future Production and Development Costs 272,268 252,901 240,417 Future Income Tax Expense at Applicable Statutory Rate 129,055 131,060 132,528 -------- -------- -------- Future Net Cash Flows 337,388 321,913 316,253 Less: 10% Annual Discount for Estimated Timing of Cash Flows 92,120 106,647 106,598 -------- -------- -------- Standardized Measure of Discounted Future Net Cash Flows $245,268 $215,266 $209,655 ======== ======== ========
The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 (in thousands) 1994 1993 1992
Year Ended September 30 (in thousands) 1995 1994 1993 ---- ---- ---- Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $209,655 $240,291 $183,512 Sales, Net of Production Costs (52,933) (44,170) (25,168) Net Changes in Prices, Net of Production Costs (48,149) (52,266) 41,322 Purchases of Minerals in Place 2,793 61 398 Sales of Minerals in Place (29) (7,286) (6,454) Extensions and Discoveries 96,134 61,476 38,874 Changes in Estimated Future Development Costs (36,466) (30,555) (15,186) Previously Estimated Development Costs Incurred 22,941 30,888 17,793 Net Change in Income Taxes at Applicable Statutory Rate 3,098 5,476 (11,662) Revisions of Previous Quantity Estimates (11,042) (25,891) (8,893) Accretion of Discount and Other 29,264 31,631 25,755 Standardized Measure of Discounted Future Net Cash Flows at End of Year $215,266 $209,655 $240,291 Sales, Net of Production Costs (35,582) (52,933) (44,170) Net Changes in Prices, Net of Production Costs 10,757 (48,149) (52,266) Purchases of Minerals in Place 18,602 2,793 61 Sales of Minerals in Place (5,688) (29) (7,286) Extensions and Discoveries 47,236 96,134 61,476 Changes in Estimated Future Development Costs (50,366) (36,466) (30,555) Previously Estimated Development Costs Incurred 39,833 22,941 30,888 Net Change in Income Taxes at Applicable Statutory Rate (6,838) 3,098 5,476 Revisions of Previous Quantity Estimates (20,934) (11,042) (25,891) Accretion of Discount and Other 32,982 29,264 31,631 -------- -------- -------- Standardized Measure of Discounted Future Net Cash Flows at End of Year $245,268 $215,266 $209,655 ======== ======== ========
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued) NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES SCHEDULE V - Property, Plant and Equipment (Note 1) (THOUSANDS OF DOLLARS) Balance at Balance at Beginning of Additions Other Charges End of Classification Period at Cost Retirements Add (Deduct) Period Year Ended September 30, 1994 Utility Operation $ 983,417 $ 59,652 $ 6,844 $ - $1,036,225 Pipeline and Storage (Note 2) 618,917 20,380 4,132 4,959 640,124 Exploration and Production 415,642 52,181 3,098 - 464,725 Other Nonregulated 21,237 4,033 332 - 24,938 Corporate 223 21 - - 244 $2,039,436 $136,267 $14,406 $4,959 $2,166,256 Year Ended September 30, 1993 Utility Operation $ 929,601 $ 60,001 $6,185 $ - $ 983,417 Pipeline and Storage (Note 2) 594,580 27,004 2,667 - 618,917 Exploration and Production 378,815 37,145 318 - 415,642 Other Nonregulated 15,170 6,235 168 - 21,237 Corporate 223 - - - 223 $1,918,389 $130,385 $9,338 $ - $2,039,436 Year Ended September 30, 1992 Utility Operation $ 871,102 $ 64,624 $ 6,125 $ - $ 929,601 Pipeline and Storage (Note 2) 539,904 58,210 3,534 - 594,580 Exploration and Production 353,090 25,769 44 - 378,815 Other Nonregulated 8,202 7,222 254 - 15,170 Corporate 216 7 - - 223 $1,772,514 $155,832 $ 9,957 $ - $1,918,389 Notes to Schedule V and VI appear on page 91 of this report. ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued) NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES SCHEDULE VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment (THOUSANDS OF DOLLARS) Additions Balance at Charged to Beginning Costs and Balance at of Expenses Other Changes End of Description Period (Note 3) Retirements Add (Deduct) Period Year Ended September 30, 1994 Utility Operation $228,951 $28,270 $ 8,790 $ - $248,431 Pipeline and Storage 185,181 18,436 4,304 - 199,313 Exploration and Production 142,172 27,443 308 - 169,307 Other Nonregulated 5,028 1,531 200 - 6,359 Corporate 101 6 - - 107 $561,433 $75,686 $13,602 $ - $623,517 Year Ended September 30, 1993 Utility Operation $209,846 $27,209 $ 8,104 $ - $228,951 Pipeline and Storage 171,197 17,479 3,495 - 185,181 Exploration and Production 117,369 24,250 119 672 142,172 Other Nonregulated 3,500 1,685 157 - 5,028 Corporate 95 6 - - 101 $502,007 $70,629 $11,875 $ 672 $561,433 Year Ended September 30, 1992 Utility Operation $192,169 $25,076 $ 7,399 $ - $209,846 Pipeline and Storage 159,896 16,900 5,599 - 171,197 Exploration and Production 104,303 13,264 - (198) 117,369 Other Nonregulated 2,306 1,260 66 - 3,500 Corporate 89 6 - - 95 $458,763 $56,506 $13,064 $ (198) $502,007 Notes to Schedule V and VI appear on page 91 of this report. ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued) NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES Notes to Schedules V and VI: (1) Because of the variety of properties and the large number of depreciation rates utilized by System companies, it is considered impractical to set forth the rates used in computing provisions. However, the total provisions for depreciation, depletion and amortization of System property, plant and equipment for the three years ended September 30, 1994, including amounts charged to accounts other than depreciation, depletion and amortization expense, were equivalent to approximately 3.9% in 1994, 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and equipment for the respective years. (2) Includes gas stored underground costing $80,942,000 at September 30, 1994, and $75,983,000 at September 30, 1993 and 1992. The cost of gas stored underground in the amount of $4,959,000 was transferred to property, plant and equipment from deferred changes in 1994. (3) Additions Charged to Costs and Expenses differs from Depreciation, Depletion and Amortization (D,D & A) as reported in the Consolidated Statement of Income, due to D,D & A provisions charged to other income and expense accounts. ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued) NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES SCHEDULE VIII - Valuation and Qualifying Accounts and Reserves (THOUSANDS OF DOLLARS)
Schedule II - Valuation and Qualifying Accounts (in thousands) ------------ Additions ---------------------- Balance at Charged to Charged to Balance at Beginning Costs and Other Deductions End of Description of Period Expenses Accounts (Note) Period - ----------- ---------- ---------- ---------- ---------- ---------- Year Ended September 30, 1995 - ----------------------------- Reserve for Doubtful Accounts $ 5,055 $15,187 $ - $14,318 $5,924 ======= ======= ====== ====== ====== Year Ended September 30, 1994 - ----------------------------- Reserve for Doubtful Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055 ======= ======= ====== ======= ======= Year Ended September 30, 1993 - ----------------------------- Reserve for Doubtful Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055 Year Ended September 30, 1993 Reserve for Doubtful Accounts $ 5,900 $ 8,713 $ - $8,874 $ 5,739 Year Ended September 30, 1992 Reserve for Doubtful Accounts $ 5,876 $ 9,723 $ - $9,699 $ 5,900 $ 8,713 $ - $8,874 $ 5,739 ======= ======= ====== ====== =======
Note - Amounts represent net accounts receivable written-off. ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued) NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES SCHEDULE IX - Short-Term Borrowings (THOUSANDS OF DOLLARS) Maximum Average Weighted Balance at Weighted Amount Amount Average Category End of Average Outstanding Outstanding Interest of Aggregate Period Interest During the During the Rate During Short-Term September 30 Rate Period Period the Period Borrowings (Note 1) (Note 2) (Note 3) (Note 4) (Note 5) Year 1994 Bank Loans $102,500 5.13% $ 182,100 $107,907 3.75% Commercial Paper $ 10,000 5.09% $ 76,000 $ 42,000 3.67% Year 1993 Bank Loans $125,800 3.29% $ 217,000 $115,159 3.58% Commercial Paper $ 71,000 3.32% $ 128,000 $ 87,427 3.56% Year 1992 Bank Loans $149,100 3.60% $ 207,200 $165,191 4.81% Commercial Paper $127,900 3.52% $ 127,900 $ 84,096 4.62% Notes: (1) At September 30, 1992, the Company reclassified $50,000,000 of short-term borrowings9 Changes in and Disagreements with Accountants on the Consolidated Balance Sheet to "Long-Term Debt, Net of Current Portion" because the Company, on November 5, 1992, issued $50,000,000 of medium-term notesAccounting and used the proceeds to reduce outstanding short-term borrowings. (2) The interest rate for bank loans is the weighted average of the rates in effect at the respective banks at September 30 of each year. The interest rate for commercial paper is the weighted average of the discount rate on those commercial paper notes outstanding at September 30 of each year. (3) Represents the maximum amount outstanding during any month of the period. (4) Represents the average amount outstanding on a daily basis. (5) Represents the weighted average interest rate on a daily basis. ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Concluded) NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES SCHEDULE X - Supplementary Income Statement Information (THOUSANDS OF DOLLARS) Charged to Costs and Expenses Item Year Ended September 30 1994 1993 1992 1. Maintenance and Repairs $30,979 $24,312 $22,439 2. Depreciation and Amortization of Intangible Assets, Preoperating Costs and Similar Deferrals (1) (1) (1) 3. Taxes, other than Payroll and Income Taxes: Gross Receipts Taxes $53,271 $48,876 $44,400 Real and Other Property Taxes 35,287 33,216 31,320 Other 7,017 5,500 6,127 $95,575 $87,592 $81,847 4. Royalties (1) (1) (1) 5. Advertising Costs (1) (1) (1) Note (1) Amount is not in excess of one percent of total operating revenues as reported in the Consolidated Statements of Income and Earnings Reinvested in the Business. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREFinancial Disclosure None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT10 Directors and Executive Officers of the Registrant The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 199515, 1996 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994.1995. The information provided in such definitive Proxy Statement is incorporated herein by reference. Information concerning the Company's executive officers can be found in Part I, Item 1, of this report. ITEM 11. EXECUTIVE COMPENSATION11 Executive Compensation The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 199515, 1996 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994.1995. The information provided in such definitive Proxy Statement is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT12 Security Ownership of Certain Beneficial Owners and Management The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 199515, 1996 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994.1995. The information provided in such definitive Proxy Statement is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS13 Certain Relationships and Related Transactions At September 30, 1994,1995, the Company knows of no relationships or transactions required to be disclosed pursuant to Item 404 of Regulation S-K. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) Financial Statement Schedules All financial statement schedules filed as part of this report are included in Item 8 of this Form 10-K and reference is made to the index on page 52 of this report.thereto. (b) Reports on Form 8-K None (c) Exhibits.Exhibits Exhibit Number Description of Exhibits ------- ----------------------- 3(i) Articles of Incorporation: * Restated Certificate of Incorporation of National Fuel Gas Company, dated March 15, 1985 (Exhibit 10-OO, Form 10-K for fiscal year ended September 30, 1991) *1991 in File No. 1-3880) 3.1 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated March 9, 1987 (Exhibit A-3 in File No. 70-7334) *3.2 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated February 22, 1988 (Exhibit B-5 in File No. 70-7478) * Certificate of Amendment of Restated Certificate of Incorporation, dated March 17, 1992 (Exhibit EX-3(a), Form 10-K for fiscal year ended September 30, 1992)1992 in File No. 1-3880) 3(ii) By-Laws: 3.1* National Fuel Gas Company By-Laws as amended through June 9, 1994 (Exhibit 3.1, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) (4) Instruments Defining the Rights of Security Holders, Including Indentures: * Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b), in File No. 2-51796) * Eighth Supplemental Indenture dated as of July 1, 1989, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit EX-4.3, Form 10-K for fiscal year ended September 30, 1992) (The Debentures issued thereunder were redeemed on March 16, 1993, July 7, 1993 and July 1, 1994) ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued) * Ninth Supplemental Indenture dated as of January 1, 1990, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit EX-4.4, Form 10-K for fiscal year ended September 30, 1992)1992 in File No. 1-3880) * Tenth Supplemental Indenture dated as of February 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a), Form 8-K dated February 14, 1992 in File No. 1-3880) * Eleventh Supplemental Indenture dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992 in File No. 1-3880) * Twelfth Supplemental Indenture dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992 in File No. 1-3880) * Thirteenth Supplemental Indenture dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401) * Fourteenth Supplemental Indenture dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) (10) Material Contracts: (ii) (B) Contracts upon which Registrant's business is substantially dependent: 10.1 Service Agreement with Empire State Pipeline under Rate Schedule FT, dated December 15, 1994. [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2] 10.2 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated August 1, 1993 10.3 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated September 19, 1995 10.4 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.5 Amendment dated as of May 1, 1995 to Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.6 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated August 1, 1993 10.7 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated October 1, 1993 * Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FTS, dated November 1, 1993 and executed February 13, 1994. 10.21994 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FSS, dated November 1, 1993 and executed February 13, 1994. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued) 10.31994 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule SST, dated November 1, 1993 and executed February 13, 1994.1994 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Gas Transportation Agreement with Tennessee Gas Pipeline Company under rate scheduleRate Schedule FT-A (Zone 4), dated September 1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) * Gas Transportation Agreement with Tennessee Gas Pipeline Company under rate scheduleRate Schedule FT-A (Zone 5), dated September 1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) * Service Agreement with Texas Eastern Transmission Corporation under rate scheduleRate Schedule CDS, dated June 1, 1993 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) * Service Agreement with Texas Eastern Transmission Corporation under rate scheduleRate Schedule FT-1, dated June 1, 1993 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) * Service Agreement with CNG Transmission Corporation under Rate Schedule FT, dated October 1, 1993 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) * Service Agreement with CNG Transmission Corporation under Rate Schedule GSS, dated October 1, 1993 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) (iii) Compensatory plans for officers: 10.4* Employment Agreement, dated September 17, 1981, with Bernard J. Kennedy.Kennedy (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Eighth Extension to Employment Agreement with Bernard J. Kennedy, dated September 20, 1991 (Exhibit 10-SS, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880) * National Fuel Gas Company 1983 Incentive Stock Option Plan, as amended and restated through February 18, 1993.1993 (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 1993)1993 in File No. 1-3880) * National Fuel Gas Company 1984 Stock Plan, as amended and restated through February 18, 1993 (Exhibit 10.3, Form 10-Q for the quarterly period ended March 31, 1993)1993 in File No. 1-3880) * National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993.1993 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1993) ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)1993 in File No. 1-3880) 10.8 Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 * Change in Control Agreement, dated May 1, 1992, with Philip C. Ackerman.Ackerman (Exhibit EX-10.4, Form 10-K for fiscal year ended September 30, 1992)1992 in File No. 1-3880) * Change in Control Agreement, dated May 1, 1992, with Richard Hare.Hare (Exhibit EX-10.5, Form 10-K for fiscal year ended September 30, 1992)1992 in File No. 1-3880) * Change in Control Agreement, dated May 1, 1992 with William J. Hill.Hill (Exhibit EX-10.6, Form 10-K for fiscal year ended September 30, 1992)1992 in File No. 1-3880) * Agreement, dated August 1, 1989, with Richard Hare.Hare (Exhibit 10-Q, Form 10-K for fiscal year ended September 30, 1989)1989 in File No. 1-3880) * Executive Death Benefits Agreement dated April 1, 1991 with William J. Hill. (Exhibit EX-10.8, Form 10-K for fiscal year ended September 30, 1992) 10.5 Amendment to Death Benefits Agreement dated March 15, 1994 with Richard Hare. 10.6 Amendment to Death Benefits Agreement dated March 15, 1994 with Philip C. Ackerman. 10.7 National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994. 10.81994 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) 10.9 Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 10.10 National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through February 17, 1994 10.9November 1, 1995 * Executive Death Benefits Agreement, dated April 1, 1991, with William J. Hill (Exhibit EX-10.8, Form 10-K for fiscal year ended September 30, 1992 in File No. 1-3880) * Split Dollar Death Benefits Agreement, dated April 1, 1991, with Richard Hare (errata). 10.10(Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Amendment to Split Dollar Death Benefits Agreement, dated March 15, 1994, with Richard Hare (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Split Dollar Death Benefits Agreement, dated April 1, 1991, with Philip C. Ackerman (errata) * Eighth Extension to Employment Agreement with Bernard J. Kennedy, dated September 20, 1991. (Exhibit 10-SS,10.10, Form 10-K for fiscal year ended September 30, 1991)1994 in File No. 1-3880) * ExecutiveAmendment to Split Dollar Death Benefits Agreement, dated March 15, 1994, with Philip C. Ackerman (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) * Death Benefits Agreement, dated August 28, 1991, with Bernard J. Kennedy.Kennedy (Exhibit 10-TT, Form 10-K for fiscal year ended September 30, 1991) ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)1991 in File No. 1-3880) 10.11 Amendment to Death Benefit Agreement of August 28, 1991 with Bernard J. Kennedy, dated March 15, 1994 * Summary of Annual at Risk Compensation Incentive Program (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1993)1993 in File No. 1-3880) * Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of December 5, 1991.1991 (Exhibit 10-UU, Form 10-K for fiscal year ended September 30, 1991)1991 in File No. 1-3880) (12) Computation of Ratio of Earnings to Fixed Charges (13) Discussion of the Company's business segments as contained in the 1995 Annual Report and incorporated by reference into this Form 10-K (21) Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K (23) Consents of Experts and Counsel: 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants (27) Financial Data ScheduleSchedules (99) Additional Exhibits: 99.1 Report of Ralph E. Davis Associates, Inc. 99.2 System Maps (Not included in EDGAR filing. See narrative description in the Appendix to this report.) All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K. *Incorporated* Incorporated herein by reference as indicated. SIGNATURESSignatures Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NATIONAL FUEL GAS COMPANYNational Fuel Gas Company (Registrant) By/s/--------------------------------- By /s/ B. J. Kennedy ------------------------------- B. J. Kennedy Chairman of the Board, President Date December 22, 199413, 1995 and Chief Executive Officer ------------------- Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title --------- ----- /s/ B. J. Kennedy Chairman of the Board, B. J. Kennedy President, Chief Executive Officer and Director DateDate: December 22, 199413, 1995 /s/ P. C. Ackerman Senior Vice President, Principal P. C. Ackerman Financial Officer and Director DateDate: December 22, 199413, 1995 /s/ R. T. Brady Director R. T. Brady Date: December 13, 1995 /s/ J. M. Brown Director J. M. Brown DateDate: December 22, 199413, 1995 /s/ D. N. Campbell Director D. N. Campbell DateDate: December 22, 199413, 1995 /s/ W. J. Hill Director W. J. Hill Date: December 13, 1995 /s/ L. F. Kahl Director L. F. Kahl DateDate: December 22, 1994 13, 1995 /s/ B. S. Lee Director B. S. Lee DateDate: December 22, 199413, 1995 /s/ E. T. Mann Director E. T. Mann DateDate: December 22, 199413, 1995 /s/ L. Rochwarger Director L. Rochwarger DateDate: December 22, 199413, 1995 /s/ G. H. Schofield Director G. H. Schofield DateDate: December 22, 199413, 1995 /s/ J. P. Pawlowski Treasurer and Principal J. P. Pawlowski Principal Accounting Officer DateDate: December 22, 199413, 1995 /s/ R.A. M. DiValerioCellino Secretary R.A. M. DiValerio DateCellino Date: December 22, 199413, 1995 /s/ G. T. Wehrlin Controller G. T. Wehrlin DateDate: December 22, 199413, 1995 APPENDIX TO ITEM 2 - PROPERTIES Three maps outlining the System'sCompany's operating areas at September 30, 1994,1995 are inlcudedincluded on page 6 in the paper format version of this the Company's combined Annual Report to Shareholders/Form 10-K, as exhibit 99.2 andbut are not included in this electronic filing. The first map identifies the System'sCompany's Exploration and Production operating area (i.e., Seneca Resources' operating area). The second map identifies the Company's Utility Operating area (i.e., Distribution Corporation's service area). The secondthird map identifiedidentifies the System'sCompany's Pipeline and Storage operating area (i.e., Supply Corporation's storage areas and pipelines). The third map identifies the System's Exploration and Production operating area (i.e., Seneca Resources' operating area). APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS A. The Revenue Dollar - 19941995 Two pie graphs detailing the revenue dollar in 1994;1995: where it came from and where it went to, broken down as follows: Where it came from: $ .592.581 Residential Sales .182.178 Commercial, Industrial and IndustrialOff-System Sales .060 Transportaion.071 Transportation Revenues .053.048 Oil and Gas Revenues .044 Natural Gas.042 Marketing Revenues .034.040 Storage Service Revenues .035.040 Other Revenues $1.000 Total Where it went to: $ .435.358 Gas Purchased .165.184 Wages, Including Benefits .128.138 Taxes .091.114 Other Materials and Services .065.073 Depreciation .051.061 Dividends - Common Stock .041.055 Interest .024.017 Reinvested in the Business $1.000 Total B. Capital Expenditures A bar graph detailing capital expenditures (millions of dollars) for the years 1991 through 1995, broken down as follows: 1991 1992 1993 1994 1995 ---- ---- ---- ---- ---- Other Nonregulated $ 1.0 $ 7.2 $ 6.2 $ 3.6 $ 9.6 Pipeline and Storage 58.6 58.7 27.4 20.5 38.7 Exploration and Production 31.7 26.3 36.5 52.5 69.7 Utility Operation 64.9 65.7 61.8 61.7 64.8 ------ ------ ------ ------ ------ $156.2 $157.9 $131.9 $138.3 $182.8 APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS (Concluded) B.C. Book Value Per Common Share A bar graph detailing book value per common share (dollars) for the years 19901991 through 1994, broken down1995, as follows: 1990 - $16.97 1991 - 17.53$17.53 1992 - 18.68 1993 - 20.08 1994 - 20.93 C. Capital Expenditures A bar graph detailing capital expenditures (millions of dollars) for the years 1990 through 1994, broken down as follows: 1990 1991 1992 1993 1994 Other Nonregulated $ 2.6 $ 1.0 $ 7.2 $ 6.2 $ 3.6 Pipeline and Storage 42.0 58.6 58.7 27.4 20.5 Exploration and Production 50.8 31.7 26.3 36.5 52.5 Utility Operation 66.1 64.9 65.7 61.8 61.7 $161.5 $156.2 $157.9 $131.9 $138.31995 - 21.39 D. Embedded Cost of Long-Term Debt A line graph detailing the embedded cost of long-term debt for the years 1990 through 1994, broken down as follows: Percent 1990 9.4 1991 9.3 1992 8.1 1993 7.3 1994 7.3 E. Capitalization Ratios A bar graph detailing capitalization (percentage) for the years 19901991 through 1994,1995, broken down as follows: Debt (%) Equity (%) 1990 56.2 43.8 1991 55.0 45.0 1992 54.5 45.5 1993 47.8 52.2 1994 46.2 53.8 1995 47.0 53.0 Exhibit Index ------------- 3.1 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated March 9, 1987 3.2 Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated February 22, 1988 10.1 Service Agreement with Empire State Pipeline under Rate Schedule FT, dated December 15, 1994. [Portions of this agreement are subject to a request for confidential treatment under Rule 24b-2] 10.2 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated August 1, 1993 10.3 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated September 19, 1995 10.4 Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.5 Amendment dated as of May 1, 1995 to Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 10.6 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated August 1, 1993 10.7 Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated October 1, 1993 10.8 Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 10.9 Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 10.10 National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 10.11 Amendment to Death Benefit Agreement of August 28, 1991 with Bernard J. Kennedy, dated March 15, 1994 (12) Computation of Ratio of Earnings to Fixed Charges (13) Discussion of the Company's business segments as contained in the 1995 Annual Report and incorporated by reference into this Form 10-K 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants 27.1 Financial Data Schedule for 12 months ending September 30, 1995 27.2 Financial Data Schedule for 12 months ending September 30, 1994, Restated 27.3 Financial Data Schedule for 9 months ending June 30, 1995, Restated 27.4 Financial Data Schedule for 6 months ending March 31, 1995, Restated 27.5 Financial Data Schedule for 3 months ending December 31, 1994, Restated 99.1 Report of Ralph E. Davis Associates, Inc.